UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
------------------------
FORM 10-K/A
AMENDMENT NO. 1
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION REGISTRANT; STATE OF INCORPORATION; IRS EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ----------------------------------- ------------------
1-9513 CMS Energy Corporation 38-2726431
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
1-5611 Consumers Energy Company 38-0442310
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF CLASS ON WHICH REGISTERED
---------- -------------- ---------------------
CMS ENERGY CORPORATION Common Stock, $.01 par value New York Stock Exchange
CMS ENERGY TRUST I 7.75% Quarterly Income Preferred Securities New York Stock Exchange
CONSUMERS ENERGY
COMPANY Preferred Stocks, $100 par value: $4.16 Series, $4.50 Series New York Stock Exchange
CONSUMERS POWER
COMPANY FINANCING I 8.36% Trust Originated Preferred Securities New York Stock Exchange
CONSUMERS ENERGY
COMPANY FINANCING II 8.20% Trust Originated Preferred Securities New York Stock Exchange
CONSUMERS ENERGY
COMPANY FINANCING
III 9.25% Trust Originated Preferred Securities New York Stock Exchange
CONSUMERS ENERGY
COMPANY FINANCING IV 9.00% Trust Originated Preferred Securities New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the Registrant (1) has 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 Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
CMS ENERGY CORPORATION: Yes X No [ ]
CONSUMERS ENERGY COMPANY: Yes [ ] No X
The aggregate market value of CMS Energy voting and non-voting common equity
held by non-affiliates was $1.167 billion for the 144,087,569 CMS Energy Common
Stock shares outstanding on June 30, 2003 based on the closing sale price of
$8.10 for CMS Energy Common Stock, as reported by the New York Stock Exchange on
such date. There were 161,148,245 shares of CMS Energy Common Stock outstanding
on March 8, 2004.
On March 8, 2004, CMS Energy held all voting and non-voting common equity of
Consumers.
Documents incorporated by reference: CMS Energy's proxy statement and Consumers'
information statement relating to the 2004 annual meeting of shareholders to be
held May 28, 2004, is incorporated by reference in Parts II and III, except for
the organization and compensation committee report and audit committee report
contained therein.
CMS Energy Corporation
Annual Report on Form 10-K/A-1 to the United States Securities and Exchange
Commission
For the Year Ended December 31, 2003
EXPLANATORY NOTE
This Form 10-K/A-1 amends CMS Energy's Form 10-K for the year ended
December 31, 2003, which was filed with the SEC on March 12, 2004. Pursuant to
Regulation S-X, Rule 3-09, this Form 10-K/A-1 includes the financial statements
as of December 31, 2003 and 2002 and for the years ended December 31, 2003, 2002
and 2001 for Emirates CMS Power Company, which is a foreign business, that are
filed as Exhibit 99(c) to this Form 10-K/A-1. These financial statements were
not available at the time of the original filing of CMS Energy's 10-K.
CMS Energy and Consumers filed a combined Form 10-K for the fiscal year
ended December 31, 2003. However, this Form 10-K/A-1 only amends the CMS Energy
Form 10-K.
CMS Energy Corporation
and
Consumers Energy Company
Annual Reports on Form 10-K to the Securities and Exchange Commission for the
Year Ended
December 31, 2003
This combined Form 10-K is separately filed by CMS Energy Corporation and
Consumers Energy Company. Information in this combined Form 10-K relating to
each individual registrant is filed by such registrant on its own behalf.
Consumers Energy Company makes no representation regarding information relating
to any other companies affiliated with CMS Energy Corporation other than its own
subsidiaries.
TABLE OF CONTENTS
PAGE
----
Glossary...................................................................... 3
PART I:
Item 1. Business.................................................... 9
Item 2. Properties.................................................. 27
Item 3. Legal Proceedings........................................... 27
Item 4. Submission of Matters to a Vote of Security Holders......... 29
PART II:
Item 5. Market for Common Equity and Related Stockholder Matters.... 30
Item 6. Selected Financial Data..................................... 30
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................. 31
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 31
Item 8. Financial Statements and Supplementary Data................. 32
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure................................... CO-1
Item 9A. Controls and Procedures..................................... CO-1
PART III:
Item 10. Directors and Executive Officers............................ CO-2
Item 11. Executive Compensation...................................... CO-2
Item 12. Security Ownership of Certain Beneficial Owners and
Management Related Stockholder Matters..................... CO-2
Item 13. Certain Relationships and Related Transactions.............. CO-2
Item 14. Principal Accountant Fees and Services...................... CO-3
PART IV:
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K......................................................... CO-3
2
GLOSSARY
Certain terms used in the text and financial statements are defined below
ABATE..................................... Association of Businesses Advocating Tariff Equity
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
AFUDC..................................... Allowance for Funds Used During Construction
ALJ....................................... Administrative Law Judge
Alliance RTO.............................. Alliance Regional Transmission Organization
AMT....................................... Alternative minimum tax
APB....................................... Accounting Principles Board
APB Opinion No. 18........................ APB Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock"
APB Opinion No. 30........................ APB Opinion No. 30, "Reporting Results of Operations --
Reporting the Effects of Disposal of a Segment of a
Business"
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
Bookouts.................................. Unplanned netting of transactions from multiple
contracts
Brownfield credit......................... Provides for a tax incentive for the redevelopment or
improvement of a facility (contaminated property), or
functionally obsolete or blighted property, provided
that certain conditions are met.
Btu....................................... British thermal unit
Centennial................................ Centennial Pipeline, LLC, in which Panhandle, formerly a
wholly owned subsidiary of CMS Gas Transmission, owned a
one-third interest
CEO....................................... Chief Executive Officer
CFO....................................... Chief Financial Officer
CFTC...................................... Commodity Futures Trading Commission
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 Land.................................. CMS Land Company, a subsidiary of Enterprises
CMS Midland............................... CMS Midland Inc., a subsidiary of Consumers
3
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
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
EITF Issue No. 97-04...................... Deregulation of the Pricing of Electricity -- Issues
Related to the Application of FASB Statements No. 71 and
101
El Chocon................................. The 1,200 MW hydro power plant located in Argentina, in
which CMS Generation holds a 17.23 percent ownership
interest
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
GCR....................................... Gas cost recovery
4
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
ITC....................................... Investment tax credit
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
MAPL...................................... Marathon Ashland Petroleum, LLC, partner in Centennial
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
Michigan Gas Storage...................... Michigan Gas Storage Company, a former subsidiary of
Consumers that merged into Consumers in November 2002
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
5
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
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
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
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"
6
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. 109.............................. SFAS No. 109, "Accounting for Income Taxes"
SFAS No. 115.............................. SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities"
SFAS No. 123.............................. 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"
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
Union..................................... Utility Workers of America, AFL-CIO
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
7
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8
PART I
ITEM 1. BUSINESS
GENERAL
CMS ENERGY
CMS Energy was formed in Michigan in 1987 and is an energy holding company
operating through subsidiaries in the United States and in selected markets
around the world. Its two principal subsidiaries are Consumers and Enterprises.
Consumers is a public utility that provides natural gas and/or electricity to
almost 6 million of Michigan's 10 million residents and serves customers in all
68 of the state's Lower Peninsula counties. Through various subsidiaries,
Enterprises is engaged in energy businesses in the United States and in selected
international markets.
In 2003, CMS Energy's consolidated operating revenue was approximately $5.5
billion. See BUSINESS SEGMENTS later in this Item 1 for further discussion of
each segment.
CONSUMERS
Consumers was formed in Michigan in 1968 and is the successor to a
corporation organized in Maine in 1910 that conducted business in Michigan from
1915 to 1968. In 1997, Consumers changed its name from Consumers Power Company
to Consumers Energy Company to better reflect its integrated electricity and gas
businesses.
Consumers' service areas include automotive, metal, chemical and food
products as well as a diversified group of other industries. Consumers'
consolidated operations account for a majority of CMS Energy's total assets and
income, as well as a substantial portion of its operating revenue. At year-end
2003, Consumers' customer base and operating revenues were as follows:
CUSTOMERS OPERATING 2003 VS. 2002
SERVED REVENUE OPERATING REVENUE
(MILLIONS) (MILLIONS) % INCREASE/(DECREASE)
---------- ---------- ---------------------
Electric Utility Business.............................. 1.75 $2,590 (2.2)
Gas Utility Business................................... 1.67 1,845 21.5
Total................................................ 2.85(a) $4,435 6.4
-------------------------
(a) Reflects total number of customers, taking into account the approximately
0.6 million combination electric and gas customers that are included in each
of the Electric Utility Business and Gas Utility Business numbers above.
Consumers' rates and certain other aspects of its business are subject to
the jurisdiction of the MPSC and FERC, as described in CMS ENERGY AND CONSUMERS
REGULATION later in this Item 1.
CONSUMERS' PROPERTIES -- GENERAL: Consumers and its subsidiaries own their
principal properties in fee, except that most electric lines and gas mains are
located in public roads or on land owned by others pursuant to easements and
other rights. Almost all of Consumers' properties are subject to the lien of its
First Mortgage Bond Indenture. For additional information on Consumers'
properties see BUSINESS SEGMENTS -- Consumers' Electric Utility
Operations -- Electric Utility Properties, and -- Consumers' Gas Utility
Operations -- Gas Utility Properties, below.
BUSINESS SEGMENTS
CMS ENERGY FINANCIAL INFORMATION
For information with respect to operating revenue, net operating income,
identifiable assets and liabilities attributable to all of CMS Energy's business
segments and international and domestic operations, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION
9
AND CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS AND NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS.
CONSUMERS' ELECTRIC UTILITY OPERATIONS
Based on the average number of customers, Consumers' electric utility
operations, if independent, would be the thirteenth largest electric utility
company in the United States. Consumers' electric utility operations include the
generation, purchase, distribution and sale of electricity. At year-end 2003, it
served customers in 61 of the 68 counties of Michigan's Lower Peninsula.
Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson,
Kalamazoo, Midland, Muskegon and Saginaw. Consumers' electric utility customer
base includes a mix of residential, commercial and diversified industrial
customers, the largest segment of which is the automotive industry. Consumers'
electric utility operations are not dependent upon a single customer, or even a
few customers, and the loss of any one or even a few of such customers is not
reasonably likely to have a material adverse effect on its financial condition.
Consumers' electric utility operations are seasonal. The summer months
usually increase demand for electric energy, principally due to the use of air
conditioners and other cooling equipment, thereby affecting revenues. In 2003,
Consumers' electric sales were 36 billion kWh and retail open access deliveries
were 3 billion kWh, for total electric deliveries of 39 billion kWh. In 2002,
Consumers' electric sales were 37 billion kWh and retail open access deliveries
were 2 billion kWh, for total electric deliveries of 39 billion kWh.
Consumers' 2003 summer peak demand was 7,721 MW (excluding retail open
access loads) and 8,170 MW (including retail open access loads). For the 2002-03
winter period, Consumers' winter peak demand was 5,862 MW (excluding retail open
access loads) and 6,140 MW (including retail open access loads). In December
2003, Consumers experienced peak demand of 5,657 MW (excluding retail open
access loads) and 6,093 MW (including retail open access loads). Based on its
summer 2003 forecast, Consumers carried an 11 percent reserve margin target.
However, as a result of lower than forecasted peak loads, Consumers' ultimate
reserve margin was 14.7 percent compared to 20.6 percent in 2002. Currently,
Consumers has a reserve margin of 5.0 percent, or supply resources equal to 105
percent of projected summer peak load for summer 2004 and is in the process of
securing the additional capacity needed to meet its summer 2004 reserve margin
target of 11 percent (111 percent of projected summer peak load). The ultimate
use of the reserve margin will depend primarily on summer weather conditions,
the level of retail open access requirements being served by others during the
summer, and any unscheduled plant outages.
ELECTRIC UTILITY PROPERTIES
GENERATION: At December 31, 2003, Consumers' electric generating system
consists of the following:
2003 NET
2003 SUMMER NET GENERATION
SIZE AND YEAR DEMONSTRATED (MILLIONS
NAME AND LOCATION (MICHIGAN) ENTERING SERVICE CAPABILITY (MWS) OF KWHS)
---------------------------- ---------------- ---------------- ----------
COAL GENERATION
J H Campbell 1 & 2 -- West Olive........... 2 Units, 1962-1967 615 4,253
J H Campbell 3 -- West Olive............... 1 Unit, 1980 765(a) 5,657
D E Karn -- Essexville..................... 2 Units, 1959-1961 511 3,429
B C Cobb -- Muskegon....................... 2 Units, 1956-1957 312 2,166
J R Whiting -- Erie........................ 3 Units, 1952-1953 326 2,256
J C Weadock -- Essexville.................. 2 Units, 1955-1958 302 2,330
----- ------
Total coal generation........................ 2,831 20,091
----- ------
OIL/GAS GENERATION
B C Cobb -- Muskegon....................... 3 Units, 1999-2000(b) 183 6
D E Karn -- Essexville..................... 2 Units, 1975-1977 1,276 352
----- ------
Total oil/gas generation..................... 1,459 358
----- ------
10
2003 NET
2003 SUMMER NET GENERATION
SIZE AND YEAR DEMONSTRATED (MILLIONS
NAME AND LOCATION (MICHIGAN) ENTERING SERVICE CAPABILITY (MWS) OF KWHS)
---------------------------- ---------------- ---------------- ----------
HYDROELECTRIC
Conventional Hydro Generation.............. 13 Plants, 1906-1949 74 335
Ludington Pumped Storage................... 6 Units, 1973 955(c) (517)(d)
----- ------
Total Hydroelectric.......................... 1,029 (182)
----- ------
NUCLEAR GENERATION
Palisades -- South Haven................... 1 Unit, 1971 767 6,151
----- ------
GAS/OIL COMBUSTION TURBINE
Generation................................. 7 Plants, 1966-1971 345 13
----- ------
Total owned generation....................... 6,431 26,431
===== ======
PURCHASED AND INTERCHANGE POWER
Capacity................................... 1,991(e)
-----
Total........................................ 8,422
=====
-------------------------
(a) Represents Consumers' share of the capacity of the J H Campbell 3 unit, net
of 6.69 percent (ownership interests of the Michigan Public Power Agency
and Wolverine Power Supply Cooperative, Inc.).
(b) Cobb 1-3 are retired coal fired units that were converted to gas fired.
Units were placed back into service in the years indicated.
(c) Represents Consumers' share of the capacity of Ludington. Consumers and
Detroit Edison have 51 percent and 49 percent undivided ownership,
respectively, in the plant.
(d) Represents Consumers' share of net pumped storage generation. This facility
electrically pumps water during off-peak hours for storage to later
generate electricity during peak-demand hours.
(e) Includes 1,240 MW of purchased contract capacity from the MCV Facility.
In 2003, through long-term purchase contracts, options, spot market and
other seasonal purchases, Consumers purchased up to 2,353 MW of net capacity
from other power producers (the largest of which was the MCV Partnership), which
amounted to 30.5 percent of Consumers' total system requirements.
DISTRIBUTION:
Consumers' distribution system includes:
- 347 miles of high-voltage distribution radial lines operating at 120
kilovolts and above;
- 4,164 miles of high-voltage distribution overhead lines operating at 23
kilovolts and 46 kilovolts;
- 16 subsurface miles of high-voltage distribution underground lines
operating at 23 kilovolts and 46 kilovolts;
- 54,922 miles of electric distribution overhead lines;
- 8,526 subsurface miles of underground distribution lines; and
- substations having an aggregate transformer capacity of 20,605,680
kilovoltamperes.
Consumers formerly owned a high-voltage transmission system that
interconnects Consumers' electric generating plants at many locations with
transmission facilities of unaffiliated systems, including those of other
utilities in Michigan and Indiana. The interconnections permit a sharing of the
reserve capacity of the connected systems. This allows mutual assistance during
emergencies and substantially reduces investment in utility plant facilities. On
May 1, 2002, Consumers transferred its investment in the high-voltage
transmission system to a third party, Michigan Electric Transmission Company,
LLC. Consequently, Consumers no longer owns or controls transmission facilities
either directly or indirectly. For additional information on the sale of the
11
transmission assets, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNCERTAINTIES) -- CONSUMERS' ELECTRIC UTILITY RESTRUCTURING
MATTERS -- TRANSMISSION SALE and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNCERTAINTIES) -- ELECTRIC RESTRUCTURING MATTERS -- TRANSMISSION SALE.
FUEL SUPPLY: Consumers has four generating plant sites that burn coal.
These plants constitute 76 percent of Consumers' baseload supply, the capacity
used to serve a constant level of customer demand. In 2003, these plants
produced a combined total of 20,091 million kWhs of electricity and burned 10.1
million tons of coal. On December 31, 2003, Consumers had on hand a 28-day
supply of coal. For additional information on future sources of coal, see ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- OTHER ELECTRIC
UNCERTAINTIES -- COMMITMENTS FOR FUTURE PURCHASES -- COAL SUPPLY.
Consumers owns Palisades, an operating nuclear power plant located near
South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers
transferred its authority to operate Palisades to the NMC. During 2003,
Palisades' net generation was 6,151 million kWhs, constituting 23.3 percent of
Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are
under NMC's control as agent for Consumers. New fuel contracts are being written
as NMC agreements. Consumers/NMC currently have sufficient contracts for uranium
concentrates to provide up to 42 percent of its fuel supply requirements for the
fall 2004 reload. A mix of spot and medium-term uranium concentrates contracts
are currently being negotiated to provide for the remaining open requirements
for the 2004 and 2006 reloads. Consumers/NMC also have contracts for conversion
services with quantity flexibility to provide up to 100 percent of the
requirements for the 2004 reload and approximately 10 percent of the
requirements for the 2006 reload. Contracts to provide for the future Consumers/
NMC requirements are currently being pursued with all suppliers of conversion
services. Enrichment services contracts with quantity flexibility ranging up to
100 percent of the requirements for the 2004 and 2006 reloads are in place. NMC
is currently negotiating a contract for supply of enrichment services beyond
2006.
NMC also has contracts for nuclear fuel services and for fabrication of
nuclear fuel assemblies. The fuel contracts are with major private industrial
suppliers of nuclear fuel and related services and with uranium producers,
converters and enrichers who participate in the world nuclear fuel marketplace.
The fabrication contract is effective for the 2004 reload with options to extend
the contract for an additional two reloads in 2006 and 2007.
As shown below, Consumers generates electricity principally from coal and
nuclear fuel.
MILLIONS OF KWHS
------------------------------------------------
POWER GENERATED 2003 2002 2001 2000 1999
--------------- ---- ---- ---- ---- ----
Coal.............................................. 20,091 19,361 19,203 17,926 19,085
Nuclear........................................... 6,151 6,358 2,326(a) 5,724 5,105
Oil............................................... 242 347 331 645 809
Gas............................................... 129 354 670 400 441
Hydro............................................. 335 387 423 351 365
Net pumped storage................................ (517) (486) (553) (541) (476)
------ ------ ------ ------ ------
Total net generation.............................. 26,431 26,321 22,400 24,505 25,329
====== ====== ====== ====== ======
-------------------------
(a) On June 20, 2001, the Palisades reactor was shut down so technicians could
inspect a small steam leak on a control rod drive assembly. The defective
components were replaced and the plant returned to service on January 21,
2002.
12
The cost of all fuels consumed, shown below, fluctuates with the mix of
fuel burned.
COST PER MILLION BTU
-----------------------------------------
FUEL CONSUMED 2003 2002 2001 2000 1999
------------- ---- ---- ---- ---- ----
Coal..................................................... $1.33 $1.34 $1.38 $1.34 $1.38
Oil...................................................... 3.92 3.49 4.02 3.30 2.69
Gas...................................................... 7.62 3.98 4.05 4.80 2.74
Nuclear.................................................. 0.34 0.35 0.39 0.45 0.52
All Fuels(a)............................................. 1.16 1.19 1.44 1.27 1.28
-------------------------
(a) Weighted average fuel costs.
The Nuclear Waste Policy Act of 1982 made the federal government
responsible for the permanent disposal of spent nuclear fuel and high-level
radioactive waste by 1998. The DOE has not arranged for storage facilities and
it does not expect to receive spent nuclear fuel for storage in 2004. Palisades
currently has spent nuclear fuel that exceeds its temporary on-site storage pool
capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved
steel and concrete vaults known as "dry casks." For additional information on
disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- OTHER CONSUMERS' ELECTRIC
UTILITY UNCERTAINTIES -- NUCLEAR MATTERS and ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (UNCERTAINTIES) -- OTHER ELECTRIC UNCERTAINTIES -- NUCLEAR MATTERS.
CONSUMERS' GAS UTILITY OPERATIONS
Based on the average number of customers, Consumers' gas utility
operations, if independent, would be the 10th largest gas utility company in the
United States. Consumers' gas utility operations purchase, transport, store,
distribute and sell natural gas. As of December 31, 2003, it was authorized to
provide service in 54 of the 68 counties in Michigan's Lower Peninsula.
Principal cities served include Bay City, Flint, Jackson, Kalamazoo, Lansing,
Pontiac and Saginaw, as well as the suburban Detroit area, where nearly 900,000
of the gas customers are located. Consumers' gas utility operations are not
dependent upon a single customer, or even a few customers, and the loss of any
one or even a few of such customers is not reasonably likely to have a material
adverse effect on its financial condition.
Consumers' gas utility operations are seasonal. Consumers injects natural
gas into storage during the summer months for use during the winter months when
the demand for natural gas is higher. Peak demand usually occurs in the winter
due to colder temperatures and the resulting increased demand for heating fuels.
In 2003, total deliveries of natural gas sold by Consumers and by other sellers
who deliver natural gas to customers (including the MCV Partnership) through
Consumers' pipeline and distribution network totaled 388 bcf.
During the winter months of 2002-03, cold weather caused heavy withdrawals
from Consumers' gas storage fields. As a result, water and other liquids entered
certain of Consumers' pipelines. The existence of water and other liquids in the
pipelines could cause pipe corrosion, which in turn may increase future
maintenance problems and costs.
GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system
consists of:
- 25,551 miles of distribution mains throughout Michigan's Lower Peninsula;
- 1,624 miles of transmission lines throughout Michigan's Lower Peninsula;
- 7 compressor stations with a total of 162,000 installed horsepower; and
- 14 gas storage fields located across Michigan with an aggregate storage
capacity of 331 bcf and a working storage capacity of 130 bcf.
13
GAS SUPPLY: In 2003, Consumers purchased 3 percent of its gas from Michigan
producers, 66 percent from United States producers outside Michigan and 22
percent from Canadian producers. Authorized suppliers in the gas customer choice
program supplied the remaining 9 percent of gas that Consumers delivered.
Consumers' firm transportation agreements are with ANR Pipeline Company,
Great Lakes Gas Transmission, L.P., Trunkline Gas Co. and Panhandle Eastern Pipe
Line Company. Consumers uses these agreements to deliver gas to Michigan for
ultimate deliveries to market. Consumers' firm transportation and city gate
arrangements are capable of delivering over 95 percent of Consumers' total gas
supply requirements. As of December 31, 2003, Consumers' portfolio of firm
transportation from pipelines to Michigan is as follows:
VOLUME
(DEKATHERMS/DAY) EXPIRATION
---------------- ----------
ANR Pipeline Company........................................ 84,054 March 2004
ANR Pipeline Company (starting 04/01/04).................... 50,000 March 2006
ANR Pipeline Company (starting 04/01/04).................... 40,000 October 2004
Great Lakes Gas Transmission, L.P. ......................... 85,092 April 2004
Great Lakes Gas Transmission, L.P. (starting 04/01/04)...... 50,000 March 2007
Great Lakes Gas Transmission, L.P. ......................... 90,000 March 2004
Great Lakes Gas Transmission, L.P. (starting 04/01/04)...... 100,000 March 2007
Trunkline Gas Co. .......................................... 336,375 October 2005
Trunkline Gas Co. .......................................... 40,106 March 2004
Panhandle Eastern Pipe Line Company (starting 04/01/04)..... 50,000 October 2004
Vector Pipeline............................................. 50,000 March 2007
Consumers purchases the balance of its required gas supply under firm city
gate contracts and as needed, interruptible contracts. The amount of
interruptible transportation service and its use varies primarily with the price
for such service and the availability and price of the spot supplies being
purchased and transported. Consumers' use of interruptible transportation is
generally in off-peak summer months and after Consumers has fully utilized the
services under the firm transportation agreements.
NATURAL GAS TRANSMISSION
CMS Gas Transmission was formed in 1988 and owns, develops and manages
domestic and international natural gas facilities. In 2003, CMS Gas
Transmission's operating revenue was $22 million.
In 1999, CMS Gas Transmission acquired Panhandle, which was primarily
engaged in the interstate transmission and storage of natural gas and also
provided LNG terminalling and regasification services. Panhandle operated a
large natural gas pipeline network, which provided customers in the Midwest and
Southwest with a comprehensive array of transportation services. Panhandle's
major customers included 25 utilities located primarily in the United States
Midwest market area, which encompassed large portions of Illinois, Indiana,
Michigan, Missouri, Ohio and Tennessee.
In February 2003, Panhandle sold its one-third equity interest in
Centennial for $40 million to Centennial's two other partners, MAPL and TE
Products Pipeline Company, Limited Partnership, through its general partner,
TEPPCO.
In March 2003, Panhandle transferred $63 million previously committed to
collateralize a letter of credit and its one-third ownership interest in
Guardian to CMS Gas Transmission. CMS Gas Transmission sold its interest in
Guardian to a subsidiary of WPS Resources Corporation in May 2003. Proceeds from
the sale were $26 million and the $63 million of cash collateral was released.
In June 2003, CMS Gas Transmission sold Panhandle to Southern Union
Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union
Panhandle Corp. purchased all of Panhandle's outstanding capital stock for
approximately $582 million in cash and 3 million shares of Southern Union common
stock. Southern Union Panhandle Corp. also assumed approximately $1.166 billion
in debt. In July 2003, Southern Union declared a five percent common stock
dividend resulting in an additional 150,000 shares of common stock
14
for CMS Gas Transmission. In October 2003, CMS Gas Transmission sold its 3.15
million shares to a private investor for $17.77 per share.
In July 2003, CMS Gas Transmission completed the sale of CMS Field Services
to Cantera Natural Gas, Inc. for gross cash proceeds of approximately $113
million, subject to post closing adjustments, and a $50 million face value note
of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to $50
million subject to the financial performance of the Fort Union and Bighorn
natural gas gathering systems from 2004 through 2008.
NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of
288 miles of gathering and transmission pipelines located in the state of
Michigan, with a daily capacity of 0.95 bcf. At December 31, 2003, CMS Gas
Transmission had nominal processing capabilities of approximately 0.33 bcf per
day of natural gas in Michigan.
At December 31, 2003, CMS Gas Transmission has ownership interests in the
following international pipelines:
LOCATION OWNERSHIP INTEREST (%) MILES OF PIPELINES
-------- ---------------------- ------------------
Argentina................................................. 29.42 3,362
Argentina to Brazil....................................... 20.00 262
Argentina to Chile........................................ 50.00 707
Australia (Western Australia)............................. 40.00(a) 927
Australia (Western Australia)............................. 100.00 259
-------------------------
(a) CMS Gas Transmission has a 45 percent interest in a consortium that
acquired an 88 percent interest in the pipeline.
Properties of certain CMS Gas Transmission subsidiaries are subject to
liens of creditors of the respective subsidiaries.
INDEPENDENT POWER PRODUCTION
CMS Generation was formed in 1986. It invests in, acquires, develops,
constructs and operates non-utility power generation plants in the United States
and abroad. In 2003, the independent power production business segment's
operating revenue, which includes revenues from CMS Generation, CMS Operating,
S.A., the MCV Facility and the MCV Partnership, was $204 million.
INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2003, CMS
Generation had ownership interests in operating power plants totaling 8,766
gross MW (4,149 net MW). At December 31, 2003, additional plants totaling
approximately 1,784 gross MW (420 net MW) were under construction or in advanced
stages of development. These plants include the Shuweihat power plant, which is
under construction in the United Arab Emirates, and the Saudi Petrochemical
Company power plant, which is under advanced development and will be located in
the Kingdom of Saudi Arabia. In 2004, CMS Generation plans to complete the
restructuring of its operations by narrowing the scope of its existing
operations and commitments from four to two regions: the U.S. and the Middle
East/North Africa. In addition, it plans to sell designated assets and
investments that are under-performing, non-region focused and non-synergistic
with other CMS Energy business units.
15
The following table details CMS Generation's interest in independent power
plants as of year-end 2003 (excluding the plants owned by CMS Operating, S.R.L.
and CMS Electric and Gas and the MCV facility, discussed further below):
PERCENTAGE OF
GROSS CAPACITY
UNDER LONG-TERM
OWNERSHIP INTEREST GROSS CAPACITY CONTRACT
LOCATION FUEL TYPE (%) (MW) (%)
-------- --------- ------------------ -------------- ---------------
California..................... Wood 37.8 36 100
Connecticut.................... Scrap tire 100 31 100
Michigan....................... Coal 50 70 100
Michigan....................... Natural gas 100 710 85
Michigan....................... Natural gas 100 224 0
Michigan....................... Wood 50 40 100
Michigan....................... Wood 50 38 100
New York....................... Hydro 0.3 14 100
North Carolina................. Wood 50 50 100
Oklahoma....................... Natural gas 8.8 124 100
-----
DOMESTIC TOTAL................. 1,337
Argentina...................... Hydro 17.2 1,320 20(a)
Australia...................... Coal 49.6 2,000 55
Chile.......................... Natural gas 50 720 100(b)
Ghana.......................... Crude oil 90 224 100
India.......................... Coal 50 250 100
India.......................... Natural gas 33.2 235 100
Jamaica........................ Diesel 42.3 63 100
Latin America.................. Various Various 484 51
Morocco........................ Coal 50 1,356 100
United Arab Emirates........... Natural gas 40 777 100
-----
INTERNATIONAL TOTAL............ 7,429
TOTAL DOMESTIC AND
INTERNATIONAL................ 8,766
=====
PROJECTS UNDER CONSTRUCTION/
ADVANCED DEVELOPMENT......... 1,784
-------------------------
(a) El Chocon is primarily on a spot market basis, however, it has a high
dispatch rate due to low cost.
(b) Atacama is not allowed to sell more than 440 MW to the grid. 100 percent of
the 440 MW is under contract.
Through a CMS International Ventures subsidiary called CMS Operating,
S.R.L., CMS Enterprises, CMS Gas Transmission and CMS Generation have a 100
percent ownership interest in a 128 MW natural gas power plant and a 92.6
percent ownership interest in a 540 MW natural gas power plant, each in
Argentina.
Through CMS Electric and Gas, CMS Enterprises has an 86 percent ownership
interest in 287 MW of gas turbine and diesel generating capacity in Venezuela.
CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, which was formed to construct and operate the MCV Facility. The MCV
Facility was sold to five owner trusts and leased back to the MCV Partnership.
CMS Holdings is a limited partner in the FMLP, which is a beneficiary of one of
these trusts. Through FMLP, CMS Holdings has a 35 percent Lessor interest in the
MCV Facility. The MCV Facility has a net electrical generating capacity of
approximately 1,500 MW.
CMS Generation has ownership interests in certain facilities such as Loy
Yang, Jorf Lasfar and El Chocon. The Loy Yang assets are owned in fee, but are
subject to the security interests of its lenders. CMS Energy is actively working
to sell its interest in the Loy Yang facility. The Jorf Lasfar facility is held
pursuant to a right of
16
possession agreement with the Moroccan state-owned Office National de
l'Electricite. The El Chocon facility is held pursuant to a 30-year possession
agreement.
For information on capital expenditures, see ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES AND LIQUIDITY AND ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 5 OF CMS ENERGY'S NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS (FINANCINGS AND CAPITALIZATION).
OIL AND GAS EXPLORATION AND PRODUCTION
CMS Energy used to own an oil and gas exploration and production company.
In October 2002, CMS Energy completed its exit from the oil and gas exploration
and production business.
ENERGY RESOURCE MANAGEMENT
In 2003, CMS ERM moved its headquarters from Houston, Texas to Jackson,
Michigan. In February 2004, CMS ERM changed its name from CMS Marketing,
Services and Trading Company to CMS Energy Resource Management Company. CMS ERM
has reduced its business focus and in the future will concentrate on the
purchase and sale of energy commodities in support of CMS Energy's generating
facilities. CMS ERM previously provided gas, oil, and electric marketing, risk
management and energy management services to industrial, commercial, utility and
municipal energy users throughout the United States. In January 2003, CMS ERM
closed the sale of a major portion of its wholesale natural gas trading book to
Sempra Energy Trading. The cash proceeds were approximately $17 million. In
April 2003, CMS ERM sold its wholesale electric power business to Constellation
Power Source, Inc. Also in April 2003, CMS ERM sold the federal business of CMS
Viron, its energy management service provider, to Pepco Energy Services, Inc. In
July 2003, CMS ERM sold CMS Viron's non-federal business to Chevron Energy
Solutions Company, a division of Chevron U.S.A. In 2003, CMS ERM marketed
approximately 85 bcf of natural gas and 5,314 GWh of electricity and its 2003
operating revenue was $711 million.
INTERNATIONAL ENERGY DISTRIBUTION
In October 2001, CMS Energy discontinued the operations of its
international energy distribution business. In 2002, CMS Energy discontinued all
new development outside North America, which included closing all non-U.S.
development offices. In 2003, CMS Energy reclassified to continuing operations
SENECA, which is its energy distribution business in Venezuela, and CPEE, which
is its energy distribution business in Brazil, due to its inability to sell
these assets.
CMS ENERGY AND CONSUMERS REGULATION
CMS Energy is a public utility holding company that is exempt from
registration under PUHCA. CMS Energy, Consumers and their subsidiaries are
subject to regulation by various federal, state, local and foreign governmental
agencies, including those described below.
MICHIGAN PUBLIC SERVICE COMMISSION
Consumers is subject to the MPSC's jurisdiction, which regulates public
utilities in Michigan with respect to retail utility rates, accounting, utility
services, certain facilities and various other matters. The MPSC also has rate
jurisdiction over several limited liability companies in which CMS Gas
Transmission has ownership interests. These companies own, or will own, and
operate intrastate gas transmission pipelines.
The Attorney General, ABATE, and the MPSC staff typically intervene in MPSC
electric- and gas-related proceedings concerning Consumers. For many years,
almost every significant MPSC order affecting Consumers has been appealed.
Certain appeals from the MPSC orders are pending in the Court of Appeals.
RATE PROCEEDINGS: In 1996, the MPSC issued an order that established the
electric authorized rate of return on common equity at 12.25 percent. In 2002,
the MPSC issued an order that established the gas authorized rate of return on
common equity at 11.4 percent.
17
MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the
retail electric and gas utility businesses has undergone significant changes. In
2000, the Michigan Legislature enacted the Customer Choice Act. The Customer
Choice Act provides that as of January 2002, all electric customers have the
choice to buy generation service from an alternative electric supplier. The
Customer Choice Act also imposes rate reductions, rate freezes and rate caps.
For additional information regarding the Customer Choice Act, see ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' ELECTRIC UTILITY
RESTRUCTURING MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNCERTAINTIES) -- ELECTRIC RESTRUCTURING MATTERS.
As a result of regulatory changes in the natural gas industry, Consumers
transports the natural gas commodity that is sold to some customers by
competitors like gas producers, marketers and others. Pursuant to a gas customer
choice program that Consumers implemented, as of April 2003 all of Consumers'
gas customers are eligible to select an alternative gas commodity supplier.
Consumers' current GCR mechanism allows it to recover from its customers all
prudently incurred costs to purchase natural gas commodity and transport it to
Consumers' facilities. For additional information, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' GAS UTILITY RATE
MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF
CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- GAS
RATE MATTERS.
FEDERAL ENERGY REGULATORY COMMISSION
FERC has exercised limited jurisdiction over several independent power
plants in which CMS Generation has ownership interests, as well as over CMS ERM.
Among other things, FERC jurisdiction relates to the acquisition, operation and
disposal of assets and facilities and to the service provided and rates charged.
Some of Consumers' gas business is also subject to regulation by FERC, including
a blanket transportation tariff pursuant to which Consumers can transport gas in
interstate commerce.
FERC also regulates certain aspects of Consumers' electric operations
including compliance with FERC accounting rules, wholesale rates, operation of
licensed hydro-electric generating plants, transfers of certain facilities, and
corporate mergers and issuance of securities. FERC is currently soliciting
comments on whether it should exercise jurisdiction over power marketers like
CMS ERM, requiring them to follow FERC's uniform system of accounts and seek
authorization for issuance of securities and assumption of liabilities. These
issues are pending before the agency.
NUCLEAR REGULATORY COMMISSION
Under the Atomic Energy Act of 1954, as amended, and the Energy
Reorganization Act of 1974, Consumers is subject to the jurisdiction of the NRC
with respect to the design, construction, operation and decommissioning of its
nuclear power plants. Consumers is also subject to NRC jurisdiction with respect
to certain other uses of nuclear material. These and other matters concerning
Consumers' nuclear plants are more fully discussed in ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTES 1 (CORPORATE STRUCTURE AND ACCOUNTING
POLICIES) AND 4 (UNCERTAINTIES) OF CMS ENERGY'S CONSOLIDATED FINANCIAL
STATEMENTS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES 1
(CORPORATE STRUCTURE AND ACCOUNTING POLICIES) AND 2 (UNCERTAINTIES) OF
CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS.
OTHER REGULATION
The Secretary of Energy regulates the importation and exportation of
natural gas and has delegated various aspects of this jurisdiction to FERC and
the DOE's Office of Fossil Fuels.
18
Pipelines owned by system companies are subject to the Natural Gas Pipeline
Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which
regulates the safety of gas pipelines. Consumers is also subject to the
Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum
pipelines.
CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE
CMS Energy, Consumers and their subsidiaries are subject to various
federal, state and local regulations for environmental quality, including air
and water quality, waste management, zoning and other matters.
Consumers has installed and is currently installing modern emission
controls at its electric generating plants and has converted and is converting
electric generating units to burn cleaner fuels. Consumers expects that the cost
of future environmental compliance, especially compliance with clean air laws,
will be significant because of EPA regulations regarding nitrogen oxide and
particulate-related emissions. These regulations will require Consumers to make
significant capital expenditures.
Consumers is in the process of closing older ash disposal areas at two
plants. Construction, operation, and closure of a modern solid waste disposal
area for ash can be expensive, because of strict federal and state requirements.
In order to significantly reduce ash field closure costs, Consumers has worked
with others to use bottom ash and fly ash as part of temporary and final cover
for ash disposal areas instead of native materials, in cases where such use of
bottom ash and fly ash is compatible with environmental standards. To reduce
disposal volumes, Consumers sells coal ash for use as a filler for asphalt, for
incorporation into concrete products and for other environmentally compatible
uses. The EPA has announced its intention to develop new nationwide standards
for ash disposal areas. Consumers intends to work through industry groups to
help ensure that any such regulations require only the minimum cost necessary to
adhere to standards that are consistent with protection of the environment.
Like most electric utilities, Consumers has PCB in some of its electrical
equipment. During routine maintenance activities, Consumers identified PCB as a
component in certain paint, grout and sealant materials at the Ludington Pumped
Storage facility. Consumers removed and replaced part of the PCB material.
Consumers has proposed a plan to the EPA to deal with the remaining materials
and is waiting for a response from the EPA.
Certain environmental regulations affecting CMS Energy and Consumers
include, but are not limited to, the Clean Air Act Amendments of 1990 and
Superfund. Superfund can require any individual or entity that may have owned or
operated a disposal site, as well as transporters or generators of hazardous
substances that were sent to such site, to share in remediation costs for the
site.
CMS Energy's and Consumers' current insurance coverage does not extend to
certain environmental clean-up costs, such as claims for air pollution, some
past PCB contamination and for some long-term storage or disposal of pollutants.
For additional information concerning environmental matters, including
estimated capital expenditures to reduce nitrogen oxide related emissions, see
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS'
ELECTRIC UTILITY CONTINGENCIES and ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (UNCERTAINTIES) -- ELECTRIC CONTINGENCIES.
CMS ENERGY AND CONSUMERS COMPETITION
ELECTRIC COMPETITION
Consumers' electric utility business experiences actual and potential
competition from many sources, both in the wholesale and retail markets, as well
as in electric generation, electric delivery and retail services.
In the wholesale electricity markets, Consumers competes with other
wholesale suppliers, marketers and brokers. Electric competition in the
wholesale markets increased significantly since 1996 due to FERC Order 888.
While Consumers is still active in wholesale electricity markets, wholesale for
resale transactions by Consumers
19
generated an immaterial amount of Consumers' 2003 revenues from electric utility
operations. Consumers believes future loss of wholesale for resale transactions
will be insignificant.
A significant increase in retail electric competition has occurred because
of the Customer Choice Act and the availability of retail open access. Price is
the principal method of competition for generation services. The Customer Choice
Act gives all electric customers the right to buy generation service from an
alternative electric supplier. As of March 2004, alternative electric suppliers
are providing 735 MW of generation supply to retail open access customers. This
represents nine percent of Consumers' total generating load and an increase of
approximately 42 percent in generation supply being purchased from alternative
electric suppliers by retail open access customers. Consumers has applied for,
but has not yet been granted, reimbursement for implementation costs incurred
for the Electric Customer Choice program. The MPSC is supposed to adopt a
mechanism pursuant to the Customer Choice Act to provide for recovery of
stranded costs. In 2000 and 2001, the MPSC determined the stranded cost recovery
was zero, contrary to Consumers' position. Consumers continues to work toward
the adoption of a stranded cost recovery mechanism that will offset margin loss.
Consumers cannot predict the total amount of electric supply load that may be
lost to competitor suppliers, whether the stranded cost recovery method adopted
by the MPSC will be applied in a manner that will fully offset any associated
margin loss, or whether implementation costs will be fully recovered.
In addition to retail electric customer choice, Consumers also has
competition or potential competition from:
- the threat of customers relocating outside Consumers' service territory;
- the possibility of municipalities owning or operating competing electric
delivery systems;
- customer self-generation; and
- adjacent municipal utilities that extend lines to customers near service
territory boundaries.
Consumers addresses this competition by offering special contracts,
providing additional non-energy services, and monitoring and enforcing
compliance with MPSC and FERC rules.
Consumers offers non-energy revenue services to electric customers,
municipalities and other utilities in an effort to offset costs. These services
include engineering and consulting, construction of customer-owned distribution
facilities, equipment sales (such as transformers), power quality analysis,
fiber optic line construction, meter reading and joint construction for phone
and cable. Consumers faces competition from many sources, including energy
management services companies, other utilities, contractors, and retail
merchandisers.
CMS ERM, which is a non-utility electric subsidiary, has modified its focus
toward optimization of CMS Energy's independent power production portfolio. CMS
Energy's independent power production business segment, another non-utility
electric subsidiary, faces competition from generators, marketers and brokers,
as well as lower power prices on the wholesale market.
For additional information concerning electric competition, see ITEM 7. CMS
ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY
BUSINESS UNCERTAINTIES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND
ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES.
GAS COMPETITION
Competition has existed for the past decade in various aspects of
Consumers' gas utility business, and is likely to increase. Competition
traditionally comes from alternate fuels and energy sources, such as propane,
oil and electricity.
INSURANCE
CMS Energy and its subsidiaries, including Consumers, maintain insurance
coverage similar to comparable companies in the same lines of business. The
insurance policies are subject to terms, conditions, limitations and exclusions
that might not fully compensate CMS Energy for all losses. As CMS Energy renews
its policies it is
20
possible that full insurance coverage may not be obtainable on commercially
reasonable terms due to restrictive insurance markets.
EMPLOYEES
CMS ENERGY
As of December 31, 2003, CMS Energy and its subsidiaries, including
Consumers, had 8,411 full-time equivalent employees, of whom 8,353 are full-time
employees and 58 are full-time equivalent employees associated with the
part-time work force. Included in the total are 3,800 employees who are covered
by union contracts.
CONSUMERS
As of December 31, 2003, Consumers and its subsidiaries had 7,947 full-time
equivalent employees, of whom 7,892 are full-time employees and 55 are full-time
equivalent employees associated with the part-time work force. Included in the
total are 3,483 full-time operating, maintenance and construction Consumers'
employees and 293 full-time and part-time Consumers' call center employees who
are represented by the Utility Workers Union of America. Consumers and the Union
negotiated a collective bargaining agreement for the operating, maintenance and
construction employees that became effective as of June 1, 2000 and will
continue in full force and effect until June 1, 2005. Consumers and the Union
negotiated a collective bargaining agreement for the call center employees that
became effective as of April 1, 2003 and will continue in full force and effect
until August 1, 2005.
CMS ENERGY EXECUTIVE OFFICERS
(as of March 1, 2004)
NAME AGE POSITION PERIOD
---- --- -------- ------
Kenneth Whipple...................... 69 Chairman of the Board, Chief Executive
Officer of CMS Energy 2002-Present
Chairman of the Board, Chief Executive
Officer of Consumers 2002-Present
Chairman of the Board of CMS Enterprises 2002-2003
Director of CMS Energy 1993-Present
Director of Consumers 1993-Present
Chairman, Chief Executive Officer of Ford
Credit Company 1997-1999
Executive Vice President, President of Ford
Financial Services Group 1989-1999
S. Kinnie Smith, Jr. ................ 73 Vice Chairman of the Board of CMS
Enterprises 2003-Present
Vice Chairman of the Board, General Counsel
of CMS Energy 2002-Present
Vice Chairman of the Board of Consumers 2002-Present
Executive Vice President of CMS Enterprises 2002-2003
Director of CMS Energy 2002-Present
Director of Consumers 2002-Present
Director of Enterprises 2003-Present
Vice Chairman of Trans-Elect, Inc. 2002
Senior Counsel at Skadden, Arps, Slate,
Meagher, & Flom LLP 1996-2002
21
NAME AGE POSITION PERIOD
---- --- -------- ------
David W. Joos........................ 50 Chairman of the Board, Chief Executive
Officer of CMS Enterprises 2003-Present
President, Chief Operating Officer of CMS
Energy 2001-Present
President, Chief Operating Officer of
Consumers 2001-Present
President, Chief Operating Officer of CMS
Enterprises 2001-2003
Director of CMS Energy 2001-Present
Director of Consumers 2001-Present
Director of Enterprises 2000-Present
Executive Vice President, Chief Operating
Officer -- Electric of CMS Energy 2000-2001
Executive Vice President, Chief Operating
Officer -- Electric of CMS Enterprises 2000-2001
Executive Vice President, President and
Chief Executive Officer -- Electric of
Consumers 1997-2001
Thomas J. Webb....................... 51 Executive Vice President, Chief Financial
Officer of CMS Energy 2002-Present
Executive Vice President, Chief Financial
Officer of Consumers 2002-Present
Executive Vice President, Chief Financial
Officer of CMS Enterprises 2002-Present
Director of Enterprises 2002-Present
Executive Vice President, Chief Financial
Officer of Panhandle Eastern Pipe Line
Company 2002-2003
Executive Vice President, Chief Financial
Officer of Kellogg Company 1999-2002
Vice President, Chief Financial Officer of
Visteon, a division of Ford Motor Company 1996-1999
Thomas W. Elward..................... 55 President, Chief Operating Officer of CMS
Enterprises 2003-Present
President, Chief Executive Officer of CMS
Generation Co. 2002-Present
Director of Enterprises 2003-Present
Senior Vice President of CMS Enterprises 2002-2003
Senior Vice President of CMS Generation Co. 1998-2001
Carl L. English...................... 57 Executive Vice President, President and
Chief Executive Officer -- Gas of
Consumers 1999-Present
Vice President of Consumers 1990-1999
John G. Russell*..................... 46 Executive Vice President, President and
Chief Executive Officer -- Electric of
Consumers 2001-Present
Senior Vice President of Consumers 2000-2001
Vice President of Consumers 1999-2000
David G. Mengebier**................. 46 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2001-Present
Senior Vice President of Consumers 2001-Present
Vice President of CMS Energy 1999-2001
Vice President of Consumers 1999-2001
22
NAME AGE POSITION PERIOD
---- --- -------- ------
John F. Drake........................ 55 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2002-Present
Senior Vice President of Consumers 2002-Present
Vice President of CMS Energy 1997-2002
Vice President of Consumers 1998-2002
Glenn P. Barba....................... 38 Vice President, Chief Accounting Officer of
CMS Enterprises 2003-Present
Vice President, Controller and Chief
Accounting Officer of CMS Energy 2003-Present
Vice President, Controller and Chief
Accounting Officer of Consumers 2003-Present
Vice President and Controller of Consumers 2001-2003
Controller of CMS Generation 1997-2001
-------------------------
* From July 1997 until October 1999, Mr. Russell served as Manager -- Electric
Customer Operations of Consumers.
** From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal
Governmental Affairs for CMS Enterprises.
There are no family relationships among executive officers and directors of
CMS Energy.
The present term of office of each of the executive officers extends to the
first meeting of the Board of Directors after the next annual election of
Directors of CMS Energy (scheduled to be held on May 28, 2004).
23
CONSUMERS EXECUTIVE OFFICERS
(as of March 1, 2004)
NAME AGE POSITION PERIOD
---- --- -------- ------
Kenneth Whipple...................... 69 Chairman of the Board, Chief Executive
Officer of CMS Energy 2002-Present
Chairman of the Board, Chief Executive
Officer of Consumers 2002-Present
Chairman of the Board of CMS Enterprises 2002-2003
Director of CMS Energy 1993-Present
Director of Consumers 1993-Present
Chairman, Chief Executive Officer of
Ford Credit Company 1997-1999
Executive Vice President, President of
Ford Financial Services Group 1989-1999
S. Kinnie Smith, Jr. ................ 73 Vice Chairman of the Board of CMS
Enterprises 2003-Present
Vice Chairman of the Board, General
Counsel of CMS Energy 2002-Present
Vice Chairman of the Board of Consumers 2002-Present
Executive Vice President of CMS
Enterprises 2002-2003
Director of CMS Energy 2002-Present
Director of Consumers 2002-Present
Director of Enterprises 2003-Present
Vice Chairman of Trans-Elect, Inc. 2002
Senior Counsel at Skadden, Arps, Slate,
Meagher, & Flom LLP 1996-2002
David W. Joos........................ 50 Chairman of the Board, Chief Executive
Officer of CMS Enterprises 2003-Present
President, Chief Operating Officer of
CMS Energy 2001-Present
President, Chief Operating Officer of
Consumers 2001-Present
President, Chief Operating Officer of
CMS Enterprises 2001-2003
Director of CMS Energy 2001-Present
Director of Consumers 2001-Present
Director of Enterprises 2000-Present
Executive Vice President, Chief
Operating Officer -- Electric of CMS
Energy 2000-2001
Executive Vice President, Chief
Operating Officer -- Electric of CMS
Enterprises 2000-2001
Executive Vice President, President and
Chief Executive Officer -- Electric of
Consumers 1997-2001
24
NAME AGE POSITION PERIOD
---- --- -------- ------
Thomas J. Webb....................... 51 Executive Vice President, Chief
Financial Officer of CMS Energy 2002-Present
Executive Vice President, Chief
Financial Officer of Consumers 2002-Present
Executive Vice President, Chief
Financial Officer of CMS Enterprises 2002-Present
Director of Enterprises 2002-Present
Executive Vice President, Chief
Financial Officer of Panhandle Eastern
Pipe Line Company 2002-2003
Executive Vice President, Chief
Financial Officer of Kellogg Company 1999-2002
Vice President, Chief Financial Officer
of Visteon, a division of Ford Motor
Company 1996-1999
Carl L. English...................... 57 Executive Vice President, President and
Chief Executive Officer -- Gas of
Consumers 1999-Present
Vice President of Consumers 1990-1999
John G. Russell*..................... 46 Executive Vice President, President and
Chief Executive Officer -- Electric of
Consumers 2001-Present
Senior Vice President of Consumers 2000-2001
Vice President of Consumers 1999-2000
John F. Drake........................ 55 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2002-Present
Senior Vice President of Consumers 2002-Present
Vice President of CMS Energy 1997-2002
Vice President of Consumers 1998-2002
Robert A. Fenech..................... 56 Senior Vice President of Consumers 1997-Present
Vice President of Consumers 1994-1997
Preston D. Hopper.................... 53 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2003-Present
Senior Vice President of Consumers 2003-Present
Senior Vice President, Chief Accounting
Officer of CMS Enterprises 1997-2003
Senior Vice President, Chief Accounting
Officer and Controller of CMS Energy 1996-2003
Senior Vice President and Controller of
CMS Enterprises 1996-1997
Frank Johnson........................ 56 Senior Vice President of Consumers 2001-Present
President, Chief Executive Officer of
CMS Electric and Gas 2000-2002
Vice President, Chief Operating Officer
of CMS Electric and Gas 2000
Vice President of CMS Electric and Gas 1996-2000
25
NAME AGE POSITION PERIOD
---- --- -------- ------
David G. Mengebier**................. 46 Senior Vice President of CMS Enterprises 2003-Present
Senior Vice President of CMS Energy 2001-Present
Senior Vice President of Consumers 2001-Present
Vice President of CMS Energy 1999-2001
Vice President of Consumers 1999-2001
David A. Mikelonis................... 55 Senior Vice President, General Counsel
of Consumers 1988-Present
Paul N. Preketes..................... 54 Senior Vice President of Consumers 1999-Present
Vice President of Consumers 1994-1999
Glenn P. Barba....................... 38 Vice President, Chief Accounting Officer
of CMS Enterprises 2003-Present
Vice President, Controller and Chief
Accounting Officer of CMS Energy 2003-Present
Vice President, Controller and Chief
Accounting Officer of Consumers 2003-Present
Vice President and Controller of
Consumers 2001-2003
Controller of CMS Generation 1997-2001
-------------------------
* From July 1997 until October 1999, Mr. Russell served as Manager -- Electric
Customer Operations of Consumers.
** From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal
Governmental Affairs for CMS Enterprises.
There are no family relationships among executive officers and directors of
Consumers.
The present term of office of each of the executive officers extends to the
first meeting of the Board of Directors after the next annual election of
Directors of Consumers (scheduled to be held on May 28, 2004).
AVAILABLE INFORMATION
CMS Energy's internet address is http://www.cmsenergy.com. You can access
free of charge on our website all of our annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act. Such
reports are available as soon as practical after they are electronically filed
with the SEC. Also on our website are our:
- Corporate Governance Principles;
- Code of Conduct (Code of Business Conduct and Ethics);
- Board Committee Charters (including the Audit Committee and the
Governance and Nominating Committee)
We will provide this information in print to any shareholder who requests
it.
26
ITEM 2. PROPERTIES.
Descriptions of CMS Energy's and Consumers' properties are found in the
following sections of Item 1, all of which are incorporated by reference herein:
- BUSINESS -- GENERAL -- Consumers -- Consumers Properties -- General;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Electric Utility
Operations -- Electric Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Gas Utility Operations -- Gas
Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Natural Gas Transmission -- Natural Gas
Transmission Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Independent Power
Production -- Independent Power Production Properties; and
- BUSINESS -- BUSINESS SEGMENTS -- International Energy Distribution
ITEM 3. LEGAL PROCEEDINGS.
CMS Energy, Consumers and some of their subsidiaries and affiliates are
parties to certain routine lawsuits and administrative proceedings incidental to
their businesses involving, for example, claims for personal injury and property
damage, contractual matters, various taxes, and rates and licensing. For
additional information regarding various pending administrative and judicial
proceedings involving regulatory, operating and environmental matters, see ITEM
1. BUSINESS -- CMS ENERGY AND CONSUMERS REGULATION, both CMS Energy's and
Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's
and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS.
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 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 the best interest of CMS Energy 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 was 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, CMS Enterprises and APT. Integrum alleges several
causes of action against APT, CMS Energy and CMS 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
CMS Enterprises from selling and APT from purchasing the CMS Pipeline Assets and
an order of specific performance mandating that CMS Energy, CMS Enterprises and
APT complete the sale of the CMS Pipeline Assets to APT and Integrum. A
27
certain officer and director of Integrum is a former officer and director of CMS
Energy, Consumers and their subsidiaries. CMS Energy, Consumers or their
subsidiaries did not employ the individual when Integrum made the offer to
purchase the CMS Pipeline Assets. CMS Energy believes that Integrum's claims are
without merit. CMS Energy will vigorously defend itself but cannot predict the
outcome of this lawsuit.
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. in July 2003, 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. 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 multi-district court
litigation ("MDL") panel decides whether to take the case. There is currently
pending in the Nevada federal district court a 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.
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 are likely to seek to remove this action to California federal
district court and have it transferred to the MDL proceeding in Nevada.
CMS Energy and its subsidiaries will vigorously defend themselves but
cannot predict the outcome of these matters.
SEC INVESTIGATION
The SEC is conducting an investigation regarding round-trip trades at CMS
MST. For additional details about this investigation, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- SEC and Other
Investigations.
CMS ENERGY AND CONSUMERS
EMPLOYMENT RETIREMENT INCOME SECURITY ACT CLASS ACTION 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 trial judge consolidated the two
cases that were originally filed in July 2002 in United States District Court
for the Eastern District of Michigan, and plaintiffs filed an amended
consolidated complaint. Plaintiffs allege breaches of fiduciary duties
28
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. CMS Energy and Consumers will
vigorously defend themselves 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. CMS Energy, Consumers and their affiliates will vigorously
defend themselves but cannot predict the outcome of this litigation.
ENVIRONMENTAL MATTERS
CMS Energy and Consumers, as well as 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, they believe it is unlikely
that these actions, individually or in total, will have a material adverse
effect on their financial condition or future results of operations. For
additional information, see both CMS Energy's and Consumers' ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
CMS ENERGY
During the fourth quarter of 2003, CMS Energy did not submit any matters to
a vote of security holders.
CONSUMERS
During the fourth quarter of 2003, Consumers did not submit any matters to
a vote of security holders.
29
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
CMS ENERGY
Market prices for CMS Energy's Common Stock and related security holder
matters are contained in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND
ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 19 OF
CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND
COMMON STOCK INFORMATION), which is incorporated by reference herein. At March
8, 2004, the number of registered shareholders totaled 60,791. Information
regarding securities authorized for issuance under equity compensation plans is
included in our definitive proxy statement, which is incorporated by reference
herein.
Recent Sales of Unregistered Securities: On December 5, 2003, in a private
placement to institutional investors pursuant to Rule 144A of the Securities Act
of 1933, as amended, CMS Energy issued $250 million of 4.50 percent cumulative
convertible preferred stock (par value $0.01 per share)(liquidation preference
$50 per share) (the "Preferred Stock"). The Preferred Stock was initially sold
to Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith
Incorporated, J.P. Morgan Securities, Inc., Wachovia Capital Markets LLC, and
Banc One Capital Markets, Inc., as initial purchasers. CMS Energy received
approximately $242 million in proceeds after the initial purchasers' discounts
and commissions and offering expenses. Holders of the Preferred Stock may
convert their stock into shares of CMS Energy Common Stock under certain
circumstances. For each share of Preferred Stock surrendered for conversion, the
holder will receive 5.0541 shares of CMS Energy Common Stock, which represents
an initial conversion price of $9.893 per share (subject to adjustment in
certain events). On or after December 5, 2008, under certain circumstances CMS
Energy may have the right to cause the Preferred Stock to be automatically
converted into shares of CMS Energy Common Stock at the then applicable
conversion price. CMS Energy has agreed to file a shelf registration statement
with the SEC by November 5, 2004 relating to the resale of the Preferred Stock
and the CMS Energy Common Stock issuable upon conversion thereof.
CONSUMERS
Consumers' common stock is privately held by its parent, CMS Energy, and
does not trade in the public market. In January, May, August and November 2003,
Consumers paid $77.5 million, $31 million, $53 million and $56.5 million in cash
dividends, respectively, on its common stock. In February, May, June, November
and December 2002, Consumers paid $55 million, $43 million, $56 million, $52
million and $25 million in cash dividends, respectively, on its common stock.
Pursuant to interim gas rate relief ordered by the MPSC, Consumers has agreed to
limit dividend payments to CMS Energy to a maximum of $190 million annually
during the period in which Consumers receives the interim relief.
ITEM 6. SELECTED FINANCIAL DATA.
CMS ENERGY
Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA -- CMS ENERGY'S SELECTED FINANCIAL INFORMATION, which is
incorporated by reference herein.
CONSUMERS
Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA -- CONSUMERS' SELECTED FINANCIAL INFORMATION, which is
incorporated by reference herein.
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
CMS ENERGY
Management's discussion and analysis of financial condition and results of
operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated
by reference herein.
CONSUMERS
Management's discussion and analysis of financial condition and results of
operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated
by reference herein.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
CMS ENERGY
Quantitative and Qualitative Disclosures About Market Risk is contained in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S MANAGEMENT'S
DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR
FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND MARKET RISK
INFORMATION, which is incorporated by reference herein.
CONSUMERS
Quantitative and Qualitative Disclosures About Market Risk is contained in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' MANAGEMENT'S
DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR
FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION, which is
incorporated by reference herein.
31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to Financial Statements:
PAGE
----
CMS ENERGY
Selected Financial Information.............................. CMS-2
Management's Discussion and Analysis........................ CMS-4
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
Notes to Consolidated Financial Statements.................. CMS-46
Report of Independent Auditors.............................. CMS-120
CONSUMERS ENERGY
Selected Financial Information.............................. CE-2
Management's Discussion and Analysis........................ CE-3
Consolidated Statements of Income........................... CE-29
Consolidated Statements of Cash Flows....................... CE-30
Consolidated Balance Sheets................................. CE-32
Consolidated Statements of Common Stockholder's Equity...... CE-34
Notes to Consolidated Financial Statements.................. CE-36
Report of Independent Auditors.............................. CE-84
32
[CMS ENERGY LOGO]
2003 FINANCIAL STATEMENTS
CMS-1
CMS ENERGY CORPORATION
SELECTED FINANCIAL INFORMATION
CMS ENERGY CORPORATION
-----------------------------------------------------------------------------
RESTATED RESTATED RESTATED
2003 2002(E) 2001(E) 2000(E) 1999
---- -------- -------- -------- ----
Operating revenue (in millions)......... ($) 5,513 8,673 8,006 6,623 5,114
Earnings from equity method investees
(in millions)......................... ($) 164 92 172 213 136
Income (loss) from continuing operations
(in millions)......................... ($) (43) (394) (327) (85) 191
Cumulative effect of change in
accounting (in millions).............. ($) (24) 18 (4) -- --
Consolidated net income (loss) (in
millions)............................. ($) (44) (650) (459) 5 277
Average common shares outstanding (in
thousands)............................ 150,434 139,047 130,758 113,128 110,140
Income (loss) from continuing operations
per average common share
CMS Energy -- Basic................... ($) (0.30) (2.84) (2.50) (0.76) 1.66(a)
-- Diluted................. ($) (0.30) (2.84) (2.50) (0.76) 1.66(a)
Class G -- Basic and Diluted....... ($) -- -- -- -- 4.21(a)
Cumulative effect of change in
accounting per average common share
CMS Energy -- Basic................... ($) (0.16) 0.13 (0.03) -- --(a)
-- Diluted................. ($) (0.16) 0.13 (0.03) -- --(a)
Net income (loss) per average common
share
CMS Energy -- Basic................... ($) (0.30) (4.68) (3.51) 0.04 2.18(a)
-- Diluted................. ($) (0.30) (4.68) (3.51) 0.04 2.17(a)
Class G -- Basic and Diluted....... ($) -- -- -- -- 4.21(a)
Cash from (used in) operations (in
millions)............................. ($) (251) 614 372 600 917
Capital expenditures, excluding
acquisitions, capital lease additions
and DSM (in millions)................. ($) 535 747 1,239 1,032 1,124
Total assets (in millions)(f)........... ($) 13,838 14,781 17,633 17,801 16,336
Long-term debt, excluding current
maturities (in millions).............. ($) 6,020 5,357 5,842 6,052 6,428
Long-term debt, related parties (in
millions)(b).......................... ($) 684 -- -- -- --
Non-current portion of capital leases
(in millions)......................... ($) 58 116 71 49 88
Total preferred stock (in millions)..... ($) 305 44 44 44 44
Total Trust Preferred Securities (in
millions)............................. ($) --(b) 883 1,214 1,088 1,119
Cash dividends declared per common share
CMS Energy............................ ($) -- 1.09 1.46 1.46 1.39
Class G............................... ($) -- -- -- -- 0.99
Market price of common stock at year-end
CMS Energy............................ ($) 8.52 9.44 24.03 31.69 31.19
Class G............................... ($) -- -- -- -- 24.56(c)
Book value per common share at year-end
CMS Energy............................ ($) 9.84 7.48 14.98 19.62 21.17
Number of employees at year-end
(full-time equivalents)............... 8,411 10,477 11,510 11,652 11,462
CMS-2
CMS ENERGY CORPORATION
-----------------------------------------------------------------------------
RESTATED RESTATED RESTATED
2003 2002(E) 2001(E) 2000(E) 1999
---- -------- -------- -------- ----
ELECTRIC UTILITY STATISTICS
Sales (billions of kWh)............... 39 39 40 41 41
Customers (in thousands).............. 1,754 1,734 1,712 1,691 1,665
Average sales rate per kWh............ cents 6.91 6.88 6.65 6.56 6.54
GAS UTILITY STATISTICS
Sales and transportation deliveries
(bcf).............................. 380 376 367 410 389
Customers (in thousands)(d)........... 1,671 1,652 1,630 1,611 1,584
Average sales rate per mcf............ ($) 6.72 5.67 5.34 4.39 4.52
-------------------------
(a) 1999 earnings per average common share includes allocation of the premium
on redemption of Class G Common Stock of $(0.26) per CMS Energy basic
share, $(0.25) per CMS Energy diluted share and $3.31 per Class G basic and
diluted share.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on
the balance sheet as Long term debt -- related parties.
(c) Reflects closing price at the October 25, 1999 exchange date.
(d) Excludes off-system transportation customers.
(e) For additional details, see Note 18, Restatement and Reclassification.
(f) For additional details on the reclassification of non-legal
cost-of-removal, see Note 16, Asset Retirement Obligations,
"Reclassification of Non-Legal Cost of Removal." Following is the amount of
cost of removal reclassified from accumulated depreciation to a regulatory
liability by year: $983 million in 2003; $907 million in 2002; $870 million
in 2001; $896 million in 2000; and $874 million in 1999.
CMS-3
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-related 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.
In 2003, we continued to implement our "utility plus" strategy centered
around growing a healthy utility in Michigan and optimizing the contribution
from key Enterprises assets. We sold over $900 million worth of non-strategic
assets, enabling us to reduce debt by $1.1 billion. We have taken advantage of
historically low interest rates to extend maturities and refinance our debt at
lower cost. We completed over $3 billion of financing and refinancing
transactions to resolve short-term liquidity concerns at the start of 2003. In
addition to improving our capital structure, we contributed $560 million to our
defined benefit pension plan. This should result in lower pension costs in the
future.
At the foundation of our financial progress was exceptional operating
performance. For the second consecutive year, our Michigan gas utility earned
the J.D. Power and Associates award for highest residential customer
satisfaction with natural gas services in the Midwest. Independent evaluators,
like J.D. Power and Associates recognize value and our regulators do too. The
MPSC authorized an annual increase in our gas utility rates of $56 million in
late 2002, and an additional interim annualized $19 million rate increase in
2003.
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 March 2004, we lost 735 MW or
nine percent of our electric business to these alternative electric suppliers.
We expect the loss to grow to over 1,000 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, and we have asked the MPSC to approve it quickly.
CMS-4
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.
Finally, we are working to resolve outstanding litigation that stemmed from
energy trading activities in 2001 and earlier. Doing so will permit us to devote
more attention to improving business growth. Our business plan is targeted at
predictable earnings growth along with reduction in our debt. We are a full year
into our five-year plan to reduce by half the debt of the CMS Energy holding
company.
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
Financial statements of prior years and quarterly data for all three
periods presented have been restated for the following events:
- International Energy Distribution, which includes SENECA and CPEE, is no
longer considered "discontinued operations",
- certain derivative accounting corrections, and
- Loy Yang deferred tax accounting correction.
For additional details on the effect of the restatements, see Note 18,
Restatement and Reclassification, and Note 19, Quarterly Financial and Common
Stock Information (Unaudited).
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-K 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 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,
- achievement of capital expenditure reductions and cost savings,
- 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,
CMS-5
- 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 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,
- 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,
- 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 CONSOLIDATED NET LOSS
Our 2003 net loss was $44 million, an improvement of $606 million from
2002. We are continuing to restructure our business operations, and as our
financial plan moves forward, we will maintain our strategy of
CMS-6
selling under-performing or non-strategic assets in order to reduce our debt, to
reduce business risk, and to provide for more predictable future earnings.
RESTATED RESTATED
YEARS ENDED DECEMBER 31 2003 2002 2001
----------------------- ---- -------- --------
IN MILLIONS (EXCEPT FOR PER
SHARE AMOUNTS)
Net Loss.................................................... $ (44) $ (650) $ (459)
Basic loss per share........................................ $(0.30) $(4.68) $(3.51)
Diluted loss per share...................................... $(0.30) $(4.68) $(3.51)
RESTATED RESTATED RESTATED
YEARS ENDED DECEMBER 31 2003 2002 CHANGE 2002 2001 CHANGE
----------------------- ---- -------- ------ -------- -------- ------
IN MILLIONS
Electric Utility............................ $ 167 $ 264 $(97) $ 264 $ 120 $ 144
Gas Utility................................. 38 46 (8) 46 21 25
Enterprises................................. 8 (419) 427 (419) (272) (147)
Corporate Interest and Other................ (256) (285) 29 (285) (196) (89)
----- ----- ---- ----- ----- -----
Loss from Continuing Operations............. (43) (394) 351 (394) (327) (67)
----- ----- ---- ----- ----- -----
Discontinued Operations..................... 23 (274) 297 (274) (128) (146)
Accounting Changes.......................... (24) 18 (42) 18 (4) 22
----- ----- ---- ----- ----- -----
Net Loss.................................... $ (44) $(650) $606 $(650) $(459) $(191)
===== ===== ==== ===== ===== =====
2003 COMPARED TO 2002: Our net loss was reduced significantly from:
- absence of $379 million, net of tax, of goodwill write downs recorded in
2002 associated with discontinued operations,
- an improvement of CMS Enterprises' earnings due to:
- decrease of $313 million, net of tax, in asset write downs from planned
and completed divestitures,
- lower expropriation and devaluation losses at the Argentine facilities
due to the stabilization of the Argentine Peso,
- absence of tax charges recorded in 2002 resulting from the loss of
indefinite tax deferral for several international investments, and
- higher revenues and lower interest costs within IPP.
- decrease in corporate interest and other.
However, our progress was slowed by:
- Electric Utility earnings:
- higher electric operating costs resulting from higher pension expense,
greater depreciation expense reflecting higher levels of plant in
service, and increased amortization expense associated with securitized
regulatory assets,
- lower electric deliveries from milder weather during the summer, and
- continuation of switching by commercial and industrial customers to
alternative electric suppliers.
- loss of $44 million, after-tax, on the sale of Panhandle,
- employee benefit plans net settlement and curtailment loss of $48
million, after tax, related to a large number of employees retiring and
exiting these plans, and
CMS-7
- cumulative effect of a change of accounting resulting in a charge of $23
million, net of tax, due to energy trading contracts that did not meet
the definition of a derivative.
2002 COMPARED TO 2001: Our net loss increased $191 million from:
- after-tax charges in recognition of planned and completed divestitures
and reduced asset valuations,
- tax credit write-offs in 2002 at the parent level, and
- restructuring and other costs in 2002.
ELECTRIC UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2003 2002 CHANGE 2002 2001 CHANGE
----------------------- ---- ---- ------ ---- ---- ------
IN MILLIONS
Net income......................................... $167 $264 $(97) $264 $120 $144
==== ==== ==== ==== ==== ====
REASONS FOR THE CHANGE:
Electric deliveries................................ $(41) $ 41
Power supply costs and related revenue............. 26 149
Other operating expenses and non-commodity
revenue.......................................... (80) (21)
Gain on asset sales................................ (38) 38
General taxes...................................... 10 (3)
Fixed charges...................................... (22) 9
Income taxes....................................... 48 (69)
---- ----
Total change....................................... $(97) $144
==== ====
ELECTRIC DELIVERIES: In 2003, electric revenues decreased, reflecting lower
deliveries. Most significantly, sales volumes to commercial and industrial
customers were 5.6 percent lower than in 2002, a result of these sectors'
continued switching to alternative electric suppliers as allowed by the Customer
Choice Act. The decrease in revenue is also the result of reduced deliveries to
higher-margin residential customers, from a milder summer's impact on air
conditioning usage. Overall, electric deliveries, including transactions with
other wholesale marketers and other electric utilities, decreased 0.4 billion
kWh or 1.1 percent.
In 2002, electric revenue increased by $41 million from the previous year,
despite lower deliveries. This was due primarily to increased deliveries to
higher-margin residential customers as a result of a significantly warmer
summer's impact on air conditioning usage. Deliveries, including transactions
with other wholesale marketers and other electric utilities, decreased 0.3
billion kWh or 0.7 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our recovery of power
supply costs was fixed, 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 2003, this difference between power supply-related revenues and
actual power supply costs benefited operating income by $26 million more than it
had in 2002. This increase is primarily the result of increased intersystem
revenues due to higher market prices and sales made from surplus capacity. The
efficient operation of our generating plants and lower priced purchased power
further decreased power supply costs.
In 2002, as compared to 2001, power supply costs and related revenues
increased operating income due primarily to reduced purchased power costs
because the Palisades plant returned to service in 2002, following an extended
2001 shutdown.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In 2003, net operating
expenses and non-commodity revenue decreased operating income by $80 million
versus 2002. This decrease relates to increased pension and other benefit costs
of $54 million, a scheduled refueling outage at Palisades, and higher
transmission costs. More plant in service increased depreciation costs by $8
million, and $11 million of higher amortization
CMS-8
expense from securitized assets further contributed to decreased operating
income. Slightly offsetting the increased operating expenses were higher
non-commodity revenues associated with other income.
In 2002, net operating expenses and non-commodity revenue decreased
operating income by $21 million compared with 2001. The decrease primarily
related to higher transmission expenses and increased depreciation costs from
more plant in service.
ASSET SALES: The reduction in operating income from asset sales for 2003
versus 2002, and the increase in operating income from asset sales for 2002
versus 2001 reflect the $31 million pretax gain associated with the 2002 sale of
our electric transmission system and the $7 million pretax gain associated with
the 2002 sale of nuclear equipment from the cancelled Midland project.
GENERAL TAXES: In 2003, general taxes decreased from 2002 due primarily to
reductions in MSBT expense, resulting primarily from a tax credit received from
the State of Michigan associated with construction of the new corporate
headquarters on a qualifying Brownfield site. In 2002, general taxes increased
over 2001 due to increases in MSBT and property tax accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002, fixed charges decreased versus 2001 because of a reduction in
long-term debt.
INCOME TAXES: In 2003, income tax decreased versus 2002 due primarily to
lower earnings by the electric utility. In 2002, income tax expense increased
versus 2001 due primarily to increased earnings.
GAS UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2003 2002 CHANGE 2002 2001 CHANGE
----------------------- ---- ---- ------ ---- ---- ------
IN MILLIONS
Net income............................................ $38 $46 $ (8) $46 $21 $ 25
=== === ==== === === ====
Reasons for the change:
Gas deliveries........................................ $ (1) $ 21
Gas rate increase..................................... 39 25
Gas wholesale and retail services and other gas
revenues............................................ 1 1
Operation and maintenance............................. (34) (14)
General taxes, depreciation, and other income......... (6) (3)
Fixed charges......................................... (5) 3
Income taxes.......................................... (2) (8)
---- ----
Total change.......................................... $ (8) $ 25
==== ====
GAS DELIVERIES: In 2003, gas deliveries, including miscellaneous
transportation, increased 4.1 bcf or 1.1 percent versus 2002. Despite increased
system deliveries, gas revenues actually declined by $1 million. Colder weather
during the first quarter of 2003 increased deliveries to the residential and
commercial sectors. Increased deliveries resulted in a $6 million increase in
gas revenues. However, the revenue increase was offset by a $7 million gas loss
adjustment recorded as a reduction to gas revenues.
In 2002, gas revenues increased by $21 million from the previous year.
System deliveries, including miscellaneous transportation, increased 9.4 bcf or
2.6 percent. The increase was due primarily to colder weather that increased
deliveries to the residential and commercial sectors.
GAS RATE INCREASE: In November 2002, the MPSC issued a final gas rate order
authorizing a $56 million annual increase to gas tariff rates. As a result of
this order, 2003 gas revenues increased $39 million. In 2002, gas rate increases
led to increased gas revenues of $25 million over 2001.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: In 2003, gas
wholesale and retail services and other gas revenues increased $1 million. The
$1 million increase includes primarily the following two items. In 2003, we
reversed a $4 million reserve, originally recorded in 2002, for non-physical gas
title tracking services.
CMS-9
In addition, in 2003, we reserved $11 million for the settlement agreement
associated with the 2002-2003 GCR disallowance. For additional details regarding
both of these issues, see the Gas Utility Business Uncertainties in the
"Outlook" section of this MD&A.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses
increased versus 2002 due to increases in pension and other benefits costs of
$27 million and additional expenditures on safety, reliability, and customer
service. In 2002, operation and maintenance expenses increased versus 2001 due
to the recognition of gas storage inventory losses and additional expenditures
on customer reliability and service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In 2003, the net of general
tax expense, depreciation expense, and other income decreased operating income
primarily because of increases in depreciation expense from increased plant in
service. In 2002, the net of general tax expense, depreciation expense, and
other income decreased operating income primarily because of increases in MSBT
and property tax expense accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002 versus 2001, fixed charges decreased due to lower long-term debt
levels.
INCOME TAXES: In 2003 versus 2002, income tax expense increased due to
reduced income tax expense in 2002. The 2002 reduction was attributable to
flow-through accounting on plant, property and equipment as required by past
MPSC rulings. In 2002, income tax expense increased versus 2001 due primarily to
increased earnings of the gas utility.
ENTERPRISES RESULTS OF OPERATIONS
RESTATED RESTATED RESTATED
YEARS ENDED DECEMBER 31 2003 2002 CHANGE 2002 2001 CHANGE
----------------------- ---- -------- ------ -------- -------- ------
IN MILLIONS
Net Income (Loss).............. $8 $(419) $427 $(419) $(272) $(147)
== ===== ==== ===== ===== =====
In 2003, Enterprises had earnings compared to a significant loss in 2002.
This year over year improvement resulted from the:
- elimination of $313 million of asset impairments, net of tax, in 2002 for
divestitures and reduced asset valuations,
- lower expropriation and devaluation losses at Argentine facilities, and
- elimination of tax charges in 2002 from the loss of indefinite tax
deferral for several international investments.
2002 losses increased by $147 million from 2001 resulting from the:
- increased asset impairments for divestitures and reduced asset
valuations, and
- discontinuing and selling several businesses.
OTHER RESULTS OF OPERATIONS
CORPORATE INTEREST AND OTHER:
RESTATED RESTATED RESTATED
YEARS ENDED DECEMBER 31 2003 2002 CHANGE 2002 2001 CHANGE
----------------------- ---- -------- ------ -------- -------- ------
IN MILLIONS
Net Loss...................... $(256) $(285) $29 $(285) $(196) $(89)
===== ===== === ===== ===== ====
Our 2003 corporate interest and other net expenses decreased $29 million
from 2002 primarily due to reduced restructuring costs and reduced taxes,
partially offset by increased interest allocation to continuing operations.
CMS-10
Our 2002 corporate interest and other net expenses increased $89 million
from 2001 primarily due to restructuring charges, including the relocation of
corporate offices from Dearborn to Jackson, Michigan, and increased taxes
resulting from the loss of certain AMT credit carryforwards.
DISCONTINUED OPERATIONS: For the years ended December 31, 2003 and 2002,
discontinued operations included Parmelia, and through their respective dates of
sale, Panhandle, CMS Viron, CMS Field Services, and Marysville. For additional
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:
- 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 $13.838
billion at December 31, 2003, 60 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
CMS-11
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 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 2003, we analyzed impairment indicators related to our long-lived assets
and equity method investments. Following our analysis, we reduced the carrying
amount of our investment in Parmelia, our investment in SENECA, and an equity
investment at CMS Generation to reflect their fair values. 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. For additional details on asset sales, see Note 2, Discontinued
Operations, Other Asset Sales, Impairments, and Restructuring.
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 contracted 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 availability 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 a
regulatory out provision under the MCV Partnership power purchase agreement.
This provision obligates us 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 equity, and
- eliminate our underrecoveries for capacity and 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 operations and
maintenance expenses. However, the MCV Partnership's costs of
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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
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 our equity interest in
the MCV Partnership 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 equity
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 an economic basis depending on 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. We
requested that the MPSC provide interim approval while it conducts a full review
of the plan. The MPSC has scheduled a prehearing conference with respect to the
MCV resource conservation plan for April 2004. We cannot predict if or when the
MPSC will approve our request.
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 our recovery of
capacity payments. Natural gas prices have been historically volatile.
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.
Therefore, we cannot predict the impact of these issues on our future earnings,
cash flows, or on the value of our equity interest in the MCV Partnership.
For additional details, see Note 4, Uncertainties, "Other Consumers'
Electric Utility 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.
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 7, Financial and
Derivative Instruments.
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The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas fuel options, 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.
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, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA,
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 December 31, 2003, we assumed a
market-based interest rate of 1 percent (six-month U.S. Treasury rate) and
volatility rates ranging between 65 percent and 120 percent to calculate the
fair value of our electric and gas call options.
TRADING ACTIVITIES: Our wholesale power and gas trading activities are also
accounted for using the criteria 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. We believe that our mathematical models utilize 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 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.
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The following tables provide a summary of the fair value of our energy
trading contracts as of December 31, 2003.
IN MILLIONS
Fair value of contracts outstanding as of December 31,
2002...................................................... $ 81
Fair value of new contracts when entered into during the
period.................................................... --
Implementation of EITF Issue No. 02-03(a)................... (36)
Fair value of derivative contracts sold and received from
asset sales(b)............................................ (30)
Changes in fair value attributable to changes in valuation
techniques and assumptions................................ --
Contracts realized or otherwise settled during the period... (10)
Other changes in fair value(c).............................. 10
----
Fair value of contracts outstanding as of December 31,
2003...................................................... $ 15
====
-------------------------
(a) Reflects the removal of contracts that do not qualify as derivatives under
SFAS No. 133 as of January 1, 2003. See Note 17, Implementation of New
Accounting Standards.
(b) Reflects $60 million decrease for price risk management assets sold and $30
million increase for price risk management assets received related to the
sales of the gas and power books.
(c) Reflects changes in price and net increase/(decrease) of forward positions
as well as changes to mark-to-market and credit reserves.
FAIR VALUE OF CONTRACTS AT DECEMBER 31, 2003
-------------------------------------------------
MATURITY (IN YEARS)
TOTAL -------------------------------------------------
SOURCE OF FAIR VALUE FAIR VALUE LESS THAN 1 1 TO 3 4 TO 5 GREATER THAN 5
-------------------- ---------- ----------- ------ ------ --------------
IN MILLIONS
Prices actively quoted........................ $(23) $ 2 $(7) $(16) $(2)
Prices based on models and other valuation
methods..................................... 38 11 13 13 1
---- --- --- ---- ---
Total......................................... $ 15 $13 $ 6 $ (3) $(1)
==== === === ==== ===
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, 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," "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
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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):
AS OF DECEMBER 31 2003 2002
----------------- ---- ----
IN MILLIONS
Variable-rate financing -- before tax annual earnings
exposure.................................................. $ 1 $ 2
Fixed-rate financing -- potential loss in fair value(a)..... 242 293
-------------------------
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
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. See discussion of these instruments in Note
18, Restatement and Reclassification.
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. The 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. The weather-based gas supply call options, along with the gas supply call
and put options, are used to purchase reasonably priced gas supply. Call options
give us the right, but not the obligation, to purchase gas supply at
predetermined fixed prices. Put options give third-party suppliers the right,
but not the obligation, to sell gas supply to us at predetermined fixed prices.
The commodity price risk sensitivity analysis was not material for the
years ending December 31, 2003 and December 31, 2002.
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):
AS OF DECEMBER 31 2003
----------------- ----
IN MILLIONS
Potential reduction in fair value:
Gas-related swaps and forward contracts..................... $3
Electricity-related forward contracts....................... 2
Electricity-related call option contracts................... 1
A sensitivity analysis was not performed for the year ended December 31,
2002. There has been a significant change in trading activity in 2003 from the
prior year. As noted in "Trading Activities" within this section, the fair value
of contracts outstanding has decreased from $81 million at December 31, 2002 to
$15 million at December 31, 2003. For further information, see "Trading
Activities" within this section.
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
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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 December 31, 2003, we had no foreign exchange hedging
contracts outstanding. As of December 31, 2003, the total foreign currency
translation adjustment was a net loss of $419 million, which included a net
hedging loss of $18 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.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
AS OF DECEMBER 31 2003 2002
----------------- ---- ----
IN MILLIONS
Potential reduction in fair value:
Nuclear decommissioning investments....................... $57 $49
Equity investments........................................ 7 6
For additional details on market risk and derivative activities, see Note
7, Financial and Derivative Instruments.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects throughout the world. As a
result of a change in business strategy, over the last two years 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 December 31, 2003, cumulative foreign currency translation
decreased stockholders' equity by $419 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: At December 31, 2003, the net foreign currency loss due to the
exchange rate of the Australian dollar recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 1.335
Australian dollars per U.S. dollars was $95 million. This amount includes an
unrealized loss related to our investment in Loy Yang. This unrealized loss, and
the impact of certain deferred taxes associated with the Loy Yang investment,
will be realized upon sale, full liquidation, or other disposition of our
investment in Loy Yang for a total loss of approximately $110 million. In July
2003, we executed a conditional share sale agreement for our investment in Loy
Yang. For additional details, see "Outlook -- Enterprises Outlook" section
within this MD&A.
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
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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 December 31, 2003, 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 2.94 pesos per U.S. dollar was $264 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. For additional
details, see Note 8, Income Taxes.
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 December 31, 2003, we had $1.105 billion recorded as
regulatory assets and $1.467 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 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,
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- 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:
PENSION EXPENSE OPEB EXPENSE CONTRIBUTIONS
--------------- ------------ -------------
IN MILLIONS
2004................................................. $21 $66 $ 98
2005................................................. 44 63 123
2006................................................. 67 61 131
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.
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.
In August 2003, we made a planned contribution of $210 million to the
Pension Plan. In December 2003, we made an additional contribution of $350
million. As a result of these contributions, we reversed the additional minimum
liability and the resulting decrease in equity that we charged in 2002. As of
December 31, 2003, we have a prepaid pension asset of $408 million recorded on
our consolidated balance sheets.
Market-Related Valuation: We determine pension expense based on a
market-related valuation of assets, which reduces year-to-year volatility. The
market-related valuation recognizes investment gains or losses over a five-year
period from the year in which the gains or losses occur. Investment gains or
losses for this purpose are the difference between the expected return
calculated using the market-related value of assets and the actual return based
on the market value of assets. Since the market-related value of assets
recognizes gains or losses over a five-year period, the future value of assets
will be impacted as previously deferred gains or losses are recorded.
Due to the unfavorable performance of the equity markets in the past few
years, as of December 31, 2003, we had cumulative losses of approximately $239
million that remain to be recognized in the calculation of the market-related
value of assets. These unrecognized net actuarial losses may result in increases
in future pension expense in accordance with SFAS No. 87.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act 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 deferring recognizing the effects of the
Act in our 2003 financial statements, as permitted by FASB Staff Position No.
106-1. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted.
For additional details on postretirement benefits, see Note 10, Retirement
Benefits.
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
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accounting principle. Accretion of $1 million related to the Big Rock and
Palisades' profit component included in the estimated cost of removal was
expensed for 2003.
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.
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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, were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
For additional details on ARO, see Note 16, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. They require, and we have established,
external trust funds to finance the decommissioning of both plants. Our electric
customers pay a surcharge to fund these trusts. 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. Spent fuel
storage costs would not be incurred if the DOE took possession of the spent
fuel. There is litigation underway to recover these costs.
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 was stopped since it was
considered fully funded, subject to further MPSC review. The funds provided by
the trusts, additional customer surcharges, and potential
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funds from DOE litigation are all required to cover fully the decommissioning
costs, and we currently expect that to happen. 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.
For additional details on nuclear decommissioning, see Note 1, Corporate
Structure and Accounting Policies, "Nuclear Plant Decommissioning."
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
have requested advance payment or other forms of assurances, including margin
calls, in connection with maintenance of ongoing deliveries of gas and
electricity.
At the beginning of 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, in 2003, we executed a financial improvement
plan to address these critical liquidity issues.
In January 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.
Gross proceeds from asset sales were $939 million in 2003. 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 will continue to monitor our operating expenses and capital
expenditures, evaluate market conditions for financing opportunities, and sell
assets that are not consistent with our strategy. We do not anticipate paying
dividends in the foreseeable future. The Board of Directors may reconsider or
revise this policy from time to time 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 December 31, 2003, $733 million consolidated cash was on hand
which includes $201 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. In 2003, Consumers
paid $218 million in common stock dividends and Enterprises paid $536 million in
common stock dividends and other distributions to us. Enterprises' other
distributions include a transfer of 1,967,640 shares of CMS Energy Common Stock,
valued at $16 million, in the form of a stock dividend. There was no impact on
shares outstanding or the consolidated income statement from this distribution.
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SELECTED MEASURES OF LIQUIDITY AND CAPITAL RESOURCES:
2003
----
Working capital (in millions)............................... $ 844
Current ratio............................................... 1.51:1
Working capital in 2003 was primarily driven by the following:
- cash proceeds from long-term debt issuance -- $2.080 billion,
- cash proceeds from asset sales -- $939 million, and
- cash proceeds from preferred stock issuance/sale -- $272 million.
partially offset by:
- cash used for long-term debt retirements, excluding current
portion -- $1.531 billion,
- cash used for pension contributions -- $560 million, and
- cash used for purchase of property, plant and equipment -- $535 million.
SUMMARY OF CASH FLOWS:
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Net cash provided by (used in):
Operating activities...................................... $(251) $ 614 $ 372
Investing activities...................................... 203 829 (1,349)
Financing activities...................................... 230 (1,223) 967
Effect of exchange rates on cash............................ (1) 8 (10)
----- ------- -------
Net increase (decrease) in cash and temporary cash
investments............................................... $ 181 $ 228 $ (20)
===== ======= =======
OPERATING ACTIVITIES:
2003: Net cash used in operating activities was $251 million in 2003
compared to net cash provided by operating activities of $614 million in 2002.
The change of $865 million was primarily due to an increase in pension plan
contributions of $496 million, an increase in inventories of $428 million due to
higher gas purchases at higher prices by our gas utility operations, and a
decrease in accounts payable and accrued expenses of $232 million due primarily
to the sale of CMS MST's wholesale gas and power contracts. This change was
partially offset by a decrease in accounts receivable and accrued revenue of
$101 million due primarily to the sale of CMS MST's wholesale gas and power
contracts.
2002: Net cash provided by operating activities increased $242 million in
2002 primarily due to a decrease in inventories of $479 million due to a lower
volume of gas purchased at lower prices, combined with increased sales volumes
at higher prices at our gas utility. This increase was partially offset by a
smaller decrease in accounts receivable and accrued revenues of $238 million.
INVESTING ACTIVITIES:
2003: Net cash provided by investing activities decreased $626 million in
2003 due primarily to a decrease in asset sale proceeds of $720 million,
primarily from the sale of Equatorial Guinea, Powder River, and CMS Oil and Gas
in 2002, offset by a decrease in 2003 versus 2002 capital expenditures of $212
million as a result of our strategic plan to reduce capital expenditures.
2002: Net cash provided by investing activities increased $2.178 billion in
2002 due primarily to a decrease in capital expenditures of $492 million as a
result of our strategic plan to reduce capital expenditures, and an
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increase in asset sale proceeds of $1.525 billion, resulting primarily from the
sales of Equatorial Guinea, Powder River, and CMS Oil and Gas.
FINANCING ACTIVITIES:
2003: Net cash provided by financing activities increased $1.453 billion in
2003 due primarily to an increase in net proceeds from borrowings of $988
million and net proceeds from preferred securities issuances/ sale of $272
million. For additional details on long-term debt activity, see Note 5,
Financings and Capitalization.
2002: Net cash used in financing activities increased $2.190 billion in
2002 due primarily to a decrease in net proceeds from borrowings of $1.733
billion and a decrease in net proceeds from common stock and preferred
securities of $454 million.
OBLIGATIONS AND COMMITMENTS
The following information on our contractual obligations, off-balance sheet
arrangements, and commercial commitments is provided to collect information in a
single location so that a picture of liquidity and capital resources is readily
available. For additional information on our obligations and commitments see
Note 5, Financings and Capitalization.
PAYMENTS DUE
----------------------------------------------------------------
DECEMBER 31 TOTAL 2004 2005 2006 2007 2008 BEYOND
----------- ----- ---- ---- ---- ---- ---- ------
IN MILLIONS
CONTRACTUAL OBLIGATIONS
On-balance sheet:
Long-term debt....................... $ 6,529 $ 509 $ 696 $ 490 $516 $987 $ 3,331
Long-term debt -- related parties.... 684 -- -- -- -- -- 684
Capital lease obligations............ 68 10 11 10 10 8 19
------- ------ ------ ------ ---- ---- -------
Total on-balance sheet................. $ 7,281 $ 519 $ 707 $ 500 $526 $995 $ 4,034
------- ------ ------ ------ ---- ---- -------
Off-balance sheet:
Non-recourse debt.................... $ 2,909 $ 233 $ 123 $ 170 $ 85 $101 $ 2,197
Capital lease obligation -- MCV...... 144 16 9 8 8 8 95
Operating leases..................... 78 12 10 10 9 7 30
Sale of accounts receivable.......... 297 297 -- -- -- -- --
Unconditional purchase
obligations(a).................... 16,370 1,895 1,258 892 711 670 10,944
------- ------ ------ ------ ---- ---- -------
Total off-balance sheet................ $19,798 $2,453 $1,400 $1,080 $813 $786 $13,266
======= ====== ====== ====== ==== ==== =======
-------------------------
(a) This excludes purchase obligations that Consumers has with Genesee,
Grayling, and Filer City generating plants because these entities are
consolidated under FASB Interpretation No. 46. Purchase obligations related
to the MCV Facility PPA assume that the regulatory out provision is
exercised in 2007. For additional details, see Note 4, Uncertainties,
"Other Consumers' Electric Utility Uncertainties -- The Midland
Cogeneration Venture."
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers must obtain FERC
authority to issue short and long-term securities. For additional details of
Consumers' existing authority, see Note 5, Financings and Capitalization.
LONG-TERM DEBT: Details on long-term debt and preferred securities
issuances, retirements, and outstanding balances are presented in Note 5,
Financings and Capitalization.
SHORT-TERM FINANCINGS: CMS Energy has $190 million available and Consumers
has $390 million available under revolving credit facilities. At December 31,
2003, the lines are available for general corporate purposes, working capital,
and letters of credit. Additional details are in Note 5, Financings and
Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of
leased service vehicles and office furniture. The full obligation of our leases
could become due in the event of lease payment default.
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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,
- 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.
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we currently sell up to $325 million of certain accounts receivable.
For additional details, see Note 5, 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 including the MCV Facility. These
contracts require us to make monthly capacity payments based on the plants'
availability or deliverability. These payments will approximate $43 million per
month during 2004, including $34 million related to the MCV Facility. 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 4, Uncertainties, "Consumers' Electric Utility Rate
Matters -- Power Supply Costs," and "Other Consumers' Electric Utility
Uncertainties -- The Midland Cogeneration Venture."
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.
COMMITMENT EXPIRATION
-------------------------------------------------------
DECEMBER 31 TOTAL 2004 2005 2006 2007 2008 BEYOND
----------- ----- ---- ---- ---- ---- ---- ------
IN MILLIONS
COMMERCIAL COMMITMENTS
Off-balance sheet:
Guarantees...................................... $239 $ 20 $36 $4 $-- $-- $179
Indemnities..................................... 28 8 -- -- -- -- 20
Letters of Credit(a)............................ 254 215 10 5 5 5 14
---- ---- --- -- --- --- ----
Total............................................. $521 $243 $46 $9 $ 5 $ 5 $213
==== ==== === == === === ====
-------------------------
(a) At December 31, 2003, we had $175 million of cash collateralized letters of
credit and the cash used to collateralize the letters of credit is included
in Restricted Cash on the Consolidated Balance Sheets.
CMS-24
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at December 31, 2003, Consumers had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in
Consumers debt facilities cap common stock dividend payments at $300 million in
a calendar year. Through December 31, 2003, we received the following common
stock dividend payments from Consumers:
IN MILLIONS
January..................................................... $ 78
May......................................................... 31
June........................................................ 53
November.................................................... 56
----
Total common stock dividends paid to CMS Energy............. $218
====
As of December 18, 2003, Consumers is also under an annual dividend cap of
$190 million imposed by the MPSC during the current interim gas rate relief
period. Because all of the $218 million of common stock dividends to CMS energy
were paid prior to December 18, 2003, Consumers was not out of compliance with
this new restriction for 2003. In February 2004, Consumers paid a $78 million
common stock dividend.
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order see Note 4, Uncertainties, "Consumers'
Electric Utility Rate Matters -- Securitization." Also, for additional details
on the cap on common dividends payable during the current interim gas rate
relief period, see Note 4, Uncertainties, "Consumers' Gas Utility Rate
Matters -- 2003 Gas Rate Case."
CAPITAL EXPENDITURES
We estimate the following capital expenditures, including new lease
commitments, by expenditure type and by business segments during 2004 through
2006. We prepare these estimates for planning purposes and may revise them.
YEARS ENDING DECEMBER 31 2004 2005 2006
------------------------ ---- ---- ----
IN MILLIONS
Electric utility operations(a)(b)........................... $395 $370 $570
Gas utility operations(a)................................... 155 185 170
Enterprises................................................. 85 5 5
---- ---- ----
$635 $560 $745
==== ==== ====
-------------------------
(a) These amounts include an attributed portion of Consumers' anticipated
capital expenditures for plant and equipment common to both the electric
and gas utility businesses.
(b) These amounts include estimates for capital expenditures that may be
required by recent revisions to the Clean Air Act's national air quality
standards.
OUTLOOK
CORPORATE OUTLOOK
During 2003, we continued to implement a back-to-basics 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 back-to-basics strategy, we are pursuing actively the
sale of non-strategic and under-performing assets and have received $3.6 billion
of cash from asset sales, securitization proceeds and proceeds from LNG
monetization since 2001. For additional details, see Note 2, Discontinued
Operations, Other Asset Sales, Impairments, and Restructuring. Some of these
assets are recorded at estimates of their current fair value. Upon the sale 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
CMS-25
make any assurance that, these sales will occur. We anticipate that the sales,
if any, will result in additional cash proceeds that will be used to retire
existing debt.
As we continue to implement our back-to-basics strategy and further reduce
our ownership of non-utility assets, the percentage of our future earnings
relating to Jorf Lasfar and the MCV Partnership may increase and our total
future earnings may depend more significantly upon the performance of Jorf
Lasfar and the MCV Partnership. For the year ended December 31, 2003, earnings
from our equity method investment in Jorf Lasfar were $61 million and earnings
from our equity method investment in the MCV Partnership were $29 million.
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.
For 2003, our electric deliveries, including delivery to customers who
chose to buy generation service from an alternative electric supplier, declined
1.4 percent from 2002. This was due to a combination of warmer than normal
summer weather in 2002, cooler than normal summer weather in 2003, and a decline
in manufacturing activity during 2003. In 2004, we project electric deliveries
to grow more than three percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
throughout 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.
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,
CMS-26
- effects of potential performance standards payments, and
- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- potential rising pension costs due to market losses and lump sum
payments. For additional details, see "Accounting for Pension and OPEB"
section within this MD&A.
- pending litigation and government investigations.
For additional details about these trends or uncertainties, see Note 4,
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 8.1 percent. As of December 31,
2003, we have incurred $446 million in capital expenditures to comply with these
regulations and anticipate that the remaining $325 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.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
The EPA continues to make new rules. The EPA has proposed changes to the
rules that govern generating plant cooling water intake systems. The proposed
rules are scheduled to be final in the first quarter of 2004. We are studying
the proposed rules to determine the most cost-effective solutions for
compliance.
For additional details on electric environmental matters, see Note 4,
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
CMS-27
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 March 2004,
alternative electric suppliers are providing 735 MW of generation supply to ROA
customers. This amount represents nine percent of our distribution load and an
increase of 42 percent compared to March 2003. We anticipate this upward trend
to continue and expect over 1,000 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 charge a transition surcharge of
approximately 0.4 cent per kWh to ROA customers and eliminates securitization
offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh
for secondary service customers. We are seeking similar recovery of Stranded
Costs due to ROA customers leaving our system and are encouraged by this ruling.
This ruling may change significantly the anticipated number of customers who
choose ROA.
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 financing order will become effective after acceptance by us and
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 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
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 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 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. We
cannot predict how the MPSC will rule on our request 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 has reviewed and
allowed certain of the implementation costs incurred through 2001, but has not
authorized recovery. Depending upon the outcome of the remanded Securitization
proceeding, a significant portion of the implementation costs could be recovered
through the Securitization process.
Our application for $2 million of implementation costs in 2002 is currently
pending approval by the MPSC. We deferred these costs as a regulatory asset. In
addition to the implementation costs filed with the MPSC, as of December 31,
2003, we recorded an additional $2 million for total implementation costs of $91
million. Included in total implementation costs is $19 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 the rate cap period has
expired. For additional information on
CMS-28
rate caps, see "Rate Caps" within this section. Once a final financing order by
the MPSC on Securitization is issued, the recoverability of the implementation
costs requested will be known. We cannot predict the amounts the MPSC will
approve as allowable costs.
Also, we are pursuing authorization at the FERC for 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 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. In addition, we continue to pursue other potential means of
recovery with FERC. We cannot predict the outcome of the appeal process or the
ultimate amount, if any, the FERC will allow us to collect for implementation
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:
- a rate freeze effective through December 31, 2003, and
- rate caps effective through December 31, 2004 for small commercial and
industrial customers, and 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
needed 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: Prior to 1998, the PSCR process provided for the reconciliation of
actual power supply costs with power supply revenues. This process assured
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
1998, as part of the electric restructuring efforts, the MPSC suspended the PSCR
process, effective through 2001. As a result of the rate freeze imposed by the
Customer Choice Act, frozen rates remained in effect until December 31, 2003,
and the PSCR process remained suspended. Therefore, changes in power supply
costs due to fluctuating electricity prices were not reflected in rates charged
to our customers during the rate freeze period.
As a result of meeting the transmission capability expansion requirements
and the market power test, we have met the requirements under the Customer
Choice Act to return to the PSCR process. For additional details see Note 4,
Uncertainties, "Consumers' Electric Utility Restructuring Matters -- Electric
Restructuring Legislation."
Accordingly, 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 cap, 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. We continued to collect the equivalent to the Big Rock
nuclear decommissioning surcharge consistent with the Customer Choice Act rate
freeze in effect through December 31, 2003. Collection of the surcharge stopped,
effective January 1, 2004, when the electric rate freeze expired. As a result,
our electric revenues will be reduced by $35 million in 2004. However, we expect
a portion of this reduction to be offset with increased electric revenues from
returning to the PSCR process.
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
CMS-29
restructured, the majority of these contracts are in effect through 2005. As of
December 31, 2003, contracts for 301 MW of load have terminated. Of the
contracts that have terminated, contracts for 64 MW have gone to an alternative
electric supplier and contracts for 237 MW 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. Other new special
contracts for 101 MW received interim approval from the MPSC and are awaiting
final approval. All new special contracts end by January 1, 2006. We cannot
predict the ultimate financial impact of changes related to these power supply
contracts, or whether additional special contracts will be necessary or
advisable.
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
impact 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 significantly affect:
- 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
currently quantifiable. 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.
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.
Approximately 100,000 of our 1.7 million electric customers were without power
for approximately 24 hours as a result of the disturbance. We incurred $1
million of immediate expense as a result of the blackout. We continue to
cooperate with investigations of the blackout by several federal and state
agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan, or actions
taken by the Michigan utilities or transmission operators, were factors
contributing to the cause of the blackout. Also in November 2003, the United
States and Canadian power system outage taskforce preliminarily reported that
the primary cause of the blackout was due to transmission line contact with
trees in areas outside of Consumers' operating territory. In December 2003, the
MPSC issued an order requiring Consumers to report by April 1, 2004, the status
of lines used to serve our customers, including details of vegetation trimming
practices in calendar year 2003. Consumers intends to comply with the MPSC's
request.
In February 2004, the Board of Trustees of NERC approved recommendations to
improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout 2004. These
recommendations could result in increased transmission costs payable by
transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
CMS-30
For additional details and material changes relating to the rate matters
and restructuring of the electric utility industry, see Note 4, Uncertainties,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC became effective in February 2004. The performance
standards establish standards related 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 value
of such incentive cannot be determined at this point as the performance
standards do not contain an approved incentive mechanism. Financial penalties in
the form of customer credits are also possible. These customer credits are based
on duration and repetition of outages. We cannot predict the likely effects of
the financial incentive or penalties, if any, on us.
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.
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 cost at a number of sites, including sites
formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases,
- potential adverse appliance service plan ruling or related legislation,
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 "Accounting for Pension and OPEB" section within this
MD&A, and
- pending litigation and government investigations.
Consumers sells 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, Consumers purchases gas for resale on a Btu
basis. The Btu content of the gas available for purchase has increased and may
result in customers using less gas for the same heating requirement. Consumers
fully recovers what it spends to purchase the gas through the approved GCR.
However, since the customer is using less gas on a volumetric basis, the revenue
from
CMS-31
the distribution charge (the non-gas cost portion of the customer bill) would be
reduced. This could affect adversely Consumers' earnings from it gas utility.
The amount of the earnings loss 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 FERC for clarification or rehearing of FERC's December 2003 order. We
cannot predict the outcome of this filing.
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 4, 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 February 2004, the parties in the
case reached a tentative settlement agreement that would result in a GCR
disallowance of $11 million for the GCR period plus $1 million accrued interest
through February 2004. A reserve was recorded in December 2003. For additional
details, see Note 4, 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 that we receive the 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 its dividend payments to
CMS Energy, to a maximum of $190 million annually during the period that
Consumers receives 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. The MPSC is not bound by
these recommendations and will consider the issues anew after receipt of
exceptions and replies to the exception filed by the parties in response to the
Proposal for Decision.
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
independent of the 2003 gas rate case. 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.
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,
CMS-32
- 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 are in the process of filing 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.
The Michigan House of Representatives is scheduled to review the proposed
legislation in 2004 that would allow us to remain in the appliance service
business. In the interim, the legislature passed a bill to extend to July 1,
2004, the deadline for exiting this business. The full impact of the new code of
conduct on our business will remain uncertain until the final judicial
resolution of our appeal or the Michigan legislature enacts clarifying
legislation.
OTHER CONSUMERS' MATTERS
2001 GAS RATE CASE: In June 2001, we filed an application with the MPSC for
a distribution service rate increase. In November 2002, the MPSC approved a $56
million annual distribution service rate increase, with an 11.4 percent
authorized return on equity.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our
IPP business by narrowing the focus of our existing operations and commitments
to North America and the Middle East/North Africa. Accordingly, 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 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 its business risk and outstanding credit guarantees. Our future
activities will be centered around meeting contractual obligations, as well as
purchasing fuel for and marketing the merchant power from DIG, Michigan Power,
LLC, and other IPPs as their current power purchase agreements expire.
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 financial plan,
- changes in exchange rates or local economic 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, and
- impact of ratings downgrades on our liquidity, operating costs, and cost
of capital.
CMS-33
PENDING ASSET SALE: Affiliates of CMS Generation and CMS Gas Transmission
own a 49.6 percent interest in the Loy Yang Power Partnership ("LYPP"), which
owns the 2,000 MW Loy Yang coal-fired power project in Victoria, Australia. Due
to unfavorable power prices in the Australian market, the LYPP is not generating
cash flow sufficient to meet its debt-service obligations. LYPP has A$500
million of term bank debt that, pursuant to extensions from the lenders, is
scheduled to mature on March 31, 2004. The partners in LYPP (including
affiliates of CMS Generation, CMS Gas Transmission, NRG Energy Inc. and Horizon
Energy Australia Investments) have been exploring the possible sale of the
project (or control of the project) and a restructuring of the finances of LYPP.
In July 2003, a conditional share sale agreement was executed by the LYPP
partners and partners of the Great Energy Alliance Corporation ("GEAC") to sell
the project to GEAC for A$3.5 billion ($2.8 billion in U.S. dollars), including
A$165 million for the project equity. The partners in GEAC are the Australian
Gas Light Company, the Tokyo Electric Power Company, and a group of financial
investors led by the Commonwealth Bank of Australia. A recent resolution of an
Australian Competition and Consumer Commission objection to the sale has led to
an extension of the exclusive arrangement with GEAC to allow enough time to
complete the sale. The conditions to completion of the sale to GEAC include
consents from LYPP's lenders to a restructuring of the debt and rulings on tax
and stamp duty obligations. The project equity portion of the sale price has
been reduced to A$155 million ($122 million in U.S. dollars) as a result of
working capital and other adjustments, and closing is targeted for March 2004.
The share sale agreement and subsequent extensions provide GEAC a period of
exclusivity while the conditions of the purchase are satisfied. The ultimate net
proceeds to CMS Energy for its equity share in LYPP may be subject to a
reduction based on the ultimate resolution of many of the factors described
above as conditions to completion of the sale, as well as closing adjustments
and transaction costs, and could likely range between $20 million and a nominal
amount.
We cannot predict whether this sale to GEAC will be consummated or, if not,
whether any of the other initiatives will be successful, and it is possible that
CMS Generation may lose all or a substantial part of its remaining equity
investment in the LYPP. We previously have written off our equity investment in
the LYPP, and further write-offs would be limited to cumulative net foreign
currency translation losses. The amount of such cumulative net foreign currency
translation losses is approximately $110 million at December 31, 2003. Any such
write-off would flow through our income statement but would not result in a
reduction in shareholders' equity or cause us to be in noncompliance with our
financing agreements.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATIONS: We are the subject of various
investigations as a result of round-trip trading transactions by CMS MST,
including investigations by the United States Department of Justice and the SEC.
Additionally, we are a party to 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 4, Uncertainties.
OTHER MATTERS
CONTROL WEAKNESSES AT CMS MST
In late 2001 and during 2002, we identified a number of deficiencies in CMS
MST's systems of internal accounting controls. The internal control deficiencies
related to, among other things, a lack of account reconciliations, unidentified
differences between subsidiary ledgers and the general ledger, and procedures
and processes surrounding our accounting for energy trading contracts, including
mark-to-market accounting.
Senior management, the Audit Committee of the Board of Directors, the Board
of Directors, and the independent auditors were notified of these deficiencies
as they were discovered, and we commenced a plan of remediation that included
replacing certain key personnel and deploying additional internal and external
accounting personnel to CMS MST. While a number of these control improvements
and changes were implemented in late 2002, the most important ones occurred in
the first quarter of 2003.
CMS-34
We believe that the improvements to our system of internal accounting
controls were appropriate and responsive to the internal control deficiencies
that were identified. We monitored the operation of the improved internal
controls throughout 2003 and have concluded that they were effective.
NEW ACCOUNTING STANDARDS
See Note 17, Implementation of New Accounting Standards, for discussion of
new standards.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: 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 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 provides an implementation deferral until the
first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the
first quarter of 2004 for all entities other than special purpose entities.
Special purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
We determined that we have the controlling financial interest in three
entities that are determined to be variable interest entities. We have 50
percent partnership interest in T.E.S Filer City Station Limited Partnership,
Grayling Generating Station Limited Partnership, and 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 provide us with the
controlling financial interest as defined by the Interpretation. Therefore, we
have consolidated these partnerships into our consolidated financial statements
for the first time as of December 31, 2003. At December 31, 2003, total assets
consolidated for these entities are $227 million and total liabilities are $164
million, including $128 million of non-recourse debt. At December 31, 2003, CMS
Energy has outstanding letters of credit and guarantees of $5 million relating
to these entities. At December 31, 2003, minority interest recorded for these
entities totaled $36 million.
We also determined that we do not hold the controlling financial interest
in 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 have reflected $684 million of long-term debt -- related
parties and have 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.
CMS-35
Additionally, we have non-controlling interests in four other variable
interest entities. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at December 31, 2003:
INVESTMENT OPERATING TOTAL
NATURE OF INVOLVEMENT BALANCE AGREEMENT WITH GENERATING
NAME (OWNERSHIP INTEREST) THE ENTITY COUNTRY DATE (IN MILLIONS) CMS ENERGY CAPACITY
------------------------- ---------- ------- ----------- ------------- -------------- ----------
Loy Yang Power (49%).... Power
Generator Australia 1997 $ -- Yes 2,000 MW
Taweelah (40%).......... Power
Generator United Arab
Emirates 1999 $ 83 Yes 777 MW
Jubail (25%)............ Generator --
Under
Construction Saudi Arabia 2001 $ -- Yes 250 MW
Shuweihat (20%)......... Generator --
Under
Construction United Arab
Emirates 2001 $(24)(a) Yes 1,500 MW
------------- ----------
Total................... $ 59 4,527 MW
============= ==========
-------------------------
(a) At December 31, 2003, we recorded 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
$27 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 $59 million, Loy Yang
currency translation losses of $110 million, net of tax, and letters of credit,
guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146
million. Included in the $146 million is 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.
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 is expected to be presented for FASB clearance in 2004 and
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment often comprises multiple parts and
costs. A component accounting policy determines the level at which those parts
are recorded. Capitalization of certain costs related to property, plant, and
equipment are included in the total cost. The Statement of Position could impact
our component and capitalization accounting for property, plant, and equipment.
We continue to evaluate the impact, if any, this Statement of Position will have
upon adoption.
CMS-36
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CMS-37
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
YEARS ENDED DECEMBER 31
-------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
OPERATING REVENUE........................................... $ 5,513 $ 8,673 $ 8,006
EARNINGS FROM EQUITY METHOD INVESTEES....................... 164 92 172
OPERATING EXPENSES
Fuel for electric generation.............................. 256 341 297
Purchased and interchange power........................... 689 2,677 1,834
Purchased power -- related parties........................ 455 564 555
Cost of gas sold.......................................... 1,791 2,745 3,233
Other operating expenses.................................. 951 915 932
Maintenance............................................... 226 212 225
Depreciation, depletion and amortization.................. 428 412 408
General taxes............................................. 191 222 220
Asset impairment charges.................................. 95 602 323
------- ------- -------
5,082 8,690 8,027
------- ------- -------
OPERATING INCOME (LOSS)..................................... 595 75 151
OTHER INCOME (DEDUCTIONS)
Accretion expense......................................... (29) (31) (37)
Gain (loss) on asset sales, net........................... (3) 37 (2)
Interest and dividends.................................... 28 15 23
Other, net................................................ 18 (21) 3
------- ------- -------
14 -- (13)
------- ------- -------
FIXED CHARGES
Interest on long-term debt................................ 473 404 420
Interest on long-term debt -- related parties............. 58 -- --
Other interest............................................ 59 32 83
Capitalized interest...................................... (9) (16) (35)
Preferred dividends....................................... 3 2 2
Preferred securities distributions........................ 10 86 96
------- ------- -------
594 508 566
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS.... 15 (433) (428)
INCOME TAX EXPENSE (BENEFIT)................................ 58 (41) (94)
MINORITY INTERESTS.......................................... -- 2 (7)
------- ------- -------
LOSS FROM CONTINUING OPERATIONS............................. (43) (394) (327)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $50 TAX
EXPENSE IN 2003, $118 TAX BENEFIT IN 2002 AND $92 TAX
EXPENSE IN 2001........................................... 23 (274) (128)
------- ------- -------
LOSS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE................................................. (20) (668) (455)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13 TAX
BENEFIT IN 2003, $10 TAX EXPENSE IN 2002 AND $-- IN 2001
DERIVATIVES (NOTE 7 AND NOTE 15).......................... (23) 18 (4)
ASSET RETIREMENT OBLIGATION, SFAS NO. 143 (NOTE 16)....... (1) -- --
------- ------- -------
(24) 18 (4)
------- ------- -------
NET LOSS.................................................... $ (44) $ (650) $ (459)
======= ======= =======
CMS-38
YEARS ENDED DECEMBER 31
------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS,
EXCEPT PER SHARE AMOUNTS
CMS ENERGY
NET LOSS
Net Loss Available to Common Stock..................... $ (44) $ (650) $ (459)
====== ====== ======
BASIC LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations........................ $(0.30) $(2.84) $(2.50)
Income (Loss) from Discontinued Operations............. 0.16 (1.97) (0.98)
Income (Loss) from Changes in Accounting............... (0.16) 0.13 (0.03)
------ ------ ------
Net Loss Attributable to Common Stock.................. $(0.30) $(4.68) $(3.51)
====== ====== ======
DILUTED LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations........................ $(0.30) $(2.84) $(2.50)
Income (Loss) from Discontinued Operations............. 0.16 (1.97) (0.98)
Income (Loss) from Changes in Accounting............... (0.16) 0.13 (0.03)
------ ------ ------
Net Loss Attributable to Common Stock.................. $(0.30) $(4.68) $(3.51)
====== ====== ======
DIVIDENDS DECLARED PER COMMON SHARE....................... $ -- $ 1.09 $ 1.46
------ ------ ------
The accompanying notes are an integral part of these statements.
CMS-39
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
-------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss.................................................. $ (44) $ (650) $ (459)
Adjustments to reconcile net loss to net cash provided
by operating activities
Depreciation, depletion and amortization (includes
nuclear decommissioning of $6, $6, and $6,
respectively)....................................... 428 412 408
Depreciation and amortization of discontinued
operations.......................................... 34 73 186
Loss (gain) on disposal of discontinued operations
(Note 2)............................................ 46 237 (8)
Asset writedowns (Note 2)............................ 95 602 323
Capital lease and debt discount amortization......... 25 18 11
Accretion expense.................................... 29 31 37
Bad debt expense..................................... 28 22 22
Distributions from related parties in excess of (less
than) earnings...................................... (41) (39) 68
Loss (gain) on sale of assets........................ 3 (37) 2
Cumulative effect of accounting changes.............. 24 (18) 4
Pension contribution................................. (560) (64) (65)
Changes in assets and liabilities:
Decrease in accounts receivable and accrued
revenue........................................ 200 99 337
Decrease (increase) in inventories................ (288) 140 (339)
Decrease in accounts payable and accrued
expenses....................................... (280) (48) (388)
Deferred income taxes and investment tax credit... 242 (398) 228
Changes in other assets and liabilities........... (192) 234 5
------- ------- -------
Net cash provided by (used in) operating
activities.......................................... (251) 614 372
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital
lease)................................................. (535) (747) (1,239)
Investments in partnerships and unconsolidated
subsidiaries........................................... -- (55) (111)
Cost to retire property................................... (72) (66) (118)
Restricted cash........................................... (163) (34) (4)
Investments in Electric Restructuring Implementation
Plan................................................... (8) (8) (13)
Investments in nuclear decommissioning trust funds........ (6) (6) (6)
Proceeds from nuclear decommissioning trust funds......... 34 30 29
Proceeds from sale of assets.............................. 939 1,659 134
Other investing........................................... 14 56 (21)
------- ------- -------
Net cash provided by (used in) investing
activities.......................................... 203 829 (1,349)
------- ------- -------
CMS-40
YEARS ENDED DECEMBER 31
-------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds and other long-term debt....... 2,080 725 2,021
Proceeds from trust preferred securities.................. -- -- 125
Issuance of common stock.................................. -- -- 326
Issuance of preferred stock............................... 272 -- --
Retirement of bonds and other long-term debt.............. (1,656) (1,834) (1,343)
Common stock repurchased.................................. -- (8) (5)
Payment of common stock dividends......................... -- (149) (190)
Payment of capital lease obligations...................... (13) (15) (20)
Increase (decrease) in notes payable...................... (470) 75 21
Other financing........................................... 17 (17) 32
------- ------- -------
Net cash provided by (used in) financing
activities.......................................... 230 (1,223) 967
------- ------- -------
EFFECT OF EXCHANGE RATES ON CASH............................ (1) 8 (10)
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH
INVESTMENTS............................................... 181 228 (20)
CASH AND TEMPORARY CASH INVESTMENTS, BEGINNING OF PERIOD.... 351 123 143
------- ------- -------
CASH AND TEMPORARY CASH INVESTMENTS, END OF PERIOD.......... $ 532 $ 351 $ 123
======= ======= =======
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND
FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized)................ $ 564 $ 409 $ 447
Income taxes paid (net of refunds)........................ (33) (217) (60)
OPEB cash contribution.................................... 76 84 57
NON-CASH TRANSACTIONS
Nuclear fuel placed under capital leases.................. $ -- $ -- $ 13
Other assets placed under capital lease................... 19 62 37
======= ======= =======
The accompanying notes are an integral part of these statements.
CMS-41
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
-------------------
RESTATED
2003 2002
---- --------
IN MILLIONS
ASSETS
PLANT AND PROPERTY (AT COST)
Electric utility.......................................... $ 7,600 $ 7,523
Gas utility............................................... 2,875 2,719
Enterprises............................................... 895 644
Other..................................................... 32 45
------- -------
11,402 10,931
Less accumulated depreciation, depletion and amortization
(Note 16).............................................. 4,846 5,385
------- -------
6,556 5,546
Construction work-in-progress............................. 388 557
------- -------
6,944 6,103
------- -------
INVESTMENTS
Enterprises Investments................................... 724 724
Midland Cogeneration Venture Limited Partnership.......... 419 388
First Midland Limited Partnership......................... 224 255
Other..................................................... 23 2
------- -------
1,390 1,369
------- -------
CURRENT ASSETS
Cash and temporary cash investments at cost, which
approximates market.................................... 532 351
Restricted cash........................................... 201 38
Accounts receivable, notes receivable and accrued revenue,
less allowances of $29 in 2003 and $15 in 2002......... 367 349
Accounts receivable -- Marketing, services and trading,
less allowances of $11 in 2003 and $8 in 2002.......... 36 248
Accounts receivable and notes receivable -- related
parties................................................ 73 186
Inventories at average cost
Gas in underground storage............................. 741 491
Materials and supplies................................. 110 96
Generating plant fuel stock............................ 41 37
Assets held for sale...................................... 24 595
Price risk management assets.............................. 102 115
Prepayments and other..................................... 267 233
------- -------
2,494 2,739
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs...................................... 648 689
Postretirement benefits................................ 162 185
Abandoned Midland project.............................. 10 11
Other.................................................. 266 168
Assets held for sale...................................... 2 2,084
Price risk management assets.............................. 177 135
Nuclear decommissioning trust funds....................... 575 536
Prepaid pension costs..................................... 388 --
Goodwill.................................................. 25 31
Notes receivable -- related parties....................... 242 160
Notes receivable.......................................... 125 126
Other..................................................... 390 445
------- -------
3,010 4,570
------- -------
TOTAL ASSETS................................................ $13,838 $14,781
======= =======
The accompanying notes are an integral part of these statements.
CMS-42
CMS ENERGY CORPORATION
DECEMBER 31
-------------------
RESTATED
2003 2002
---- --------
IN MILLIONS
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 250.0 shares; outstanding 161.1
shares in 2003 and 144.1 shares in 2002................ $ 2 $ 1
Other paid-in capital..................................... 3,846 3,605
Accumulated other comprehensive loss...................... (419) (728)
Retained deficit.......................................... (1,844) (1,800)
------- -------
1,585 1,078
Preferred stock of subsidiary (Note 5).................... 44 44
Preferred stock........................................... 261 --
Company-obligated convertible Trust Preferred Securities
of subsidiaries (Note 5)............................... -- 393
Company-obligated mandatorily redeemable Trust Preferred
Securities of Consumers' subsidiaries (Note 5)......... -- 490
Long-term debt............................................ 6,020 5,357
Long-term debt -- related parties (Note 5)................ 684 --
Non-current portion of capital leases..................... 58 116
------- -------
8,652 7,478
------- -------
MINORITY INTERESTS.......................................... 73 38
------- -------
CURRENT LIABILITIES
Current portion of long-term debt and capital leases...... 519 646
Notes payable............................................. -- 458
Accounts payable.......................................... 296 377
Accounts payable -- Marketing, services and trading....... 21 119
Accounts payable -- related parties....................... 40 53
Accrued interest.......................................... 130 131
Accrued taxes............................................. 285 291
Liabilities held for sale................................. 2 427
Price risk management liabilities......................... 89 96
Current portion of purchase power contracts............... 27 26
Current portion of gas supply contract obligations........ 29 25
Deferred income taxes..................................... 27 15
Other..................................................... 185 225
------- -------
1,650 2,889
------- -------
NON-CURRENT LIABILITIES
Postretirement benefits................................... 265 725
Deferred income taxes..................................... 615 438
Deferred investment tax credit............................ 85 91
Regulatory liabilities for income taxes, net.............. 312 297
Regulatory liabilities for cost of removal (Note 16)...... 983 907
Other regulatory liabilities.............................. 172 4
Asset retirement obligation............................... 359 --
Liabilities held for sale................................. -- 1,218
Price risk management liabilities......................... 175 135
Gas supply contract obligations........................... 208 241
Power purchase agreement -- MCV Partnership............... -- 27
Other..................................................... 289 293
------- -------
3,463 4,376
------- -------
Commitments and Contingencies (Notes 2, 4, 5, 8, 10,
11)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES.............. $13,838 $14,781
======= =======
CMS-43
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31
----------------------------------------------------------------
RESTATED RESTATED
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- -------- --------
NUMBER OF SHARES IN THOUSANDS IN MILLIONS
COMMON STOCK
At beginning and end of period........ $ 2 $ 1 $ 1
OTHER PAID-IN CAPITAL
At beginning of period................ 144,088 132,989 121,201 3,605 3,257 2,936
Common stock repurchased.............. (14) (39) (232) -- (8) (5)
Common stock reacquired............... (217) (220) (11) (5) (1) (1)
Common stock issued................... 17,273 11,358 11,681 234 357 320
Common stock reissued................. -- -- 350 1 -- 7
Issuance cost of preferred stock...... -- -- -- (8) -- --
Deferred gain (Note 5)................ -- -- -- 19 -- --
------- ------- ------- ------- ------- -------
At end of period................. 161,130 144,088 132,989 3,846 3,605 3,257
------- ------- ------- ------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Minimum Pension Liability
At beginning of period............. (241) -- --
Minimum pension liability
adjustments(a)................... 241 (241) --
------- ------- -------
At end of period................. -- (241) --
------- ------- -------
Investments
At beginning of period............. 2 (5) (2)
Unrealized gain (loss) on
investments(a)................... 6 -- (3)
Realized gain on investments(a).... -- 7 --
------- ------- -------
At end of period................. 8 2 (5)
------- ------- -------
Derivative Instruments
At beginning of period(b).......... (31) (28) 10
Unrealized gain (loss) on
derivative instruments(a)........ 4 (7) (31)
Reclassification adjustments
included in consolidated net
income (loss)(a)................. 19 4 (7)
------- ------- -------
At end of period................. (8) (31) (28)
------- ------- -------
FOREIGN CURRENCY TRANSLATION
At beginning of period................ (458) (233) (206)
Change in foreign currency
translation(a)..................... 39 (225) (27)
------- ------- -------
At end of period................. (419) (458) (233)
------- ------- -------
At end of period.............. (419) (728) (266)
------- ------- -------
RETAINED DEFICIT
At beginning of period(c)............. (1,800) (1,001) (352)
Consolidated net loss(a).............. (44) (650) (459)
Common stock dividends declared....... -- (149) (190)
------- ------- -------
At end of period................. (1,844) (1,800) (1,001)
------- ------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY....... $ 1,585 $ 1,078 $ 1,991
======= ======= =======
CMS-44
YEARS ENDED DECEMBER 31
-----------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
(a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum pension liability
Minimum pension liability adjustments, net of tax
(tax benefit) of $132, $(132), and $--,
respectively...................................... $ 241 $ (241) $ --
Investments
Unrealized gain (loss) on investments, net of tax
(tax benefit) of $3, $--, and $(2),
respectively...................................... 6 -- (3)
Realized gain on investments, net of tax of $--, $--,
and $--, respectively............................. -- 7 --
Derivative Instruments
Unrealized gain (loss) on derivative instruments,
net of tax (tax benefit) of $--, $(4), and
$(13), respectively............................. 4 (7) (31)
Reclassification adjustments included in net loss,
net of tax (tax benefit) of $11, $2, and $(3),
respectively.................................... 19 4 (7)
Foreign currency translation, net...................... 39 (225) (27)
Consolidated net loss.................................. (44) (650) (459)
------- ------- -------
Total Other Comprehensive Income (Loss).............. $ 265 $(1,112) $ (527)
======= ======= =======
(b) YEAR ENDED DECEMBER 31, 2001 REFLECTS THE CUMULATIVE
CHANGE IN ACCOUNTING PRINCIPLE, NET OF $7 TAX (NOTE 7.)
(c) BEGINNING BALANCE FOR YEAR ENDED DECEMBER 31, 2001 WAS
DECREASED BY $38 MILLION DUE TO AN ADJUSTMENT TO
DEFERRED TAXES RELATED TO LOY YANG (NOTE 8.)
The accompanying notes are an integral part of these statements.
CMS-45
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have determined the need to make certain adjustments to our consolidated
financial statements for the fiscal years ended December 31, 2002, December 31,
2001, and December 31, 2000. Therefore, the consolidated financial statements
for 2002 and 2001 have been restated from amounts previously reported. See Note
18, Restatement and Reclassification.
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, in accordance with Revised FASB
Interpretation No. 46. Intercompany transactions and balances have been
eliminated. 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 not a controlling financial
interest.
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 4,
Uncertainties.
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
December 31, 2003, our restricted cash on hand was $201 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.
COAL INVENTORY: We use the weighted average cost method for valuing coal
inventory.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the
weighted average number of shares of common stock and 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 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
6, Earnings Per Share and Dividends.
CMS-46
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities in accordance with SFAS No. 115. These debt and equity securities are
classified into three categories: held-to-maturity, trading, or
available-for-sale. Our investments in equity securities are classified as
available-for-sale. 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. For additional details
regarding financial instruments, see Note 7, 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 of the balance sheet. 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 in determining net income.
The change in the foreign currency translation adjustment increased equity by
$39 million for the year ended December 31, 2003. The change in the foreign
currency translation adjustment decreased equity by $225 million for the year
ended December 31, 2002.
GAS INVENTORY: Consumers uses the weighted average cost method for valuing
working gas and recoverable cushion gas in underground storage facilities.
GOODWILL: Goodwill represents the excess of the purchase price over the
fair value of the net assets of acquired companies. Goodwill is not amortized,
but is tested annually for impairment. For additional information, see Note 3,
Goodwill.
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.
MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property
replacements to maintenance expense. We also charge planned major maintenance
activities to operating expense unless the cost represents the acquisition of
additional components or the replacement of an existing component. We capitalize
the cost of plant additions and replacements. We depreciate utility property on
straight-line and units-of-production rates approved by the MPSC. The composite
depreciation rates for our properties are:
YEARS ENDED
DECEMBER 31
---------------------
2003 2002 2001
---- ---- ----
Electric utility property................................... 3.1% 3.1% 3.1%
Gas utility property........................................ 4.6% 4.5% 4.4%
Other property.............................................. 8.1% 7.2% 11.2%
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
CMS-47
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
disposal of spent nuclear fuel burned before April 7, 1983. As of December 31,
2003, 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 4, Uncertainties, "Other Consumers' Electric Utility
Uncertainties -- Nuclear Matters."
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.
Trust Funds: MPSC orders, received in March 1999 for Big Rock and December
1999 for Palisades, provided for fully funding the decommissioning trust funds
for both sites. The December 1999 order set the annual decommissioning surcharge
for Palisades at $6 million. In 2003, we collected $6 million from our electric
customers for the decommissioning of our Palisades nuclear plant. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
In December 2000, we stopped depositing funds in the Big Rock trust fund
based on its funding status at that time. However, the current level of funds
provided by the trust may not be adequate to fully fund the decommissioning of
Big Rock. This is due in part to the DOE's failure to accept spent nuclear fuel
and lower returns on the trust fund. We are attempting to recover our additional
costs for storing spent nuclear fuel through litigation, as discussed in Note 4,
Uncertainties, "Other Consumers' Electric Utility Uncertainties -- Nuclear
Matters." To the extent the funds are not sufficient, we would seek additional
relief from the MPSC. We can make no assurance that the MPSC would grant this
request.
In March 2001, we filed with the MPSC a "Report on the Adequacy of the
Existing Provision for Nuclear Plant Decommissioning" for each plant reflecting
decommissioning cost estimates of $349 million for Big Rock, excluding spent
nuclear fuel storage costs, and $739 million for Palisades, in 2000 dollars. We
are required to file the next such reports with the MPSC by March 31, 2004 for
Big Rock and Palisades and we are in the process of preparing updated cost
estimates.
Big Rock: In 1997, Big Rock closed permanently and plant decommissioning
began. We estimate that the Big Rock site will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The
following table shows our Big Rock decommissioning activities:
YEAR-TO-DATE ACCUMULATIVE
DECEMBER 31, 2003 TOTAL-TO-DATE
----------------- -------------
IN MILLIONS
Decommissioning expenditures................................ $45 $263
Withdrawals from trust funds................................ 34 243
These activities had no material impact on net income. At December 31,
2003, we have an investment in nuclear decommissioning trust funds of $88
million for Big Rock. In addition, at December 31, 2003, we have charged $7
million to our FERC jurisdictional depreciation reserve for the decommissioning
of Big Rock.
Palisades: In December 2000, the NRC extended the Palisades operating
license to March 2011 and the impact of this extension was included as part of
our March 2001 filing with the MPSC.
At December 31, 2003, we have an investment in the MPSC nuclear
decommissioning trust funds of $477 million for Palisades. In addition, at
December 31, 2003, we have a FERC decommissioning trust fund with a balance of
$10 million. For additional details on decommissioning costs accounted for as
asset retirement obligations, see Note 16, Asset Retirement Obligations.
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
CMS-48
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
original cost is charged to accumulated depreciation and cost of removal, less
salvage is recorded as a regulatory liability. For additional details, see Note
16, 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.
Property, plant, and equipment at December 31, 2003 and 2002, was as
follows:
ESTIMATED
DEPRECIABLE
YEARS ENDED DECEMBER 31 LIFE IN YEARS(E) 2003 2002
----------------------- ---------------- ---- ----
IN MILLIONS
Electric:
Generation................................................ 13-75 $3,332 $3,489
Distribution.............................................. 12-85 3,799 3,619
Other..................................................... 5-50 388 300
Capital leases(a)......................................... 81 115
Gas:
Underground storage facilities(b)......................... 30-75 232 217
Transmission.............................................. 15-75 342 310
Distribution.............................................. 35-75 1,976 1,899
Other..................................................... 5-48 300 237
Capital leases(a)......................................... 25 56
Enterprises:
IPP....................................................... 3-40 511 250
CMS Gas Transmission...................................... 5-40 119 120
CMS Electric and Gas...................................... 2-30 241 227
Other..................................................... 4-25 24 47
Other:...................................................... 7-71 32 45
Construction work-in-progress(c)............................ 388 557
Less accumulated depreciation, depletion, and
amortization.............................................. 4,846 5,385
------ ------
Net property, plant, and equipment(d)....................... $6,944 $6,103
====== ======
-------------------------
(a) Capital leases presented in this table are gross amounts. Amortization of
capital leases was $38 million in 2003 and $96 million in 2002.
(b) Includes unrecoverable base natural gas in underground storage of $23
million at December 31, 2003 and $23 million at December 31, 2002, which is
not subject to depreciation.
(c) Included in construction costs at December 31, 2002 was $54 million,
relating to the capital lease of our main headquarters. We purchased the
main headquarters in November 2003.
(d) Included in net property, plant and equipment are intangible assets
primarily related to software development costs, consents, and rights of
way. The estimated amortization life for software development costs is seven
years and other intangible amortization lives range from 50 to 75 years.
Intangible assets at December 31, 2003 and 2002 were as follows:
CMS-49
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31 2003 2002
----------------------- ---- ----
IN MILLIONS
------------
Intangible assets at cost................................... $419 $479
Less accumulated amortization............................... 211 236
---- ----
Net intangible assets....................................... $208 $243
==== ====
(e) The following table illustrates the depreciable life for electric and gas
structures and improvements.
ESTIMATED ESTIMATED
DEPRECIABLE DEPRECIABLE
ELECTRIC LIFE IN YEARS GAS LIFE IN YEARS
-------- ------------- --- -------------
Generation: Underground storage facilities 45
Coal 39-43 Transmission 60
Nuclear 25 Distribution 60
Hydroelectric 55-71 Other 42-48
Other 32
Distribution 50-60
Other 40-42
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
RELATED-PARTY TRANSACTIONS: Consumers paid $64 million in 2003, $67 million
in 2002, and $71 million in 2001 for electric generating capacity and energy
from affiliates of Enterprises. CMS Energy recorded interest charges on
long-term debt to related parties of $58 million in 2003. Affiliates of CMS
Energy sold, stored and transported natural gas and provided other services to
the MCV Partnership totaling $17 million in 2003, $41 million in 2002, and $35
million in 2001. We expensed purchases of capacity and energy from the MCV
Partnership totaling $455 million in 2003, $497 million in 2002, and $488
million in 2001. For additional discussion of related-party transactions with
the MCV Partnership and the FMLP, see Note 4, Uncertainties and Note 15,
Summarized Financial Information of Significant Related Energy Supplier. Other
related-party transactions are immaterial.
TRADE RECEIVABLES: We record our accounts receivable at fair value.
Accounts deemed uncollectable are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE: We amortize premiums,
discounts and expenses incurred in connection with the issuance of outstanding
long-term debt over the terms of the issues. For the regulated portions of our
businesses, if debt is refinanced, we amortize any unamortized premiums,
discounts and expenses over the term of the new debt.
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.
In 1999, we received MPSC electric restructuring orders, which, among other
things, identified the terms and timing for implementing electric restructuring
in Michigan. Consistent with these orders and EITF No. 97-4, we discontinued the
application of SFAS No. 71 for the energy supply portion of our business because
we expected to implement ROA at competitive market based rates for our electric
customers.
CMS-50
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Since 1999, there have been significant legislative and regulatory changes
in Michigan that has resulted in:
- electric supply customers of utilities remaining on cost-based rates, and
- utilities being provided the opportunity to recover Stranded Costs
associated with electric restructuring, from customers who choose an
alternative electric supplier.
During 2002, we re-evaluated the criteria used to determine if an entity or
a segment of an entity meets the requirements to apply regulated utility
accounting, and determined that the energy supply portion of our business could
meet the criteria if certain regulatory events occurred. In December 2002, we
received a MPSC Stranded Cost order that allowed us to re-apply regulatory
accounting standard SFAS No. 71 to the energy supply portion of our business.
Re-application of SFAS No. 71 had no effect on the prior discontinuation
accounting, but allowed us to apply regulatory accounting treatment to the
energy supply portion of our business beginning in the fourth quarter of 2002,
including regulatory accounting treatment of costs required to be recognized in
accordance with SFAS No. 143. For additional details, see Note 12, Asset
Retirement Obligations.
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.
The following regulatory assets and liabilities, which include both current
and non-current amounts, are reflected in the Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up to 14 years. We
recognized an OPEB transition obligation in accordance with SFAS No. 106 and
established a regulatory asset for this amount that we expect to recover in
rates over the next nine years.
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Securitized costs (Note 4).................................. $ 648 $ 689
Postretirement benefits (Note 10)........................... 181 204
Electric Restructuring Implementation Plan (Note 4)......... 91 83
Manufactured gas plant sites (Note 4)....................... 67 69
Abandoned Midland project................................... 10 11
Unamortized debt............................................ 51 14
Asset retirement obligation (Note 16)....................... 49 --
Other....................................................... 8 2
------ ------
Total regulatory assets..................................... $1,105 $1,072
====== ======
Cost of removal (Note 16)................................... $ 983 $ 907
Income taxes (Note 8)....................................... 312 297
Asset retirement obligation (Note 16)....................... 168 --
Other....................................................... 4 4
------ ------
Total regulatory liabilities................................ $1,467 $1,208
====== ======
In October 2000, we received an MPSC order authorizing us to securitize
certain regulatory assets up to $469 million, net of tax, see Note 4,
Uncertainties, "Consumers' Electric Utility Restructuring Matters --
Securitization." Accordingly, in December 2000, we established a regulatory
asset for securitized costs of $709 million, before tax, that had previously
been recorded in other regulatory asset accounts. To prepare for the financing
of the securitized assets and the subsequent retirement of debt with
Securitization proceeds, issuance
CMS-51
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
fees were capitalized as a part of Securitization costs. These issuance costs
are amortized each month for up to fourteen years. The components of the
unamortized securitized costs are illustrated below.
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Unamortized nuclear costs................................... $405 $405
Postretirement benefits..................................... 84 84
Income taxes................................................ 203 203
Uranium enrichment facility................................. 16 16
Other....................................................... 12 12
Accumulated Securitization cost amortization................ (72) (31)
---- ----
Total unamortized securitized costs......................... $648 $689
==== ====
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 $939 million in 2003 and $1.659 billion in 2002.
DISCONTINUED OPERATIONS
We have discontinued the following operations:
PRETAX AFTER-TAX
BUSINESS/PROJECT DISCONTINUED GAIN(LOSS) GAIN(LOSS) STATUS
---------------- ------------ ---------- ---------- ------
IN MILLIONS
Equatorial Guinea(a)................ December 2001 $ 497 $310 Sold January 2002
Powder River........................ March 2002 17 11 Sold May 2002
Zirconium Recovery.................. June 2002 (47) (31) Abandoned
CMS Viron........................... June 2002 (14) (9) Sold June 2003
Oil and Gas(b)...................... September 2002 (126) (82) Sold September 2002
Panhandle(c)........................ December 2002 (39) (44) Sold June 2003
Field Services...................... December 2002 (5) (1) Sold July 2003
Marysville.......................... June 2003 2 1 Sold November 2003
Parmelia(d)......................... December 2003 -- -- Held for sale
(a) In the first quarter of 2003, we settled a liability with the purchaser of
Equatorial Guinea and reversed the remaining excess reserve. This
settlement resulted in a gain of $6 million after-tax, which is included in
discontinued operations.
(b) As a result of the sale of CMS Oil and Gas, we recorded liabilities for
certain sale indemnification obligations and other matters. In September
2003, we re-evaluated our exposure to the obligations and reduced the
carrying value of these liabilities by $8 million after-tax. This
adjustment is reported in discontinued operations.
(c) The Pension Plan retained pension payment obligations for Panhandle
employees who were vested under the Pension Plan. Panhandle employees are
no longer eligible to accrue additional benefits. Because of the
significant change in the makeup of the plan, a remeasurement of the
obligation at the date of sale was required. The remeasurement resulted in
a $4 million increase in our 2003 OPEB expense, as well as an additional
charge to accumulated other comprehensive income of approximately $34
million ($22 million after-tax) as a result of the increase in the
additional minimum pension liability. Additionally, a significant
CMS-52
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
number of Panhandle employees elected to retire as of July 1, 2003 under
the CMS Energy Employee Pension Plan. As a result, we have recorded a $25
million ($16 million after-tax) settlement loss, and a $10 million ($7
million after-tax) curtailment gain, pursuant to the provisions of SFAS No.
88, which is reflected in discontinued operations.
(d) In December 2003, we began reporting the operations of our Parmelia
business in discontinued operations and reduced the carrying amount of our
Parmelia business to reflect fair value. The $26 million after-tax
adjustment is reported in discontinued operations. We expect the sale of
Parmelia to occur in 2004.
Due to lack of progress on the sale, we reclassified our international
energy distribution business, which includes CPEE and SENECA, from discontinued
operations to continuing operations for the years 2003, 2002, and 2001. When we
initially reported the international energy distribution business as a
discontinued operation in 2001, we applied APB Opinion No. 30, which allowed us
to record a provision for anticipated operating losses. We currently apply FASB
No. 144, which does not allow us to record a provision for future operating
losses. Therefore, in the process of reclassifying the international energy
distribution business to continuing operations and reversing such provisions, we
increased our net loss by $3 million in 2002 and decreased our net loss by $3
million in 2001. In 2003, there was an increase to net income of $75 million as
a result of reversing the previously recognized impairment loss in discontinued
operations.
At December 31, 2003, "Assets held for sale" includes Parmelia, Bluewater
Pipeline, and our investment in the American Gas Index fund. Although Bluewater
Pipeline and the American Gas Index fund are considered held for sale, they did
not meet the criteria for discontinued operations. At December 31, 2002, "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:
AS OF
DECEMBER 31
----------------
RESTATED
2003 2002
---- --------
IN MILLIONS
Assets
Cash...................................................... $ 7 $ 82
Accounts receivable....................................... 2 133
Property, plant and equipment -- net...................... 2 2,003
Goodwill.................................................. -- 117
Other..................................................... 15 344
--- ------
Total assets held for sale.................................. $26 $2,679
=== ======
Liabilities
Accounts payable.......................................... $ 2 $ 74
Long-term debt............................................ -- 1,150
Minority interest......................................... -- 45
Other..................................................... -- 376
--- ------
Total liabilities held for sale............................. $ 2 $1,645
=== ======
CMS-53
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following amounts are reflected in the Consolidated Statements of
Income (Loss) for discontinued operations:
YEARS ENDED DECEMBER 31
----------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Revenues.................................................... $504 $ 891 $1,453
==== ===== ======
Discontinued operations:
Pretax gain (loss) from discontinued operations........... $115 $ (38) $ (53)
Income tax expense (benefit).............................. 46 (1) 83
---- ----- ------
Income (loss) from discontinued operations................ 69 (37) (136)
==== ===== ======
Pretax gain (loss) on disposal of discontinued
operations............................................. (42) (354) 17
Income tax expense (benefit).............................. 4 (117) 9
---- ----- ------
Gain (loss) on disposal of discontinued operations........ (46) (237) 8
---- ----- ------
Income (loss) from discontinued operations.................. $ 23 $(274) $ (128)
==== ===== ======
The income (loss) from discontinued operations includes a reduction in
asset values, a provision for anticipated closing costs, and a portion of the
Parent Company's interest expense. Interest expense of $22 million for 2003, $71
million for 2002 and $86 million for 2001 has been allocated based on a ratio of
the expected proceeds for the asset to be sold divided by the Parent Company's
total capitalization of each discontinued operation times the Parent Company'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).
In 2003, we sold the following assets that did not meet the definition of,
and therefore were not reported as, discontinued operations:
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN (LOSS) GAIN (LOSS)
--------- ---------------- ----------- -----------
IN MILLIONS
January CMS MST Wholesale Gas....................................... $(6) $(4)
March CMS MST Wholesale Power..................................... 2 1
June Guardian Pipeline........................................... (4) (3)
December CMS Land -- Arcadia......................................... 3 2
Various Other....................................................... 2 1
--- ---
Total loss on asset sales................................... $(3) $(3)
=== ===
In June 2003, we received three million shares of Southern Union common
stock worth $49 million from the sale of Panhandle, a discontinued operation. In
July 2003, Southern Union declared a five percent common stock dividend payable
July 31, 2003, to shareholders of record as of July 17, 2003. As a result of the
stock dividend, on September 30, 2003, we held 3.15 million shares of Southern
Union common stock worth $54 million based on the closing price of $17.00 per
share. The $2 million increase in value was recorded in dividend income. In
October 2003, we sold our 3.15 million shares of Southern Union common stock to
a private investor for $17.77 per share. The additional $5 million gain was
recorded in other income in 2003.
CMS-54
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In 2002, we sold the following assets that did not meet the definition of,
and therefore were not reported as, discontinued operations:
PRETAX AFTER-TAX
DATE SOLD BUSINESS/PROJECT GAIN (LOSS) GAIN (LOSS)
--------- ---------------- ----------- -----------
IN MILLIONS
January Equatorial Guinea -- methanol plant......................... $ 19 $ 12
April Toledo Power................................................ (11) (5)
May Electric Transmission System................................ 38 31
August National Power Supply....................................... 15 30
October Vasavi Power Plant.......................................... (25) (24)
Various Other....................................................... 1 --
---- ----
Total gain on asset sales................................... $ 37 $ 44
==== ====
In 2001, we sold miscellaneous assets for a pretax loss of $2 million.
In February 2004, we sold Bluewater Pipeline, a 24.9 mile pipeline that
extends from Marysville, Michigan to Armada, Michigan to Bluewater Gas Storage,
LLC, a subsidiary of Sempra Energy Trading Corporation. We do not expect the
gain or loss on the sale to be significant.
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.
CMS-55
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The table below summarizes our asset impairments:
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
RESTATED RESTATED
------------------- -------------------
PRETAX AFTER-TAX PRETAX AFTER-TAX PRETAX AFTER-TAX
2003 2003 2002 2002 2001 2001
------ --------- ------ --------- ------ ---------
IN MILLIONS
Asset impairments:
Consumers.................................. $-- $-- $ -- $ -- $ 3 $ 2
Enterprises:
International Energy Distribution(a).... 72 53 4 3 95 62
CMS Generation
DIG(b)................................ -- -- 460 299 -- --
Michigan Power........................ -- -- 62 40 -- --
Craven................................ -- -- 23 15 -- --
National Power Supply................. -- -- -- -- 89 88
El Chocon............................. -- -- -- -- 45 42
HL Power.............................. -- -- -- -- 30 18
Other(c).............................. 16 11 20 13 16 11
Natural Gas Transmission................ -- -- -- -- 31 20
Marketing, Services and Trading......... -- -- 18 11 -- --
Other(d)................................ 7 4 15 10 14 9
--- --- ---- ---- ---- ----
Total asset impairments...................... $95 $68 $602 $391 $323 $252
=== === ==== ==== ==== ====
-------------------------
(a) In September 2003, we wrote down our investment in CMS Electric and Gas'
Venezuelan electric distribution utility and an associated equipment lease
to reflect fair value. The impairment was based on estimates of the
utility's future cash flows, incorporating certain assumptions about
Venezuela's regulatory, political, and economic environment.
(b) DIG's reduced valuation was primarily a reflection of the unfavorable terms
of its power purchase agreement.
(c) At CMS Generation, we determined that the fair value of our equity
investments was lower than its carrying amount, and that this decline in
value was other than temporary. Therefore, in accordance with APB No. 18,
we recognized an impairment charge of $16 million ($11 million, net of
tax).
(d) Includes development projects of $7 million ($4 million, net of tax) in
2003 that would no longer be pursued.
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:
- 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
- terminated 64 employees, including five officers. Prior to December 31,
2002, 123 employees elected severance arrangements. Of these 187 officers
and employees, 65 had been terminated as of December 31, 2002. All
remaining terminations were completed in 2003.
CMS-56
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs at December
31, 2002 and December 31, 2003.
INVOLUNTARY LEASE
TERMINATION TERMINATION TOTAL
----------- ----------- -----
IN MILLIONS
Beginning accrual balance, January 1, 2002.................. $ -- $-- $ --
Expense..................................................... 22 11 33
Payments.................................................... (10) (3) (13)
---- --- ----
Ending accrual balance at December 31, 2002................. $ 12 $ 8 $ 20
---- --- ----
Expense..................................................... 3 -- 3
Payments.................................................... (12) (2) (14)
---- --- ----
Ending accrual balance at December 31, 2003................. $ 3 $ 6 $ 9
==== === ====
Restructuring costs for the year ended December 31, 2003, which are
included in operating expenses, include $3 million of involuntary employee
termination benefits.
3: GOODWILL
Our goodwill balance was $25 million at December 31, 2003 and $31 million
at December 31, 2002.
CMS GAS TRANSMISSION: We recorded goodwill as an asset when we purchased
Panhandle and began, over time, to expense a portion of goodwill. Effective
January 1, 2002, a new accounting standard went into effect that required us to
stop expensing goodwill and to test for impairment. We tested the value of the
goodwill related to Panhandle for impairment by comparing the fair value of
goodwill, as determined by independent appraisers, to the value on our books.
The test results showed that the goodwill was impaired. We recorded a loss of
$601 million ($369 million, after-tax), that was the amount by which the value
on our books exceeded the fair value. In 2002, we also discontinued the
operations of Panhandle; therefore, the $369 million after-tax goodwill
impairment is reflected in discontinued operations. In 2003, we sold Panhandle.
CMS MST: During the third quarter of 1999, we purchased a 100 percent
interest in CMS Viron and recorded goodwill. In 2002, we performed an impairment
test, which determined our goodwill related to CMS Viron was impaired. In the
first quarter of 2002, we recorded a loss of $15 million ($10 million,
after-tax) for goodwill impairment. In 2002, we also discontinued the operations
of CMS Viron; therefore, the $10 million after-tax goodwill impairment is
reflected in discontinued operations. In 2003, we sold CMS Viron.
CMS-57
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Additionally, the following table represents net loss for the year 2001
without goodwill amortization expense.
RESTATED
2001
--------
IN MILLIONS
Reported net loss........................................... $ (459)
Add: goodwill amortization expense(a)....................... 13
------
Adjusted net loss........................................... $ (446)
Adjusted basic and diluted loss per share................... $(3.41)
======
-------------------------
(a) Net of tax of $7 million.
4: 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 other investigations concerning round-trip
trading, including an investigation by the SEC regarding round-trip trades and
CMS Energy's financial statements, accounting policies and controls, and an
investigation by the DOJ. CMS Energy is unable to predict the outcome of these
matters, and what effect, if any, these investigations will have on its
business.
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. 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
CMS-58
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 the best interest of CMS Energy 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 was 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. 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 investigation
by the DOJ regarding this matter. In November 2003, CMS MST and CMS Field
Services (now Cantera Gas Company) entered into a settlement with the CFTC
pursuant to which they paid a $16 million civil monetary penalty in connection
with the inaccurate reporting of natural gas trading data to publications that
compile and publish price indices. The settlement resolves all matters
investigated by the CFTC involving CMS Energy, including round-trip trading. CMS
Energy neither admits nor denies the CFTC's findings in the settlement order.
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. The plaintiff in the
Texas-Ohio case has agreed to extend the time for all defendants to answer or
otherwise respond until after the multi district court litigation ("MDL") panel
decides whether to take the case. There is currently pending in the Nevada
federal district court a MDL matter involving seven complaints originally filed
in various state courts in California. These complaints make allegations similar
to those in the
CMS-59
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
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 are likely to seek to remove this action from the California federal
district court and 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.
CONSUMERS' UNCERTAINTIES
Several business trends or uncertainties may affect Consumers' 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 conclusions about the causes of the August 14, 2003 blackout,
including exposure to liability, increased regulatory requirements, and
new legislation,
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to purchased
power price increases,
- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel,
- potential adverse appliance service plan ruling or related legislation,
- 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.
CMS-60
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Other
- pending litigation regarding PURPA qualifying facilities, and
- pending litigation and government investigations.
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. It submitted these rules to
the EPA for approval in the first quarter of 2003. The EPA has yet to approve
the Michigan rules. If the EPA does not approve the Michigan rules, 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 December 31, 2003, we have
incurred $446 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $325 million of capital expenditures will be
incurred 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 a 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.
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.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
Water: The EPA has proposed changes to the rules that govern generating
plant cooling water intake systems. The proposed rules will require significant
reduction in fish killed by operating equipment. The proposed rules are
scheduled to become final in the first quarter of 2004 and some of our
facilities would be required to comply by 2006. We are studying the proposed
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
CMS-61
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
the total liability for the known Superfund sites will be between $1 million and
$9 million. As of December 31, 2003, 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 in regard to the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
effectively suspends the lawsuit until the MPSC rules. 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: In June 2000, 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,
- 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
CMS-62
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
achieve the increased transmission capacity required under the Customer Choice
Act. The MPSC found that once the planned projects were completed and
verification was submitted, a utility was in technical compliance. 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 PLAN: In 1998, we submitted a plan for electric ROA to the
MPSC. In March 1999, the MPSC issued orders generally supporting the plan. The
Customer Choice Act states that the MPSC orders issued before June 2000 are in
compliance with this act and enforceable by the MPSC. Those MPSC orders:
- allow electric customers to choose their supplier,
- authorize recovery of net Stranded Costs from ROA customers and
implementation costs from all customer classes, and
- confirm any voluntary commitments of electric utilities.
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 March 2004, alternative electric suppliers are
providing 735 MW of load. This amount represents nine percent of the total
distribution load and an increase of 42 percent compared to March 2003.
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. 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 of approximately 0.4 cent per kWh to ROA customers and
eliminates securitization offsets of 0.7 cents per kWh for primary service
customers and 0.9 cents per kWh for secondary service customers. We are seeking
similar recovery of Stranded Costs due to ROA customers leaving our system and
are encouraged by this ruling.
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
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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 prior to 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, $50
million for the twelve months ended December 31, 2003, and $52 million for the
twelve months ended December 31, 2002, 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. The MPSC rejected the portion of the application related to pension
costs. The MPSC based its decision on the reasoning that a rebounding economy
and stock market could potentially reverse recent Pension Plan losses. Also, the
MPSC rejected Palisades expenditures previously not securitized as eligible
securitized costs; therefore, these costs will be included in a future electric
rate case proceeding with the MPSC and as a component of the 2002 net Stranded
Cost calculation. 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 financing order will become effective after acceptance by us and
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.
We are authorized by the MPSC 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 and we have not recorded regulatory assets to recognize the future
recovery of such costs.
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 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. We cannot predict
how the MPSC will rule on our request for the recoverability of Stranded Costs.
Implementation Costs: Since 1997, we have incurred significant electric
utility restructuring 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.
YEAR FILED YEAR INCURRED REQUESTED PENDING ALLOWED DISALLOWED
---------- ------------- --------- ------- ------- ----------
IN MILLIONS
1999...................................... 1997 & 1998 $20 $ -- $15 $5
2000...................................... 1999 30 -- 25 5
2001...................................... 2000 25 -- 20 5
2002...................................... 2001 8 -- 8 --
2003...................................... 2002 2 2 Pending Pending
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 December 31, 2003, $2 million of
additional implementation costs and $19 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. Cash recovery from customers is expected to begin after the rate cap
period expires. The rate cap expired for large commercial and industrial
customers on December 31, 2003. We have asked to include implementation costs
through December 31, 2000 in the pending Securitization case. If approved, the
sale of Securitization bonds will allow for the recovery of a significant
portion of these costs. We cannot predict the amount the MPSC will approve as
allowable costs.
Also, we are pursuing authorization at the FERC for 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. In May 2003, the FERC issued an order
denying MISO's request for authorization to reimburse us. In June 2003, we filed
a joint petition with MISO for rehearing with the FERC, which the FERC denied in
September 2003. We appealed the FERC ruling at the United States Court of
Appeals for the District of Columbia and are pursuing other potential means of
recovery at the FERC. In conjunction with our appeal of the September order
denying recovery, MISO agreed to file a request with the FERC seeking authority
to reimburse METC. As part of the contract for the sale of our former
transmission system, should the FERC approve the new MISO filing, METC is
contractually obligated to flow-through to us the full amount of any Alliance
RTO start-up costs that it is authorized to recover by FERC. We cannot predict
the outcome of the
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
appeal process, the MISO request, or the ultimate amount, if any, FERC will
allow us to collect for implementation 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 the remaining open items will
impact 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, transmission rates charged to us are fixed by
contract at current levels through December 31, 2005, and are subject to FERC
ratemaking thereafter. However, we are subject to certain additional MISO
surcharges, which are estimated to be $15 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
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.
Approximately 100,000 of our 1.7 million electric customers were without power
for approximately 24 hours as a result of the disturbance. We incurred $1
million of immediate expense as a result of the blackout. We continue to
cooperate with investigations of the blackout by several federal and state
agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan or actions taken
by the Michigan utilities or transmission operators were factors contributing to
the cause of the blackout. Also in November 2003, the United States and Canadian
power system outage task force preliminarily reported that the primary cause of
the blackout was due to transmission line contact with trees in areas outside of
Consumers' operating territory. 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. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to
improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2004. These recommendations could result in increased transmission costs payable
by transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC were in proposal status during 2002 and 2003. The
performance standards were placed into Michigan law in January 2004 and became
effective on February 9, 2004. They relate to restoration after an outage,
safety, and customer relations. During 2002 and 2003, Consumers monitored and
reported to the MPSC its 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 value of such
incentive cannot be determined at this point as the performance standards do not
contain an approved incentive mechanism. Financial penalties in the form of
customer credits are also possible. These customer credits are based on duration
and repetition of outages. We cannot predict the likely effects of the financial
incentive or penalties, if any, on us.
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 option 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 December 31, 2003, 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 $20 million for
unexpired capacity and energy contracts. Currently, we have a reserve margin of
5 percent, or supply resources equal to 105 percent of projected summer peak
load for summer 2004. We are in the process of securing the additional capacity
needed to meet our summer 2004 reserve margin target of 11 percent (111 percent
of projected summer peak load). The total premium costs of electricity call
option and capacity and energy contracts for 2003 were approximately $10
million.
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 cap, 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
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
steam to Dow. We hold, through two wholly owned subsidiaries, the following
assets related to the MCV Partnership and MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, and
- CMS Holdings holds, through FMLP, a 35 percent lessor interest in the MCV
Facility.
Our consolidated retained earnings include undistributed earnings from the
MCV Partnership, which at December 31, 2003 are $245 million and at December 31,
2002 are $226 million.
Summarized Statements of Income for CMS Midland and CMS Holdings
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Earnings from equity method investees....................... $42 $52 $38
Operating expenses, taxes and other......................... 22 18 13
--- --- ---
Income before cumulative effect of accounting change........ $20 $34 $25
Cumulative effect of change in method of accounting for
derivatives, net of $10 million tax expense in 2002 (Note
15)....................................................... -- 18 --
--- --- ---
Net income.................................................. $20 $52 $25
=== === ===
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 MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $27 million at December 31, 2003, $53 million at December 31,
2002, and $77 million at December 31, 2001. 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
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
MCV Facility's generating availability remains at the maximum 98.5 percent
level, our cash underrecoveries associated with the PPA could be as follows:
2004 2005 2006 2007
---- ---- ---- ----
IN MILLIONS
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 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 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 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 our equity interest in the MCV Partnership may be
affected negatively.
Under the PPA, variable energy payments to the MCV Partnership are based on
the cost of coal burned at our coal plants and 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 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 exercise 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 equity interest 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 equity
investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility on an economic basis depending 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. We requested that the MPSC provide
interim approval while it conducts a full review of the plan. The MPSC has
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
scheduled a prehearing conference with respect to the MCV resource conservation
plan for April 2004. We cannot predict if or when the MPSC will approve our
request.
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 our recovery of capacity
payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot
predict the impact of these issues on our future earnings, cash flows, or on the
value of our equity interest in the MCV Partnership.
NUCLEAR MATTERS: Big Rock: Significant progress continues to be made in the
decommissioning of Big Rock. We submitted the License Termination Plan to the
NRC staff for review in April 2003. System dismantlement and building demolition
are on schedule to return the 560-acre site to a natural setting for
unrestricted use in early 2006. The NRC and Michigan Department of Environmental
Quality continue to find that all decommissioning activities at Big Rock are
being performed in accordance with applicable regulatory and license
requirements.
Seven transportable dry casks have been loaded with spent nuclear fuel and
an eighth cask has been loaded with high-level radioactive waste material. These
dry casks will remain onsite until the DOE moves the material to a national
spent nuclear fuel repository.
Palisades: In July 2003, the NRC completed its mid-cycle plant performance
assessment of Palisades. The mid-cycle assessment for Palisades covered the
period from January 1, 2003 through the end of July 2003. The NRC determined
that Palisades was operated in a manner that preserved public health and safety
and fully met all cornerstone objectives. Based on the plant's performance, only
regularly scheduled inspections are planned through September 2004.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite
storage pool capacity. We are using dry casks for temporary onsite storage. As
of December 31, 2003, we have loaded 18 dry casks with spent nuclear fuel and we
will need to load additional dry casks by the fall of 2004 in order to continue
operation. Palisades currently has three empty dry casks onsite, with storage
pad capacity for up to seven additional loaded dry casks. We anticipate that
transportable dry casks, along with more storage pad capacity, will be available
by fall 2004.
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
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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.
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 $26 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 $10.862 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 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
from 2004 to 2005, and total an estimated $177 million. Our coal transportation
contracts expire from 2004 to 2007, and total an estimated $139 million.
Long-term coal supply contracts account for approximately 60 to 90 percent of
our annual coal requirements. In 2003, coal purchases totaled $265 million of
which $207 million (78 percent of the tonnage requirement) was under long-term
contract. We supplement our long-term contracts with spot-market purchases.
Power Supply, Capacity, and Transmission: As of December 31, 2003, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants including the MCV Facility. These
contracts require monthly capacity payments based on the plants' availability or
deliverability. These payments for 2004 through 2030 total an
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
estimated $14.483 billion, undiscounted, which includes $11.381 billion related
to the MCV Facility. These payments exclude the obligations that Consumers has
with the Genesee, Grayling, and Filer City generating plants because these
entities are consolidated for CMS Energy under FASB Interpretation No. 46. 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.
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 MPSC approved rates charged to our customers. As of
December 31, 2003, we have recorded a liability of $44 million, net of $38
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
February 2004, the parties in the case reached a tentative settlement agreement
that would result in a GCR disallowance of $11 million for the GCR period.
Interest on the disallowed amount from April 1, 2003 through February 2004, at
the Consumers' authorized rate of return, adds $1 million to the cost of the
settlement. We believe this settlement agreement will be executed by the parties
in the case in the near future and approved by the MPSC. A reserve was recorded
in December 2003.
CMS-72
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In July 2003, the MPSC approved a settlement agreement authorizing us to
increase our gas cost recovery for the remainder of the current GCR plan year
(August 2003 through March 2004) and to apply a quarterly ceiling price
adjustment, based on a formula that tracks changes in NYMEX natural gas prices.
The terms of the settlement allow a GCR ceiling price of $6.11 per mcf. Our GCR
is $5.36 per mcf for March 2004 bills.
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 its dividend payments to CMS
Energy, to a maximum of $190 million annually during the period that Consumers
receives 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. The MPSC is not bound by these
recommendations and will consider the issues anew after receipt of exceptions
and replies to the exception filed by the parties in response to the Proposal
for Decision.
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
independent of the 2003 gas rate case. 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.
OTHER CONSUMERS' GAS UTILITY UNCERTAINTIES
COMMITMENTS FOR GAS SUPPLIES: We enter into contracts to purchase gas and
gas transportation from various suppliers for our natural gas business. These
contracts have expiration dates that range from 2004 to 2007. Our 2003 gas
purchases totaled 248 bcf at a cost of $1.379 billion. At the end of 2003, we
estimate our gas purchases for 2004 to be 235 bcf, of which 22 percent is
covered by existing fixed price contracts and 37 percent is covered by indexed
price contracts that are subject to price variations. The remaining 2004 gas
purchases will be made at market prices at the time of purchase.
OTHER CONSUMERS' 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.
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
CMS-73
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 believes that Integrum's claims are without merit. CMS Energy will
defend itself vigorously but cannot predict the outcome of this lawsuit.
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 reached an agreement in principle with the U.S.
Coast Guard to settle this matter for $475,000.
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 CUSTOMER DISPUTES: As a result of the continued delays in the DIG
project becoming fully operational, DIG's customers, Ford Motor Company, and
Rouge Industries, asserted claims that the continued delays relieve them of
certain contractual obligations, totaling $43 million. In addition, Ford and/or
Rouge asserted several other commercial claims against DIG relating to operation
of the DIG plant. In February 2003, Rouge filed an Arbitration Demand against
DIG and CMS MST Michigan L.L.C. with the American Arbitration Association. Rouge
was seeking a total of approximately $27 million, plus additional accrued
damages at the time of any award, plus interest. More specifically, Rouge was
seeking at least $20 million under a Blast Furnace Gas Delivery Agreement in
connection with DIG's purported failure to declare a Blast Furnace Gas Delivery
Date within a reasonable time period, plus approximately $7 million for assorted
damage claims under several legal theories. As part of this arbitration, DIG
filed claims against Rouge and Ford, and Ford filed claims for unspecified
amounts against DIG. In October 2003, Rouge filed bankruptcy under Chapter 11 of
the United States Bankruptcy Code and as a result, the arbitration was subject
to the automatic stay imposed by the Bankruptcy Code. OAO Severstal, which has
acquired substantially all of Rouge's assets, has indicated it will continue
operations at the Rouge site and will honor the contractual obligations to pay
for the steam and electricity DIG and CMS MST Michigan L.L.C. provide. In
January 2004, DIG and CMS MST Michigan L.L.C. entered into a
CMS-74
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
settlement agreement with Ford and Rouge to resolve all outstanding claims
between the parties, including the arbitration claims and DIG and CMS MST
Michigan L.L.C.'s claims in the Rouge bankruptcy. The settlement was approved by
the bankruptcy court. Under the settlement, Ford paid DIG $12 million cash and
Rouge and Ford paid DIG and CMS MST Michigan L.L.C. a total of $3.8 million owed
by Rouge for steam and electricity supplied to Rouge prior to the filing of the
bankruptcy petition.
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 resident 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 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 will appeal this judgment.
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 December 31, 2003, 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 2.94 pesos per U.S. dollar was $264 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.
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
CMS-75
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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.
CMS-76
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5: FINANCINGS AND CAPITALIZATION
CMS Energy's Long-term debt as of December 31 follows:
INTEREST RATE (%) MATURITY 2003 2002
----------------- -------- ---- ----
IN MILLIONS
CMS ENERGY CORPORATION
Senior notes..................................... 6.750 2004 $ -- $ 287
7.625 2004 176 176
9.875 2007 468 468
8.900 2008 260 260
7.500 2009 409 409
7.750 2010 300 --
8.500 2011 300 300
8.375 2013 -- 150
3.375(a) 2023 150 --
------ ------
2,063 2,050
------ ------
General term notes:
Series D....................................... 6.938(b)(c) 2004-2008 65 94
Series E....................................... 7.788(b)(c) 2004-2009 139 227
Series F....................................... 7.487(b)(c) 2004-2016 292 298
------ ------
496 619
------ ------
Extendible tenor rate adjusted securities........ 7.000 2005 180 180
Revolving credit facilities and other............ 7 320
------ ------
Total -- CMS Energy Corporation............. 2,746 3,169
------ ------
CONSUMERS ENERGY COMPANY
First mortgage bonds............................. 4.250 2008 250 --
4.800 2009 200 --
4.000 2010 250 --
5.375 2013 375 --
6.000 2014 200 --
7.375 2023 208 208
------ ------
1,483 208
------ ------
Senior notes..................................... 6.000 2005 300 300
6.250 2006 332 332
6.375 2008 159 159
6.200 2008 -- 250
6.875 2018 180 180
6.500(d) 2018 141 141
6.500(e) 2028 142 142
------ ------
1,254 1,504
------ ------
Securitization bonds............................. 5.097(c) 2005-2015 426 453
Long-term bank debt.............................. Variable 2006-2009 200 328
Nuclear fuel disposal liability.................. (f) 139 138
Pollution control revenue bonds.................. Various 2010-2018 126 126
Other............................................ 4 8
------ ------
Total -- Consumers Energy Company........... 3,632 2,765
------ ------
OTHER SUBSIDIARIES................................. 191 84
------ ------
Total principal amount outstanding................. 6,569 6,018
Current amounts.................................. (509) (633)
Net unamortized discount......................... (40) (28)
------ ------
Total consolidated long-term debt.................. $6,020 $5,357
====== ======
-------------------------
(a) These notes are putable to CMS Energy by the note holders at par on July
15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the
holder's option into CMS Energy Common Stock at $10.671 per share under
certain circumstances, none of which currently are probable to occur. CMS
Energy intends to file a registration statement with the SEC by October 16,
2004, relating to the resale of the notes and the convertibility into
common stock.
CMS-77
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(b) $29 million Series D, $112 million Series E, and $104 million Series F have
been called and redeemed through February 15, 2004.
(c) Represents the weighted average interest rate at December 31, 2003.
(d) 2018 maturity is subject to successful remarketing by Consumers after June
15, 2005.
(e) Callable at par.
(f) Maturity date uncertain.
LONG-TERM DEBT -- RELATED PARTIES:
Long-term debt -- related parties as of December 31, 2003 follows:
DEBENTURE AND RELATED PARTY INTEREST RATE MATURITY 2003
--------------------------- ------------- -------- ----
IN MILLIONS
Convertible subordinated debentures, CMS Energy Trust I..... 7.75% 2027 $178
Subordinated deferrable interest notes, Consumers Power
Company Financing I....................................... 8.36% 2015 73
Subordinated deferrable interest notes, Consumers Energy
Company Financing II...................................... 8.20% 2027 124
Subordinated debentures, Consumers Energy Company Financing
III....................................................... 9.25% 2029 180
Subordinated debentures, Consumers Energy Company Financing
IV........................................................ 9.00% 2031 129
----
Total amount outstanding.................................... $684
====
DEBT ISSUANCES: The following is a summary of long-term debt issuances
during 2003:
PRINCIPAL USE OF
FACILITY TYPE (IN MILLIONS) ISSUE RATE ISSUE DATE MATURITY DATE PROCEEDS COLLATERAL
------------- ------------- ---------- ---------- ------------- -------- ----------
CMS ENERGY
Senior notes(a)...... $ 150 3.375% July 2003 July 2023 (c) Unsecured
Senior notes(b)...... 300 7.750% July 2003 August 2010 (c) Unsecured
CONSUMERS ENERGY
Term loan............ 140 LIBOR + March 2003 March 2009 GCP FMB(h)
475 bps
Term loan............ 150 LIBOR + March 2003 March 2006 GCP FMB(h)
450 bps (paid off)(f)
FMB(i)............... 375 5.375% April 2003 April 2013 (d) --
FMB(i)............... 250 4.250% April 2003 April 2008 (d) --
FMB(i)............... 250 4.000% May 2003 May 2010 (e) --
FMB(i)............... 200 4.800% August 2003 February 2009 (f) --
FMB(i)............... 200 6.000% August 2003 February 2014 (f) --
Term loan............ 60 LIBOR + November 2003 November 2006 (g) FMB(h)
135 bps
------
Total......... $2,075
======
-------------------------
(bps -- basis points), (GCP -- General corporate purposes)
(a) These notes are putable to CMS Energy by the note holders at par on July
15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the
holder's option into CMS Energy Common Stock at $10.671 per share under
certain circumstances, none of which currently are probable to occur. CMS
Energy intends to file a registration statement with the SEC by October 16,
2004, relating to the resale of the notes and the convertibility into
common stock.
CMS-78
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(b) CMS Energy intends to file a registration statement with the SEC by March
14, 2004, to permit note holders to exchange their securities for ones that
will be registered under the Securities Act of 1933.
(c) CMS Energy used the net proceeds to retire revolving debt and redeem a
portion of a 6.75 percent Senior note due January 2004.
(d) Consumers used the net proceeds to fund the maturity of a $250 million
bond, to fund a $32 million option call payment, and for general corporate
purposes.
(e) Consumers used the net proceeds to prepay a portion of a term loan that was
due to mature in July 2004.
(f) Consumers used the net proceeds to pay off a $150 million term loan, to pay
off $50 million balance on a term loan that was due to mature in July 2004,
and for general corporate purposes.
(g) Consumers used the net proceeds to purchase its headquarters building and
pay off the capital lease.
(h) Refer to "Regulatory Authorization for Financings" below for details about
Consumers' FERC debt authorization.
(i) Consumers filed a registration statement with the SEC in December 2003 to
permit holders of these FMBs to exchange their bonds for FMBs that are
registered under the Securities Act of 1933. The exchange offer was
completed on February 13, 2004.
DEBT MATURITIES: The aggregate annual maturities for long-term debt for the
next five years are:
PAYMENTS DUE DECEMBER 31
------------------------------------
2004 2005 2006 2007 2008
---- ---- ---- ---- ----
IN MILLIONS
Long-term debt.............................................. $509 $696 $490 $516 $987
DEBT COVENANT RESTRICTIONS: The indenture pursuant to our GTNs contains
certain provisions that can trigger a limitation on our consolidated
indebtedness. The limitation can be activated when our consolidated leverage
ratio, as defined in the indenture (essentially the ratio of consolidated debt
to consolidated capital), exceeds 0.75 to 1.0. At June 30 and September 30,
2003, our consolidated leverage ratio was 0.76 to 1.0. As a result, we were
subject to certain debt limitations. At December 31, 2003, the ratio was 0.72 to
1, and we were no longer subject to the debt limitations.
The indenture under which Senior notes are issued and certain other debt
agreements contain provisions requiring us to maintain interest coverage ratios,
and debt to earnings ratios. We were in compliance with these ratios, as
defined, at December 31, 2003.
CMS ENERGY CREDIT FACILITY: CMS Energy has a $185 million revolving credit
facility with banks. This facility matures on May 21, 2005. This facility
provides letter of credit support for Enterprises' subsidiary activities,
principally credit support for project debt. Enterprises provides funds to cash
collateralize the letters of credit issued through this facility. As of December
31, 2003, approximately $165 million of letters of credit were issued under this
facility and the cash used to collateralize the letters of credit is included on
the Consolidated Balance Sheet as Restricted cash.
REGULATORY AUTHORIZATION FOR FINANCINGS: At December 31, 2003, 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 December 31, 2003, 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.
CMS-79
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
With the granting of authorization, FERC waived its competitive
bid/negotiated placement requirements applicable to the long-term securities
authorization. The authorizations expire on June 30, 2004.
SHORT-TERM FINANCINGS: CMS Energy has a $190 million revolving credit
facility with banks. The facility is secured by our investment in Enterprises
and Consumers. The interest rate of the facility is LIBOR plus 325 basis points.
This facility expires in November 2004. At December 31, 2003, all of the $190
million is available.
Consumers has a $400 million revolving credit facility with banks. The
facility is secured with first mortgage bonds. The interest rate of the facility
is LIBOR plus 175 basis points. This facility expires in March 2004 with two
annual extensions at Consumers' option, which would extend the maturity to March
2006. At December 31, 2003, $390 million is available for general corporate
purposes, working capital, and letters of credit.
At December 31, 2002, Consumers had $457 million of bank notes outstanding
at a weighted average interest rate of 4.50 percent.
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.
POLLUTION CONTROL REVENUE BONDS: In January 2004, Consumers amended the
PCRB indentures to add an auction rate interest mode and switched to that mode
for the two floating rate bonds. Under the auction rate mode, the bonds'
interest rate will be reset every 35 days. While in the auction rate mode, no
letter of credit liquidity facility is required and investors do not have a put
right.
PREFERRED STOCK ISSUANCE: In December 2003, CMS Energy issued 5 million
shares of 4.50 percent cumulative convertible preferred stock. Each share has a
liquidation value of $50.00 and is convertible into CMS Energy common stock at
the option of the holder under certain circumstances. The initial conversion
price is $9.893 per share, which translates into 5.0541 shares of common stock
for each share of preferred stock converted. The annual dividend of $2.25 per
share is payable quarterly, in cash, in arrears commencing March 1, 2004. We
used the net proceeds of $242 million to retire other long-term debt in January
2004 and February 2004. We have agreed to file a shelf registration with the SEC
by November 5, 2004, covering resales of the preferred stock and of common stock
issuable upon conversion of the preferred stock.
SALE OF SUBSIDIARY INTEREST: In December 2003, we sold, in a private
placement, a non-voting preferred interest in an indirect subsidiary of CMS
Enterprises that owns certain gas pipeline and power generation assets. CMS
Energy received $30 million for the preferred interest, of which $19 million has
been recorded as an addition to other paid-in capital (deferred gain) and $11
million has been recorded as a preferred stock issuance.
WARRANTS: We granted warrants to purchase 204,000 shares of our common
stock to a third party and expensed $1 million in 2003. The warrants which are
fully vested are exercisable for seven years at an exercise price of $8.25 per
share.
CAPITALIZATION: The authorized capital stock of CMS Energy consists of 250
million shares of CMS Energy Common Stock and 10 million shares of CMS Energy
Preferred Stock, $.01 par value.
CMS-80
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PREFERRED STOCK OF SUBSIDIARY: The follow table describes Consumers'
Preferred Stock outstanding:
OPTIONAL NUMBER OF SHARES
REDEMPTION -----------------
DECEMBER 31 SERIES PRICE 2003 2002 2003 2002
----------- ------ ---------- ---- ---- ---- ----
IN MILLIONS
PREFERRED STOCK
Cumulative, $100 par value, authorized
7,500,000 shares, with no mandatory
redemption.............................. $4.16 $103.25 68,451 68,451 $ 7 $ 7
4.50 110.00 373,148 373,148 37 37
--- ---
TOTAL PREFERRED STOCK........................ $44 $44
=== ===
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARIES: CMS Energy and Consumers each formed various statutory wholly
owned business trusts for the sole purpose of issuing preferred securities and
lending the gross proceeds to the parent companies. The sole assets of the
trusts are debentures of the parent company with terms similar to those of the
preferred security. Summarized information for company-obligated mandatorily
redeemable preferred securities is as follows:
AMOUNT
OUTSTANDING EARLIEST
TRUST AND SECURITIES --------------- OPTIONAL
DECEMBER 31 RATE 2003 2002 MATURITY REDEMPTION(B)
-------------------- ---- ---- ---- -------- -------------
IN MILLIONS
CMS Energy Trust I(c)............................. 7.75% $ --(a) $173 2027 2001
CMS Energy Trust III.............................. 7.25% --(d) 220 2004 2003
Consumers Power Company Financing I, Trust
Originated Preferred Securities................. 8.36% --(a) 70 2015 2000
Consumers Energy Company Financing II, Trust
Originated Preferred Securities................. 8.20% --(a) 120 2027 2002
Consumers Energy Company Financing III, Trust
Originated Preferred Securities................. 9.25% --(a) 175 2029 2004
Consumers Energy Company Financing IV, Trust
Preferred Securities............................ 9.00% --(a) 125 2031 2006
----- ----
Total amount outstanding.......................... $ -- $883
===== ====
-------------------------
(a) We determined that we do not hold the controlling financial interest in 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. For additional details, see "Long-Term
Debt -- Related Parties" within this Note and Note 17, Implementation of
New Accounting Standards.
(b) The trusts must redeem the securities at a liquidation value of $25 per
share ($50 per share for QUIPS (c)), which is equivalent to the carrying
cost, plus accrued but unpaid distributions when the securities are paid at
maturity or upon any earlier redemption. Prior to an early redemption date,
the securities could be redeemed at market value.
(c) Represents 3,450,000 shares of Quarterly Income Preferred Securities
(QUIPS) that are convertible into 1.2255 shares of CMS Energy Common Stock
(equivalent to a conversion price of $40.80). Conversion is unlikely as of
December 31, 2003, based on the market price of CMS Energy's Common Stock
of $8.52. If conversion were to occur in the future, the securities would
be converted into 4,227,975 shares of CMS Energy Common Stock. Effective
July 2001, we can revoke the conversion rights if certain conditions are
met.
CMS-81
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(d) In August 2003, 8,800,000 units of outstanding 7.25 percent Premium Equity
Participating Security Units (CMS Energy Trust III) were converted to
16,643,440 newly issued shares of CMS Energy Common Stock.
Each trust receives payments on the debenture it holds. Those receipts are
used to make cash distributions on the preferred securities the trust has
issued.
The securities allow CMS Energy and Consumers the right to defer interest
payment on the debentures, and, as a consequence, the trusts would defer
dividend payments on the preferred securities. Should the parent companies
exercise this right, they cannot declare or pay dividends on, or redeem,
purchase or acquire, any of their capital stock during the deferral period until
all deferred dividends are paid in full.
In the event of default, holders of the preferred securities would be
entitled to exercise and enforce the trusts' creditor rights against CMS Energy
and Consumers, which may include acceleration of the principal amount due on the
debentures. The parent companies have issued certain guarantees with respect to
payments on the preferred securities. These guarantees, when taken together with
each parent company's obligations under the debentures, related indenture and
trust documents, provide full and unconditional guarantees for the trust's
obligations under the preferred securities.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. The amounts sold were $297 million at December 31, 2003 and $325
million at December 31, 2002. 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:
YEARS ENDED
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Proceeds from sales (remittance of collections) under the
program................................................... $ (28) $ (9)
Collections reinvested under the program.................... 4,361 4,080
DIVIDEND RESTRICTIONS: Under the provisions of its articles of
incorporation, at December 31, 2003, Consumers had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in
Consumers' debt facilities cap common stock dividend payments at $300 million in
a calendar year. Through December 31, 2003, we received the following common
stock dividend payments from Consumers:
IN MILLIONS
January..................................................... $ 78
May......................................................... 31
June........................................................ 53
November.................................................... 56
----
Total common stock dividends paid to CMS Energy............. $218
====
As of December 18, 2003, Consumers is also under an annual dividend cap of
$190 million imposed by the MPSC during the current interim gas rate relief
period. Because all of the $218 million of common stock dividends to CMS Energy
were paid prior to December 18, 2003, Consumers was not out of compliance with
this new restriction for 2003. In February 2004, Consumers paid a $78 million
common stock dividend.
CMS-82
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order, see Note 4, Uncertainties,
"Consumers' Electric Utility Rate Matters -- Securitization." Also, for
additional details on the cap on common dividends payable during the current
interim gas rate relief period, see Note 4, 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 describe our guarantees at December 31, 2003:
ISSUE EXPIRATION MAXIMUM CARRYING RECOURSE
GUARANTEE DESCRIPTION DATE DATE OBLIGATION AMOUNT(B) PROVISION(C)
--------------------- ----- ---------- ---------- --------- ------------
IN MILLIONS
Indemnifications from asset sales and other
agreements(a)............................ Various Various $1,955 $ 3 $--
Letters of credit.......................... Various Various 254 -- --
Surety bonds and other indemnifications.... Various Various 28 -- --
Other guarantees........................... Various Various 239 -- --
Nuclear insurance retrospective premiums... Various Various 133 -- --
-------------------------
(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. Included in this amount is a $739 million
indemnification obligation related to the sale of CMS Oil and Gas
facilities in Equatorial Guinea which expired January 3, 2004, and for
which no loss occurred. 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. In addition, $25 million has been recorded prior to 2003
in accordance with SFAS No. 5.
(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
The following table provides additional information regarding our
guarantees at December 31, 2003:
EVENTS THAT WOULD
GUARANTEE DESCRIPTION HOW GUARANTEE AROSE REQUIRE PERFORMANCE
--------------------- ------------------- -------------------
Indemnifications from asset Stock and asset sales Findings of
sales and other agreements agreements misrepresentation, breach
of warranties, and other
specific events or
circumstances
Standby letters of credit Normal operations of coal Noncompliance with
power plants environmental regulations
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, Nonperformance
permits and license
Nuclear insurance Normal operations of nuclear Call by NEIL and Price
retrospective premiums plants Anderson Act for nuclear
incident
CMS-83
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 $521 million as of December 31, 2003. 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:
COMMITMENT EXPIRATION
-------------------------------------------------------
DECEMBER 31 TOTAL 2004 2005 2006 2007 2008 BEYOND
----------- ----- ---- ---- ---- ---- ---- ------
IN MILLIONS
COMMERCIAL COMMITMENTS
Off-balance sheet:
Guarantees..................................... $239 $ 20 $36 $4 $-- $-- $179
Indemnities.................................... 28 8 -- -- -- -- 20
Letters of Credit(a)........................... 254 215 10 5 5 5 14
---- ---- --- -- --- --- ----
Total..................................... $521 $243 $46 $9 $ 5 $ 5 $213
==== ==== === == === === ====
-------------------------
(a) At December 31, 2003, we had $175 million of cash collateralized letters of
credit and the cash used to collateralize the letters of credit is included
in Restricted cash on the Consolidated Balance Sheets.
6: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share
computations.
YEAR ENDED DECEMBER 31
------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS,
EXCEPT PER SHARE AMOUNTS
NET LOSS ATTRIBUTABLE TO COMMON STOCK:
CMS Energy -- Basic....................................... $ (44) $ (650) $ (459)
Add conversion of Trust Preferred Securities (net of
tax)................................................... --(a) --(a) --(a)
------ ------ ------
CMS Energy -- Diluted..................................... $ (44) $ (650) $ (459)
====== ====== ======
AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND
DILUTED EPS
CMS Energy:
Average Shares -- Basic................................ 150.4 139.0 130.7
Add conversion of Trust Preferred Securities........... --(a) --(a) --(a)
Stock Options and Warrants............................. --(b) -- --(b)
------ ------ ------
Average Shares -- Diluted.............................. 150.4 139.0 130.7
====== ====== ======
LOSS PER AVERAGE COMMON SHARE
Basic..................................................... $(0.30) $(4.68) $(3.51)
Diluted................................................... $(0.30) $(4.68) $(3.51)
-------------------------
(a) Due to antidilution, the computation of diluted earnings per share excluded
the conversion of Trust Preferred Securities.
(b) Due to antidilution, the computation of diluted earnings per share excluded
shares of outstanding stock options and warrants of 0.3 million for the
year ended 2003 and 0.2 million for the year ended 2001.
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In January 2003, the Board of Directors suspended the payment of common
stock dividends. However, in 2002, we paid the following dividends per share:
CMS ENERGY COMMON STOCK
DIVIDENDS PER SHARE PAYOUT
--------------------------
February.................................................... $0.365
April....................................................... $0.365
August...................................................... $0.180
November.................................................... $0.180
7: 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 investments
based on quoted market prices or, in the absence of specific market prices, on
quoted market prices of similar investments or other valuation techniques. The
carrying amount of all long-term financial instruments, except as shown below,
approximate fair value. For additional details, see Note 1, Corporate Structure
and Accounting Policies.
DECEMBER 31
-----------------------------------------------------------------
2003 2002
------------------------------- ------------------------------
FAIR UNREALIZED FAIR UNREALIZED
COST VALUE GAIN (LOSS) COST VALUE GAIN
---- ----- ----------- ---- ----- ----------
IN MILLIONS
Long-term debt(a)....................... $6,020 $6,225 $(205) $5,357 $5,027 $330
Long-term debt -- related parties(b).... 684 648 36 -- -- --
Trust Preferred Securities(b)........... -- -- -- 883 704 179
Available for sale securities:
Nuclear decommissioning(c).............. 442 575 133 458 536 78
SERP.................................... 54 66 12 54 57 3
-------------------------
(a) Settlement of long-term debt is generally not expected until maturity.
(b) We determined that we do not hold the controlling financial interest in 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, refer to Note 5, Financings and Capitalization,
"Long-Term Debt -- Related Parties" and Note 17, 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.
CMS-85
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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. 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:
DECEMBER 31
------------------------------------------------------------
2003 2002
---------------------------- ----------------------------
FAIR UNREALIZED FAIR UNREALIZED
DERIVATIVE INSTRUMENTS COST VALUE GAIN (LOSS) COST VALUE GAIN (LOSS)
---------------------- ---- ----- ----------- ---- ----- -----------
IN MILLIONS
Other than trading
Electric -- related contracts................ $-- $ -- $ -- $ 8 $ 1 $ (7)
Gas contracts................................ 3 2 (1) -- 1 1
Interest rate risk contracts................. -- (3) (3) -- (28) (28)
Derivative contracts associated with equity
investments in:
Shuweihat.................................... -- (27) (27) -- (30) (30)
Taweelah..................................... -- (26) (26) -- (33) (33)
MCV Partnership.............................. -- 15 15 -- 13 13
Jorf Lasfar.................................. -- (11) (11) -- (11) (11)
Other........................................ -- 1 1 -- (2) (2)
Trading
Electric -- related contracts................ (2) -- 2 -- 43 43
Gas contracts................................ -- 15 15 -- 38 38
CMS-86
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The fair value of other than trading derivative contracts is included in
either Other Assets or Other Liabilities 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 investment in the MCV Partnership is included in Investments -- Midland
Cogeneration Venture Limited Partnership on the Consolidated Balance Sheets.
Effective April 1, 2002, the MCV Partnership changed its accounting for
derivatives. For additional details see Note 15, Summarized Financial
Information of Significant Related Energy Supplier. The fair value of derivative
contracts associated with other equity investments is included in Enterprises
Investments on the Consolidated Balance Sheets.
Cumulative Effect of Change in Accounting Principle: On January 1, 2001,
upon initial adoption of the derivatives standard, we recorded a $10 million,
net of tax, cumulative effect adjustment as an increase in accumulated other
comprehensive income. This adjustment relates to the difference between the fair
value and recorded book value of contracts related to gas call options, gas fuel
for generation swap contracts, and interest rate swap contracts that qualified
for hedge accounting prior to the initial adoption of SFAS No. 133 and our
proportionate share of the effects of adopting SFAS No. 133 related to our
equity investments in the MCV Partnership and Taweelah. Based on the initial
transition adjustment of $21 million, net of tax, recorded in accumulated other
comprehensive income at January 1, 2001, Consumers reclassified to earnings $12
million as a reduction to the cost of gas, $1 million as a reduction to the cost
of power supply, $2 million as an increase in interest expense, and $8 million
as an increase in other revenues for the twelve months ended December 31, 2001.
CMS Energy recorded $12 million as an increase in interest expense during 2001,
which includes the $2 million of additional interest expense at Consumers. The
difference between the initial transition adjustment and the amounts
reclassified to earnings represents an unrealized loss in the fair value of the
derivative instruments since January 1, 2001, resulting in a decrease of
accumulated other comprehensive income. We also recorded a $7 million, net of
tax, cumulative effect adjustment as an increase to earnings. This adjustment
relates to our proportionate share of the difference between the fair value and
the recorded book value of interest rate swaps at Taweelah, and financial gas
and supply contracts that were required to be accounted for as derivatives as of
January 1, 2001.
In June and December 2001, the FASB issued guidance that resolved the
accounting for certain utility industry contracts. As a result, we recorded a $3
million, net of tax, cumulative effect adjustment as an unrealized loss,
decreasing accumulated other comprehensive income, and on December 31, 2001,
recorded an $11 million, net of tax, cumulative effect adjustment as a decrease
to earnings. These adjustments relate to the difference between the fair value
and the recorded book value of certain electric call option contracts.
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. For additional details regarding this loss see
Note 17, Implementation of New Accounting Standards.
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.
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, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA,
could be material to the financial statements.
CMS-87
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Our electric business also uses gas option and swap contracts to protect
against price risk due to the fluctuations in the market price of gas used as
fuel for generation of electricity. These contracts are financial contracts that
are used to offset increases in the price of potential gas purchases. These
contracts do not qualify for hedge accounting. Therefore, we record any change
in the fair value of these contracts directly in earnings as part of power
supply costs.
For the year ended December 31, 2003, the unrealized gain in accumulated
other comprehensive income related to our proportionate share of the effects of
derivative accounting related to our equity investment in the MCV Partnership is
$10 million, net of tax. We expect to reclassify this gain, if this value
remains, as an increase to earnings from equity method investees during the next
12 months.
GAS CONTRACTS: Our gas utility business uses fixed price 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.
ENERGY TRADING ACTIVITIES: Through December 31, 2002, CMS MST's wholesale
power and gas trading activities were accounted for under the mark-to-market
method of accounting. Under mark-to-market accounting, energy-trading contracts
are reflected at fair market value, net of reserves, with unrealized gains and
losses recorded as an asset or liability in the Consolidated Balance Sheets.
These assets and liabilities are affected by the timing of settlements related
to these contracts, current-period changes from newly originated transactions
and the impact of price movements. Changes in fair value are recognized as
revenues in the Consolidated Statements of Income in the period in which the
changes occur. 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 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
CMS-88
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 at year end:
FLOATING TO FIXED NOTIONAL MATURITY FAIR
INTEREST RATE SWAPS AMOUNT DATE VALUE
------------------- -------- -------- -----
IN MILLIONS
December 31, 2003........................................... $ 28 2005-2006 $ (3)
December 31, 2002........................................... 493 2003-2007 (28)
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 7.4 percent at December 31, 2003 and 4.0 percent at December 31,
2002.
Certain equity method investees have issued interest rate swaps. These
instruments are not included in this analysis, but can have an impact on
financial results. See discussion of these instruments in Note 18, Restatement
and Reclassification.
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.
There were no outstanding foreign exchange contracts at December 31, 2003.
The notional amount of the outstanding foreign exchange contracts at December
31, 2002 was $1 million Canadian. The estimated fair value of the foreign
exchange and option contracts at December 31, 2002 was zero.
8: INCOME TAXES
CMS Energy and its subsidiaries file a consolidated federal income tax
return. Income taxes generally are allocated based on each company's separate
taxable income. We practice deferred tax accounting for temporary differences in
accordance with SFAS No. 109, Accounting for Income Taxes.
U.S. income taxes are not recorded on the undistributed earnings of foreign
subsidiaries that have been or are intended to be reinvested indefinitely. Upon
distribution, those earnings may be subject to both U.S. income taxes (adjusted
for foreign tax credits or deductions) and withholding taxes payable to various
foreign countries. We annually determine the amount of undistributed foreign
earnings that we expect will remain invested indefinitely in foreign
subsidiaries. Cumulative undistributed earnings of foreign subsidiaries for
which income taxes have not been provided totaled approximately $106 million at
December 31, 2003. It is impractical to estimate the amount of unrecognized
deferred income taxes or withholding taxes on these undistributed earnings.
Also, at December 31, 2003 and 2002, we recorded U.S. income taxes with respect
to temporary differences between the book and tax bases of foreign investments
that were determined to be no longer essentially permanent in duration.
The Job Creation and Worker Assistance Act of 2002 provided corporate
taxpayers a 5-year carryback of tax losses incurred in 2001 and 2002. As a
result of this legislation, we carried back consolidated 2001 and 2002 tax
losses to tax years 1996 through 1999 to obtain refunds totaling $250 million.
The tax loss carryback, however, resulted in a reduction in AMT credit
carryforwards that previously had been recorded as deferred tax assets in the
amount of $47 million. This non-cash reduction in AMT credit carryforwards was
reflected in our tax provision in 2002.
CMS-89
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
We use ITC to reduce current income taxes payable, and amortize ITC over
the life of the related property. AMT paid generally becomes a tax credit that
we can carry forward indefinitely to reduce regular tax liabilities in future
periods when regular taxes paid exceed the tax calculated for AMT. At December
31, 2003, we had AMT credit carryforwards in the amount of $214 million that do
not expire, tax loss carryforwards in the amount of $1.151 billion that expire
from 2021 through 2023. In addition, we had capital loss carryforwards in the
amount of $29 million that expire in 2007, and general business credit
carryforwards in the amount of $42 million that primarily expire in 2005, for
which valuation allowances have been provided.
During the fourth quarter of 2000, we wrote down the value of our
investment in Loy Yang by $329 million ($268 million after-tax). We have now
concluded the tax benefit associated with the write-down should have been
reduced by $38 million. Accordingly, retained earnings as of January 1, 2001
have been reduced by this amount. For additional details, see Note 18,
Restatement and Reclassification.
The significant components of income tax expense (benefit) on continuing
operations consisted of:
YEARS ENDED DECEMBER 31
-----------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Current income taxes:
Federal................................................... $ (17) $(171) $(209)
State and local........................................... 1 (8) 6
Foreign................................................... 17 28 8
----- ----- -----
$ 1 $(151) $(195)
Deferred income taxes
Federal................................................... $ 54 $ 107 $ 97
State..................................................... 4 7 3
Foreign................................................... 5 2 8
----- ----- -----
$ 63 $ 116 $ 108
Deferred ITC, net........................................... (6) (6) (7)
----- ----- -----
Tax expense (benefit)....................................... $ 58 $ (41) $ (94)
===== ===== =====
CMS-90
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The principal components of deferred tax assets (liabilities) recognized in
the consolidated balance sheet are as follows:
DECEMBER 31
-------------------
RESTATED
2003 2002
---- --------
IN MILLIONS
Property.................................................... $ (842) $ (814)
Securitization costs........................................ (186) (192)
Prepaid pension............................................. (136) --
Unconsolidated investments.................................. (254) 55
Postretirement benefits..................................... (70) (72)
Gas inventories............................................. (100) (74)
Employee benefit obligations................................ 130 265
Tax credit carryforwards.................................... 255 247
Tax loss carryforwards...................................... 413 190
Valuation allowances........................................ (54) (4)
Regulatory liabilities...................................... 120 115
Other, net.................................................. 82 (169)
------- -------
Net deferred tax liabilities.............................. $ (642) $ (453)
======= =======
Deferred tax liabilities.................................... $(1,581) $(1,339)
Deferred tax assets, net of valuation reserves.............. 939 886
------- -------
Net deferred tax liabilities.............................. $ (642) $ (453)
======= =======
CMS-91
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The actual income tax expense (benefit) on continuing operations differs
from the amount computed by applying the statutory federal tax rate of 35
percent to income before income taxes as follows:
YEARS ENDED DECEMBER 31
----------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Income (loss) from continuing operations before income taxes
and minority interests
Domestic.................................................. $(73) $(527) $(320)
Foreign................................................... 88 94 (108)
---- ----- -----
Total................................................ 15 (433) (428)
Statutory federal income tax rate........................... x 35% x 35% x 35%
---- ----- -----
Expected income tax expense (benefit)....................... 5 (152) (150)
Increase (decrease) in taxes from:
Property differences...................................... 18 18 23
Income tax effect of foreign investments.................. (18) 47 52
Tax credits............................................... (6) 51 (8)
State and local income taxes, net of federal benefit...... -- (7) 3
Tax return accrual adjustments............................ (1) (7) (4)
Minority interests........................................ -- (5) (9)
Valuation allowance provision (reversal).................. 50 -- (1)
Other, net................................................ 10 14 --
---- ----- -----
Recorded income tax expense (benefit)(a).................... $ 58 $ (41) $ (94)
---- ----- -----
Effective tax rate(b)....................................... (b) 9.5% 22.0%
==== ===== =====
-------------------------
(a) The increased income tax expense for 2003 is primarily attributable to the
valuation reserve provisions for the possible loss of general business
credit, capital loss, and charitable contributions carryforwards.
(b) Because of the small size of the net income in 2003, the effective tax rate
is not meaningful. Changes in the effective tax rate in 2002 from 2001
resulted principally from the reduction in AMT credit carryforwards and the
recording of U.S. taxes on undistributed earnings and basis differences of
foreign subsidiaries.
9: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan to key management employees
based on their contributions to the successful management of the Company. The
Plan includes the following type of awards for common stock:
- restricted shares of common stock,
- stock options, and
- stock appreciation rights.
Restricted shares of common stock are outstanding shares with full voting
and dividend rights. These awards vest over five years at the rate of 25 percent
per year after two years. Some restricted shares are subject to achievement of
specified levels of total shareholder return and are subject to forfeiture if
employment terminates before vesting. Restricted shares vest fully if control of
CMS Energy changes, as defined by the plan.
Stock options give the holder the right to purchase common stock at a given
price over an extended period of time. Stock appreciation rights give the holder
the right to receive common stock appreciation, which is defined
CMS-92
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
as the excess of the market price of the stock at the date of exercise over the
grant date price. Our stock options and stock appreciation rights are valued at
market price when granted. All options and rights may be exercised upon grant
and they expire up to ten years and one month from the date of grant.
Our Performance Incentive Stock Plan was amended in January 1999. It uses
the following formula to grant awards:
- Up to five percent of our common stock outstanding at January 1 each year
less:
+ the number of shares of restricted common stock awarded, and
+ common stock subject to options granted under the plan during the
immediately preceding four calendar years.
- the number of shares of restricted common stock awarded under this plan
cannot exceed 20 percent of the aggregate number of shares reserved for
awards, and
- forfeiture of shares previously awarded will increase the number of
shares available to be awarded under the plan.
Awards of up to 2,240,247 shares of CMS Energy Common Stock may be issued
as of December 31, 2003.
The following table summarizes the restricted stock and stock options
granted to our key employees under the Performance Incentive Stock Plan:
RESTRICTED
STOCK OPTIONS
---------- -----------------------------
NUMBER OF NUMBER OF WEIGHTED AVERAGE
SHARES SHARES EXERCISE PRICE
--------- --------- ----------------
CMS ENERGY COMMON STOCK
Outstanding at January 1, 2001.......................... 786,427 3,058,186 $31.47
Granted............................................... 266,500 1,036,000 $30.21
Exercised or Issued................................... (82,765) (150,174) $19.11
Forfeited or Expired.................................. (182,177) (31,832) $35.10
--------- --------- ------
Outstanding at December 31, 2001........................ 787,985 3,912,180 $31.58
Granted............................................... 512,726 1,492,200 $15.64
Exercised or Issued................................... (116,562) (39,600) $17.07
Forfeited or Expired.................................. (225,823) (243,160) $28.91
--------- --------- ------
Outstanding at December 31, 2002........................ 958,326 5,121,620 $27.18
Granted............................................... 600,000 1,593,000 $ 6.35
Exercised or Issued................................... (80,425) (8,000) $ 8.12
Forfeited or Expired.................................. (213,873) (885,044) $28.66
--------- --------- ------
Outstanding at December 31, 2003........................ 1,264,028 5,821,576 $21.27
========= ========= ======
At December 31, 2003, 186,522 of the 1,264,028 shares of restricted common
stock outstanding are subject to performance objectives. Compensation expense
included in income for restricted stock was $2 million for 2003, less than $1
million in 2002, and $1 million in 2001.
CMS-93
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes our stock options outstanding at December
31, 2003:
NUMBER OF
SHARES WEIGHTED AVERAGE WEIGHTED AVERAGE
OUTSTANDING REMAINING LIFE EXERCISE PRICE
----------- ---------------- ----------------
Range of Exercise Prices
CMS ENERGY COMMON STOCK:
$6.35 -- $6.35..................................... 1,593,000 9.72 years $ 6.35
$8.12 -- $22.00.................................... 1,184,300 6.94 years $13.43
$22.20 -- $31.04................................... 1,785,772 6.65 years $27.06
$34.80 -- $43.38................................... 1,255,504 4.92 years $39.31
$44.06 -- $44.06................................... 3,000 4.91 years $44.06
--------- ---------- ------
$6.35 -- $44.06.................................... 5,821,576 7.17 years $21.27
The number of stock options exercisable was 5,795,145 at December 31, 2003,
5,007,329 at December 31, 2002 and 3,760,883 at December 31, 2001.
In December 2002, we adopted the fair value based method of accounting for
stock-based employee compensation, under SFAS No. 123, as amended by SFAS No.
148. We elected to adopt the prospective method recognition provisions of this
Statement, which applies the recognition provisions to all awards granted,
modified, or settled after the beginning of the fiscal year that the recognition
provisions are first applied.
The following table summarizes the weighted average fair value of stock
options granted:
OPTIONS GRANT DATE 2003 2002(A) 2001
------------------ ---- ------- ----
Fair value at grant date.................................... $2.96 $3.84, $1.44 $6.43
-------------------------
(a) For 2002, there were two stock option grants.
The stock options fair value is estimated using the Black-Scholes model, a
mathematical formula used to value options traded on securities exchanges. The
following assumptions were used in the Black-Scholes model:
YEARS ENDED DECEMBER 31 2003 2002(A) 2001
----------------------- ---- ------- ----
CMS ENERGY COMMON STOCK OPTIONS
Risk-free interest rate.............................. 3.02% 3.95%, 3.16% 4.77%
Expected stock price volatility...................... 55.46% 32.44%, 40.81% 30.59%
Expected dividend rate............................... -- $0.365, $0.1825 $0.365
Expected option life (years)......................... 4.2 4.2 4.2 4.2
-------------------------
(a) For 2002, there were two stock option grants.
CMS-94
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
We recorded $5 million as stock-based employee compensation cost for 2003
and $4 million for 2002. All stock options vest at date of grant. If stock-based
compensation costs had been determined under SFAS No. 123 for the year ended
December 31, 2001, consolidated net loss and pro forma net loss would have been
as follows:
YEARS ENDED DECEMBER 31
-----------------------------
RESTATED 2001
-----------------------------
NET LOSS BASIC DILUTED
-------- ----- -------
IN MILLIONS,
EXCEPT PER SHARE AMOUNTS
Net loss, as reported....................................... $(459) $(3.51) $(3.51)
Add: Stock-based employee compensation expense included in
reported net loss, net of related taxes................ -- -- --
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all
awards, net of related taxes........................... (4) (0.03) (0.03)
----- ------ ------
Pro forma net loss.......................................... $(463) $(3.54) $(3.54)
===== ====== ======
10: 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 all of our employees, and
the employees of our subsidiaries, including Panhandle. The Pension Plan's
assets are not distinguishable by company.
In June 2003, we sold Panhandle to Southern Union Panhandle Corp. No
portion of the Pension Plan assets were transferred with the sale and Panhandle
employees are no longer eligible to accrue additional benefits. The Pension Plan
retained pension payment obligations for Panhandle employees that were vested
under the Pension Plan.
The sale of Panhandle resulted in a significant change in the makeup of the
Pension Plan. A remeasurement of the obligation was required at the date of
sale. The remeasurement further resulted in the following:
- an increase in OPEB expense of $4 million for 2003, and
- an additional charge to accumulated other comprehensive income of $34
million ($22 million after-tax) as a result of the increase in the
additional minimum pension liability. Due to large contributions, the
additional minimum pension liability was eliminated as of December 31,
2003.
Additionally, a significant number of Panhandle employees elected to retire
as of July 1, 2003 under the CMS Energy Employee Pension Plan. As a result, we
have recorded a $25 million ($16 million after-tax) settlement loss, and a $10
million ($7 million after-tax) curtailment gain, pursuant to the provisions of
SFAS No. 88, which is reflected in discontinued operations.
In 2003, a substantial number of non-Panhandle retiring employees also
elected a lump sum payment instead of receiving pension benefits as an annuity
over time. Lump sum payments constitute a settlement under SFAS
CMS-95
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
No. 88. A settlement loss must be recognized when the cost of all settlements
paid during the year exceeds the sum of the service and interest costs for that
year. We recorded settlement loss of $59 million ($39 million after-tax) in
December 2003.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not
a qualified plan under the Internal Revenue Code; SERP trust earnings are
taxable and trust assets are included in consolidated assets. Trust assets were
$66 million at December 31, 2003, and $57 million at December 31, 2002. The
assets are classified as other non-current assets. The Accumulated Benefit
Obligation for SERP was $62 million at December 31, 2003 and $54 million at
December 31, 2002.
OPEB: Retiree health care costs at December 31, 2003 are based on the
assumption that costs would increase 8.5 percent in 2003. The rate of increase
is expected to be 7.5 percent for 2004. The rate of increase is expected to slow
to an estimated 5.5 percent by 2010 and thereafter.
The health care cost trend rate assumption significantly affects the
estimated costs recorded. A one-percentage point change in the assumed health
care cost trend assumption would have the following effects:
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
IN MILLIONS
Effect on total service and interest cost component......... $ 15 $ (12)
Effect on postretirement benefit obligation................. $149 $(129)
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
(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.
EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select group of management, or other highly
compensated employees. Terms of the plan may include payment of a lump sum,
payment of monthly benefits for life, payment of premium for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. EISP expense was $1 million in 2003 and $2 million in 2002.
As of December 31, 2003, the Accumulated Benefit Obligation of the EISP was $3
million.
The measurement date for all plans is December 31.
Assumptions: The following table recaps the weighted-average assumptions
used in our retirement benefits plans to determine benefit obligations and net
periodic benefit cost:
YEARS ENDED DECEMBER 31
--------------------------------------------------
PENSION & SERP OPEB
----------------------- -----------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
Discount rate................................. 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%
Expected long-term rate of return on plan
assets(a)................................... 8.75% 8.75% 9.75%
Union....................................... 8.75% 8.75% 9.75%
Non-Union................................... 6.00% 6.00% 6.00%
Rate of compensation increase:
Pension..................................... 3.25% 3.50% 5.25%
SERP........................................ 5.50% 5.50% 5.50%
-------------------------
(a) We determine our long-term rate of return by considering historical market
returns, the current and future economic environment, the capital market
principles of risk and return, and the expertise of individuals and firms
with financial market knowledge. We use the asset allocation of the
portfolio to forecast the future
CMS-96
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
expected total return of the portfolio. The goal is to determine a long-term
rate of return that can be incorporated into the planning of future cash
flow requirements in conjunction with the change in the liability. The use
of forecasted returns for various classes of assets used to construct an
expected return model is reviewed periodically for reasonability and
appropriateness.
Costs: The following table recaps the costs incurred in our retirement
benefits plans:
YEARS ENDED DECEMBER 31
---------------------------------------------
PENSION & SERP OPEB
--------------------- --------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
IN MILLIONS
Service cost.......................................... $ 40 $ 44 $ 39 $ 21 $ 20 $ 16
Interest expense...................................... 79 89 88 66 69 62
Expected return on plan assets........................ (81) (103) (98) (42) (43) (41)
Plan amendments....................................... -- 4 -- -- -- --
Curtailment credit.................................... (2) -- -- (8) -- --
Settlement charge..................................... 84 -- -- -- -- --
Amortization of:
Net transition (asset).............................. -- -- (5) -- -- --
Prior service cost.................................. 7 8 8 (7) (1) (1)
Other............................................... 9 (1) (1) 19 10 1
---- ----- ---- ---- ---- ----
Net periodic pension and postretirement benefit
cost................................................ $136 $ 41 $ 31 $ 49 $ 55 $ 37
==== ===== ==== ==== ==== ====
Plan Assets: The following table recaps the categories of plan assets in
our retirement benefits plans:
YEARS ENDED DECEMBER 31
-------------------------------
PENSION OPEB
------------ ------------
2003 2002 2003 2002
---- ---- ---- ----
Asset Category:
Fixed Income.............................................. 52% 32%(b) 51% 55%
Equity Securities......................................... 44% 60% 48% 44%
CMS Energy Common Stock(a)............................. 4% 8% 1% 1%
-------------------------
(a) At December 31, 2003, there were 4,970,000 shares of CMS Energy Common Stock
in the Pension Plan assets with a fair value of $42 million, and 414,000
shares in the OPEB plan assets with a fair value of $4 million. At December
31, 2002, there were 5,099,000 shares of CMS Energy Common Stock in the
Pension Plan assets with a fair value of $48 million, and 284,000 shares in
the OPEB plan assets with a fair value of $3 million.
(b) At February 29, 2004, the Pension Plan assets were 66 percent equity, 34
percent fixed income. We plan to contribute $72 million to our OPEB plan in
2004. We estimate a contribution of $26 million to our Pension Plan in 2004.
We have established a target asset allocation for our Pension Plan assets
of 65 percent equity and 35 percent fixed income investments to maximize the
long-term return on plan assets, while maintaining a prudent level of risk. The
level of acceptable risk is a function of the liabilities of the plan. Equity
investments are diversified mostly across the Standard & Poor's 500 Index, with
a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a
Foreign Equity Index Fund. Fixed income investments are diversified across
investment grade instruments of both government and corporate issuers. Annual
liability measurements, quarterly portfolio reviews, and periodic
asset/liability studies are used to evaluate the need for adjustments to the
portfolio allocation.
CMS-97
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
We have established union and non-union VEBA trusts to fund our future
retiree health and life insurance benefits. These trusts are funded through the
rate making process for Consumers, and through direct contributions from the
non-utility subsidiaries. The equity portions of the union and non-union health
care VEBA trusts are invested in an Standard & Poor's 500 Index fund. The fixed
income portion of the union health care VEBA trust is invested in domestic
investment grade taxable instruments. The fixed income portion of the non-union
health care VEBA trust is invested in a diversified mix of domestic tax-exempt
securities. The investment selections of each VEBA are influenced by the tax
consequences, as well as the objective of generating asset returns that will
meet the medical and life insurance costs of retirees.
Reconciliations: The following table reconciles the funding of our
retirement benefit plans with our retirement benefit plans' liability:
YEARS ENDED DECEMBER 31
---------------------------------------------------
PENSION PLAN SERP OPEB
---------------- ------------ ---------------
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
IN MILLIONS
Benefit obligation January 1..................... $1,256 $1,195 $ 81 $ 73 $ 982 $ 956
Service cost..................................... 38 40 2 4 21 20
Interest cost.................................... 74 84 5 5 66 69
Plan amendment................................... (19) 3 -- -- (47) (64)
Actuarial loss (gain)............................ 55 72 (10) 1 91 41
Business combinations............................ -- -- -- -- (42) --
Benefits paid.................................... (215) (138) (2) (2) (42) (40)
------ ------ ---- ---- ------ -----
Benefit obligation December 31(a)................ 1,189 1,256 76 81 1,029 982
------ ------ ---- ---- ------ -----
Plan assets at fair value at January 1........... 607 845 -- -- 508 508
Actual return on plan assets..................... 115 (164) -- -- 75 (43)
Company contribution............................. 560 64 2 2 76 83
Actual benefits paid............................. (215) (138) (2) (2) (41) (40)
------ ------ ---- ---- ------ -----
Plan assets at fair value at December 31......... 1,067 607 -- -- 618 508
------ ------ ---- ---- ------ -----
Benefit obligation in excess of plan assets...... (122) (649) (76) (81) (411) (474)
Unrecognized net loss from experience different
than assumed................................... 501 573 3 13 313 313
Unrecognized prior service cost (benefit)........ 29 60 1 1 (112) (77)
Panhandle adjustment............................. -- (7) -- -- -- --
------ ------ ---- ---- ------ -----
Net Balance Sheet Asset (Liability).............. 408 (23) (72) (67) (210) (238)
Additional minimum liability adjustment(b)....... -- (426) -- -- -- --
------ ------ ---- ---- ------ -----
Total Net Balance Sheet Asset (Liability)...... $ 408 $ (449) $(72) $(67) $ (210) $(238)
====== ====== ==== ==== ====== =====
-------------------------
(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act 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 have decided to defer
recognizing the effects of the Act in our 2003 financial statements, as
permitted by FASB Staff Position No. 106-1. When accounting guidance is
issued, our retiree health benefit obligation may be adjusted.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.055 billion
exceeded the value of the Pension Plan assets and net balance sheet
liability at December 31, 2002. As a result, we recorded an additional
minimum liability, including an intangible asset of $53 million, and $373
million of accumulated other
CMS-98
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
comprehensive income. In August 2003, we made our planned contribution of
$210 million to the Pension Plan. In December 2003, we made an additional
contribution of $350 million to the Pension Plan that eliminated the
additional minimum liability. The Accumulated Benefit Obligation for the
pension plan was $1.019 billion at December 31, 2003.
11: LEASES
We lease various assets including vehicles, railcars, construction
equipment, an airplane, computer equipment, and buildings. We have both
full-service and net leases. A net lease requires us to pay for taxes,
maintenance, operating costs, and insurance. Most of our leases contain options
at the end of the initial lease term to:
- purchase the asset at the then fair value of the asset, or
- renew the lease at the then fair rental value.
Minimum annual rental commitments under our non-cancelable leases at
December 31, 2003 were:
CAPITAL LEASES OPERATING LEASES
-------------- ----------------
IN MILLIONS
2004........................................................ $13 $12
2005........................................................ 12 10
2006........................................................ 12 10
2007........................................................ 11 9
2008........................................................ 9 7
2009 and thereafter......................................... 21 30
--- ---
Total minimum lease payments................................ 78 $78
===
Less imputed interest....................................... 10
---
Present value of net minimum lease payments................. 68
Less current portion........................................ 10
---
Non-current portion......................................... $58
===
Consumers is authorized by the MPSC to record both capital and operating
lease payments as operating expense and recover the total cost from our
customers. Operating lease charges were $14 million in 2003, $13 million in
2002, and $15 million in 2001.
Capital lease expenses were $17 million in 2003, $20 million, in 2002 and
$26 million in 2001. Included in the $26 million for 2001 is $7 million of
nuclear fuel lease expense. In November 2001, our nuclear fuel capital leasing
arrangement expired. At termination of the lease, we paid the lessor $48
million, which was the lessor's remaining investment at that time.
In April 2001, we entered into a lease agreement for the construction of an
office building to be used as the main headquarters for CMS Energy and Consumers
in Jackson, Michigan. In November 2003, we exercised our purchase option under
the lease agreement and bought the office building with proceeds from a $60
million term loan.
CMS-99
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12: JOINTLY OWNED REGULATED UTILITY FACILITIES
We are required to provide only our share of financing for the jointly
owned utility facilities. The direct expenses of the jointly owned plants are
included in operating expenses. Operation, maintenance, and other expenses of
these jointly owned utility facilities are shared in proportion to each
participant's undivided ownership interest. The following table indicates the
extent of our investment in jointly owned regulated utility facilities:
DECEMBER 31
----------------------------
NET ACCUMULATED
INVESTMENT DEPRECIATION
------------ ------------
2003 2002 2003 2002
---- ---- ---- ----
IN MILLIONS
Campbell Unit 3 -- 93.3 percent............................. $299 $298 $328 $313
Ludington -- 51 percent..................................... 84 83 87 85
Distribution -- various..................................... 74 77 32 31
13: 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. The most significant of these investments is our 50 percent interest in Jorf
Lasfar, and our 49 percent interest in the MCV Partnership (Note 15). Our
investment in Jorf Lasfar is $256 million at December 31, 2003 and $240 million
at December 31, 2002. Net income from these investments included undistributed
earnings of $41 million in 2003 and $39 million in 2002 and distributions in
excess of earnings of $68 million in 2001. Summarized financial information of
the MCV Partnership is disclosed separately in
CMS-100
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note 15, Summarized Financial Information of Significant Related Energy
Supplier. Listed below is the summarized income and balance sheet information
for these investments.
Income Statement Data
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
2003
-------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue.......................... $369 $79 $99 $74 $1,135 $1,756
Operating expenses......................... 191 4 38 18 1,006 1,257
---- --- --- --- ------ ------
Operating income........................... 178 75 61 56 129 499
Other expense, net......................... 58 43 18 25 35 179
---- --- --- --- ------ ------
Net income (loss).......................... $120 $32 $43 $31 $ 94 $ 320
==== === === === ====== ======
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
2002
-------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue.......................... $364 $91 $101 $43 $3,376 $3,975
Operating expenses......................... 176 4 33 13 3,209 3,435
---- --- ---- --- ------ ------
Operating income........................... 188 87 68 30 167 540
Other expense, net......................... 56 49 86 16 206 413
---- --- ---- --- ------ ------
Net income (loss).......................... $132 $38 $(18) $14 $ (39) $ 127
==== === ==== === ====== ======
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
2001
-------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Operating revenue.......................... $357 $99 $ 44 $39 $3,814 $4,353
Operating expenses......................... 151 6 17 12 3,459 3,645
---- --- ---- --- ------ ------
Operating income........................... 206 93 27 27 355 708
Other expense, net......................... 45 63 42 16 237 403
---- --- ---- --- ------ ------
Net income................................. $161 $30 $(15) $11 $ 118 $ 305
==== === ==== === ====== ======
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Balance Sheet Data
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2003
--------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
IN MILLIONS
Assets
Current assets.......................... $ 277 $ -- $ 93 $ 60 $ 434 $ 864
Property, plant and equipment, net...... 10 -- 638 383 2,475 3,506
Other assets............................ 1,152 893 10 -- 1,159 3,214
------ ---- ---- ---- ------ ------
$1,439 $893 $741 $443 $4,068 $7,584
====== ==== ==== ==== ====== ======
Liabilities
Current liabilities..................... $ 314 $ 21 $ 81 $ 19 $ 425 $ 860
Long-term debt and other non-current
liabilities.......................... 612 411 509 225 3,121 4,878
Equity.................................... 513 461 151 199 522 1,846
------ ---- ---- ---- ------ ------
$1,439 $893 $741 $443 $4,068 $7,584
====== ==== ==== ==== ====== ======
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002
--------------------------------------------------------------
JORF SCP ALL
LASFAR FMLP TAWEELAH INVESTMENTS OTHERS TOTAL
------ ---- -------- ----------- ------ -----
Assets
Current assets.......................... $ 225 $ -- $ 91 $ 36 $ 676 $1,028
Property, plant and equipment, net...... 7 -- 656 291 2,695 3,649
Other assets............................ 1,118 998 10 -- 1,076 3,202
------ ---- ---- ---- ------ ------
$1,350 $998 $757 $327 $4,447 $7,879
====== ==== ==== ==== ====== ======
Liabilities
Current liabilities..................... $ 249 $ 22 $ 95 $ 18 $ 692 $1,076
Long-term debt and other non-current
liabilities.......................... 622 428 530 172 2,896 4,648
Equity.................................... 479 548 132 137 859 2,155
------ ---- ---- ---- ------ ------
$1,350 $998 $757 $327 $4,447 $7,879
====== ==== ==== ==== ====== ======
14: 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 its subsidiary, Consumers. The gas
utility segment consists of regulated activities like transportation, storage,
and distribution of natural gas in the state of Michigan through its 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.
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. We restated 2002
and 2001 information due to the management reorganization and the change in our
business strategy in 2003 from five to three operating segments.
Reportable Segments
YEARS ENDED DECEMBER 31
-------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Revenues
Electric utility.......................................... $ 2,583 $ 2,644 $ 2,630
Gas utility............................................... 1,845 1,519 1,338
Enterprises............................................... 1,085 4,508 4,034
Other..................................................... -- 2 4
------- ------- -------
$ 5,513 $ 8,673 $ 8,006
======= ======= =======
Earnings from Equity Method Investees
Enterprises............................................... $ 164 $ 92 $ 172
------- ------- -------
$ 164 $ 92 $ 172
======= ======= =======
Depreciation, Depletion, and Amortization
Electric utility.......................................... $ 247 $ 228 $ 219
Gas utility............................................... 128 118 118
Enterprises............................................... 52 64 70
Other..................................................... 1 2 1
------- ------- -------
$ 428 $ 412 $ 408
======= ======= =======
Income Taxes
Electric utility.......................................... $ 90 $ 138 $ 69
Gas utility............................................... 35 33 25
Enterprises............................................... 14 (155) (83)
Other..................................................... (81) (57) (105)
------- ------- -------
$ 58 $ (41) $ (94)
======= ======= =======
Net Income (Loss)
Electric utility.......................................... $ 167 $ 264 $ 120
Gas utility............................................... 38 46 21
Enterprises............................................... 8 (419) (272)
Other..................................................... (257) (541) (328)
------- ------- -------
$ (44) $ (650) $ (459)
======= ======= =======
Investments in Equity Method Investees
Enterprises............................................... $ 1,366 $ 1,367 $ 1,912
Other..................................................... 24 2 36
------- ------- -------
$ 1,390 $ 1,369 $ 1,948
======= ======= =======
CMS-103
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31
-------------------------------
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
Identifiable Assets
Electric utility(a)....................................... $ 6,831 $ 6,058 $ 5,784
Gas utility(a)............................................ 2,983 2,586 2,734
Enterprises............................................... 3,670 5,724 8,891
Other..................................................... 354 413 224
------- ------- -------
$13,838 $14,781 $17,633
======= ======= =======
Capital Expenditures(b)
Electric utility.......................................... $ 310 $ 437 $ 623
Gas utility............................................... 135 181 145
Enterprises............................................... 49 235 427
Other..................................................... -- 8 263
------- ------- -------
$ 494 $ 861 $ 1,458
======= ======= =======
Geographic Areas(c)
RESTATED RESTATED
2003 2002 2001
---- -------- --------
IN MILLIONS
United States
Operating Revenue......................................... $ 5,222 $ 8,361 $ 7,639
Operating Income (Loss)................................... 511 (36) 189
Identifiable Assets....................................... 12,372 13,355 14,770
International
Operating Revenue......................................... $ 291 $ 312 $ 367
Operating Income (Loss)................................... 84 111 (38)
Identifiable Assets....................................... 1,466 1,426 2,863
-------------------------
(a) Amounts includes a portion of Consumers' assets for both the Electric and
Gas utility units.
(b) Amounts include electric restructuring implementation plan, capital leases
for nuclear fuel, purchase of nuclear fuel and other assets and electric
DSM costs. Amounts also include a portion of Consumers' capital
expenditures for plant and equipment that both the electric and gas utility
units use.
(c) Revenues are based on the country location of customers.
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
15: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under the PPA with the MCV Partnership discussed in Note 4, Uncertainties,
our 2003 obligation to purchase electric capacity from the MCV Partnership
provided 15 percent of our owned and contracted electric generating capacity.
Summarized financial information of the MCV Partnership follows:
Statements of Income
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Operating revenue(a)........................................ $584 $597 $611
Operating expenses.......................................... 416 409 453
---- ---- ----
Operating income............................................ 168 188 158
Other expense, net.......................................... 108 114 110
---- ---- ----
Income before cumulative effect of accounting change........ 60 74 48
Cumulative effect of change in method of accounting for
derivative options contracts(b)........................... -- 58 --
---- ---- ----
Net Income.................................................. $ 60 $132 $ 48
==== ==== ====
Balance Sheets
DECEMBER 31
---------------
2003 2002
---- ----
IN MILLIONS
ASSETS
Current assets(c)........ $ 389 $ 358
Plant, net............... 1,494 1,550
Other assets............. 187 190
------ ------
$2,070 $2,098
====== ======
DECEMBER 31
---------------
2003 2002
---- ----
IN MILLIONS
LIABILITIES AND EQUITY
Current liabilities...... $ 250 $ 209
Non-current
liabilities(d)......... 1,021 1,155
Partners' equity(e)...... 799 734
------ ------
$2,070 $2,098
====== ======
-------------------------
(a) Revenue from Consumers totaled $514 million in 2003, $557 million in 2002,
and $550 million in 2001.
(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard
for derivatives. As a result, the MCV Partnership began accounting for
several natural gas contracts containing an option component at fair value.
The MCV Partnership recorded a $58 million cumulative effect adjustment for
the change in accounting principle as an increase to earnings. CMS
Midland's 49 percent ownership share was $28 million ($18 million
after-tax), which is reflected as a change in accounting principle on our
Consolidated Statements of Income (Loss).
(c) Receivables from Consumers totaled $40 million for December 31, 2003 and
$44 million for December 31, 2002.
(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term
direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4
percent ownership interest in FMLP. The MCV Partnership's
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
lease obligations, assets, and operating revenues secure FMLP's debt. The
following table summarizes obligation and payment information regarding the
direct finance lease.
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Balance Sheet:
MCV Partnership: Lease obligation........................................ $894 $975
FMLP: Non-recourse debt....................................... 431 449
Lease payment to service non-recourse debt (including
interest)............................................... 158 370
CMS Holdings: Share of interest portion of lease payment.............. 37 34
Share of principle portion of lease payment............. 36 65
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Income Statement:
FMLP: Earnings............................................. $32 $38 $30
(e) CMS Midland's recorded investment in the MCV Partnership includes
capitalized interest, which we are expensing over the life of our
investment in the MCV Partnership. The financing agreements prohibit the
MCV Partnership from distributing any cash to its owners until it meets
certain financial test requirements. We do not anticipate receiving a cash
distribution in the near future.
16: 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. Accretion of $1 million related to the Big Rock and
Palisades' profit component included in the estimated cost of removal was
expensed for 2003.
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
CMS-106
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
reasonable estimate could not be made. If a five percent market risk premium
were assumed, our ARO liability would be $381 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. The pro forma effect on results of
operations would not have been material for the year ended December 31, 2002.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
IN SERVICE TRUST
ARO DESCRIPTION DATE LONG LIVED ASSETS FUND
--------------- ---------- ----------------- -----
IN MILLIONS
December 31, 2003
Palisades-decommission plant site..... 1972 Palisades nuclear plant $487
Big Rock-decommission plant site...... 1962 Big Rock nuclear plant 88
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 --
PRO FORMA ARO LIABILITY ARO
ARO LIABILITY ----------------------------- CASH FLOW LIABILITY
ARO DESCRIPTION 1/1/02 1/1/03 INCURRED SETTLED ACCRETION REVISIONS 12/31/03
--------------- ------------- ------ -------- ------- --------- --------- ---------
IN MILLIONS
December 31, 2003
Palisades-decommission...... $232 $249 $-- $ -- $19 $-- $268
Big Rock-decommission....... 94 61 -- (39) 13 -- 35
JHCampbell intake line...... -- -- -- -- -- -- --
Coal ash disposal areas..... 46 51 -- (4) 5 -- 52
Wells at gas storage
fields................... 2 2 -- -- -- -- 2
Indoor gas services
relocations.............. 1 1 -- -- -- -- 1
Closure of gas
pipelines(a)............. 7 8 -- (8) -- -- --
Dismantle natural gas-fired
power plant.............. 1 1 -- -- -- -- 1
---- ---- --- ---- --- --- ----
Total.................. $383 $373 $-- $(51) $37 $-- $359
==== ==== === ==== === === ====
-------------------------
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and
CMS Field Services.
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
accumulated depreciation, were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
17: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND
HEDGING ACTIVITIES: Amends and clarifies financial accounting and reporting for
derivative instruments, including certain derivative instruments embedded in
other contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. This statement is effective for
contracts entered into or modified after June 30, 2003. Implementation of this
statement has not impacted our Consolidated Financial Statements.
SFAS NO. 150, ACCOUNTING FOR CERTAIN FINANCIAL INSTRUMENTS WITH
CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY: Establishes standards for how
we classify and measure certain financial instruments with characteristics of
both liabilities and equity. The statement requires us to classify financial
instruments within its scope as liabilities rather than mezzanine equity, the
area between liabilities and equity. SFAS No. 150 became effective July 1, 2003.
We have five Trust Preferred Securities outstanding as of December 31, 2003
that are issued by our affiliated trusts. Each trust holds a subordinated
debenture from the parent company. The terms of the debentures are identical to
those of the trust-preferred securities, except that the debenture has an
explicit maturity date. The trust documents, in turn, require that the trust be
liquidated upon the repayment of the debenture. The preferred securities are
redeemable upon the liquidation of the subsidiary; therefore, are considered
equity in the financial statements of the subsidiary.
At their October 29, 2003 Board meeting, the FASB deferred the
implementation of the portion of SFAS No. 150 relating to mandatorily redeemable
noncontrolling interests in subsidiaries when the noncontrolling interests are
classified as equity in the financial statements of the subsidiary. Our Trust
Preferred Securities are included in the deferral action.
Upon adoption of FASB Interpretation No. 46, we determined that our trusts
that issue Trust Preferred Securities should be deconsolidated and reported as
long-term debt -- related parties. Refer to further discussion under FASB
Interpretation No. 46, Consolidation of Variable Interest Entities.
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 the 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 cumulative effect of change in
accounting principle loss of $23 million, net of tax, for the year ended
December 31, 2003.
EITF ISSUE NO. 01-08, DETERMINING WHETHER AN ARRANGEMENT CONTAINS A
LEASE: In May 2003, the EITF reached consensus in EITF Issue No. 01-08
requiring both parties to a transaction, such as power purchase agreements, to
determine whether a service contract or similar arrangement is or includes a
lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is
to be applied prospectively to arrangements agreed to, modified, or acquired in
business combinations in fiscal periods beginning July 1, 2003.
Prospective accounting under EITF Issue No. 01-08, could affect the timing
and classification of revenue and expense recognition. Certain product sales and
service revenue and expenses may be required to be reported as rental or leasing
income and/or expenses. Transactions deemed to be capital lease arrangements
would be included on our balance sheet. The adoption of EITF Issue No. 01-08 has
not impacted our results of operations, cash flows, or financial position.
CMS-108
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
EITF ISSUE NO. 03-04, ACCOUNTING FOR CASH BALANCE PENSION PLANS: In May
2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address
the accounting for certain cash balance pension plans. EITF Issue No. 03-04
concluded that certain cash balance plans be accounted for as defined benefit
plans under SFAS No. 87, Employers' Accounting for Pensions. The EITF
requirements must be applied as of our next plan measurement date after
issuance, which is December 31, 2003. In 2003, we started a cash balance pension
plan that covers employees hired after June 30, 2003. We do account for this
plan as a defined benefit plan under SFAS No. 87 and comply with EITF Issue No.
03-04. For further information, see Note 10, Retirement Benefits.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: 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 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 provides an implementation deferral, until
the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for
the first quarter of 2004 for all entities other than special purpose entities.
Special-purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
We determined that we have the controlling financial interest in three
entities that are determined to be variable interest entities. We have
50-percent partnership interest in T.E.S Filer City Station Limited Partnership,
Grayling Generating Station Limited Partnership, and 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 provide us with the
controlling financial interest as defined by the Interpretation. Therefore, we
have consolidated these partnerships into our consolidated financial statements
for the first time as of December 31, 2003. At December 31, 2003, total assets
consolidated for these entities are $227 million and total liabilities are $164
million, including $128 million of non-recourse debt. At December 31, 2003, CMS
Energy has outstanding letters of credit and guarantees of $5 million relating
to these entities. At December 31, 2003, minority interest recorded for these
entities totaled $36 million.
We also determined that we do not hold the controlling financial interest
in 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
CMS-109
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
eliminated due to deconsolidation. As a result of the deconsolidation, we have
reflected $684 million of long-term debt -- related parties and have 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 non-controlling interests in four other variable
interest entities. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at December 31, 2003:
INVESTMENT OPERATING
NAME INVOLVEMENT BALANCE AGREEMENT WITH
(OWNERSHIP INTEREST) NATURE OF THE ENTITY COUNTRY DATE (IN MILLIONS) CMS ENERGY
-------------------- -------------------- ------- ----------- ------------- --------------
Loy Yang Power (49%) Power Generator Australia 1997 $ -- Yes
Taweelah (40%) Power Generator United Arab Emirates 1999 $ 83 Yes
Jubail (25%) Generator -- Saudi Arabia 2001 $ -- Yes
Under Construction
Shuweihat (20%) Generator -- United Arab Emirates 2001 $(24)(a) Yes
Under Construction
----
Total $ 59
====
TOTAL
NAME GENERATING
(OWNERSHIP INTEREST) CAPACITY
-------------------- ----------
Loy Yang Power (49%) 2,000 MW
Taweelah (40%) 777 MW
Jubail (25%) 250 MW
Shuweihat (20%) 1,500 MW
--------
Total 4,527 MW
========
-------------------------
(a) At December 31, 2003, we recorded 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
$27 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 $59 million, Loy Yang
currency translation losses of $110 million, net of tax, and letters of credit,
guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146
million. Included in the $146 million is 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.
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 is expected to be presented for FASB clearance in 2004 and
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment asset often comprises multiple
parts and costs. A component accounting policy determines the level at which
those parts are recorded. Capitalization of certain costs related to property,
plant, and equipment are included in the total cost. The Statement of Position
could impact our component and capitalization accounting for property, plant,
and equipment. We continue to evaluate the impact, if any, this Statement of
Position will have upon adoption.
CMS-110
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
18: RESTATEMENT AND RECLASSIFICATION
We have determined the need to make certain adjustments to our consolidated
financial statements for the fiscal years ended December 31, 2002, December 31,
2001, and December 31, 2000. Therefore, the consolidated financial statements
for 2002 and 2001 have been restated from amounts previously reported. The table
below summarizes the significant adjustments and the effects on our consolidated
net loss.
NET LOSS (INCREASE) DECREASE 2002 2001 TOTAL
---------------------------- ---- ---- -----
IN MILLIONS
Interest allocation reclassification for International
Energy Distribution....................................... $ (3) $ 3 $ --
Derivatives related to the equity method investments........ (27) (14) (41)
---- ---- ----
Total....................................................... $(30) $(11) $(41)
==== ==== ====
INTEREST ALLOCATION RECLASSIFICATION FOR INTERNATIONAL ENERGY
DISTRIBUTION: Due to lack of progress on the sale, we reclassified our
international energy distribution business, which includes CPEE and SENECA, from
discontinued operations to continuing operations for the years 2003, 2002, and
2001. When we initially reported the international energy distribution business
as a discontinued operation in 2001, we applied APB Opinion No. 30, which
allowed us to record a provision for anticipated operating losses. We currently
apply FASB No. 144 which does not allow us to record a provision for future
operating losses. Therefore, in the process of reclassifying the international
energy distribution business to continuing operations and reversing such
provisions, we increased our net loss by $3 million in 2002 and decreased our
net loss by $3 million in 2001.
DERIVATIVES RELATED TO THE EQUITY METHOD INVESTMENTS: Some of our equity
affiliates hold derivative instruments, including interest rate swaps and other
similar instruments. Some of these instruments have been accounted for as cash
flow hedges, with changes in the fair value of the hedges reported in
accumulated other comprehensive income in 2003, 2002 and 2001. However, in late
2003 it was determined that certain of our equity affiliates did not formally
designate their instruments as hedges, or did not do so in a timely manner, in
accordance with SFAS No. 133. Therefore, the changes in the fair value of the
hedges should have been reported in earnings in 2003, 2002, and 2001. As a
result, the effects of the changes in the fair value of the hedges require
restatement. Our proportionate share of the adjustments increased our net loss
by $27 million in 2002 and increased our net loss by $14 million in 2001.
BALANCE SHEET IMPACTS: The most significant effects on our consolidated
balance sheets include the reclassification of International Energy Distribution
from "held for sale" to continuing operations and the change in our investments
due to the correction of the derivatives discussed above.
During the fourth quarter of 2000, we wrote down the value of our
investment in Loy Yang by $329 million ($268 million after-tax). We have now
concluded that the tax benefit associated with the write-down should have been
reduced by $38 million. Accordingly, our retained deficit as of January 1, 2001
increased by this amount.
CMS-111
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables present the effects of the adjustments we made to our
consolidated financial statements for the fiscal years ended December 31, 2002
and December 31, 2001, as well as effects of reclassifying Marysville and
Parmelia into discontinued operations.
CONSOLIDATED STATEMENTS OF INCOME
2002 2001
-------------------------- --------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Operating Revenue............................... $8,561 $8,673 $7,878 $8,006
Earnings from Equity Method Investees........... 126 92 185 172
Operating expenses
Operation..................................... 7,177 7,242 6,762 6,851
Maintenance................................... 211 212 224 225
Depreciation, depletion and amortization...... 403 412 398 408
General taxes................................. 199 222 196 220
Asset impairment charges...................... 598 602 240 323
------ ------ ------ ------
Total Operating Expenses...................... 8,588 8,690 7,820 8,027
------ ------ ------ ------
Operating Income................................ 99 75 243 151
------ ------ ------ ------
Other Income (Deductions):
Accretion expense............................. (31) (31) (37) (37)
Gain (loss) on asset sales, net............... 37 37 - (2)
Other, net.................................... (4) (6) 25 26
------ ------ ------ ------
Total Other Income (Deductions)............... 2 -- (12) (13)
------ ------ ------ ------
Fixed Charges................................... 504 508 562 566
Loss From Continuing Operations Before Income
Taxes and Minority Interests.................. (403) (433) (331) (428)
------ ------ ------ ------
Income Tax Expense (Benefit).................... 13 (41) (98) (94)
Minority Interests.............................. -- 2 3 (7)
------ ------ ------ ------
Loss From Continuing Operations................. (416) (394) (236) (327)
------ ------ ------ ------
Loss From Discontinued Operations............... (222) (274) (210) (128)
------ ------ ------ ------
Loss Before Cumulative Effect of Change in
Accounting Principle.......................... (638) (668) (446) (455)
------ ------ ------ ------
Cumulative Effect of Change in Accounting....... 18 18 (2) (4)
------ ------ ------ ------
Consolidated Net Loss........................... $ (620) $ (650) $ (448) $ (459)
====== ====== ====== ======
Basic and Diluted Loss Per Share................ $(4.46) $(4.68) $(3.42) $(3.51)
====== ====== ====== ======
CMS-112
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001
-------------------------- --------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Consolidated net loss........................... $ (620) $ (650) $ (448) $ (459)
Net cash provided by operating activities....... 624 614 366 372
Net cash provided by (used in) investing
activities.................................... 863 829 (1,348) (1,349)
Net cash provided by (used in) financing
activities.................................... (1,237) (1,223) 968 967
Effect of Exchange Rate on Cash................. -- 8 -- (10)
Net Increase (Decrease) in Cash and Temporary
Cash Investments.............................. 250 228 (14) (20)
------- ------- ------- -------
Cash and Cash Investments, End of Period........ $ 377 $ 351 $ 127 $ 123
======= ======= ======= =======
CONSOLIDATED BALANCE SHEETS
2002 2001
-------------------------- --------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
ASSETS
Plant and Property (at cost).................... $ 5,234 $ 6,103 $ 5,848 $ 6,703
------- ------- ------- -------
Investments..................................... 1,398 1,369 1,961 1,960
------- ------- ------- -------
Current Assets:
Cash and temporary cash investments........... 377 351 127 123
Restricted cash............................... -- 38 -- 4
Accounts receivable, notes receivable, and
accrued revenue............................ 757 783 704 743
Assets held for sale.......................... 644 595 471 412
Price risk management assets.................. 115 115 327 327
Prepayments, inventories, and other........... 855 857 931 951
------- ------- ------- -------
Total Current Assets............................ 2,748 2,739 2,560 2,560
------- ------- ------- -------
Non-current Assets:
Regulatory assets............................. 1,053 1,053 1,105 1,105
Assets held for sale.......................... 2,081 2,084 3,480 3,438
Price risk management assets.................. 135 135 368 368
Other......................................... 1,266 1,298 1,453 1,499
------- ------- ------- -------
Total Non-current Assets........................ 4,535 4,570 6,406 6,410
------- ------- ------- -------
Total Assets.................................... $13,915 $14,781 $16,775 $17,633
======= ======= ======= =======
CMS-113
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2002 2001
-------------------------- --------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
STOCKHOLDERS' INVESTMENT AND LIABILITIES
Capitalization:
Common stockholders' equity..................... $ 1,133 $ 1,078 $ 2,038 $ 1,991
Long-term debt.................................. 5,356 5,357 5,840 5,842
Non-current portion of capital leases........... 116 116 71 71
Other........................................... 927 927 1,258 1,258
------- ------- ------- -------
Total Capitalization............................ 7,532 7,478 9,207 9,162
------- ------- ------- -------
Minority Interests.............................. 21 38 24 43
------- ------- ------- -------
Current Liabilities:
Current portion of long-term debt and capital
leases..................................... 640 646 1,016 1,016
Notes payable................................. 458 458 416 416
Accounts payable.............................. 482 496 595 614
Accrued taxes................................. 291 291 111 111
Liabilities held for sale..................... 465 427 639 605
Price risk management liabilities............. 96 96 367 367
Deferred income taxes......................... 15 15 49 49
Other......................................... 451 460 478 494
------- ------- ------- -------
Total Current Liabilities....................... 2,898 2,889 3,671 3,672
------- ------- ------- -------
Non-current Liabilities:
Deferred income taxes......................... 414 438 824 864
Regulatory liabilities for cost of removal.... -- 907 -- 870
Liabilities held for sale..................... 1,243 1,218 1,376 1,354
Price risk management liabilities............. 135 135 287 287
Other......................................... 1,672 1,678 1,386 1,381
------- ------- ------- -------
Total Non-current Liabilities................... 3,464 4,376 3,873 4,756
------- ------- ------- -------
Total Stockholders' Investment and
Liabilities................................... $13,915 $14,781 $16,775 $17,633
======= ======= ======= =======
CMS-114
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
2002 2001
-------------------------- --------------------------
AS REPORTED AS RESTATED AS REPORTED AS RESTATED
----------- ----------- ----------- -----------
IN MILLIONS
Retained Deficit
At beginning of period........................ $ (951) $(1,001) $ (313) $ (352)
Consolidated net loss......................... (620) (650) (448) (459)
Common stock dividends declared............... (149) (149) (190) (190)
------- ------- ------ -------
At end of period........................... (1,720) (1,800) (951) (1,001)
------- ------- ------ -------
Accumulated Other Comprehensive Loss
At beginning of period........................ (269) (266) (201) (198)
Minimum pension liability..................... (241) (241) -- --
Investments................................... 7 7 (3) (3)
Derivative instruments........................ (25) (3) (38) (38)
Foreign currency translation.................. (225) (225) (27) (27)
------- ------- ------ -------
At end of period........................... (753) (728) (269) (266)
------- ------- ------ -------
Common stock.................................... 1 1 1 1
Other paid-in capital........................... 3,605 3,605 3,257 3,257
------- ------- ------ -------
Total Common Stockholders' Equity............... $ 1,133 $ 1,078 $2,038 $ 1,991
======= ======= ====== =======
Total Other Comprehensive Loss.................. $(1,104) $(1,112) $ (516) $ (527)
======= ======= ====== =======
CMS-115
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
19: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
We have determined the need to make certain adjustments to our consolidated
financial statements for the quarterly periods of 2003 and 2002. Therefore, the
consolidated financial statements for the quarterly periods of 2003 and 2002
have been restated from amounts previously reported.
2003 (RESTATED)
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------------- -------- ------- -------- -------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue.......................................... $1,968 $1,126 $1,047 $1,372
Operating income........................................... 236 176 78 105
Income (loss) from continuing operations................... 75 (12) (71) (35)
Discontinued operations(a)................................. 31 (53) 2 43
Cumulative effect of change in accounting principles(a).... (24) -- -- --
Consolidated net income (loss)............................. 82 (65) (69) 8
Income (loss) from continuing operations per average common
share -- basic........................................... 0.52 (0.08) (0.47) (0.22)
Income (loss) from continuing operations per average common
share -- diluted......................................... 0.47 (0.08) (0.47) (0.22)
Basic earnings (loss) per average common share(b).......... 0.57 (0.45) (0.46) 0.05
Diluted earnings (loss) per average common share(b)........ 0.52 (0.45) (0.46) 0.05
Dividends declared per common share........................ -- -- -- --
Common stock prices(c)
High..................................................... 10.59 8.50 7.99 8.63
====== ====== ====== ======
Low...................................................... 3.49 4.58 6.11 7.44
====== ====== ====== ======
2002 (RESTATED)
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------------- -------- ------- -------- -------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue.......................................... $2,248 $2,123 $2,566 $1,736
Operating income (loss).................................... 283 136 178 (522)
Income (loss) from continuing operations................... 103 17 (1) (513)
Discontinued operations(a)................................. (52) (128) 26 (120)
Cumulative effect of change in accounting principles(a).... -- 17 1 --
Consolidated net income (loss)............................. 51 (94) 26 (633)
Income (loss) from continuing operations per average common
share -- basic........................................... 0.77 0.14 -- (3.57)
Income (loss) from continuing operations per average common
share -- diluted......................................... 0.77 0.14 -- (3.57)
Basic earnings (loss) per average common share(b).......... 0.38 (0.69) 0.18 (4.40)
Diluted earnings (loss) per average common share(b)........ 0.38 (0.69) 0.18 (4.40)
Dividends declared per common share........................ 0.365 0.365 0.18 0.18
Common stock prices(c)
High..................................................... 24.62 22.24 11.28 10.48
====== ====== ====== ======
Low...................................................... 21.27 10.46 7.49 5.79
====== ====== ====== ======
-------------------------
(a) Net of tax
(b) Sum of the quarters may not equal the annual earnings per share due to
changes in shares outstanding
(c) Based on New York Stock Exchange -- Composite transactions
CMS-116
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables present the effects of the adjustments we made to our
consolidated financial statements for the quarterly periods of 2003 and 2002, as
well as the effects of reclassifying Marysville and Parmelia into discontinued
operations.
2003
-----------------------------------------
QUARTERS ENDED -- REPORTED VS. RESTATED MARCH 31 JUNE 30 SEPT. 30
--------------------------------------- -------- ------- --------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue as reported............................... $1,992 $1,154 $1,016
Operating revenue as restated............................... 1,968 1,126 1,047
Operating income as reported................................ 239 183 129
Operating income as restated................................ 236 176 78
Income (loss) from continuing operations as reported........ 76 (5) (34)
Income (loss) from continuing operations as restated........ 75 (12) (71)
Discontinued operations as reported......................... 27 (40) (43)
Discontinued operations as restated......................... 31 (53) 2
Consolidated net income (loss) as reported.................. 79 (45) (77)
Consolidated net income (loss) as restated.................. 82 (65) (69)
Basic earnings (loss) per average common share as
reported.................................................. 0.55 (0.31) (0.51)
Basic earnings (loss) per average common share as
restated.................................................. 0.57 (0.45) (0.46)
Diluted earnings (loss) per average common share as
reported.................................................. 0.51 (0.31) (0.51)
Diluted earnings (loss) per average common share as
restated.................................................. 0.52 (0.45) (0.46)
2002
------------------------------------------
QUARTERS ENDED -- REPORTED VS. RESTATED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
--------------------------------------- -------- ------- -------- -------
IN MILLIONS, EXCEPT PER SHARE AMOUNTS
Operating revenue as reported.............................. $2,263 $2,135 $2,534 $1,708
Operating revenue as restated.............................. 2,248 2,123 2,566 1,736
Operating income (loss) as reported........................ 275 152 190 (520)
Operating income (loss) as restated........................ 283 136 178 (522)
Income (loss) from continuing operations as reported....... 93 36 11 (557)
Income (loss) from continuing operations as restated....... 103 17 (1) (513)
Discontinued operations as reported........................ (51) (127) 25 (68)
Discontinued operations as restated........................ (52) (128) 26 (120)
Consolidated net income (loss) as reported................. 42 (74) 37 (625)
Consolidated net income (loss) as restated................. 51 (94) 26 (633)
Basic earnings (loss) per average common share as
reported................................................. 0.32 (0.55) 0.26 (4.34)
Basic earnings (loss) per average common share as
restated................................................. 0.38 (0.69) 0.18 (4.40)
Diluted earnings (loss) per average common share as
reported................................................. 0.32 (0.55) 0.26 (4.34)
Diluted earnings (loss) per average common share as
restated................................................. 0.38 (0.69) 0.18 (4.40)
CMS-117
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The table below summarizes the significant adjustments and the effect on
consolidated net income (loss) by quarter.
2003 2002
------------------------------ -----------------------------------------
QUARTERS ENDED MAR. 31 JUNE 30 SEPT. 30 MAR. 31 JUNE 30 SEPT. 30 DEC. 31
-------------- ------- ------- -------- ------- ------- -------- -------
IN MILLIONS
Consolidated net income (loss) as
reported............................... $79 $(45) $(77) $42 $(74) $37 $(625)
Discontinued operations reclass(a)....... -- -- -- (1) (1) (1) --
Derivative accounting changes(b)......... 3 (6) 8 10 (19) (10) (8)
Panhandle sale adjustment(c)............. -- (14) -- -- -- -- --
--- ---- ---- --- ---- --- -----
Consolidated net income (loss) as
restated............................... $82 $(65) $(69) $51 $(94) $26 $(633)
=== ==== ==== === ==== === =====
-------------------------
(a) We continue to pursue the sale of International Energy Distribution, which
includes CPEE and SENECA, but due to the slow progress on the sale, we have
reclassified this entity from discontinued operations to continuing
operations for the years 2003, 2002, and 2001. When we initially reported
the international energy distribution business as a discontinued operation
in 2001, we applied APB Opinion No. 30, which allowed us to record a
provision for anticipated closing costs and operating losses. We currently
apply FASB No. 144 which does not allow us to record a provision for future
operating losses. Therefore, in the process of reclassifying the
international energy distribution business to continuing operations and
reversing such provisions, we increased our net loss by $3 million in 2002
and decreased our net loss by $3 million in 2001. In 2003, there was an
increase to net income of $75 million as a result of reversing the
previously recognized impairment loss in discontinued operations.
(b) We determined that certain equity method investees inappropriately
accounted for interest rate swaps as hedges. For additional details, see
Note 18, Restatement and Reclassification.
(c) We determined the net loss recorded in the second quarter of 2003 relating
to the sale of Panhandle, reflected as Discontinued Operations, was
understated by approximately $14 million, net of tax. The understatement
occurred because we did not recognize through our second quarter 2003
earnings an unrealized loss related to certain Panhandle interest rate
hedging derivative instruments. Pursuant to SFAS No. 133, the unrealized
loss was accounted for in Other Comprehensive Income, but needed to be
recognized through earnings upon the sale of Panhandle.
CMS-118
(This page intentionally left blank)
CMS-119
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
CMS Energy Corporation
We have audited the accompanying consolidated balance sheets of CMS Energy
Corporation (a Michigan corporation) and subsidiaries as of December 31, 2003
and 2002, and the related consolidated statements of income (loss), common
stockholders' equity and cash flows for each of three years in the period ended
December 31, 2003. Our audits also included the financial statement schedule
listed in the Index at Item 15(a)(2). These financial statements and schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and schedule based on our
audits. The financial statements of Midland Cogeneration Venture Limited
Partnership and Jorf Lasfar Energy Company S.C.A., which represent investments
accounted for under the equity method of accounting, have been audited by other
auditors (the other auditors for 2001 for Midland Cogeneration Venture Limited
Partnership have ceased operations) whose reports have been furnished to us;
insofar as our opinion on the consolidated financial statements relates to the
amounts included for Midland Cogeneration Venture Limited Partnership and Jorf
Lasfar Energy Company S.C.A., respectively, it is based solely on their reports.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits and the reports of other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and the reports of other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of CMS Energy Corporation
and subsidiaries at December 31, 2003 and 2002, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2003 in conformity with U.S. generally accepted accounting
principles. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As discussed in Notes 16 and 17 to the consolidated financial statements,
in 2003, the Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations", EITF
Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy
Trading Contracts" and of Financial Accounting Standards Board Interpretation
No. 46, "Consolidation of Variable Interest Entities". As discussed in Notes 3,
9 and 15 to the consolidated financial statements, in 2002, the Company adopted
the provisions of SFAS No. 142, "Goodwill and Other Intangibles", SFAS No. 148,
"Accounting for Stock-Based Compensation" and Midland Cogeneration Venture
Limited Partnership adopted the provisions of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", as amended and interpreted.
As discussed in Note 18 to the consolidated financial statements, the
Company restated its 2002 and 2001 financial statements.
/s/ ERNST & YOUNG LLP
Detroit, Michigan
February 27, 2004
CMS-120
REPORT OF INDEPENDENT AUDITORS
We have audited the accompanying balance sheets of Jorf Lasfar Energy
Company S.C.A (the "Company") as of December 31, 2003, 2002 and 2001, and the
related statements of income, of stockholders' equity and of cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statements presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Jorf Lasfar Energy Company
S.C.A at December 31, 2003, 2002 and 2001, and the results of its operations and
its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.
Price Waterhouse
Casablanca, Morocco,
February 10, 2004
CMS-121
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, partners' equity and cash flows
present fairly, in all material respects, the financial position of the Midland
Cogeneration Limited Partnership (a Michigan limited partnership) and its
subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their
operations and their cash flows for the each of the two years ended December 31,
2003 and 2002 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
MCV's management. Our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The financial statements of
MCV for the year ended December 31, 2001, were audited by other independent
accountants who have ceased operations. Those independent accountants expressed
an unqualified opinion on those financial statements in their report dated
January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1,
2002, Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 18, 2004
CMS-122
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED
ARTHUR ANDERSEN REPORT AND THIS REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the
Midland Cogeneration Venture Limited Partnership:
We have audited the accompanying consolidated balance sheets of the MIDLAND
COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited partnership) and
subsidiaries (MCV) as of December 31, 2001 and 2000, and the related
consolidated statements of operations, partners' equity and cash flows for each
of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of MCV's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of the Midland
Cogeneration Venture Limited Partnership and subsidiaries as of December 31,
2001 and 2000, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1,
2001, Midland Cogeneration Venture Limited Partnership changed its method of
accounting related to derivatives and hedging activities.
/s/Arthur Andersen LLP
Detroit, Michigan,
January 18, 2002
CMS-123
[CONSUMERS ENERGY LOGO]
2003 FINANCIAL STATEMENTS
CE-1
CONSUMERS ENERGY COMPANY
SELECTED FINANCIAL INFORMATION
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Operating revenue (in millions).................... ($) 4,435 4,169 3,976 3,878 3,824
Earnings from equity method investees.............. ($) 42 53 38 57 50
Income before cumulative effect of change in
accounting principle (in millions)............... ($) 196 363 199 284 340
Net income (in millions) (a)....................... ($) 196 381 188 284 340
Net income available to common stockholder (in
millions)........................................ ($) 194 335 145 248 313
Cash from operations (in millions)................. ($) 5 760 518 515 791
Capital expenditures, excluding capital lease
additions (in millions).......................... ($) 486 559 745 498 444
Total assets (in millions) (e)..................... ($) 10,745 9,598 9,191 8,672 8,044
Long-term debt, excluding current maturities (in
millions)........................................ ($) 3,583 2,442 2,472 2,110 2,006
Long-term debt -- related parties (in millions)
(b).............................................. ($) 506 -- -- -- --
Non-current portion of capital leases (in
millions)........................................ ($) 58 116 72 49 85
Total preferred stock (in millions)................ ($) 44 44 44 44 44
Total Trust Preferred Securities (in millions)
(b).............................................. ($) -- 490 520 395 395
Number of preferred shareholders at year-end....... 2,032 2,132 2,220 2,365 2,534
Book value per common share at year-end............ ($) 24.51 22.46 22.81 23.85 23.87
Return on average common equity.................... (%) 9.8 17.6 7.4 12.4 16.2
Return on average assets........................... (%) 3.6 5.3 3.5 4.8 6.0
Number of full-time equivalent employees at
year-end
Consumers..................................... 7,947 8,311 8,405 8,698 8,736
Michigan Gas Storage (c)...................... -- -- 62 57 63
ELECTRIC STATISTICS
Sales (billions of kWh).......................... 39 39 40 41 41
Customers (in thousands)......................... 1,754 1,734 1,712 1,691 1,665
Average sales rate per kWh....................... (c) 6.91 6.88 6.65 6.56 6.54
GAS UTILITY STATISTICS
Sales and transportation deliveries (bcf)........ 380 376 367 410 389
Customers (in thousands) (d)..................... 1,671 1,652 1,630 1,611 1,584
Average sales rate per mcf....................... ($) 6.72 5.67 5.34 4.39 4.52
-------------------------
(a) See Notes 1 and 2 in the notes to the consolidated financial statements.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on
the balance sheets as Long-term debt -- related parties.
(c) Effective November 2002, Michigan Gas Storage Company was merged into
Consumers.
(d) Excludes off-system transportation customers.
(e) For additional details on the reclassification of non-legal cost of
removal, see Note 12, Asset Retirement Obligation, "Reclassification of
Non-Legal Cost of Removal." Following is the amount of cost of removal
reclassified from accumulated depreciation to a regulatory liability by
year: $983 million in 2003; $907 million in 2002; $870 million in 2001;
$896 million in 2000; and $874 million in 1999.
CE-2
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. 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.
In 2003, we continued to implement our strategy centered around growing a
healthy utility in Michigan. We have taken advantage of historically low
interest rates to extend maturities and refinance our debt at lower cost. We
completed financing and refinancing transactions to resolve liquidity concerns
at the start of 2003. In addition, we contributed $501 million to our defined
benefit pension plan. This should result in lower pension costs in the future.
At the foundation of our financial progress was exceptional operating
performance. For the second consecutive year, our Michigan gas utility earned
the J.D. Power and Associates award for highest residential customer
satisfaction with natural gas services in the Midwest. Independent evaluators,
like J.D. Power and Associates recognize value and our regulators do too. The
MPSC authorized an annual increase in our gas utility rates of $56 million in
late 2002, and an additional interim annualized $19 million rate increase in
2003.
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 March 2004, we lost 735 MW or
nine percent of our electric business to these alternative electric suppliers.
We expect the loss to grow to over 1,000 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, and we have asked the MPSC to approve it quickly.
We also are focused on further reducing our business risk and leverage,
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.
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FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-K 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:
- achievement of capital expenditure reductions and cost savings,
- 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 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,
- 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,
- 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,
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- 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
YEARS ENDED DECEMBER 31
------------------------------------------------
2003 2002 CHANGE 2002 2001 CHANGE
---- ---- ------ ---- ---- ------
IN MILLIONS
Net income available to common stockholder......... $194 $335 $(141) $335 $145 $190
==== ==== ===== ==== ==== ====
2003 COMPARED TO 2002: Net income in 2003 was reduced $141 million as
compared to 2002 for several reasons. Higher electric and gas operating costs in
2003 were responsible for $80 million of the reduction in net income. Increased
operating costs include $53 million in higher pension and other benefit costs,
see Note 7, Retirement Benefits, $12 million of increased depreciation expense
reflecting higher levels of plant in service, and $7 million of increased
amortization expense associated with securitized regulatory assets. Amortization
expense is recognized as principal is repaid to the Securitization bondholders.
A significant reduction in 2003 electric deliveries also contributed to
reduced net income. Milder weather during the summer air conditioning season,
and a continuation of the trend of commercial and industrial customers switching
from us to other electric suppliers, impacted net income negatively by $27
million in 2003 versus 2002. Increased costs of borrowing reduced 2003 net
income by $23 million, reflecting higher levels of debt, and higher average
interest rates.
Our ownership interest in the MCV Partnership reflects a $27 million
reduction, as compared to 2002, in the fair value of certain gas contracts held
by the MCV Partnership. The fair value of these contracts is adjusted through
earnings in accordance with SFAS No. 133. For additional details on SFAS No.
133, see Note 4, Financial and Derivative Instruments.
The 2003 decrease in net income also reflects a $7 million charge at CMS
Holdings to reflect the loss of certain tax credits.
Finally, contrary to 2002, net income in 2003 did not reflect any gains or
losses associated with asset sales. In 2002, gains primarily associated with the
sale of the electric transmission system contributed $31 million to net income.
On the positive side, 2003 net income increased $25 million as compared to
2002 due to a full year of higher gas tariff rates, as authorized by the MPSC in
late 2002. Lower general taxes in 2003 contributed an additional $8 million to
net income during the year. The reduction in general taxes primarily reflects a
MSBT credit received from the State of Michigan associated with the construction
of our headquarters on a qualifying Brownfield site. Our ability to manage our
electric power supply costs also provided additional net income in 2003. Lower
average fuel costs and the availability of higher market prices for our excess
capacity increased net income by $17 million as compared to 2002.
2002 COMPARED TO 2001: Net income increased $190 million as compared to
2001. This increase was the result of several factors. Reduced electric power
costs in 2002 were responsible for $85 million of the increase in net income.
This reduction in power costs was due primarily to higher cost replacement power
purchased in 2001 because of a refueling outage and an unscheduled forced outage
at Palisades. Lower prices for power options and dispatchable capacity contracts
purchased in 2002 also contributed to the reduction in power costs.
In 2002, gains primarily associated with the sale of the electric
transmission system contributed $31 million to net income. Net income in 2001
did not reflect any gains or losses associated with asset sales.
Under SFAS No. 133, certain MCV gas contracts are adjusted, through
earnings, to reflect fair value. Earnings received by our ownership interest in
the MCV Partnership reflect a $25 million increase, compared to 2001, in the
fair value of these contracts held by the MCV Partnership. Net income also
increased as a result of an
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$11 million adjustment to electric call option and option-like contracts booked
in 2001, due to SFAS No. 133 implementation.
Increased electric deliveries to the higher margin residential and
commercial customers contributed $27 million to net income in 2002. The interim
and final gas rate orders issued in 2001 and 2002 increased net income by $16
million. Offsetting these increases to net income is a $9 million decrease
resulting from the recognition of a historic gas inventory adjustment in the
cumulative amount of 4 bcf.
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
YEARS ENDED DECEMBER 31
------------------------------------------------
2003 2002 CHANGE 2002 2001 CHANGE
---- ---- ------ ---- ---- ------
IN MILLIONS
Net income available to common stockholder......... $167 $264 $(97) $264 $109 $155
==== ==== ==== ==== ==== ====
Reasons for the change:
Electric deliveries................................ $(41) $ 41
Power supply costs and related revenue............. 26 149
Other operating expenses and non-commodity
revenue.......................................... (80) (21)
Implementation of accounting standards (SFAS No.
133)............................................. -- 17
Gain on asset sales................................ (38) 38
General taxes...................................... 10 (3)
Fixed charges...................................... (22) 9
Income taxes....................................... 48 (75)
---- ----
Total change....................................... $(97) $155
==== ====
ELECTRIC DELIVERIES: In 2003, electric revenues decreased, reflecting lower
deliveries. Most significantly, sales volumes to commercial and industrial
customers were 5.6 percent lower than in 2002, a result of these sectors'
continued switching to alternative electric suppliers as allowed by the Customer
Choice Act. The decrease in revenue is also the result of reduced deliveries to
higher-margin residential customers, from a milder summer's impact on air
conditioning usage. Overall, electric deliveries, including transactions with
other wholesale marketers and other electric utilities, decreased 0.4 billion
kWh or 1.1 percent.
In 2002, electric revenue increased by $41 million from the previous year,
despite lower deliveries. This was due primarily to increased deliveries to
higher-margin residential customers as a result of a significantly warmer
summer's impact on air conditioning usage. Deliveries, including transactions
with other wholesale marketers and other electric utilities, decreased 0.3
billion kWh or 0.7 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our recovery of power
supply costs was fixed, 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 2003, this difference between power supply-related revenues and
actual power supply costs benefited operating income by $26 million more than it
had in 2002. This increase is primarily the result of increased intersystem
revenues due to higher market prices and sales made from surplus capacity. The
efficient operation of our generating plants and lower priced purchased power
further decreased power supply costs.
In 2002, as compared to 2001, power supply costs and related revenues
increased operating income due primarily to reduced purchased power costs
because the Palisades plant returned to service in 2002, following an extended
2001 shutdown.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In 2003, net operating
expenses and non-commodity revenue decreased operating income by $80 million
versus 2002. This decrease relates to increased
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pension and other benefit costs of $54 million, a scheduled refueling outage at
Palisades, and higher transmission costs. More plant in service increased
depreciation costs by $8 million, and $11 million of higher amortization expense
from securitized assets further contributed to decreased operating income.
Slightly offsetting the increased operating expenses were higher non-commodity
revenues associated with other income.
In 2002, net operating expenses and non-commodity revenue decreased
operating income by $21 million compared with 2001. The decrease primarily
related to higher transmission expenses and increased depreciation costs from
more plant in service.
ASSET SALES: The reduction in operating income from asset sales for 2003
versus 2002, and the increase in operating income from asset sales for 2002
versus 2001 reflect the $31 million pretax gain associated with the 2002 sale of
our electric transmission system and the $7 million pretax gain associated with
the 2002 sale of nuclear equipment from the cancelled Midland project.
GENERAL TAXES: In 2003, general taxes decreased from 2002 due primarily to
reductions in MSBT expense, resulting primarily from a tax credit received from
the State of Michigan associated with construction of the new corporate
headquarters on a qualifying Brownfield site. In 2002, general taxes increased
over 2001 due to increases in MSBT and property tax accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002, fixed charges decreased versus 2001 because of a reduction in
long-term debt.
INCOME TAXES: In 2003, income tax decreased versus 2002 due primarily to
lower earnings by the electric utility. In 2002, income tax expense increased
versus 2001 due primarily to increased earnings.
GAS UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31
------------------------------------------------
2003 2002 CHANGE 2002 2001 CHANGE
---- ---- ------ ---- ---- ------
IN MILLIONS
Net income available to common stockholder............ $38 $46 $ (8) $46 $21 $ 25
=== === ==== === === ====
Reasons for the change:
Gas deliveries........................................ $ (1) $ 21
Gas rate increase..................................... 39 25
Gas wholesale and retail services and other gas
revenues............................................ 1 1
Operation and maintenance............................. (34) (14)
General taxes, depreciation, and other income......... (6) (3)
Fixed charges......................................... (5) 3
Income taxes.......................................... (2) (8)
------ ------
Total change.......................................... $ (8) $ 25
====== ======
GAS DELIVERIES: In 2003, gas deliveries, including miscellaneous
transportation, increased 4.1 bcf or 1.1 percent versus 2002. Despite increased
system deliveries, gas revenues actually declined by $1 million. Colder weather
during the first quarter of 2003 increased deliveries to the residential and
commercial sectors. Increased deliveries resulted in a $6 million increase in
gas revenues. However, the revenue increase was offset by a $7 million gas loss
adjustment recorded as a reduction to gas revenues.
In 2002, gas revenues increased by $21 million from the previous year.
System deliveries, including miscellaneous transportation, increased 9.4 bcf or
2.6 percent. The increase was due primarily to colder weather that increased
deliveries to the residential and commercial sectors.
GAS RATE INCREASE: In November 2002, the MPSC issued a final gas rate order
authorizing a $56 million annual increase to gas tariff rates. As a result of
this order, 2003 gas revenues increased $39 million. In 2002, gas rate increases
led to increased gas revenues of $25 million over 2001.
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GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: In 2003, gas
wholesale and retail services and other gas revenues increased $1 million. The
$1 million increase includes primarily the following two items. In 2003, we
reversed a $4 million reserve, originally recorded in 2002, for non-physical gas
title tracking services. In addition, in 2003, we reserved $11 million for the
settlement agreement associated with the 2002-2003 GCR disallowance. For
additional details regarding both of these issues, see the Gas Utility Business
Uncertainties in the "Outlook" section of this MD&A.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses
increased versus 2002 due to increases in pension and other benefits costs of
$27 million and additional expenditures on safety, reliability, and customer
service. In 2002, operation and maintenance expenses increased versus 2001 due
to the recognition of gas storage inventory losses and additional expenditures
on customer reliability and service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In 2003, the net of general
tax expense, depreciation expense, and other income decreased operating income
primarily because of increases in depreciation expense from increased plant in
service. In 2002, the net of general tax expense, depreciation expense, and
other income decreased operating income primarily because of increases in MSBT
and property tax expense accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily
to higher average debt levels, but also because of higher average interest
rates. In 2002 versus 2001, fixed charges decreased due to lower long-term debt
levels.
INCOME TAXES: In 2003 versus 2002, income tax expense increased due to
reduced income tax expense in 2002. The 2002 reduction was attributable to
flow-through accounting on plant, property and equipment as required by past
MPSC rulings. In 2002, income tax expense increased versus 2001 due primarily to
increased earnings of the gas utility.
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,
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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 contracted 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 availability 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 a
regulatory out provision under the MCV Partnership power purchase agreement.
This provision obligates us 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 equity, and
- eliminate our underrecoveries for capacity and 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 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
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 our equity interest in
the MCV Partnership 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 equity
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 an economic basis depending on 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. We
requested that the MPSC provide interim approval while it conducts a full review
of the plan. The MPSC has scheduled a prehearing conference with respect to the
MCV resource conservation plan for April 2004. We cannot predict if or when the
MPSC will approve our request.
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 our recovery of
capacity payments. Natural gas prices have been historically volatile.
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.
Therefore, we cannot predict the impact of these issues on our future earnings,
cash flows, or on the value of our equity interest in the MCV Partnership.
For additional details, see Note 2, Uncertainties, "Other Electric
Uncertainties -- The Midland Cogeneration Venture."
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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 December 31, 2003, we had $1.105 billion recorded as
regulatory assets and $1.467 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, including our investment in
CMS Energy Common Stock, 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.
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 options, 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.
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, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA,
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 December 31, 2003, we
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assumed a market-based interest rate of 1 percent (six-month U.S. Treasury rate)
and an average volatility rate of 79 percent to calculate the fair value of our
gas call options.
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, 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.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market interest rates):
AS OF
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Variable-rate financing -- before tax annual earnings
exposure.................................................. $ 1 $ 2
Fixed-rate financing -- potential loss in fair value(a)..... 154 137
-------------------------
(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. The 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. The weather-based gas supply call options, along with the gas supply call
and put options, are used to purchase reasonably priced gas supply. Call options
give us the right, but not the obligation, to purchase gas supply at
predetermined fixed prices. Put options give third-party suppliers the right,
but not the obligation, to sell gas supply to us at predetermined fixed prices.
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The commodity price risk sensitivity analysis was not material for the
years ending December 31, 2003 and December 31, 2002.
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.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
AS OF
DECEMBER 31
--------------
2003 2002
---- ----
IN MILLIONS
Potential reduction in fair value:
Nuclear decommissioning investments....................... $57 $49
Equity investments........................................ 4 4
For additional details on market risk and derivative activities, see Note
4, Financial and Derivative Instruments.
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement
pension benefits to our employees under a non-contributory, defined benefit
Pension Plan. We implemented a cash balance plan for 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
------------------------------------------------
PENSION EXPENSE OPEB EXPENSE CONTRIBUTIONS
--------------- ------------ -------------
IN MILLIONS
2004................................................. $20 $62 $ 94
2005................................................. 41 60 117
2006................................................. 63 58 124
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.
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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.
In August 2003, we made a planned contribution of $172 million to the
Pension Plan. In December 2003, we made an additional contribution of $329
million. As a result of these contributions, we reversed the additional minimum
liability and the resulting decrease in equity that we charged in 2002. As of
December 31, 2003, we have a prepaid pension asset of $384 million recorded on
our consolidated balance sheets.
Market-Related Valuation: We determine pension expense on a market-related
valuation of assets, which reduces year-to-year volatility. The market-related
valuation includes investment gains or losses over a five-year period from the
year in which the gains or losses occur. Investment gains or losses for this
purpose are the difference between the expected return calculated using the
market-related value of assets and the actual return based on the market value
of assets. Since the market-related value of assets recognizes gains or losses
over a five-year period, the future value of assets will be impacted as
previously deferred gains or losses are recorded.
The Pension Plan includes funds for our employees and our non-utility
affiliates. The Pension Plan assets are not distinguishable by company. Due to
the unfavorable performance of the equity markets in the past few years, as of
December 31, 2003, we had cumulative losses of approximately $239 million that
remain to be included in the calculation of the market-related value of assets.
These unrecognized net actuarial losses may result in increases in future
pension expense in accordance with SFAS No. 87.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act 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 deferring recognizing the effects of the
Act in our 2003 financial statements, as permitted by FASB Staff Position No.
106-1. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted.
For additional details on postretirement benefits, see Note 7, Retirement
Benefits.
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. Accretion of $1 million related to the Big Rock and
Palisades' profit component included in the estimated cost of removal was
expensed in 2003.
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.
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Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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, were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
For additional details on ARO, see Note 12, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. They require, and we have established,
external trust funds to finance the decommissioning of both plants. Our electric
customers pay a surcharge to fund these trusts. 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. Spent fuel
storage costs would not be incurred if the DOE took possession of the spent
fuel. There is litigation underway to recover these costs.
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 was stopped since it was
considered fully funded, subject to further MPSC review. The funds provided by
the trusts, additional customer surcharges, and potential funds from DOE
litigation are all required to cover fully the decommissioning costs and we
currently expect that to happen. 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.
For additional details on nuclear decommissioning, see Note 1, Corporate
Structure and Accounting Policies, "Nuclear Plant Decommissioning."
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties.
These transactions include:
- purchases of capacity and energy from the MCV Partnership and from
affiliates of Enterprises,
- sale of storage and transportation of natural gas and other services to
the MCV Partnership,
- issuance of Trust Preferred Securities with Consumers' affiliated
companies,
- purchases and sales of electricity and gas for generation from CMS ERM,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
CE-14
- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates, and the sale of
storage and transportation of natural gas and other services to the MCV
Partnership are generally based on regulated prices, market prices or
competitive bidding. Transactions involving the power supply purchases from the
MCV Partnership, and certain affiliates of Enterprises, are based upon avoided
costs under PURPA and competitive bidding. The payment of parent company
overhead costs is based on use of accepted industry allocation methodologies.
In 2002, MTH purchased our transmission facilities. MTH is a non-affiliated
limited partnership whose general partner is a subsidiary of Trans-Elect, Inc.,
an independent company, whose management includes former executive employees of
CMS Energy. The sale was based on competitive bidding. We continue to use the
transmission facilities now owned by MTH, and one of our directors is currently
a stockholder of Trans-Elect, Inc.
For additional details on related party transactions, see Note 1, Corporate
Structure and Accounting Policies, "Related Party Transactions," Note 2,
Uncertainties, "Electric Restructuring Matters - Transmission Sales," and "Other
Electric Uncertainties -- The Midland Cogeneration Venture."
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
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. As a result, in 2003, 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
implemented our strategic plan, including reducing 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
SELECTED MEASURES OF LIQUIDITY AND CAPITAL RESOURCES:
2003
----
Working capital (in millions)............................... $450
Current ratio............................................... 1.47:1
In 2003, working capital was driven primarily by the following:
- cash proceeds from long-term debt issuance -- $1,603 million
partially offset by:
- cash used for long-term debt retirements, excluding current
portion -- $483 million,
- cash used for pension contributions, excluding notes payable to related
party -- $301 million, and
- cash used for capital expenditures -- $486 million.
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SUMMARY OF CASH FLOWS:
2003 2002 2001
---- ---- ----
IN MILLIONS
Net cash provided by (used in):
Operating activities...................................... $ 5 $ 760 $ 518
Investing activities...................................... (528) (325) (807)
Financing activities...................................... 325 (204) 281
----- ----- -----
Net Increase (Decrease) in Cash and Cash Equivalents........ $(198) $ 231 $ (8)
===== ===== =====
OPERATING ACTIVITIES:
2003: Net cash provided by operating activities decreased $755 million in
2003 primarily due to an increase in pension plan contributions of $454 million
and an increase in gas inventory of $346 million due to higher gas purchases at
higher prices.
2002: Net cash provided by operating activities increased $242 million in
2002 primarily due to a decrease in gas inventory of $397 million due to a lower
volume of gas purchased at lower prices, combined with increased sales volume at
higher prices. This increase was partially offset by an increase in accounts
receivable and accrued revenue of $247 million due to a gas rate increase,
colder weather in the fourth quarter of 2002, and increased electric deliveries
to higher margin customer sectors.
INVESTING ACTIVITIES:
2003: Net cash used in investing activities increased $203 million in 2003
primarily due to a decrease in asset sale proceeds of $288 million resulting
from the sale of METC in 2002, offset by a decrease in 2003 versus 2002 capital
expenditures of $73 million as a result of our strategic plan to reduce capital
expenditures.
2002: Net cash used in investing activities decreased $482 million in 2002
primarily due to a decrease in capital expenditures of $186 million as a result
of our strategic plan to reduce capital expenditures, and an increase in asset
sale proceeds of $298 million resulting from the sale of METC.
FINANCING ACTIVITIES:
2003: Net cash provided by financing activities increased $529 million in
2003 primarily due to an increase in net proceeds from borrowings of $490
million. For additional details on long-term debt activity, see Note 3,
Financings and Capitalization.
2002: Net cash used in financing activities increased $485 million in 2002
primarily due to a decrease in proceeds from securitization bonds of $459
million and a decrease in proceeds from preferred securities of $121 million.
The decrease in proceeds was partially offset by an increase in net proceeds
from borrowings of $101 million. For additional details on long-term debt
activity, see Note 3, Financings and Capitalization.
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OBLIGATIONS AND COMMITMENTS
The following schedule is a summary of our contractual obligations and
commercial commitments. We aggregate this information into a single location so
that a picture of our obligations and commitments is readily available. For
additional details, see Note 2, Uncertainties, and Note 3, Financings and
Capitalization.
DECEMBER 31
----------------------------------------------------
PAYMENTS DUE
----------------------------------------------------
2009 AND
TOTAL 2004 2005 2006 2007 2008 BEYOND
----- ---- ---- ---- ---- ---- --------
IN MILLIONS
CONTRACTUAL OBLIGATIONS
On-balance sheet:
Long-term debt....................... $ 3,611 $ 28 $ 328 $422 $ 31 $441 $ 2,361
Long-term debt -- related parties.... 506 -- -- -- -- -- 506
Notes payable -- related parties..... 200 200 -- -- -- -- --
Capital lease obligations............ 68 10 11 10 10 8 19
------- ------ ------ ---- ---- ---- -------
Total on-balance sheet............ $ 4,385 $ 238 $ 339 $432 $ 41 $449 $ 2,886
------- ------ ------ ---- ---- ---- -------
Off-balance sheet:
Operating leases..................... $ 64 $ 9 $ 8 $ 7 $ 6 $ 5 $ 29
Non-recourse debt.................... 200 63 41 26 13 29 28
Capital lease obligation - MCV....... 144 16 9 8 8 8 95
Sale of accounts receivable.......... 297 297 -- -- -- -- --
Unconditional purchase obligations
(a)............................... 17,903 1,961 1,323 958 776 736 12,149
------- ------ ------ ---- ---- ---- -------
Total off-balance sheet........... $18,608 $2,346 $1,381 $999 $803 $778 $12,301
======= ====== ====== ==== ==== ==== =======
-------------------------
(a) Purchase obligations related to the MCV Facility PPA assume that the
regulatory out provision is exercised in 2007. For additional details, see
Note 2, Uncertainties, "Other Electric Uncertainties - The Midland
Cogeneration Venture," "Commitments for Future Purchases," and "Gas
Contingencies - Other Gas Uncertainties."
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers must obtain FERC
authority to issue short and long-term securities. For additional details of
Consumers' existing authority, see Note 3, Financings and Capitalization.
LONG-TERM DEBT: Details on our long-term debt issuances, retirements, and
outstanding balances are presented in Note 3, Financings and Capitalization.
SHORT-TERM FINANCINGS: We have $390 million available under a revolving
credit facility. At December 31, 2003, the line is available for general
corporate purposes, working capital, and letters of credit. For additional
details, see Note 3, Financings and Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of
leased service vehicles and 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,
- sale of accounts receivable, and
- unconditional purchase obligations.
Operating Leases: Leases of railroad cars are accounted for as operating
leases.
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Non-recourse Debt: Our share of unconsolidated debt associated with
partnerships and joint ventures in which we have a minority interest is
non-recourse.
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we currently sell up to $325 million of certain accounts receivable.
For additional details, see Note 3, 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 including the MCV Facility. These
contracts require us to make monthly capacity payments based on the plants'
availability or deliverability. These payments will approximate $47 million per
month during 2004, including $34 million related to the MCV Facility. 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,"
and "Other Electric Uncertainties -- The Midland Cogeneration Venture."
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.
DECEMBER 31
-------------------------------------------------------------
COMMITMENT EXPIRATION
-------------------------------------------------------------
2009 AND
TOTAL 2004 2005 2006 2007 2008 BEYOND
----- ---- ---- ---- ---- ---- --------
IN MILLIONS
COMMERCIAL COMMITMENTS
Off-balance sheet:
Indemnities.................................... $ 8 $8 $ -- $ -- $ -- $ -- $ --
Letters of credit.............................. 10 5 5 -- -- -- --
DIVIDEND RESTRICTIONS: Under the provisions of our articles of
incorporation, at December 31, 2003, we had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in our
debt facilities cap common stock dividend payments at $300 million in a calendar
year. Through December 31, 2003, we made the following common stock dividend
payments:
IN MILLIONS
-----------
January..................................................... $ 78
May......................................................... 31
June........................................................ 53
November.................................................... 56
----
Total common stock dividends paid to CMS Energy............. $218
====
As of December 18, 2003, we are also under an annual dividend cap of $190
million imposed by the MPSC during the current interim gas rate relief period.
Because all of the $218 million of common stock dividends to
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CMS Energy were paid prior to December 18, 2003, we were not out of compliance
with this new restriction for 2003. In February 2004, we paid a $78 million
common stock dividend.
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order, see Note 2, Uncertainties, "Electric
Restructuring Matters -- Securitization." Also, 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."
CAPITAL EXPENDITURES:
We estimate the following capital expenditures, including new lease
commitments, by expenditure type and by business segments during 2004 through
2006. We prepare these estimates for planning purposes and may revise them.
YEARS ENDING
DECEMBER 31
--------------------
2004 2005 2006
---- ---- ----
IN MILLIONS
Construction................................................ $505 $541 $687
Nuclear fuel................................................ 36 -- 32
Other capital leases........................................ 9 14 21
---- ---- ----
$550 $555 $740
==== ==== ====
Electric utility operations(a)(b)........................... $395 $370 $570
Gas utility operations(a)................................... 155 185 170
---- ---- ----
$550 $555 $740
==== ==== ====
-------------------------
(a) These amounts include a portion of our anticipated capital expenditures for
plant and equipment attributable to both the electric and gas utility
businesses.
(b) These amounts include estimates for capital expenditures that may be
required by revisions to the Clean Air Act's national air quality
standards.
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.
For 2003, our electric deliveries, including delivery to customers who
chose to buy generation service from an alternative electric supplier, declined
1.4 percent from 2002. This was due to a combination of warmer than normal
summer weather in 2002, cooler than normal summer weather in 2003, and a decline
in manufacturing activity during 2003. In 2004, we project electric deliveries
to grow more than three percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
throughout the year.
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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, and
- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- potential rising pension costs due to market losses and lump sum
payments. For additional details, see "Accounting for Pension and OPEB"
section within this MD&A.
- pending litigation and government investigations.
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,
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- 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 8.1 percent. As of December 31,
2003, we have incurred $446 million in capital expenditures to comply with these
regulations and anticipate that the remaining $325 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.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
The EPA continues to make new rules. The EPA has proposed changes to the
rules that govern generating plant cooling water intake systems. The proposed
rules are scheduled to be final in the first quarter of 2004. We are studying
the proposed 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 March 2004, alternative electric suppliers are providing 735 MW of
generation supply to ROA customers. This amount represents nine percent of our
distribution load and an increase of 42 percent compared to March 2003. We
anticipate this upward trend to continue and expect over 1,000 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 charge a transition surcharge of
approximately 0.4 cent per kWh to ROA customers and eliminates securitization
offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh
for secondary service customers. We are seeking similar recovery of Stranded
Costs due to ROA customers leaving our system and are encouraged by this ruling.
This ruling may change significantly the anticipated number of customers who
choose ROA.
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 financing order will become effective after acceptance by us and
resolution of any appeals.
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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 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
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 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 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. We
cannot predict how the MPSC will rule on our request 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 has reviewed and
allowed certain of the implementation costs incurred through 2001, but has not
authorized recovery. Depending upon the outcome of the remanded Securitization
proceeding, a significant portion of the implementation costs could be recovered
through the Securitization process.
Our application for $2 million of implementation costs in 2002 is currently
pending approval by the MPSC. We deferred these costs as a regulatory asset. In
addition to the implementation costs filed with the MPSC in 2003, we recorded an
additional $2 million for total implementation costs of $91 million. Included in
total implementation costs is $19 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 the rate cap period has expired. For
additional information on rate caps, see "Rate Caps" within this section. Once a
final financing order by the MPSC on Securitization is issued, the
recoverability of the implementation costs requested will be known. We cannot
predict the amounts the MPSC will approve as allowable costs. Also, we are
pursuing authorization at the FERC for 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 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. In addition, we
continue to pursue other potential means of recovery with FERC. We cannot
predict the outcome of the appeal process or the ultimate amount, if any, the
FERC will allow us to collect for implementation 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:
- a rate freeze effective through December 31, 2003, and
- rate caps effective through December 31, 2004 for small commercial and
industrial customers, and 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
needed 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: Prior to 1998, the PSCR process provided for the reconciliation of
actual power supply costs with power supply revenues. This process assured
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
1998, as part of the
CE-22
electric restructuring efforts, the MPSC suspended the PSCR process, effective
through 2001. As a result of the rate freeze imposed by the Customer Choice Act,
frozen rates remained in effect until December 31, 2003, and the PSCR process
remained suspended. Therefore, changes in power supply costs due to fluctuating
electricity prices were not reflected in rates charged to our customers during
the rate freeze period.
As a result of meeting the transmission capability expansion requirements
and the market power test, we have met the requirements under the Customer
Choice Act to return to the PSCR process. For additional details see Note 2,
Uncertainties, "Electric Restructuring Matters -- Electric Restructuring
Legislation."
Accordingly, 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 cap, 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. We continued to collect the equivalent to the Big Rock
nuclear decommissioning surcharge consistent with the Customer Choice Act rate
freeze in effect through December 31, 2003. Collection of the surcharge stopped,
effective January 1, 2004, when the electric rate freeze expired. As a result,
our electric revenues will be reduced by $35 million in 2004. However, we expect
a portion of this reduction to be offset with increased electric revenues from
returning to the PSCR process.
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 December 31, 2003, contracts for 301 MW of load have
terminated. Of the contracts that have terminated, contracts for 64 MW have gone
to an alternative electric supplier and contracts for 237 MW 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. Other new
special contracts for 101 MW received interim approval from the MPSC and are
awaiting final approval. All new special contracts end by January 1, 2006. We
cannot predict the ultimate financial impact of changes related to these power
supply contracts, or whether additional special contracts will be necessary or
advisable.
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
impact 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 significantly affect:
- 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
currently quantifiable. 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.
CE-23
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.
Approximately 100,000 of our 1.7 million electric customers were without power
for approximately 24 hours as a result of the disturbance. We incurred $1
million of immediate expense as a result of the blackout. We continue to
cooperate with investigations of the blackout by several federal and state
agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan, or actions
taken by the Michigan utilities or transmission operators, were factors
contributing to the cause of the blackout. Also in November 2003, the United
States and Canadian power system outage taskforce preliminarily reported that
the primary cause of the blackout was due to transmission line contact with
trees in areas outside of Consumers' operating territory. In December 2003, the
MPSC issued an order requiring Consumers to report by April 1, 2004, the status
of lines used to serve our customers, including details of vegetation trimming
practices in calendar year 2003. Consumers intends to comply with the MPSC's
request.
In February 2004, the Board of Trustees of NERC approved recommendations to
improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout 2004. These
recommendations could result in increased transmission costs payable by
transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
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."
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC became effective in February 2004. The performance
standards establish standards related 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 value
of such incentive cannot be determined at this point as the performance
standards do not contain an approved incentive mechanism. Financial penalties in
the form of customer credits are also possible. These customer credits are based
on duration and repetition of outages. We cannot predict the likely effects of
the financial incentive or penalties, if any, on us.
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.
CE-24
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 cost at a number of sites, including sites
formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases,
- potential adverse appliance service plan ruling or related legislation,
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 "Accounting for Pension and OPEB" section within this
MD&A, and
- pending litigation and government investigations.
Consumers sells 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, Consumers purchases gas for resale on a Btu
basis. The Btu content of the gas available for purchase has increased and may
result in customers using less gas for the same heating requirement. Consumers
fully recovers what it spends to purchase the gas through the approved GCR.
However, since the customer is using less gas on a volumetric basis, the revenue
from the distribution charge (the non-gas cost portion of the customer bill)
would be reduced. This could affect adversely Consumers' earnings from its gas
utility. The amount of the earnings loss 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 FERC for clarification or rehearing of FERC's December 2003 order. We
cannot predict the outcome of this filing.
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 February 2004, the parties in the
case reached a tentative settlement agreement that would result in a GCR
disallowance of $11 million for the GCR period plus $1 million accrued interest
through February 2004. A reserve was recorded in December 2003. 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
CE-25
$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 rate 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. The MPSC is not bound by these
recommendations and will consider the issues anew after receipt of exceptions
and replies to the exception filed by the parties in response to the Proposal
for Decision.
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
independent of the 2003 gas rate case. 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.
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 are in the process of filing 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.
The Michigan House of Representatives is scheduled to review the proposed
legislation in 2004 that would allow us to remain in the appliance service
business. In the interim, the legislature passed a bill to extend to July 1,
2004, the deadline for exiting this business. The full impact of the new code of
conduct on our business will remain uncertain until the final judicial
resolution of our appeal or the Michigan legislature enacts clarifying
legislation.
LITIGATION AND REGULATORY INVESTIGATIONS: CMS Energy is the subject of
various investigations as a result of round-trip trading transactions by CMS
MST, including investigations by the United States Department of Justice and the
SEC. Additionally, CMS Energy and Consumers are parties to 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.
CE-26
OTHER MATTERS
2001 GAS RATE CASE: In June 2001, we filed an application with the MPSC for
a distribution service rate increase. In November 2002, the MPSC approved a $56
million annual distribution service rate increase, with an 11.4 percent
authorized return on equity.
NEW ACCOUNTING STANDARDS
See Note 13, Implementation of New Accounting Standards, for discussion of
new standards.
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: 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 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 provides an implementation deferral until the
first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the
first quarter of 2004 for all entities other than special purpose entities.
Special purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
We also determined that we do not hold the controlling financial interest
in 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 have reflected $506 million of long-term debt -- related
parties and have 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.
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 is expected to be presented for FASB clearance in 2004 and
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment often comprises multiple parts and
costs. A component accounting policy determines the level at which those parts
are recorded. Capitalization of certain costs related to property, plant, and
equipment are included in the total cost. The Statement of Position could impact
our component and capitalization accounting for property, plant, and equipment.
We continue to evaluate the impact, if any, this Statement of Position will have
upon adoption.
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CE-28
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31
--------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
OPERATING REVENUE........................................... $4,435 $4,169 $3,976
EARNINGS FROM EQUITY METHOD INVESTEES....................... 42 53 38
OPERATING EXPENSES
Fuel for electric generation.............................. 320 320 330
Purchased power -- related parties........................ 519 564 559
Purchased and interchange power........................... 310 296 460
Cost of gas sold.......................................... 1,221 831 707
Cost of gas sold -- related parties....................... 28 131 123
Other..................................................... 739 660 625
------ ------ ------
3,137 2,802 2,804
Maintenance............................................... 199 190 203
Depreciation.............................................. 316 300 309
Amortization.............................................. 61 48 30
General taxes............................................. 181 193 187
------ ------ ------
3,894 3,533 3,533
------ ------ ------
OPERATING INCOME (LOSS)..................................... 583 689 481
OTHER INCOME (DEDUCTIONS)
Dividends and interest from affiliates.................... 2 3 6
Accretion expense......................................... (7) (6) (11)
Other, net................................................ -- 25 6
------ ------ ------
(5) 22 1
------ ------ ------
INTEREST CHARGES
Interest on long-term debt................................ 196 153 151
Interest on long-term debt -- related parties............. 45 -- --
Other interest............................................ 13 27 41
Capitalized interest...................................... (9) (12) (6)
------ ------ ------
245 168 186
------ ------ ------
INCOME BEFORE INCOME TAXES.................................. 333 543 296
INCOME TAXES................................................ 137 180 97
------ ------ ------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE................................................. 196 363 199
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR DERIVATIVE
INSTRUMENTS, NET OF $10 TAX IN 2002 (NOTE 11) AND $6 TAX
BENEFIT IN 2001 (NOTE 4).................................. -- 18 (11)
------ ------ ------
NET INCOME.................................................. 196 381 188
PREFERRED STOCK DIVIDENDS................................... 2 2 2
PREFERRED SECURITIES DISTRIBUTIONS.......................... -- 44 41
------ ------ ------
NET INCOME AVAILABLE TO COMMON STOCKHOLDER.................. $ 194 $ 335 $ 145
====== ====== ======
The accompanying notes are an integral part of these statements.
CE-29
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
----------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 196 $ 381 $ 188
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes
nuclear decommissioning of $6, $6, and $6,
respectively)....................................... 377 348 339
Deferred income taxes and investment tax credit...... 195 277 136
Capital lease and other amortization................. 28 15 20
Gain on sale of METC and other assets................ (1) (38) --
Loss on CMS Energy stock............................. 12 12 --
Cumulative effect of change in accounting............ -- (18) 11
Distributions from related parties in excess of (less
than) earnings (net of dividends, $45, $15, and $8,
respectively)....................................... 3 (38) (30)
Pension contribution................................. (501) (47) (49)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable and
accrued revenue................................. (12) (98) 149
Increase (decrease) in accounts payable........... (61) (39) 53
Decrease (increase) in inventories................ (256) 90 (307)
Changes in other assets and liabilities........... 25 (85) 8
------ ----- -----
Net cash provided by operating activities....... 5 760 518
------ ----- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital
lease)................................................. (486) (559) (745)
Cost to retire property................................... (72) (66) (118)
Restricted cash on hand(a)................................ -- (14) (4)
Investments in Electric Restructuring Implementation
Plan................................................... (8) (8) (13)
Investments in nuclear decommissioning trust funds........ (6) (6) (6)
Associated company preferred stock redemption............. -- -- 50
Proceeds from nuclear decommissioning trust funds......... 34 30 29
Cash proceeds from sale of assets......................... 10 298 --
------ ----- -----
Net cash used in investing activities.................. (528) (325) (807)
------ ----- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt.................. 1,603 601 355
Retirement of long-term debt.............................. (788) (574) (401)
Payment of common stock dividends......................... (218) (231) (190)
Preferred securities distributions........................ -- (44) (41)
Redemption of preferred securities........................ -- (30) --
Payment of capital lease obligations...................... (13) (15) (20)
Contribution from (return of equity to) stockholder,
net.................................................... -- 50 (14)
Payment of preferred stock dividends...................... (2) (2) (1)
Increase (decrease) in notes payable, net................. (257) 41 13
Proceeds from preferred securities........................ -- -- 121
Proceeds from securitization bonds........................ -- -- 459
------ ----- -----
Net cash provided by (used in) financing activities.... 325 (204) 281
------ ----- -----
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (198) 231 (8)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. 244 13 21
------ ----- -----
CASH AND CASH EQUIVALENTS, END OF PERIOD(A)................. $ 46 $ 244 $ 13
====== ===== =====
CE-30
YEARS ENDED DECEMBER 31
----------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND
FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized)................ $ 227 $ 147 $ 169
Income taxes paid (net of refunds, $91, $205, and $53,
respectively).......................................... (56) (78) 3
OPEB cash contribution.................................... 71 73 47
NON-CASH TRANSACTIONS
Nuclear fuel placed under capital leases.................. $ -- $ -- $ 13
Other assets placed under capital lease................... 19 62 37
-------------------------
(a) Cash and Cash Equivalents decreased $18 million for 2002 and $4 million for
2001 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-31
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
-----------
2003 2002
---- ----
IN MILLIONS
ASSETS
PLANT AND PROPERTY (AT COST)
Electric.................................................. $ 7,600 $ 7,523
Gas....................................................... 2,875 2,719
Other..................................................... 15 23
------- -------
10,490 10,265
Less accumulated depreciation, depletion, and amortization
(Note 12).............................................. 4,417 4,993
------- -------
6,073 5,272
Construction work-in-progress............................. 375 548
------- -------
6,448 5,820
------- -------
INVESTMENTS
Stock of affiliates....................................... 20 22
First Midland Limited Partnership......................... 224 255
Midland Cogeneration Venture Limited Partnership.......... 419 388
Other..................................................... 18 2
------- -------
681 667
------- -------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates
market................................................. 46 244
Restricted cash........................................... 18 18
Accounts receivable, notes receivable and accrued revenue,
less allowances of $8 in 2003 and $5 in 2002........... 257 236
Accounts receivable -- related parties.................... 4 13
Inventories at average cost
Gas in underground storage............................. 739 486
Materials and supplies................................. 70 71
Generating plant fuel stock............................ 41 37
Deferred property taxes................................... 143 142
Regulatory assets -- postretirement benefits.............. 19 19
Other..................................................... 80 38
------- -------
1,417 1,304
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs...................................... 648 689
Postretirement benefits................................ 162 185
Abandoned Midland project.............................. 10 11
Other.................................................. 266 168
Nuclear decommissioning trust funds....................... 575 536
Prepaid pension costs..................................... 364 --
Other..................................................... 174 218
------- -------
2,199 1,807
------- -------
TOTAL ASSETS................................................ $10,745 $ 9,598
======= =======
CE-32
DECEMBER 31
-----------------
2003 2002
---- ----
IN MILLIONS
STOCKHOLDER'S INVESTMENT AND LIABILITIES
CAPITALIZATION
Common stockholder's equity
Common stock, authorized 125.0 shares; outstanding 84.1
shares for all periods................................ $ 841 $ 841
Paid-in capital........................................ 682 682
Accumulated other comprehensive income (loss).......... 17 (179)
Retained earnings since December 31, 1992.............. 521 545
------- ------
2,061 1,889
Preferred stock (Note 3).................................. 44 44
Company-obligated mandatorily redeemable Trust Preferred
Securities of subsidiaries (Note 3).................... -- 490
Long-term debt............................................ 3,583 2,442
Long-term debt -- related parties (Note 3)................ 506 --
Non-current portion of capital leases..................... 58 116
------- ------
6,252 4,981
------- ------
CURRENT LIABILITIES
Current portion of long-term debt and capital leases...... 38 318
Notes payable............................................. -- 457
Note payable -- related parties........................... 200 --
Accounts payable.......................................... 200 252
Accrued taxes............................................. 209 214
Accounts payable -- related parties....................... 75 84
Current portion of purchase power contracts............... 27 26
Deferred income taxes..................................... 33 25
Other..................................................... 185 200
------- ------
967 1,576
------- ------
NON-CURRENT LIABILITIES
Deferred income taxes..................................... 1,233 949
Regulatory liabilities for cost of removal (Note 12)...... 983 907
Postretirement benefits................................... 190 563
Regulatory liabilities for income taxes, net.............. 312 297
Asset retirement obligations.............................. 358 --
Other regulatory liabilities.............................. 172 4
Power purchase agreement -- MCV Partnership............... -- 27
Deferred investment tax credit............................ 85 91
Other..................................................... 193 203
------- ------
3,526 3,041
------- ------
Commitments and Contingencies (Notes 1, 2, 5, 7, 8, and
11)
TOTAL STOCKHOLDER'S INVESTMENT AND LIABILITIES.............. $10,745 $9,598
======= ======
The accompanying notes are an integral part of these statements.
CE-33
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
YEARS ENDED DECEMBER 31
--------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
COMMON STOCK
At beginning and end of period (a)........................ $ 841 $ 841 $ 841
OTHER PAID-IN CAPITAL
At beginning of period.................................... 682 632 646
Stockholder's contribution................................ -- 150 150
Return of stockholder's contribution...................... -- (100) (164)
------ ------ ------
At end of period.......................................... 682 682 632
------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period................................. (185) -- --
Minimum pension liability adjustments (b).............. 185 (185) --
------ ------ ------
At end of period..................................... -- (185) --
------ ------ ------
Investments
At beginning of period................................. 1 16 33
Unrealized gain (loss) on investments (b).............. 8 (16) (16)
Reclassification adjustments included in net income
(b)................................................... -- 1 (1)
------ ------ ------
At end of period..................................... 9 1 16
------ ------ ------
Derivative Instruments
At beginning of period (c)............................. 5 (12) 18
Unrealized gain (loss) on derivative instruments (b)... 13 10 (30)
Reclassification adjustments included in net income
(b)................................................... (10) 7 --
------ ------ ------
At end of period..................................... 8 5 (12)
------ ------ ------
Total Accumulated Other Comprehensive Income (Loss)......... 17 (179) 4
------ ------ ------
RETAINED EARNINGS
At beginning of period.................................... 545 441 486
Net income (b)............................................ 196 381 188
Cash dividends declared -- Common Stock................... (218) (231) (190)
Cash dividends declared -- Preferred Stock................ (2) (2) (2)
Preferred securities distributions........................ -- (44) (41)
------ ------ ------
At end of period.......................................... 521 545 441
------ ------ ------
TOTAL COMMON STOCKHOLDER'S EQUITY........................... $2,061 $1,889 $1,918
====== ====== ======
-------------------------
(a) Number of shares of common stock outstanding was 84,108,789 for all periods
presented.
CE-34
(b) Disclosure of Comprehensive Income:
Other comprehensive income (loss)
2003 2002 2001
---- ---- ----
IN MILLIONS
Minimum pension liability adjustments, net of tax (tax
benefit) of $100, $(100), and $--, respectively........... $185 $(185) --
Investments
Unrealized loss on investments, net of tax (tax benefit)
of $4, $(9), and $(9), respectively.................... 8 (16) (16)
Reclassification adjustments included in net income, net
of tax (tax benefit) of $--, $1, and $(1),
respectively........................................... -- 1 (1)
Derivative Instruments
Unrealized gain (loss) on derivative instruments, net of
tax (tax benefit) of $7, $6, and $(15), respectively... 13 10 (30)
Reclassification adjustments included in net income, net
of tax (tax benefit) of $(5), $4, and $--,
respectively........................................... (10) 7 --
Net income.................................................. 196 381 188
---- ----- ----
Total Comprehensive Income.................................. $392 $ 198 $141
==== ===== ====
(c) Cumulative effect of change in accounting principle, as of 1/1/01 and
7/1/01, net of tax of $9 (Note 4).
The accompanying notes are an integral part of these statements.
CE-35
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, in accordance with Revised FASB Interpretation No. 46. Intercompany
transactions and balances have been eliminated. 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 not a controlling financial interest.
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.
REVENUE RECOGNITION POLICY: Revenues from deliveries of electricity and
natural gas, and the storage of natural gas are recognized when services are
provided. Sales taxes are recorded as liabilities and are not included in
revenues.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents. At
December 31, 2003, our restricted cash on hand was $18 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.
COAL INVENTORY: We use the weighted average cost method for valuing coal
inventory.
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, including our
investment in CMS Energy Common Stock, are classified as available-for-sale.
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. For additional details regarding financial
instruments, see Note 4, Financial and Derivative Instruments, "Financial
Instruments."
GAS INVENTORY: We use the weighted average cost method for valuing working
gas and recoverable cushion gas in underground storage facilities.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential
impairment of our investments in projects and other long-lived assets, other
than goodwill, based on various analyses, including the projection of
undiscounted cash flows, whenever events or changes in circumstances indicate
that the carrying amount of the assets may not be recoverable. If the carrying
amount of the investment or asset exceeds the amount of the expected future
undiscounted cash flows, an impairment loss is recognized, and the investment or
asset is written down to its estimated fair value.
MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property
replacements to maintenance expense. We also charge planned major maintenance
activities to operating expense unless the cost
CE-36
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
represents the acquisition of additional components or the replacement of an
existing component. We capitalize the cost of plant additions and replacements.
We depreciate utility property on straight-line and units-of-production rates
approved by the MPSC. The composite depreciation rates for our properties are:
YEARS ENDED
DECEMBER 31
---------------------
2003 2002 2001
---- ---- ----
Electric utility property................................... 3.1% 3.1% 3.1%
Gas utility property........................................ 4.6% 4.5% 4.4%
Other property.............................................. 8.1% 7.2% 11.2%
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 December 31, 2003, 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."
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.
Trust Funds: MPSC orders, received in March 1999 for Big Rock and December
1999 for Palisades, provided for fully funding the decommissioning trust funds
for both sites. The December 1999 order set the annual decommissioning surcharge
for Palisades at $6 million. In 2003, we collected $6 million from our electric
customers for the decommissioning of our Palisades nuclear plant. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
In December 2000, we stopped depositing funds in the Big Rock trust fund
based on its funding status at that time. However, the current level of funds
provided by the trust may not be adequate to fully fund the decommissioning of
Big Rock. This is due in part to the DOE's failure to accept spent nuclear fuel
and lower returns on the trust fund. We are attempting to recover our additional
costs for storing spent nuclear fuel through litigation, as discussed in Note 2,
Uncertainties, "Other Electric Uncertainties -- Nuclear Matters." To the extent
the funds are not sufficient, we would seek additional relief from the MPSC. We
can make no assurance that the MPSC would grant this request.
In March 2001, we filed with the MPSC a "Report on the Adequacy of the
Existing Provision for Nuclear Plant Decommissioning" for each plant reflecting
decommissioning cost estimates of $349 million for Big Rock, excluding spent
nuclear fuel storage costs, and $739 million for Palisades, in 2000 dollars. We
are required to file the next such reports with the MPSC by March 31, 2004 for
Big Rock and Palisades and are in the process of preparing updated cost
estimates.
CE-37
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Big Rock: In 1997, Big Rock closed permanently and plant decommissioning
began. We estimate that the Big Rock site will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The
following table shows our Big Rock decommissioning activities:
YEAR-TO-DATE ACCUMULATIVE
DECEMBER 31, 2003 TOTAL-TO-DATE
----------------- -------------
IN MILLIONS
Decommissioning expenditures................................ $45 $263
Withdrawals from trust funds................................ 34 243
These activities had no material impact on net income. At December 31,
2003, we have an investment in nuclear decommissioning trust funds of $88
million for Big Rock. In addition, at December 31, 2003, we have charged $7
million to our FERC jurisdictional depreciation reserve for the decommissioning
of Big Rock.
Palisades: In December 2000, the NRC extended the Palisades operating
license to March 2011 and the impact of this extension was included as part of
our March 2001 filing with the MPSC.
At December 31, 2003, we have an investment in the MPSC nuclear
decommissioning trust funds of $477 million for Palisades. In addition, at
December 31, 2003, we have a FERC decommissioning trust fund with a balance of
$10 million. For additional details on decommissioning costs accounted for as
asset retirement obligations, see Note 12, Asset Retirement Obligations.
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 12, Asset
Retirement Obligation. 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.
CE-38
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Property, plant, and equipment at December 31, 2003 and 2002, was as
follows:
YEARS ENDED DECEMBER 31
------------------------------------
ESTIMATED
DEPRECIABLE
LIFE IN YEARS(E) 2003 2002
---------------- ---- ----
IN MILLIONS
Electric:
Generation................................................ 13-75 $3,332 $3,489
Distribution.............................................. 12-85 3,799 3,619
Other..................................................... 5-50 388 300
Capital leases(a)......................................... 81 115
Gas:
Underground storage facilities(b)......................... 30-75 232 217
Transmission.............................................. 15-75 342 310
Distribution.............................................. 35-75 1,976 1,899
Other..................................................... 5-48 300 237
Capital leases(a)......................................... 25 56
Other:
Non-utility property...................................... 7-71 15 23
Construction work-in-progress(c).......................... 375 548
Less accumulated depreciation, depletion, and
amortization.............................................. 4,417 4,993
------ ------
Net property, plant, and equipment(d)....................... $6,448 $5,820
====== ======
-------------------------
(a) Capital leases presented in this table are gross amounts. Amortization of
capital leases was $38 million in 2003 and $96 million in 2002.
(b) Includes unrecoverable base natural gas in underground storage of $23
million at December 31, 2003 and $23 million at December 31, 2002, which is
not subject to depreciation.
(c) Included in construction costs at December 31, 2002 was $54 million,
relating to the capital lease of our main headquarters. We purchased the
main headquarters in November 2003.
(d) Included in net property, plant and equipment are intangible assets
primarily related to software development costs, consents, and rights of
way. The estimated amortization life for software development costs is
seven years and other intangible amortization lives range from 50 to 75
years. Intangible assets at December 31, 2003 and 2002, were as follows:
YEARS ENDED
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Intangible assets at cost................................... $336 $304
Less accumulated amortization............................... 184 167
---- ----
Net intangible assets....................................... $152 $137
==== ====
CE-39
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(e) The following table illustrates the depreciable life for electric and
gas structures and improvements.
ESTIMATED ESTIMATED
DEPRECIABLE DEPRECIABLE
ELECTRIC LIFE IN YEARS GAS LIFE IN YEARS
-------- ------------- --- -------------
Generation:
Coal............................ 39-43 Underground storage facilities 45
Nuclear......................... 25 Transmission 60
Hydroelectric................... 55-71 Distribution 60
Other........................... 32 Other 42-48
Distribution...................... 50-60
Other............................. 40-42
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
RELATED PARTY TRANSACTIONS: We received income from related parties as
follows:
TYPE OF INCOME RELATED PARTY 2003 2002 2001
-------------- ------------- ---- ---- ----
IN MILLIONS
Gas sales, storage, transportation and other
services............................................. MCV Partnership $17 $27 $27
Dividend income........................................ Consumers' affiliated
Trust Preferred
Securities companies 2 -- --
Dividend income........................................ CMS Energy parent
company -- 3 6
We sell, store, and transport natural gas, as well as provide various other
services to the MCV Partnership. For additional details on transactions with the
MCV Partnership and the FMLP, see Note 2, Uncertainties, "Other Electric
Uncertainties -- The Midland Cogeneration Venture," and Note 11, Summarized
Financial Information of Significant Related Energy Supplier.
We issued Trust Preferred Securities through several Consumers' affiliated
companies. As of December 31, 2003, we deconsolidated the trusts that hold the
mandatorily redeemable Trust Preferred Securities. As a result of the
deconsolidation, we now record on the Consolidated Statements of Income interest
on long-term debt -- related parties to the trusts holding the Trust Preferred
Securities. For additional information on Consumers' affiliated Trust Preferred
Securities companies, see Note 3, Financings and Capitalization,
"Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries"
and Note 13, Implementation of New Accounting Standards.
We own 2.4 million shares of CMS Energy Common Stock with a fair value of
$20 million at December 31, 2003. For additional details on our investment in
CMS Energy Common Stock, see Note 4, Financial and Derivative Instruments.
CE-40
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
We recorded expense from related parties as follows:
TYPE OF COST RELATED PARTY 2003 2002 2001
------------ ------------- ---- ---- ----
IN MILLIONS
Electric generating capacity and energy..... MCV Partnership $455 $497 $488
Electric generating capacity and energy..... Affiliates of Enterprises 64 67 71
Interest expense on long-term debt.......... Consumers' affiliated Trust
Preferred Securities
companies 45 -- --
Gas purchases............................... CMS MST 27 127 120
Overhead expense............................ CMS Energy parent company 8 18 11
Gas transportation.......................... CMS Bay Area Pipeline, L.L.C 4 4 4
Gas transportation.......................... Panhandle/Trunkline 1 22 21
We pay overhead costs to CMS Energy based on accepted industry allocation
methodologies, such as the Massachusetts Formula. We base our other related
party transactions on regulated prices, market prices, or competitive bidding.
TRADE RECEIVABLES: We record our accounts receivable at fair value.
Accounts deemed uncollectable are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We amortize premiums,
discounts, and expenses incurred in connection with the issuance of outstanding
long-term debt over the terms of the issues. For the regulated portions of our
businesses, if debt is refinanced, we amortize any unamortized premiums,
discounts, and expenses over the term of the new debt.
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.
In 1999, we received MPSC electric restructuring orders, which, among other
things, identified the terms and timing for implementing electric restructuring
in Michigan. Consistent with these orders and EITF No. 97-4, we discontinued the
application of SFAS No. 71 for the energy supply portion of our business because
we expected to implement ROA at competitive market based rates for our electric
customers.
Since 1999, there have been significant legislative and regulatory changes
in Michigan that has resulted in:
- electric supply customers of utilities remaining on cost-based rates, and
- utilities being provided the opportunity to recover Stranded Costs
associated with electric restructuring, from customers who choose an
alternative electric supplier.
During 2002, we re-evaluated the criteria used to determine if an entity or
a segment of an entity meets the requirements to apply regulated utility
accounting, and determined that the energy supply portion of our business could
meet the criteria if certain regulatory events occurred. In December 2002, we
received a MPSC Stranded Cost order that allowed us to re-apply regulatory
accounting standard SFAS No. 71 to the energy supply portion of our business.
Re-application of SFAS No. 71 had no effect on the prior discontinuation
accounting, but allowed us to apply regulatory accounting treatment to the
energy supply portion of our business beginning in the fourth quarter of 2002,
including regulatory accounting treatment of costs required to be recognized in
accordance with SFAS No. 143. For additional details, see Note 12, Asset
Retirement Obligations.
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.
CE-41
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following regulatory assets and liabilities, which include both current
and non-current amounts, are reflected in the Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up to 14 years. We
recognized an OPEB transition obligation in accordance with SFAS No. 106 and
established a regulatory asset for this amount that we expect to recover in
rates over the next nine years.
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Securitized costs (Note 2).................................. $ 648 $ 689
Postretirement benefits (Note 7)............................ 181 204
Electric Restructuring Implementation Plan (Note 2)......... 91 83
Manufactured gas plant sites (Note 2)....................... 67 69
Abandoned Midland project................................... 10 11
Unamortized debt............................................ 51 14
Asset retirement obligation (Note 12)....................... 49 --
Other....................................................... 8 2
------ ------
Total regulatory assets..................................... $1,105 $1,072
====== ======
Cost of removal (Note 12)................................... $ 983 $ 907
Income taxes (Note 5)....................................... 312 297
Asset retirement obligation (Note 12)....................... 168 --
Other....................................................... 4 4
------ ------
Total regulatory liabilities................................ $1,467 $1,208
====== ======
In October 2000, we received an MPSC order authorizing us to securitize
certain regulatory assets up to $469 million, net of tax, see Note 2,
Uncertainties, "Electric Restructuring Matters-Securitization." Accordingly, in
December 2000, we established a regulatory asset for securitized costs of $709
million, before tax, that had previously been recorded in other regulatory asset
accounts. To prepare for the financing of the securitized assets and the
subsequent retirement of debt with Securitization proceeds, issuance fees were
capitalized as a part of Securitization costs. These issuance costs are
amortized each month for up to fourteen years. The components of the unamortized
securitized costs are illustrated below.
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Unamortized nuclear costs................................... $405 $405
Postretirement benefits..................................... 84 84
Income taxes................................................ 203 203
Uranium enrichment facility................................. 16 16
Other....................................................... 12 12
Accumulated Securitization cost amortization................ (72) (31)
---- ----
Total unamortized securitized costs......................... $648 $689
==== ====
CE-42
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 conclusions about the causes of the August 14, 2003 blackout,
including exposure to liability, increased regulatory requirements, and
new legislation,
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to purchased
power price increases,
- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel,
- potential adverse appliance service plan ruling or related legislation,
- 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 litigation and government investigations.
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
CE-43
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 other investigations concerning round-trip
trading, including an investigation by the SEC regarding round-trip trades and
CMS Energy's financial statements, accounting policies and controls, and an
investigation by the United States Department of Justice. CMS Energy is unable
to predict the outcome of these matters, and what effect, if any, these
investigations will have on its business.
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. 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. 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. It submitted these rules to
the EPA for approval in the first quarter of 2003. The EPA has yet to approve
the Michigan rules. If the EPA does not approve the Michigan rules, 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 December 31, 2003, we have
incurred $446 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $325 million of capital expenditures will be
incurred 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 a 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
CE-44
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
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.
Future clean air regulations requiring emission controls for sulfur
dioxide, nitrogen oxides, mercury, and nickel may require additional capital
expenditures. Total expenditures will depend upon the final makeup of the new
regulations.
Water: The EPA has proposed changes to the rules that govern generating
plant cooling water intake systems. The proposed rules will require significant
reduction in fish killed by operating equipment. The proposed rules are
scheduled to become final in the first quarter of 2004 and some of our
facilities would be required to comply by 2006. We are studying the proposed
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 December 31, 2003, 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 in regard to the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
effectively suspends the lawsuit until the MPSC rules. 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, 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,
- 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. The MPSC found
that once the planned projects were completed and verification was submitted, a
utility was in technical compliance. 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 PLAN: In 1998, we submitted a plan for electric ROA to the
MPSC. In March 1999, the MPSC issued orders generally supporting the plan. The
Customer Choice Act states that the MPSC orders issued before June 2000 are in
compliance with this act and enforceable by the MPSC. Those MPSC orders:
- allow electric customers to choose their supplier,
- authorize recovery of net Stranded Costs from ROA customers and
implementation costs from all customer classes, and
- confirm any voluntary commitments of electric utilities.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 March 2004, alternative electric suppliers are
providing 735 MW of load. This amount represents nine percent of the total
distribution load and an increase of 42 percent compared to March 2003.
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. 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 of approximately 0.4 cent per kWh to ROA customers and
eliminates securitization offsets of 0.7 cents per kWh for primary service
customers and 0.9 cents per kWh for secondary service customers. We are seeking
similar recovery of Stranded Costs due to ROA customers leaving our system and
are encouraged by this ruling.
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 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 prior to 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, $50
million for the twelve months ended December 31, 2003, and $52 million for the
twelve months ended December 31, 2002, 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. The MPSC rejected the portion of the application related to pension
costs. The MPSC based
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
its decision on the reasoning that a rebounding economy and stock market could
potentially reverse recent Pension Plan losses. Also, the MPSC rejected
Palisades expenditures previously not securitized as eligible securitized costs;
therefore, these costs will be included in a future electric rate case
proceeding with the MPSC and as a component of the 2002 net Stranded Cost
calculation. 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 financing order will become effective after acceptance by us and
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.
We are authorized by the MPSC 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 and 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 in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $85 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. We cannot predict
how the MPSC will rule on our request for the recoverability of Stranded Costs.
Implementation Costs: Since 1997, we have incurred significant electric
utility restructuring 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.
YEAR FILED YEAR INCURRED REQUESTED PENDING ALLOWED DISALLOWED
---------- ------------- --------- ------- ------- ----------
IN MILLIONS
1999............................. 1997 & 1998 $20 $ -- $15 $5
2000............................. 1999 30 -- 25 5
2001............................. 2000 25 -- 20 5
2002............................. 2001 8 -- 8 --
2003............................. 2002 2 2 Pending Pending
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 December 31, 2003, $2 million of
additional implementation costs and $19 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. Cash recovery from customers is expected to begin after the rate cap
period expires. The rate cap expired for large commercial and industrial
customers on December 31, 2003. We have asked to include implementation costs
through December 31, 2000 in the pending Securitization case. If approved, the
sale of Securitization bonds will allow for the recovery of a significant
portion of these costs. We cannot predict the amount the MPSC will approve as
allowable costs.
Also, we are pursuing authorization at the FERC for 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. In May 2003, the FERC issued an order
denying MISO's request for authorization to reimburse us. In June 2003, we filed
a joint petition with MISO for rehearing with the FERC, which the FERC denied in
September 2003. We appealed the FERC ruling at the United States Court of
Appeals for the District of Columbia and are pursuing other potential means of
recovery at the FERC. In conjunction with our appeal of the September order
denying recovery, MISO agreed to file a request with the FERC seeking authority
to reimburse METC. As part of the contract for the sale of our former
transmission system, should the FERC approve the new MISO filing, METC is
contractually obligated to flow-through to us the full amount of any Alliance
RTO start-up costs that it is authorized to recover by FERC. We cannot predict
the outcome of the appeal process, the MISO request, or the ultimate amount, if
any, FERC will allow us to collect for implementation 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 impact
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, transmission rates charged to us are fixed by
contract at current levels through December 31, 2005, and are subject to FERC
ratemaking thereafter. However, we are subject to certain additional MISO
surcharges, which are estimated to be $15 million in 2004.
ELECTRIC RATE MATTERS
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
businesses. Approximately 100,000 of our 1.7 million electric customers were
without power for approximately 24 hours as a result of the disturbance. We
incurred $1 million of immediate expense as a result of the blackout. We
continue to cooperate with investigations of the blackout by several federal and
state agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC
report found no evidence to suggest that the events in Michigan or actions taken
by the Michigan utilities or transmission operators were factors contributing to
the cause of the blackout. Also in November 2003, the United States and Canadian
power system outage task force preliminarily reported that the primary cause of
the blackout was due to transmission line contact with trees in areas outside of
Consumers' operating territory. 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. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to
improve electric transmission reliability. The key recommendations are as
follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is
not, to submit annual reports on vegetation management beginning March 2005 and
improve technology over various milestones throughout 2004. These
recommendations could result in increased transmission costs payable by
transmission customers in the future. The financial impacts of these
recommendations are not currently quantifiable.
PERFORMANCE STANDARDS: Electric distribution performance standards
developed by the MPSC were in proposal status during 2002 and 2003. The
performance standards were placed into Michigan law in January 2004 and became
effective on February 9, 2004. They relate to restoration after an outage,
safety, and customer relations. During 2002 and 2003, Consumers monitored and
reported to the MPSC its 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 value of such
incentive cannot be determined at this point as the performance standards do not
contain an approved incentive mechanism. Financial penalties in the form of
customer credits are also possible. These customer credits are based on duration
and repetition of outages. We cannot predict the likely effects of the financial
incentive or penalties, if any, on us.
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 option 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 December 31, 2003, 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 $20 million for
unexpired capacity and energy contracts. Currently, we have a reserve margin of
5 percent, or supply resources equal to 105 percent of projected summer peak
load for summer 2004. We are in the process of securing the additional capacity
needed to meet our summer 2004 reserve margin target of 11 percent (111 percent
of projected summer
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
peak load). The total premium costs of electricity call option and capacity and
energy contracts for 2003 were approximately $10 million.
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 cap, 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 MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, and
- CMS Holdings holds, through FMLP, a 35 percent lessor interest in the MCV
Facility.
Our consolidated retained earnings include undistributed earnings from the
MCV Partnership, which at December 31, 2003 are $245 million and at December 31,
2002 are $226 million.
Summarized Statements of Income for CMS Midland and CMS Holdings
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Earnings from equity method investees....................... $42 $52 $38
Operating expenses, taxes and other......................... 22 18 13
--- --- ---
Income before cumulative effect of accounting change........ $20 $34 $25
Cumulative effect of change in method of accounting for
derivatives, net of $10 million tax expense in 2002 (Note
11)....................................................... -- 18 --
--- --- ---
Net income.................................................. $20 $52 $25
=== === ===
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $27 million at December 31, 2003, $53 million at December 31,
2002, and $77 million at December 31, 2001. 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:
2004 2005 2006 2007
---- ---- ---- ----
IN MILLIONS
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 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 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 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
our equity interest in the MCV Partnership may be affected negatively.
Under the PPA, variable energy payments to the MCV Partnership are based on
the cost of coal burned at our coal plants and 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 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 exercise 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 equity interest in the MCV Partnership.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In February 2004, we filed a resource conservation plan with the MPSC that
is intended to help conserve natural gas and thereby improve our equity
investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility on an economic basis depending 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. We requested that the MPSC provide
interim approval while it conducts a full review of the plan. The MPSC has
scheduled a prehearing conference with respect to the MCV resource conservation
plan for April 2004. We cannot predict if or when the MPSC will approve our
request.
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 our recovery of capacity
payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot
predict the impact of these issues on our future earnings, cash flows, or on the
value of our equity interest in the MCV Partnership.
NUCLEAR MATTERS: Big Rock: Significant progress continues to be made in the
decommissioning of Big Rock. We submitted the License Termination Plan to the
NRC staff for review in April 2003. System dismantlement and building demolition
are on schedule to return the 560-acre site to a natural setting for
unrestricted use in early 2006. The NRC and Michigan Department of Environmental
Quality continue to find that all decommissioning activities at Big Rock are
being performed in accordance with applicable regulatory and license
requirements.
Seven transportable dry casks have been loaded with spent nuclear fuel and
an eighth cask has been loaded with high-level radioactive waste material. These
dry casks will remain onsite until the DOE moves the material to a national
spent nuclear fuel repository.
Palisades: In July 2003, the NRC completed its mid-cycle plant performance
assessment of Palisades. The mid-cycle assessment for Palisades covered the
period from January 1, 2003 through the end of July 2003. The NRC determined
that Palisades was operated in a manner that preserved public health and safety
and fully met all cornerstone objectives. Based on the plant's performance, only
regularly scheduled inspections are planned through September 2004.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite
storage pool capacity. We are using dry casks for temporary onsite storage. As
of December 31, 2003, we have loaded 18 dry casks with spent nuclear fuel and we
will need to load additional dry casks by the fall of 2004 in order to continue
operation. Palisades currently has three empty dry casks onsite, with storage
pad capacity for up to seven additional loaded dry casks. We anticipate that
transportable dry casks, along with more storage pad capacity, will be available
by fall 2004.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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.
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 $26 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 $10.862 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.
CE-54
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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
from 2004 to 2005, and total an estimated $177 million. Our coal transportation
contracts expire from 2004 to 2007, and total an estimated $139 million.
Long-term coal supply contracts account for approximately 60 to 90 percent of
our annual coal requirements. In 2003, coal purchases totaled $265 million of
which $207 million (78 percent of the tonnage requirement) was under long-term
contract. We supplement our long-term contracts with spot-market purchases.
Power Supply, Capacity, and Transmission: As of December 31, 2003, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants including the MCV Facility. These
contracts require monthly capacity payments based on the plants' availability or
deliverability. These payments for 2004 through 2030 total an estimated $16.016
billion, undiscounted, which includes $11.381 billion related to the MCV
Facility. 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.
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 MPSC approved rates charged to our customers. As of
December 31, 2003, we have recorded a liability of $44 million, net of $38
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.
CE-55
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
February 2004, the parties in the case reached a tentative settlement agreement
that would result in a GCR disallowance of $11 million for the GCR period.
Interest on the disallowed amount from April 1, 2003 through February 2004, at
the Consumers' authorized rate of return, adds $1 million to the cost of the
settlement. We believe this settlement agreement will be executed by the parties
in the case in the near future and approved by the MPSC. A reserve was recorded
in December 2003.
In July 2003, the MPSC approved a settlement agreement authorizing us to
increase our gas cost recovery for the remainder of the current GCR plan year
(August 2003 through March 2004) and to apply a quarterly ceiling price
adjustment, based on a formula that tracks changes in NYMEX natural gas prices.
The terms of the settlement allow a GCR ceiling price of $6.11 per mcf. Our GCR
is $5.36 per mcf for March 2004 bills.
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. The MPSC is not bound by these
recommendations and will consider the issues anew after receipt of exceptions
and replies to the exception filed by the parties in response to the Proposal
for Decision.
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
independent of the 2003 gas rate case. 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.
OTHER GAS UNCERTAINTIES
COMMITMENTS FOR GAS SUPPLIES: We enter into contracts to purchase gas and
gas transportation from various suppliers for our natural gas business. These
contracts have expiration dates that range from 2004 to 2007. Our 2003 gas
purchases totaled 248 bcf at a cost of $1.379 billion. At the end of 2003, we
estimate our gas purchases for 2004 to be 235 bcf, of which 22 percent is
covered by existing fixed price contracts and 37 percent is covered by indexed
price contracts that are subject to price variations. The remaining 2004 gas
purchases will be made at market prices at the time of purchase.
CE-56
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
3: FINANCINGS AND CAPITALIZATION
LONG-TERM DEBT:
Long-term debt as of December 31 follows:
INTEREST RATE (%) MATURITY 2003 2002
----------------- -------- ---- ----
IN MILLIONS
First mortgage bonds............................ 4.250 2008 $ 250 $ --
4.800 2009 200 --
4.000 2010 250 --
5.375 2013 375 --
6.000 2014 200 --
7.375 2023 208 208
------ ------
1,483 208
------ ------
Senior notes.................................... 6.000 2005 300 300
6.250 2006 332 332
6.375 2008 159 159
6.200 2008 -- 250
6.875 2018 180 180
6.500(a) 2018 141 141
6.500(b) 2028 142 142
------ ------
1,254 1,504
------ ------
Securitization bonds............................ 5.097(c) 2005-2015 426 453
Long-term bank debt............................. Variable 2006-2009 200 328
Nuclear fuel disposal liability................. (d) 139 138
Pollution control revenue bonds................. Various 2010-2018 126 126
Other........................................... 4 8
------ ------
895 1,053
------ ------
Principal amount outstanding...................... 3,632 2,765
Current amounts................................. (28) (305)
Net unamortized discount........................ (21) (18)
------ ------
Total Long-term debt.............................. $3,583 $2,442
====== ======
-------------------------
(a) 2018 maturity is subject to successful remarketing after June 15, 2005.
(b) Callable at par.
(c) Represents the weighted average interest rate at December 31, 2003.
(d) Maturity date uncertain.
CE-57
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
LONG-TERM DEBT -- RELATED PARTIES:
Long-term debt -- related parties as of December 31, 2003 follows:
DEBENTURE AND RELATED PARTY INTEREST RATE MATURITY 2003
--------------------------- ------------- -------- ----
IN MILLIONS
Subordinated deferrable interest notes, Consumers Power
Company Financing I....................................... 8.36% 2015 $ 73
Subordinated deferrable interest notes, Consumers Energy
Company Financing II...................................... 8.20% 2027 124
Subordinated debentures, Consumers Energy Company Financing
III....................................................... 9.25% 2029 180
Subordinated debentures, Consumers Energy Company Financing
IV........................................................ 9.00% 2031 129
----
Total amount outstanding.................................... $506
====
NOTES PAYABLE -- RELATED PARTIES: Consumers issued a $200 million unsecured
promissory note to CMS Energy on December 30, 2003. The proceeds were used to
pay a portion of Consumers' Pension Plan contribution of $329 million in
December 2003. This note matures on December 29, 2004 and is payable on three
business days' notice by CMS Energy.
DEBT ISSUANCES: The following is a summary of our long-term debt issuances
during 2003:
FACILITY PRINCIPAL USE OF
TYPE (IN MILLIONS) ISSUE RATE ISSUE DATE MATURITY DATE PROCEEDS COLLATERAL
-------- ------------- ---------- ---------- ------------- -------- ----------
Term loan............. $ 140 LIBOR + March 2003 March 2009 GCP FMB(f)
475 bps
Term loan............. 150 LIBOR + March 2003 March 2006 GCP FMB(f)
450 bps (paid off)(b)
FMB(a)................ 375 5.375% April 2003 April 2013 (c) --
FMB(a)................ 250 4.250% April 2003 April 2008 (c) --
FMB(a)................ 250 4.000% May 2003 May 2010 (d) --
FMB(a)................ 200 4.800% August 2003 February 2009 (b) --
FMB(a)................ 200 6.000% August 2003 February 2014 (b) --
Term loan............. 60 LIBOR + November 2003 November 2006 (e) FMB(f)
135 bps
-------------
Total................. $1,625
=============
-------------------------
(bps -- basis points), (GCP -- General corporate purposes)
(a) We filed a registration statement with the SEC in December 2003 to permit
holders of these FMBs to exchange their bonds for FMBs that are registered
under the Securities Act of 1933. The exchange offer was completed on
February 13, 2004.
(b) We used the net proceeds to pay off a $150 million term loan, to pay off a
$50 million balance on a term loan that was due to mature in July 2004, and
for general corporate purposes.
(c) We used the net proceeds to fund the maturity of a $250 million bond, to
fund a $32 million option call payment, and for general corporate purposes.
(d) We used the net proceeds to prepay a portion of a term loan that was due to
mature in July 2004.
(e) We used the net proceeds to purchase the headquarters building and pay off
the capital lease.
(f) Refer to "Regulatory Authorization for Financings" within this note for
details about our remaining FERC debt authorization.
CE-58
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DEBT MATURITIES: The aggregate annual maturities for long-term debt for the
next five years are:
DECEMBER 31
------------------------------------
PAYMENTS DUE
------------------------------------
2004 2005 2006 2007 2008
---- ---- ---- ---- ----
IN MILLIONS
Long-term debt.............................................. $28 $328 $422 $31 $441
PREFERRED STOCK: The following table describes our Preferred Stock
outstanding:
DECEMBER 31
------------------------------------
OPTIONAL NUMBER OF SHARES
REDEMPTION --------------------
SERIES PRICE 2003 2002 2003 2002
------ ---------- ---- ---- ---- ----
IN MILLIONS
Preferred Stock
Cumulative, $100 par value, authorized
7,500,000 shares, with no mandatory
redemption............................ $4.16 $103.25 68,451 68,451 $ 7 $ 7
4.50 110.00 373,148 373,148 37 37
--- ---
Total Preferred Stock...................... $44 $44
=== ===
REGULATORY AUTHORIZATION FOR FINANCINGS: At December 31, 2003, 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 December 31, 2003, 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 other
long-term securities.
With the granting of authorization, FERC waived its competitive
bid/negotiated placement requirements applicable to the long-term securities
authorization. The authorizations expire on June 30, 2004.
SHORT-TERM FINANCINGS: We have a $400 million revolving credit facility
with banks. The facility is secured with first mortgage bonds. The interest rate
of the facility is LIBOR plus 175 basis points. This facility expires in March
2004 with two annual extensions at our option, which would extend the maturity
to March 2006. At December 31, 2003, $390 million is available for general
corporate purposes, working capital, and letters of credit.
At December 31, 2002, $457 million of bank notes were outstanding at a
weighted average interest rate of 4.50 percent.
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.
POLLUTION CONTROL REVENUE BONDS: In January 2004, we amended the PCRB
indentures to add an auction rate interest mode and switched to that mode for
the two floating rate bonds. Under the auction rate mode, the bonds' interest
rate will be reset every 35 days. While in the auction rate mode, no letter of
credit liquidity facility is required and investors do not have a put right.
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARIES: We formed various statutory wholly owned business trusts for the
sole purpose of issuing preferred securities and lending the gross
CE-59
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
proceeds to ourselves. The sole assets of the trusts are debentures with terms
similar to those of the preferred security. Summarized information for
mandatorily redeemable preferred securities is as follows:
AMOUNT
OUTSTANDING(A) EARLIEST
TRUST AND SECURITIES --------------- OPTIONAL
DECEMBER 31 RATE 2003 2002 MATURITY REDEMPTION(B)
-------------------- ---- ---- ---- -------- -------------
IN MILLIONS
Consumers Power Company Financing I, Trust
Originated Preferred Securities................. 8.36% $ -- $ 70 2015 2000
Consumers Energy Company Financing II, Trust
Originated Preferred Securities................. 8.20% -- 120 2027 2002
Consumers Energy Company Financing III, Trust
Originated Preferred Securities................. 9.25% -- 175 2029 2004
Consumers Energy Company Financing IV, Trust
Preferred Securities............................ 9.00% -- 125 2031 2006
----- ----
Total amount outstanding.......................... $ -- $490
===== ====
-------------------------
(a) We determined that we do not hold the controlling financial interest in 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 and are reflected in
Long-term debt -- related parties. For additional details, refer to
"Long-Term Debt -- Related Parties" within this Note and Note 13,
Implementation of New Accounting Standards.
(b) The trusts must redeem the securities at a liquidation value of $25 per
share, which is equivalent to the carrying cost plus accrued but unpaid
distributions, when the securities are paid at maturity or upon any earlier
redemption. Prior to an early redemption date, the securities could be
redeemed at market value.
Each trust receives payments on the debenture it holds. Those receipts are
used to make cash distributions on the preferred securities the trust has
issued.
The securities allow us the right to defer interest payments on the
debentures, and, as a consequence, the trusts will defer dividend payments on
the preferred securities. Should we exercise this right, we cannot declare or
pay dividends on, or redeem, purchase or acquire, any of our capital stock
during the deferral period until all deferred dividends are paid in full.
In the event of default, holders of the preferred securities will be
entitled to exercise and enforce the trusts' creditor rights against us, which
may include acceleration of the principal amount due on the debentures. We have
issued certain guarantees with respect to payments on the preferred securities.
These guarantees, when taken together with our obligations under the debentures,
related indenture and trust documents, provide full and unconditional guarantees
for the trusts' obligations under the preferred securities.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. The amounts sold were $297 million at December 31, 2003 and $325
million at December 31, 2002. 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.
CE-60
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Certain cash flows received from and paid to us under our accounts
receivable sales program are shown below:
YEARS ENDED
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Proceeds from sales (remittance of collections) under the
program................................................... $ (28) $ (9)
Collections reinvested under the program.................... 4,361 4,080
DIVIDEND RESTRICTIONS: Under the provisions of our articles of
incorporation, at December 31, 2003, we had $373 million of unrestricted
retained earnings available to pay common dividends. However, covenants in our
debt facilities cap common stock dividend payments at $300 million in a calendar
year. Through December 31, 2003, we made the following common stock dividend
payments:
IN MILLIONS
-----------
January..................................................... $ 78
May......................................................... 31
June........................................................ 53
November.................................................... 56
----
Total common stock dividends paid to CMS Energy............. $218
====
As of December 18, 2003, we are also under an annual dividend cap of $190
million imposed by the MPSC during the current interim gas rate relief period.
Because all of the $218 million of common stock dividends to CMS Energy were
paid prior to December 18, 2003, we were not out of compliance with this new
restriction for 2003. In February 2004, we paid a $78 million common stock
dividend.
For additional details on the potential cap on common dividends payable
included in the MPSC Securitization order, see Note 2, Uncertainties, "Electric
Restructuring Matters -- Securitization." Also, 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."
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.
CE-61
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables describe our guarantees at December 31, 2003:
EXPIRATION MAXIMUM CARRYING RECOURSE
GUARANTEE DESCRIPTION ISSUE DATE DATE OBLIGATION AMOUNT PROVISION(a)
--------------------- ---------- ---------- ---------- -------- ------------
IN MILLIONS
Standby letters of credit.................. Various Various $ 10 $ -- $ --
Surety bonds............................... Various Various 8 -- --
Nuclear insurance retrospective premiums... Various Various 133 -- --
-------------------------
(a) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
EVENTS THAT WOULD
GUARANTEE DESCRIPTION HOW GUARANTEE AROSE REQUIRE PERFORMANCE
--------------------- ------------------- -------------------
Standby letters of credit Normal operations of coal Noncompliance with
power plants environmental regulations
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, Nonperformance
permits and license
Nuclear insurance Normal operations of nuclear Call by NEIL and Price
retrospective premiums plants 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 investments
based on quoted market prices or, in the absence of specific market prices, on
quoted market prices of similar investments or other valuation techniques. The
carrying amount of all long-term financial instruments, except as shown below,
approximate fair value. For additional details, see Note 1, Corporate Structure
and Accounting Policies.
DECEMBER 31
-----------------------------------------------------------------
2003 2002
------------------------------- ------------------------------
FAIR UNREALIZED FAIR UNREALIZED
COST VALUE GAIN (LOSS) COST VALUE GAIN
---- ----- ----------- ---- ----- ----------
IN MILLIONS
Long-term debt(a)....................... $3,583 $3,666 $(83) $2,442 $2,404 $38
Long-term debt-related parties(b)....... 506 518 (12) -- -- --
Trust Preferred Securities(b)........... -- -- -- 490 447 43
Available for sale securities:
Common stock of CMS Energy(c)........... 10 20 10 22 22 --
SERP.................................... 17 21 4 18 19 1
Nuclear decommissioning
investments(d)........................ 442 575 133 458 536 78
-------------------------
(a) Settlement of long-term debt is generally not expected until maturity.
(b) We determined that we do not hold the controlling financial interest in 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 and are reflected in
Long-term debt -- related parties on the Consolidated Balance Sheets. For
additional details, see Note 3, Financings and Capitalization, "Long-Term
Debt -- Related Parties" and Note 13, Implementation of New Accounting
Standards.
CE-62
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 December 31, 2003, 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) 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. Derivative accounting is required for certain contracts used to limit
our exposure to electricity and gas commodity price risk and interest rate risk.
CE-63
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table reflects the fair value of all contracts requiring
derivative accounting:
DECEMBER 31
-------------------------------------------------------------
2003 2002
----------------------------- ----------------------------
FAIR UNREALIZED FAIR UNREALIZED
COST VALUE GAIN (LOSS) COST VALUE GAIN (LOSS)
---- ----- ----------- ---- ----- -----------
IN MILLIONS
Electric -- related contracts.................. $ -- $ -- $ -- $8 $ 1 $(7)
Gas contracts.................................. 3 2 (1) -- 1 1
Interest rate risk contracts................... -- -- -- -- (1) (1)
Derivative contracts associated with Consumers'
equity investment in the MCV Partnership..... -- 15 15 -- 13 13
The fair value of all derivative contracts, except the fair value of
derivative contracts associated with our equity investment in the MCV
Partnership, is included in either Other Assets or Other Liabilities on the
Consolidated Balance Sheets. The fair value of derivative contracts associated
with our equity investment in the MCV Partnership is included in Investments --
Midland Cogeneration Venture Limited Partnership on the Consolidated Balance
Sheets. Effective April 1, 2002, the MCV Partnership changed its accounting for
derivatives. For additional details see Note 11, Summarized Financial
Information of Significant Related Energy Supplier.
Cumulative Effect of Change in Accounting Principle: On January 1, 2001,
upon initial adoption of the derivatives standard, we recorded a $21 million,
net of tax, cumulative effect transition adjustment as an unrealized gain
increasing accumulated other comprehensive income. In June and December 2001,
the FASB issued guidance that resolved the accounting for certain utility
industry contracts. As a result, we recorded a $3 million, net of tax,
cumulative effect adjustment as an unrealized loss, decreasing accumulated other
comprehensive income, and on December 31, 2001, recorded an $11 million, net of
tax, cumulative effect adjustment as a decrease to earnings. These adjustments
relate to the difference between the fair value and the recorded book value of
certain electric call option contracts.
ELECTRIC CONTRACTS: Our electric 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.
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, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA,
could be material to the financial statements.
Our electric business also uses gas option and swap contracts to protect
against price risk due to the fluctuations in the market price of gas used as
fuel for generation of electricity. These contracts are financial contracts that
are used to offset increases in the price of potential gas purchases. These
contracts do not qualify for hedge accounting. Therefore, we record any change
in the fair value of these contracts directly in earnings as part of power
supply costs.
For the year ended December 31, 2003, the unrealized gain in accumulated
other comprehensive income related to our proportionate share of the effects of
derivative accounting related to our equity investment in the MCV Partnership is
$10 million, net of tax. We expect to reclassify this gain, if this value
remains, as an increase to earnings from equity method investees during the next
12 months.
CE-64
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
GAS CONTRACTS: Our gas utility business uses fixed price 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.
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 December 31, 2003, we did not have any
interest rate swaps outstanding. As of December 31, 2002, 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 all interest
rate hedges; therefore, there was no ineffectiveness associated with these
hedges.
5: INCOME TAXES
We file a consolidated federal income tax return with CMS Energy. Income
taxes are generally allocated based on each company's separate taxable income.
We had tax related receivables from CMS Energy of $46 million in 2003 and $44
million in 2002.
The Job Creation and Worker Assistance Act of 2002 provided corporate
taxpayers a 5-year carryback of tax losses incurred in 2001 and 2002. As a
result of this legislation, CMS Energy was able to carry back consolidated 2001
and 2002 tax losses to tax years 1996 through 1999 to obtain refunds of prior
years tax payments totaling $250 million. The tax loss carryback, however,
resulted in a reduction in AMT credit carryforwards that previously had been
recorded by CMS Energy as deferred tax assets in the amount of $47 million. This
non-cash reduction in AMT credit carryforwards was reflected in the 2002 tax
provision of CMS Energy and allocated to each of its consolidated subsidiaries
under the CMS Energy tax sharing agreement. Consumers' allocable share, $25
million, was reflected in 2002 as a dividend paid by us to CMS Energy.
We practice deferred tax accounting for temporary differences in accordance
with SFAS No. 109. We use ITC to reduce current income taxes payable, and defer
and amortize ITC over the life of the related property. AMT paid generally
becomes a tax credit that we can carry forward indefinitely to reduce regular
tax liabilities in future periods when regular taxes paid exceed the tax
calculated for AMT. At December 31, 2003, we had AMT credit carryforwards in the
amount of $11 million that do not expire, and tax loss carryforwards in the
amount of $71 million that expire in 2021 and 2022.
The significant components of income tax expense (benefit) consisted of:
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Current federal income taxes................................ $(58) $(97) $(39)
Deferred income taxes....................................... 201 283 143
Deferred ITC, net........................................... (6) (6) (7)
---- ---- ----
Income tax expense.......................................... $137 $180 $ 97
==== ==== ====
CE-65
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The principal components of our deferred tax assets (liabilities)
recognized in the balance sheet are as follows:
DECEMBER 31
------------------
2003 2002
---- ----
IN MILLIONS
Property.................................................... $ (826) $ (789)
Unconsolidated investments.................................. (226) (223)
Securitization costs........................................ (186) (192)
Prepaid pension............................................. (134) --
Gas inventories............................................. (100) (74)
Postretirement benefits..................................... (70) (72)
Employee benefit obligations................................ 114 208
SFAS No. 109 regulatory liability........................... 120 115
Nuclear decommissioning..................................... 59 55
Tax loss carryforwards...................................... 25 15
AMT credit carryforwards.................................... 11 7
Other, net.................................................. (53) (24)
------- -------
Net deferred tax liabilities................................ $(1,266) $ (974)
======= =======
Deferred tax liabilities.................................... $(1,967) $(1,528)
Deferred tax assets......................................... 701 554
------- -------
Net deferred tax liabilities................................ $(1,266) $ (974)
======= =======
The actual income tax expense differs from the amount computed by applying
the statutory federal tax rate of 35 percent to income before income taxes as
follows:
YEARS ENDED
DECEMBER 31
------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Income before cumulative effect of change in accounting
principle................................................. $196 $363 $199
Income taxes................................................ 137 180 97
Preferred securities distributions (Note 3)................. -- (44) (41)
---- ---- ----
Pretax income............................................... 333 499 255
Statutory federal income tax rate........................... x35% x35% x35%
---- ---- ----
Expected income tax expense................................. 117 174 89
Increase (decrease) in taxes from:
Property differences not previously deferred.............. 16 14 17
Reserve for tax credits previously claimed................ 8 -- --
Loss on investment in CMS Energy Common Stock............. 4 4 --
Sale of METC.............................................. -- (5) --
ITC amortization/adjustments.............................. (6) (6) (7)
Affiliated companies' dividends........................... -- (1) (2)
Other, net................................................ (2) -- --
---- ---- ----
Actual income tax expense................................... $137 $180 $ 97
==== ==== ====
Effective tax rate.......................................... 41.1% 36.0% 38.0%
==== ==== ====
CE-66
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan to key management employees
based on their contributions to the successful management of the company. The
Plan includes the following type of awards for common stock:
- restricted shares of common stock,
- stock options, and
- stock appreciation rights.
Restricted shares of CMS Energy Common Stock are outstanding shares with
full voting and dividend rights. These awards vest over five years at the rate
of 25 percent per year after two years. Some restricted shares are subject to
achievement of specified levels of total shareholder return and are subject to
forfeiture if employment terminates before vesting. Restricted shares vest fully
if control of CMS Energy changes.
Stock options give the holder the right to purchase common stock at a given
price over an extended period of time. Stock appreciation rights give the holder
the right to receive common stock appreciation, which is defined as the excess
of the market price of the stock at the date of exercise over the grant date
price. CMS Energy stock options and stock appreciation rights are valued at
market price when granted. All options and rights may be exercised upon grant
and they expire up to ten years and one month from the date of grant.
Our Performance Incentive Stock Plan was amended in January 1999. It uses
the following formula to grant awards:
- up to five percent of CMS Energy Common Stock outstanding at January 1
each year less:
- the number of shares of restricted common stock awarded, and
- Common Stock subject to options granted under the plan during the
immediately preceding four calendar years.
- the number of shares of restricted CMS Energy Common Stock awarded under
this plan cannot exceed 20 percent of the aggregate number of shares
reserved for award, and
- forfeiture of shares previously awarded will increase the number of
shares available to be awarded under the plan.
Awards of up to 2,240,247 shares of CMS Energy Common Stock may be issued
as of December 31, 2003.
CE-67
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes the restricted stock and stock options
granted to our key employees under the Performance Incentive Stock Plan:
RESTRICTED
STOCK OPTIONS
---------- -----------------------------
NUMBER NUMBER WEIGHTED AVERAGE
CMS ENERGY COMMON STOCK OF SHARES OF SHARES EXERCISE PRICE
----------------------- --------- --------- ----------------
Outstanding at January 1, 2001........................... 259,377 842,119 $30.75
Granted.................................................. 71,930 294,150 $30.04
Exercised or Issued...................................... (34,704) (35,317) $19.34
Forfeited or Expired..................................... (56,938) -- --
Outstanding at December 31, 2001......................... 239,665 1,100,952 $30.93
Granted.................................................. 163,890 490,600 $14.32
Exercised or Issued...................................... (26,663) (6,083) $17.13
Forfeited or Expired..................................... (56,172) (65,080) $32.03
Outstanding at December 31, 2002......................... 320,720 1,520,389 $25.58
Granted.................................................. 434,011 1,105,490 $ 6.35
Exercised or Issued...................................... (22,812) -- --
Forfeited or Expired..................................... (69,372) (31,667) $26.25
Outstanding at December 31, 2003......................... 662,547 2,594,212 $17.37
At December 31, 2003, 70,567 of the 662,547 shares of CMS Energy restricted
common stock outstanding are subject to performance objectives. Compensation
expense for restricted stock was $4 million in 2003, less than $1 million in
2002, and $3 million in 2001.
The following table summarizes our stock options outstanding at December
31, 2003:
NUMBER OF SHARES
OUTSTANDING AND WEIGHTED AVERAGE WEIGHTED AVERAGE
RANGE OF EXERCISE PRICES EXERCISABLE REMAINING LIFE EXERCISE PRICE
------------------------ ---------------- ---------------- ----------------
CMS Energy Common Stock:
$6.35 -- $6.35............................... 1,105,490 9.70 years $ 6.35
$8.12 -- $31.04............................... 1,074,441 6.96 years $20.36
$34.80 -- $43.38............................... 414,281 4.89 years $39.05
--------- ---------- ------
$6.35 -- $43.38............................... 2,594,212 7.80 years $17.37
========= ========== ======
In December 2002, we adopted the fair value based method of accounting for
stock-based employee compensation, under SFAS No. 123, as amended by SFAS No.
148. We elected to adopt the prospective method recognition provisions of this
Statement, which applies the recognition provisions to all awards granted,
modified, or settled after the beginning of the fiscal year that the recognition
provisions are first applied.
The following table summarizes the weighted average fair value of stock
options granted:
OPTIONS GRANT DATE 2003 2002(a) 2001
------------------ ---- ------- ----
Fair value at grant date.................................... $3.04 $3.79, $1.40 $6.37
-------------------------
(a) For 2002, there were two stock option grants.
CE-68
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The stock options fair value is estimated using the Black-Scholes model, a
mathematical formula used to value options traded on securities exchanges. The
following assumptions were used in the Black-Scholes model:
YEARS ENDED DECEMBER 31
---------------------------------
2003 2002(a) 2001
---- ------- ----
CMS Energy Common Stock Options
Risk-free interest rate................................... 3.23% 4.02%, 3.28% 4.80%
Expected stock price volatility........................... 53.10% 31.64%, 39.67% 29.48%
Expected dividend rate.................................... -- $.365, $.1825 $.365
Expected option life (years).............................. 4.7 4.5 4.6
-------------------------
(a) For 2002, there were two stock option grants.
We recorded $3 million as stock-based employee compensation cost for 2003,
and $1 million for 2002. If stock-based compensation costs had been determined
under SFAS No. 123 for the year ended December 31, 2001, consolidated net income
and pro forma net income would have been as follows:
YEAR ENDED
DECEMBER 31
-----------
2001
----
IN MILLIONS
Net income, as reported..................................... $188
Add: Stock-based employee compensation expense included in
reported net income, net of related taxes................. --
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related taxes...................................... (1)
----
Pro forma net income........................................ $187
====
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 Panhandle. The Pension Plan's assets are not
distinguishable by company.
In June 2003, CMS Energy sold Panhandle to Southern Union Panhandle Corp.
No portion of the Pension Plan assets were transferred with the sale and
Panhandle employees are no longer eligible to accrue additional benefits. The
Pension Plan retained pension payment obligations for Panhandle employees that
were vested under the Pension Plan.
CE-69
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The sale of Panhandle resulted in a significant change in the makeup of the
Pension Plan. A remeasurement of the obligation was required at the date of
sale. The remeasurement further resulted in the following:
- an increase in OPEB expense of $4 million for 2003, and
- an additional charge to accumulated other comprehensive income of $31
million ($20 million after-tax) because of the increase in the additional
minimum pension liability. Due to large contributions, the additional
minimum pension liability was eliminated as of December 31, 2003.
In 2003, a substantial number of retiring employees elected a lump sum
payment instead of receiving pension benefits as an annuity over time. Lump sum
payments constitute a settlement under SFAS No. 88. A settlement loss must be
recognized when the cost of all settlements paid during the year exceeds the sum
of the service and interest costs for that year. We recorded a settlement loss
of $48 million ($31 million after-tax) in December 2003.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not
a qualified plan under the Internal Revenue Code; SERP trust earnings are
taxable and trust assets are included in consolidated assets. Trust assets were
$22 million at December 31, 2003, and $19 million at December 31, 2002. The
assets are classified as other non-current assets. The Accumulated Benefit
Obligation for SERP was $19 million at December 31, 2003 and $17 million at
December 31, 2002.
OPEB: Retiree health care costs at December 31, 2003 are based on the
assumption that costs would increase 8.5 percent in 2003. The rate of increase
is expected to be 7.5 percent for 2004. The rate of increase is expected to slow
to an estimated 5.5 percent by 2010 and thereafter.
The health care cost trend rate assumption significantly affects the
estimated costs recorded. A one-percentage point change in the assumed health
care cost trend assumption would have the following effects:
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
IN MILLIONS
Effect on total service and interest cost component......... $ 13 $ (11)
Effect on postretirement benefit obligation................. $136 $(119)
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.
EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select group of management, or other highly
compensated employees. Terms of the plan may include payment of a lump sum,
payment of monthly benefits for life, payment of premium for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. As of December 31, 2003, the Accumulated Benefit Obligation
of the EISP was $3 million. Consumers' portion of the EISP was $300,000.
The measurement date for all plans is December 31.
CE-70
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Assumptions: The following table recaps the weighted-average assumptions
used in our retirement benefits plans to determine the benefit obligation and
net periodic benefit cost:
PENSION & SERP OPEB
----------------------- -----------------------
YEARS ENDED DECEMBER 31
--------------------------------------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
Discount rate................................. 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%
Expected long-term rate of return on plan
assets(a)................................... 8.75% 8.75% 9.75%
Union....................................... 8.75% 8.75% 9.75%
Non-Union................................... 6.00% 6.00% 6.00%
Rate of compensation increase:
Pension..................................... 3.25% 3.50% 5.25%
SERP........................................ 5.50% 5.50% 5.50%
-------------------------
(a) We determine our long-term rate of return by considering historical market
returns, the current and future economic environment, the capital market
principals of risk and return, and the expertise of individuals and firms
with financial market knowledge. We use the asset allocation of the
portfolio to forecast the future expected total return of the portfolio. The
goal is to determine a long-term rate of return that can be incorporated
into the planning of future cash flow requirements in conjunction with the
change in the liability. The use of forecasted returns for various classes
of assets used to construct an expected return model is reviewed
periodically for reasonability and appropriateness.
Costs: The following table recaps the costs incurred in our retirement
benefits plans:
PENSION & SERP OPEB
--------------------- --------------------
YEARS ENDED DECEMBER 31
---------------------------------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
IN MILLIONS
Service cost.......................................... $ 39 $ 40 $ 37 $ 17 $ 16 $ 13
Interest expense...................................... 75 86 84 61 63 57
Expected return on plan assets........................ (80) (103) (99) (39) (40) (40)
Amortization of unrecognized transition (asset)....... -- -- (5) -- -- --
Plan amendments....................................... -- 4 -- -- -- --
Settlement charge..................................... 48 -- -- -- -- --
Amortization of:
Net loss............................................ 9 -- -- 18 8 --
Prior service cost.................................. 7 8 8 (6) (1) (1)
---- ----- ---- ---- ---- ----
Net periodic pension and postretirement benefit
cost................................................ $ 98 $ 35 $ 25 $ 51 $ 46 $ 29
==== ===== ==== ==== ==== ====
Plan Assets: The following table recaps the categories of plan assets in
our retirement benefits plans:
PENSION OPEB
------------ ------------
YEARS ENDED DECEMBER 31
------------------------------
2003 2002 2003 2002
---- ---- ---- ----
Asset Category:
Fixed Income.............................................. 52% 32%(b) 51% 55%
Equity Securities......................................... 44% 60% 48% 44%
CMS Energy Common Stock(a)............................. 4% 8% 1% 1%
-------------------------
(a) At December 31, 2003, there were 4,970,000 shares of CMS Energy Common
Stock in the Pension Plan assets with a fair value of $42 million, and
414,000 shares in the OPEB plan assets, with a fair value of
CE-71
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
$4 million. At December 31, 2002, there were 5,099,000 shares of CMS Energy
Common Stock in the Pension Plan assets with a fair value of $48 million,
and 284,000 shares in the OPEB plan assets, with a fair value of $3
million.
(b) At February 29, 2004, the Pension Plan assets were 66 percent equity and 34
percent fixed income. We plan to contribute $71 million to our OPEB plan in
2004. We estimate a contribution of $23 million to our Pension Plan in
2004.
We have established a target asset allocation for our Pension Plan assets
of 65 percent equity and 35 percent fixed income investments to maximize the
long-term return on plan assets, while maintaining a prudent level of risk. The
level of acceptable risk is a function of the liabilities of the plan. Equity
investments are diversified mostly across the Standard & Poor's 500 Index, with
a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a
Foreign Equity Index Fund. Fixed income investments are diversified across
investment grade instruments of both government and corporate issuers. Annual
liability measurements, quarterly portfolio reviews, and periodic
asset/liability studies are used to evaluate the need for adjustments to the
portfolio allocation.
We have established union and non-union VEBA trusts to fund our future
retiree health and life insurance benefits. These trusts are funded through the
rate making process for Consumers, and through direct contributions from the
non-utility subsidiaries. The equity portions of the union and non-union health
care VEBA trusts are invested in an Standard & Poor's 500 Index fund. The fixed
income portion of the union health care VEBA trust is invested in domestic
investment grade taxable instruments. The fixed income portion of the non-union
health care VEBA trust is invested in a diversified mix of domestic tax-exempt
securities. The investment selections of each VEBA are influenced by the tax
consequences, as well as the objective of generating asset returns that will
meet the medical and life insurance costs of retirees.
CE-72
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Reconciliations: The following table reconciles the funding of our
retirement benefit plans with our retirement benefit plans liability:
YEARS ENDED DECEMBER 31
--------------------------------------------------
PENSION PLAN SERP OPEB
---------------- ------------ --------------
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
IN MILLIONS
Benefit obligation January 1...................... $1,256 $1,195 $ 21 $ 19 $ 890 $ 876
Service cost...................................... 38 40 1 1 17 16
Interest cost..................................... 74 84 1 2 61 63
Plan amendment.................................... (19) 3 -- -- (44) (57)
Actuarial loss.................................... 55 72 -- -- 76 31
Benefits paid..................................... (215) (138) (1) (1) (40) (39)
------ ------ ---- ---- ----- -----
Benefit obligation December 31(a)................. 1,189 1,256 22 21 960 890
------ ------ ---- ---- ----- -----
Plan assets at fair value at January 1............ 607 845 -- -- 465 475
Actual return on plan assets...................... 115 (164) -- -- 68 (44)
Company contribution.............................. 560 64 -- -- 71 73
Actual benefits paid.............................. (215) (138) -- -- (40) (39)
------ ------ ---- ---- ----- -----
Plan assets at fair value at December 31.......... 1,067 607 -- -- 564 465
------ ------ ---- ---- ----- -----
Benefit obligation in excess of plan assets....... (122) (649) (22) (21) (396) (425)
Unrecognized net loss from experience different
than assumed.................................... 501 573 3 3 312 282
Unrecognized prior service cost (benefit)......... 29 60 -- -- (107) (70)
Panhandle adjustment.............................. -- (7) -- -- -- --
------ ------ ---- ---- ----- -----
Net Balance Sheet Asset (Liability)............... 408 (23) (19) (18) (191) (213)
Additional minimum liability adjustment(b)........ -- (426) -- -- -- --
------ ------ ---- ---- ----- -----
Total Net Balance Sheet Asset (Liability)(c)...... $ 408 $ (449) $(19) $(18) $(191) $(213)
====== ====== ==== ==== ===== =====
-------------------------
(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. This Act 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 have decided to defer
recognizing the effects of the Act in our 2003 financial statements, as
permitted by FASB Staff Position No. 106-1. When accounting guidance is
issued, our retiree health benefit obligation may be adjusted.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.055 billion
exceeded the value of the Pension Plan assets and net balance sheet
liability at December 31, 2002. As a result, we recorded an additional
minimum liability, including an intangible asset of $40 million, and $285
million of accumulated other comprehensive income. In August 2003, we made
our planned contribution of $172 million to the Pension Plan. In December
2003, we made an additional contribution of $329 million to the Pension
Plan that eliminated the additional minimum liability. The Accumulated
Benefit Obligation for the Pension Plan was $1.019 billion at December 31,
2003.
(c) As of December 31, 2003, we have recorded a prepaid pension asset of $384
million, $20 million of which is in other current assets on our
consolidated balance sheets.
CE-73
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8: LEASES
We lease various assets, including vehicles, railcars, construction
equipment, furniture, and buildings. We have both full-service and net leases. A
net lease requires us to pay for taxes, maintenance, operating costs, and
insurance. Most of our leases contain options at the end of the initial lease
term to:
- purchase the asset at the then fair value of the asset, or
- renew the lease at the then fair rental value.
Minimum annual rental commitments under our non-cancelable leases at
December 31, 2003, were:
CAPITAL LEASES OPERATING LEASES
-------------- ----------------
IN MILLIONS
2004........................................................ $13 $ 9
2005........................................................ 12 8
2006........................................................ 12 7
2007........................................................ 11 6
2008........................................................ 9 5
2009 and thereafter......................................... 21 29
--- ---
Total minimum lease payments................................ 78 $64
===
Less imputed interest....................................... 10
---
Present value of net minimum lease payments................. 68
Less current portion........................................ 10
---
Non-current portion......................................... $58
===
We are authorized by the MPSC to record both capital and operating lease
payments as operating expense and recover the total cost from our customers.
Operating lease charges were $13 million in 2003, $13 million in 2002, and $15
million in 2001.
Capital lease expenses were $17 million in 2003, $20 million in 2002, and
$26 million in 2001. Included in the $26 million for 2001, is $7 million of
nuclear fuel lease expense. In November 2001, our nuclear fuel capital leasing
arrangement expired. At termination of the lease, we paid the lessor $48
million, which was the lessor's remaining investment at that time.
In April 2001, we entered into a lease agreement for the construction of an
office building to be used as the main headquarters for CMS Energy in Jackson,
Michigan. In November 2003, we exercised our purchase option under the lease
agreement and bought the office building with proceeds from a $60 million term
loan.
9: JOINTLY OWNED REGULATED UTILITY FACILITIES
We are required to provide only our share of financing for the jointly
owned utility facilities. The direct expenses of the jointly owned plants are
included in operating expenses. Operation, maintenance, and other expenses of
these jointly owned utility facilities are shared in proportion to each
participant's undivided
CE-74
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
ownership interest. The following table indicates the extent of our investment
in jointly owned regulated utility facilities:
DECEMBER 31
----------------------------
NET ACCUMULATED
INVESTMENT DEPRECIATION
------------ ------------
2003 2002 2003 2002
---- ---- ---- ----
IN MILLIONS
Campbell Unit 3 -- 93.3 percent............................. $299 $298 $328 $313
Ludington -- 51 percent..................................... 84 83 87 85
Distribution -- various..................................... 74 77 32 31
10: REPORTABLE SEGMENTS
Our reportable segments are strategic business units organized and managed
by the nature of the products and services each provides. We evaluate
performance based upon the net income 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 tables show 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.
YEARS ENDED DECEMBER 31
---------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Operating Revenues
Electric.................................................. $ 2,590 $2,648 $2,633
Gas....................................................... 1,845 1,519 1,338
Other..................................................... -- 2 5
------- ------ ------
$ 4,435 $4,169 $3,976
======= ====== ======
Earnings from Equity Method Investees
Other (a)................................................. $ 42 $ 53 $ 38
======= ====== ======
Depreciation, Depletion and Amortization
Electric.................................................. $ 247 228 $ 219
Gas....................................................... 128 118 118
Other..................................................... 2 2 2
------- ------ ------
$ 377 $ 348 $ 339
======= ====== ======
CE-75
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31
---------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Interest Charges
Electric.................................................. $ 166 $ 144 $ 153
Gas....................................................... 52 47 50
Other..................................................... 30 21 21
------- ------ ------
Subtotal.................................................. 248 212 224
Eliminations.............................................. (3) (44) (38)
------- ------ ------
$ 245 $ 168 $ 186
======= ====== ======
Income Taxes
Electric.................................................. $ 90 $ 138 $ 69
Gas....................................................... 35 33 25
Other (b)................................................. 12 9 3
------- ------ ------
$ 137 $ 180 $ 97
======= ====== ======
Net Income Available to Common Stockholder
Electric.................................................. $ 167 $ 264 $ 109
Gas....................................................... 38 46 21
Other..................................................... (11) 25 15
------- ------ ------
$ 194 $ 335 $ 145
======= ====== ======
Investments in Equity Method Investees
Electric.................................................. $ 2 $ 2 $ 2
Other (c)................................................. 659 643 553
------- ------ ------
$ 661 $ 645 $ 555
======= ====== ======
Total Assets
Electric (d).............................................. $ 6,831 $6,058 $5,784
Gas (d)................................................... 2,983 2,586 2,734
Other..................................................... 931 1,398 1,142
------- ------ ------
Subtotal.................................................. 10,745 10,042 9,660
Eliminations.............................................. -- (444) (469)
------- ------ ------
$10,745 $9,598 $9,191
======= ====== ======
Capital Expenditures (e)
Electric.................................................. $ 310 $ 437 $ 623
Gas....................................................... 135 181 145
------- ------ ------
$ 445 $ 618 $ 768
======= ====== ======
-------------------------
(a) 2002 excludes $28 million benefit and 2001 excludes $17 million expense due
to the change in accounting for derivative instruments.
(b) 2002 excludes $10 million tax expense and 2001 excludes $6 million tax
benefit due to the change in accounting for derivative instruments.
(c) As of December 31, 2003, the trusts that hold the mandatorily redeemable
Trust Preferred Securities were deconsolidated. The trusts are now included
on the Consolidated Balance Sheets as Investments -- Other.
(d) Amounts include a portion of our other common assets attributable to both
the electric and gas utility businesses.
CE-76
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(e) Amounts include electric restructuring implementation plan, capital leases
for nuclear fuel, purchase of nuclear fuel, and other assets. Amounts also
include a portion of capital expenditures for plant and equipment
attributable to both the electric and gas utility businesses.
11: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under the PPA with the MCV Partnership discussed in Note 2, Uncertainties,
our 2003 obligation to purchase electric capacity from the MCV Partnership
provided 15 percent of our owned and contracted electric generating capacity.
Summarized financial information of the MCV Partnership follows:
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31
------------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Operating revenue(a)........................................ $584 $597 $611
Operating expenses.......................................... 416 409 453
---- ---- ----
Operating income............................................ 168 188 158
Other expense, net.......................................... 108 114 110
---- ---- ----
Income before cumulative effect of accounting change........ 60 74 48
Cumulative effect of change in method of accounting for
derivative options contracts(b)........................... -- 58 --
---- ---- ----
Net Income.................................................. $ 60 $132 $ 48
==== ==== ====
CE-77
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
BALANCE SHEETS
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Assets
Current assets(c)...... $ 389 $ 358
Plant, net............. 1,494 1,550
Other assets........... 187 190
------ ------
$2,070 $2,098
====== ======
DECEMBER 31
----------------
2003 2002
---- ----
IN MILLIONS
Liabilities and Equity
Current liabilities.... $ 250 $ 209
Non-current
liabilities(d)...... 1,021 1,155
Partners' equity(e).... 799 734
------ ------
$2,070 $2,098
====== ======
-------------------------
(a) Revenue from Consumers totaled $514 million in 2003, $557 million in 2002,
and $550 million in 2001.
(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard
for derivatives. As a result, the MCV Partnership began accounting for
several natural gas contracts containing an option component at fair value.
The MCV Partnership recorded a $58 million cumulative effect adjustment for
the change in accounting principle as an increase to earnings. CMS
Midland's 49 percent ownership share was $28 million ($18 million
after-tax), which is reflected as a change in accounting principle on our
Consolidated Statements of Income.
(c) Receivables from Consumers totaled $40 million for December 31, 2003 and
$44 million for December 31, 2002.
(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term
direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4
percent ownership interest in FMLP. The MCV Partnership's lease
obligations, assets, and operating revenues secure FMLP's debt. The
following table summarizes obligation and payment information regarding the
direct finance lease.
DECEMBER 31
------------
2003 2002
---- ----
IN MILLIONS
Balance Sheet:
MCV Partnership: Lease obligation......................................... $894 $975
FMLP: Non-recourse debt........................................ 431 449
Lease payment to service non-recourse debt (including
interest)................................................ 158 370
CMS Holdings: Share of interest portion of lease payment............... 37 34
Share of principle portion of lease payment.............. 36 65
YEARS ENDED
DECEMBER 31
--------------------
2003 2002 2001
---- ---- ----
IN MILLIONS
Income Statement:
FMLP: Earnings.............................................. $32 $38 $30
-------------------------
(e) CMS Midland's recorded investment in the MCV Partnership includes
capitalized interest, which we are expensing over the life of our investment
in the MCV Partnership. The financing agreements prohibit the MCV
Partnership from distributing any cash to its owners until it meets certain
financial test requirements. We do not anticipate receiving a cash
distribution in the near future.
CE-78
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12: 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. Accretion of $1 million related to the Big Rock and
Palisades' profit component included in the estimated cost of removal was
expensed for 2003.
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 be $381 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.
CE-79
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
IN SERVICE TRUST
ARO DESCRIPTION DATE LONG LIVED ASSETS FUND
--------------- ---------- ----------------- -----
IN MILLIONS
December 31, 2003
Palisades -- decommission plant
site............................... 1972 Palisades nuclear plant $487
Big Rock -- decommission plant site... 1962 Big Rock nuclear plant 88
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
PRO FORMA ARO LIABILITY ARO
ARO LIABILITY ----------------------------- CASH FLOW LIABILITY
ARO DESCRIPTION 1/1/02 1/1/03 INCURRED SETTLED ACCRETION REVISIONS 12/31/03
--------------- ------------- ------ -------- ------- --------- --------- ---------
IN MILLIONS
December 31, 2003
Palisades -- decommission... $232 $249 $-- $ -- $19 $-- $268
Big Rock -- decommission.... 94 61 -- (39) 13 -- 35
JHCampbell intake line...... -- -- -- -- -- -- --
Coal ash disposal areas..... 46 51 -- (4) 5 -- 52
Wells at gas storage
fields................... 2 2 -- -- -- -- 2
Indoor gas services
relocations.............. 1 1 -- -- -- -- 1
---- ---- --- ---- --- --- ----
Total.................. $375 $364 $-- $(43) $37 $-- $358
==== ==== === ==== === === ====
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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 were reclassified as regulatory liabilities in the
accompanying consolidated balance sheets.
13: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND
HEDGING ACTIVITIES: Amends and clarifies financial accounting and reporting for
derivative instruments, including certain derivative instruments embedded in
other contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. This statement is effective for
contracts entered into or modified after June 30, 2003. Implementation of this
statement has not impacted our Consolidated Financial Statements.
SFAS NO. 150, ACCOUNTING FOR CERTAIN FINANCIAL INSTRUMENTS WITH
CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY: Establishes standards for how we
classify and measure certain financial instruments with characteristics of both
liabilities and equity. The statement requires us to classify financial
instruments within its scope as liabilities rather than mezzanine equity, the
area between liabilities and equity. SFAS No. 150 became effective July 1, 2003.
We have four Trust Preferred Securities outstanding as of December 31, 2003
that are issued by our affiliated trusts. Each trust holds a subordinated
debenture from the parent company. The terms of the debentures are identical to
those of the trust-preferred securities, except that the debenture has an
explicit maturity date. The
CE-80
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
trust documents, in turn, require that the trust be liquidated upon the
repayment of the debenture. The preferred securities are redeemable upon the
liquidation of the subsidiary; therefore, they are considered equity in the
financial statements of the subsidiary.
At their October 29, 2003 Board meeting, the FASB deferred the
implementation of the portion of SFAS No. 150 relating to mandatorily redeemable
noncontrolling interests in subsidiaries when the noncontrolling interests are
classified as equity in the financial statements of the subsidiary. Our Trust
Preferred Securities are included in the deferral action.
Upon adoption of FASB Interpretation No. 46, we determined that our trusts
that issue Trust Preferred Securities should be deconsolidated and reported as
long-term debt -- related parties. Refer to further discussion under "Accounting
Standards Not Yet Effective -- FASB Interpretation No. 46, Consolidation of
Variable Interest Entities."
EITF ISSUE NO. 01-08, DETERMINING WHETHER AN ARRANGEMENT CONTAINS A
LEASE: In May 2003, the EITF reached consensus in EITF Issue No. 01-08 requiring
both parties to a transaction, such as power purchase agreements, to determine
whether a service contract or similar arrangement is or includes a lease within
the scope of SFAS No. 13, Accounting for Leases. The consensus is to be applied
prospectively to arrangements agreed to, modified, or acquired in business
combinations in fiscal periods beginning July 1, 2003.
Prospective accounting under EITF Issue No. 01-08, could affect the timing
and classification of revenue and expense recognition. Certain product sales and
service revenue and expenses may be required to be reported as rental or leasing
income and/or expenses. Transactions deemed to be capital lease arrangements
would be included on our balance sheet. The adoption of EITF Issue No. 01-08 has
not impacted our results of operations, cash flows, or financial position.
EITF ISSUE NO. 03-04, ACCOUNTING FOR CASH BALANCE PENSION PLANS: In May
2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address
the accounting for certain cash balance pension plans. EITF Issue No. 03-04
concluded that certain cash balance plans be accounted for as defined benefit
plans under SFAS No. 87, Employers' Accounting for Pensions. The EITF
requirements must be applied as of our next plan measurement date after
issuance, which is December 31, 2003. In 2003, we started a cash balance pension
plan that covers employees hired after June 30, 2003. We account for this plan
as a defined benefit plan under SFAS No. 87 and comply with EITF Issue No.
03-04. For further information, see Note 7, Retirement Benefits.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: 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 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 provides an implementation deferral, until
the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for
the first quarter of 2004 for all entities other than special purpose entities.
Special-purpose entities must apply either FASB Interpretation No. 46 or Revised
FASB Interpretation No. 46 for the first reporting period that ends after
December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have
adopted Revised FASB Interpretation No. 46 for all entities other than the MCV
Partnership and FMLP. We continue to evaluate and gather information regarding
those entities. We will adopt the provisions of Revised FASB Interpretation No.
46 for the MCV Partnership and FMLP in the first quarter of 2004.
CE-81
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
If our completed analysis shows we have the controlling financial interest
in the MCV Partnership and FMLP, we would consolidate their assets, liabilities,
and activities, including $700 million of non-recourse debt, into our financial
statements. Financial covenants under our financing agreements could be impacted
negatively after such a consolidation. As a result, it may become necessary to
seek amendments to the relevant financing agreements to modify the terms of
certain of these covenants to remove the effect of this consolidation, or to
refinance the relevant debt. As of December 31, 2003, our investment in the MCV
Partnership was $419 million and our investment in the FMLP was $224 million.
We also determined that we do not hold the controlling financial interest
in 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 have reflected $506 million of long-term debt -- related
parties and have 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.
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 is expected to be presented for FASB clearance in 2004 and
would be applicable for fiscal years beginning after December 15, 2004. An asset
classified as property, plant, and equipment asset often comprises multiple
parts and costs. A component accounting policy determines the level at which
those parts are recorded. Capitalization of certain costs related to property,
plant, and equipment are included in the total cost. The Statement of Position
could impact our component and capitalization accounting for property, plant,
and equipment. We continue to evaluate the impact, if any, this Statement of
Position will have upon adoption.
14: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
2003
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------------- -------- ------- -------- -------
IN MILLIONS
Operating revenue.......................................... $1,442 $902 $879 $1,212
Earnings from equity method investees...................... 16 18 (3) 11
Operating income........................................... 233 139 115 96
Income (loss) before cumulative effect of change in
accounting principle (a)................................. 110 52 44 (10)
Net income (loss) (a)...................................... 110 52 44 (10)
Preferred stock dividends.................................. -- 1 -- 1
Preferred securities distributions (a)..................... 11 11 11 (33)
Net income available to common stockholder................. 99 40 33 22
-------------------------
(a) As of December 31, 2003, we deconsolidated the trusts that hold the
mandatorily redeemable Trust Preferred Securities. As a result of the
deconsolidation, we now record on the Consolidated Statements of Income
interest on long-term debt -- related parties to the trusts holding the
Trust Preferred Securities.
CE-82
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2002
------------------------------------------
QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------------- -------- ------- -------- -------
IN MILLIONS
Operating revenue (b)...................................... $1,226 $883 $911 $1,149
Earnings from equity method investees...................... 10 18 8 17
Operating income (b)....................................... 188 152 168 181
Income before cumulative effect of change in accounting
principle (b)............................................ 92 107 84 80
Cumulative effect of change in accounting for derivative
instruments, net of $10 tax expense in 2002 (b).......... -- 17 1 --
Net income................................................. 92 124 85 80
Preferred stock dividends.................................. -- -- -- 2
Preferred securities distributions......................... 11 11 11 11
Net income available to common stockholder................. 81 113 74 67
-------------------------
(b) We reclassified $28 million ($18 million after taxes) reducing June and
September 2002 operating amounts to reflect the MCV Partnership's change in
accounting for derivative instruments as a separate item. For additional
details see Note 11, Summarized Financial Information of Significant
Related Energy Supplier.
CE-83
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Consumers Energy Company
We have audited the accompanying consolidated balance sheets of Consumers
Energy Company (a Michigan corporation and wholly-owned subsidiary of CMS Energy
Corporation) and subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of income, common stockholder's equity and cash flows
for each of the three years in the period ended December 31, 2003. Our audits
also included the financial statement schedule listed in the Index at Item
15(a)(2). These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits. The financial statements
of Midland Cogeneration Venture Limited Partnership (a limited partnership in
which Consumers Energy Company and subsidiaries has a 49% interest), have been
audited by other auditors (the other auditors for 2001 for Midland Cogeneration
Venture Limited Partnership have ceased operations) whose reports have been
furnished to us; insofar as our opinion on the consolidated financial statements
relates to the amounts included for Midland Cogeneration Venture Limited
Partnership, it is based solely on their reports.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits and the reports of other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and the reports of other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Consumers Energy
Company and subsidiaries at December 31, 2003 and 2002, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 in conformity with U.S. generally accepted
accounting principles. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly in all material respects the information set forth
therein.
As discussed in Notes 12 and 13 to the consolidated financial statements,
in 2003, the Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" and of
Financial Accounting Standards Board Interpretation No. 46, "Consolidation of
Variable Interest Entities". As discussed in Notes 6 and 11 to the consolidated
financial statements, in 2002, the Company adopted the provisions SFAS No. 148,
"Accounting for Stock-Based Compensation" and Midland Cogeneration Venture
Limited Partnership adopted the provisions of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", as amended and interpreted.
/s/ ERNST & YOUNG LLP
Detroit, Michigan
February 27, 2004
CE-84
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, partners' equity and cash flows
present fairly, in all material respects, the financial position of the Midland
Cogeneration Limited Partnership (a Michigan limited partnership) and its
subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their
operations and their cash flows for the each of the two years ended December 31,
2003 and 2002 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
MCV's management. Our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The financial statements of
MCV for the year ended December 31, 2001, were audited by other independent
accountants who have ceased operations. Those independent accountants expressed
an unqualified opinion on those financial statements in their report dated
January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1,
2002, Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 18, 2004
CE-85
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED
ARTHUR ANDERSEN REPORT AND THIS REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the
Midland Cogeneration Venture Limited Partnership:
We have audited the accompanying consolidated balance sheets of the MIDLAND
COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited partnership) and
subsidiaries (MCV) as of December 31, 2001 and 2000, and the related
consolidated statements of operations, partners' equity and cash flows for each
of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of MCV's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of the Midland
Cogeneration Venture Limited Partnership and subsidiaries as of December 31,
2001 and 2000, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1,
2001, Midland Cogeneration Venture Limited Partnership changed its method of
accounting related to derivatives and hedging activities.
/s/Arthur Andersen LLP
Detroit, Michigan,
January 18, 2002
CE-86
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE.
CMS ENERGY
In April 2002, CMS Energy's Board of Directors, upon the recommendation of
the Audit Committee of the Board, voted to discontinue using Arthur Andersen LLP
to audit CMS Energy's financial statements for the year ending December 31,
2002. CMS Energy had previously retained Arthur Andersen LLP to review its
financial statements for the quarter ended March 31, 2002. In May 2002, CMS
Energy's Board of Directors engaged Ernst & Young LLP to audit its financial
statements for the year ending December 31, 2002. Ernst & Young LLP audited
2000, 2001, and 2002. As a result, CMS Energy restated its 2000 and 2001
financial statements. The restated 2001 financial statements are contained
herein.
CONSUMERS
In April 2002, Consumers' Board of Directors, upon the recommendation of
the Audit Committee of the Board, voted to discontinue using Arthur Andersen LLP
to audit Consumers' financial statements for the year ending December 31, 2002.
Consumers had previously retained Arthur Andersen LLP to review its financial
statements for the quarter ended March 31, 2002. In May 2002, Consumers' Board
of Directors engaged Ernst & Young LLP to audit its financial statements for the
year ending December 31, 2002. Ernst & Young LLP audited 2000, 2001, and 2002.
As a result, Consumers restated its 2000 and 2001 financial statements. The
restated 2001 financial statements are contained herein.
ITEM 9A. 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.
CO-1
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.
CMS ENERGY
Information that is required in Item 10 regarding directors and executive
officers is included in CMS Energy's definitive proxy statement, which is
incorporated by reference herein.
CONSUMERS
Information that is required in Item 10 regarding Consumers' directors and
executive officers is included in CMS Energy's definitive proxy statement, which
is incorporated by reference herein.
ITEM 11. EXECUTIVE COMPENSATION.
CMS ENERGY
Information that is required in Item 11 regarding executive compensation is
included in CMS Energy's definitive proxy statement, which is incorporated by
reference herein.
CONSUMERS
Information that is required in Item 11 regarding executive compensation of
Consumers' executive officers is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT RELATED STOCKHOLDER MATTERS.
CMS ENERGY
Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management of Consumers is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
CMS ENERGY
Information that is required in Item 13 regarding certain relationships and
related transactions is included in CMS Energy's definitive proxy statement,
which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 13 regarding certain relationships and
related transactions regarding Consumers is included in CMS Energy's definitive
proxy statement, which is incorporated by reference herein.
CO-2
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
CMS ENERGY
Information that is required in Item 14 regarding principal accountant fees
and services is included in CMS Energy's definitive proxy statement, which is
incorporated by reference herein.
CONSUMERS
Information that is required in Item 14 regarding Consumers' principal
accountant fees and services is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.
(a)(1) Financial Statements and Reports of Independent Public Accountants
for CMS Energy and Consumers are included in each company's ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by
reference herein.
(a)(2) Financial Statement Schedules and Reports of Independent Public
Accountants for CMS Energy and Consumers are included after the
Exhibits to the Index to Financial Statement Schedules and are
incorporated by reference herein.
(a)(3) Exhibits for CMS Energy and Consumers are listed after Item 15(c)
below and are incorporated by reference herein.
(b) Reports on Form 8-K
CMS ENERGY
During the fourth quarter of 2003, CMS Energy filed or furnished the
following Current Reports on Form 8-K:
- 8-K filed on October 17, 2003 covering matters pursuant to Item 5, Other
Events;
- 8-K filed on October 24, 2003 covering matters pursuant to Item 5, Other
Events;
- 8-K furnished on November 12, 2003 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);
- 8-K filed on November 26, 2003 covering matters pursuant to Item 5, Other
Events;
- 8-K filed on December 5, 2003 covering matters pursuant to Item 5, Other
Events; and
- 8-K filed on December 19, 2003 covering matters pursuant to Item 5, Other
Events.
CONSUMERS
During the fourth quarter of 2003, Consumers filed or furnished the
following Current Reports on Form 8-K:
- 8-K filed on October 24, 2003 covering matters pursuant to Item 5, Other
Events;
- 8-K furnished on November 12, 2003 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);
- 8-K filed on November 26, 2003 covering matters pursuant to Item 5, Other
Events;
CO-3
- 8-K filed on December 5, 2003 covering matters pursuant to Item 5, Other
Events; and
- 8-K filed on December 19, 2003 covering matters pursuant to Item 5, Other
Events.
(c) Exhibits, including those incorporated by reference (see also
Exhibit volume).
CO-4
CMS ENERGY'S AND CONSUMERS' EXHIBITS
PREVIOUSLY FILED
--------------------------
WITH FILE AS EXHIBIT
EXHIBITS NUMBER NUMBER DESCRIPTION
-------- --------- ---------- -----------
(3)(a) 333-51932 (3)(a) -- Restated Articles of Incorporation of CMS Energy (Form
S-3 filed December 15, 2000)
(3)(b) 333-45556 (3)(b) -- By-Laws of CMS Energy (Form S-3 filed September 11, 2000)
(3)(c) 1-5611 3(c) -- Restated Articles of Incorporation dated May 26, 2000, of
Consumers (2000 Form 10-K)
(3)(d) 1-5611 (3)(d) -- By-Laws of Consumers (1st qtr. 2003 Form 10-Q)
(4)(a) 2-65973 (b)(1)-4 -- Indenture dated as of September 1, 1945, between
Consumers and Chemical Bank (successor to Manufacturers
Hanover Trust Company), as Trustee, including therein
indentures supplemental thereto through the Forty-third
Supplemental Indenture dated as of May 1, 1979
-- Indentures Supplemental thereto:
33-41126 (4)(c) -- 68th dated as of 06/15/93
1-5611 (4) -- 69th dated as of 09/15/93 (Form 8-K dated Sep. 21, 1993)
1-5611 (4)(a) -- 70th dated as of 02/01/98 (1997 Form 10-K)
1-5611 (4)(a) -- 71st dated as of 03/06/98 (1997 Form 10-K)
333-58943 (4)(d) -- 73rd dated as of 06/15/98 (Form S-4 dated July 13, 1998)
1-5611 (4)(b) -- 74th dated as of 10/29/98 (3rd qtr. 1998 Form 10-Q)
1-5611 (4)(b) -- 75th dated as of 10/1/99 (1999 Form 10-K)
1-5611 (4)(d) -- 77th dated as of 10/1/99 (1999 Form 10-K)
1-5611 4(b) -- 79th dated as of 9/26/01 (3rd qtr 2001 10-Q)
1-5611 4(a)(i) -- 80th dated as of 3/22/02 (2001 Form 10-K)
1-5611 (4)(a) -- 87th dated as of 3/26/03 (1st qtr. 2003 Form 10-Q)
1-5611 (4)(d) -- 90th dated as of 3/30/03 (1st qtr. 2003 Form 10-Q)
1-5611 (4)(a) -- 91st dated as of 5/23/03 (3rd qtr. 2003 Form 10-Q)
1-5611 (4)(b) -- 92nd dated as of 8/26/03 (3rd qtr. 2003 Form 10-Q)
1-5611 (4)(c) -- 93rd dated as of 9/17/03 (3rd qtr. 2003 Form 10-Q)
333-111220 (4)(a)(i) -- 94th dated as of 11/7/03 (Consumers Form S-4 dated
December 16, 2003)
(4)(b) 1-5611 (4)(b) -- Indenture dated as of January 1, 1996 between Consumers
and The Bank of New York, as Trustee (1995 Form 10-K)
-- Indentures Supplemental thereto:
1-5611 (4)(b) -- 1st dated as of 01/18/96 (1995 Form 10-K)
1-5611 (4)(a) -- 2nd dated as of 09/04/97 (3rd qtr 1997 Form 10-Q)
1-9513 (4)(a) -- 3rd 11/04/99 (3rd qtr 1999 Form 10-Q)
(4)(c) 1-5611 (4)(c) -- Indenture dated as of February 1, 1998 between Consumers
and JPMorgan Chase (formerly "The Chase Manhattan Bank),
as Trustee (1997 Form 10-K)
1-5611 (4)(a) -- 1st dated as of 05/01/98 (1st Qtr. 1998 Form 10-Q)
333-58943 (4)(b) -- 2nd dated as of 06/15/98
1-5611 (4)(a) -- 3rd 10/29/98 (3rd qtr. 1998 Form 10-Q)
4(d) 1-5611 (4)(e) -- $140 million Term Loan Agreement dated March 26, 2003
between Consumers Energy Company and the Bank/Agent, as
defined therein (1st qtr. 2003 Form 10-Q)
(4)(e) 33-47629 (4)(a) -- Indenture dated as of September 15, 1992 between CMS
Energy and NBD Bank, as Trustee (Form S-3 filed May 1,
1992)
-- Indentures Supplemental thereto:
333-37241 (4)(a) -- 4th dated as of 09/26/97 (Form S-3 filed October 6, 1997)
CO-5
PREVIOUSLY FILED
--------------------------
WITH FILE AS EXHIBIT
EXHIBITS NUMBER NUMBER DESCRIPTION
-------- --------- ---------- -----------
1-9513 (4)(d) -- 6th dated as of 01/13/98 (1997 Form 10-K)
1-9513 (4)(d)(i) -- 7th dated as of 01/25/99 (1998 Form 10-K)
333-48276 (4) -- 10th dated as of 10/12/00 (Form S-3 filed October 19,
2000)
333-58686 (4) -- 11th dated as of 03/29/01 (Form S-8 filed April 11, 2001)
333-51932 (4)(a) -- 12th dated as of 07/02/01 (Form POS AM filed August 8,
2001)
4(e)(i) -- 13th dated as of 07/16/03
4(e)(ii) -- 14th dated as of 07/17/03
(4)(f) 1-9513 (4)(b) -- Indenture between CMS Energy and JPMorgan Chase (formerly
"The Chase Manhattan Bank"), as Trustee, dated as of
January 15, 1994 (Form 8-K dated March 29, 1994)
-- Indentures Supplemental thereto:
1-9513 (4b) -- 1st dated as of 01/20/94 (Form 8-K dated March 29, 1994)
1-9513 (4) -- 2nd dated as of 03/19/96 (1st qtr 1996 Form 10-Q)
1-9513 (4)(a)(iv) -- 3rd dated as of 03/17/97 (Form 8-K dated May 1, 1997)
333-36115 (4)(d) -- 4th dated as of 09/17/97 (Form S-3 filed September 22,
1997)
333-63229 (4)(c) -- 5th dated as of 08/26/98 (Form S-4 filed September 10,
1998)
1-9513 (4) -- 6th dated as of 11/9/00 (3rd qtr 2000 Form 10-Q)
333-74958 (4)(a)(viii) -- Form of Seventh Indenture (Form S-3 filed December 12,
2001)
(4)(g) 1-9513 (4a) -- Indenture dated as of June 1, 1997, between CMS Energy
and The Bank of New York, as trustee (Form 8-K filed July
1, 1997) Indentures Supplemental thereto:
1-9513 (4)(b) -- 1st dated as of 06/20/97 (Form 8-K filed July 1, 1997)
333-45556 (4)(e) -- 4th dated as of 08/22/00 (Form S-3 filed September 11,
2000)
(4)(h) -- $185 million Credit Agreement, as amended, dated May 22,
2003 among CMS Energy and the Financial Institutions,
Documentation Agent and Administrative Agent, as defined
therein
(4)(i) -- Certificate of Designation of 4.50% Cumulative
Convertible Preferred Stock dated as of December 2, 2003
(4)(j) -- Registration Rights Agreement dated as of July 16, 2003
between CMS Energy and the Initial Purchasers, all as
defined therein
(4)(k) -- Registration Rights Agreement dated as of July 17, 2003
between CMS Energy and the Initial Purchasers, all as
defined therein
(4)(l) -- Registration Rights Agreement dated as of December 5,
2003 between CMS Energy and the Initial Purchasers, all
as defined therein
(4)(m) -- $190 million Fourth Amended and Restated Credit Agreement
dated as of December 8, 2003 among CMS Energy, CMS
Enterprises, the Banks, and the Administrative Agent and
Collection Agent, all defined therein
(4)(n) 1-9513 4.9 -- Pledge and Security Agreement dated as of July 12, 2002
among CMS Energy, Grantors and the Collateral Agent, all
as defined therein (Form 8-K filed July 30, 2002)
(4)(o) -- Third Amended and Restated Pledge and Security Agreement
dated as of December 8, 2003 among CMS Energy and the
Collateral Agent, as defined therein
(4)(p) -- Amended and Restated Guaranty dated as of December 8,
2003 by the Guarantor in favor of the Lenders, all as
defined therein
(10)(a) 1-9513 (10)(b) -- Form of Employment Agreement entered into by CMS Energy's
and Consumers' executive officers (1999 Form 10-K)
CO-6
PREVIOUSLY FILED
--------------------------
WITH FILE AS EXHIBIT
EXHIBITS NUMBER NUMBER DESCRIPTION
-------- --------- ---------- -----------
(10)(b) 1-9513 (10)(a) -- Acknowledgement of Resignation between Tamela W. Pallas
and CMS Energy Corporation (3rd qtr 2002 Form 10-Q)
(10)(c) 1-5611 (10)(g) -- Consumers' Executive Stock Option and Stock Appreciation
Rights Plan effective December 1, 1989 (1990 Form 10-K)
(10)(d) 1-9513 (10)(b) -- Employment, Separation and General Release Agreement
between William T. McCormick and CMS Energy Corporation
(3rd qtr 2002 Form 10-Q)
(10)(e) 1-9513 (10)(d) -- CMS Energy's Performance Incentive Stock Plan effective
February 3, 1988, as amended December 3, 1999 (1999 Form
10-K)
(10)(f) 1-9513 (10)(c) -- Employment, Separation and General Release Agreement
between Alan M. Wright and CMS Energy Corporation (3rd
qtr 2002 Form 10-Q)
(10)(g) -- CMS Energy's Salaried Employees Merit Program for 2003
effective January 1, 2003
(10)(h) 1-9513 (10)(m) -- CMS Deferred Salary Savings Plan effective January 1,
1994 (1993 Form 10-K)
(10)(i) -- Annual Officer Incentive Compensation Plan for CMS Energy
Corporation and its Subsidiaries effective January 1,
2003
(10)(j) 1-9513 (10)(h) -- Supplemental Executive Retirement Plan for Employees of
CMS Energy/Consumers Energy Company effective January 1,
1982, as amended December 3, 1999 (1999 Form 10-K)
(10)(k) 33-37977 4.1 -- Senior Trust Indenture, Leasehold Mortgage and Security
Agreement dated as of June 1, 1990 between The
Connecticut National Bank and United States Trust Company
of New York (MCV Partnership)
Indenture Supplemental thereto:
33-37977 4.2 -- Supplement No. 1 dated as of June 1, 1990 (MCV
Partnership)
(10)(l) 1-9513 (28)(b) -- Collateral Trust Indenture dated as of June 1, 1990 among
Midland Funding Corporation I, MCV Partnership and United
States Trust Company of New York, Trustee (3rd qtr 1990
Form 10-Q)
Indenture Supplemental thereto:
33-37977 4.4 -- Supplement No. 1 dated as of June 1, 1990 (MCV
Partnership)
(10)(m) 1-9513 (10)(v) -- Amended and Restated Investor Partner Tax Indemnification
Agreement dated as of June 1, 1990 among Investor
Partners, CMS Midland as Indemnitor and CMS Energy as
Guarantor (1990 Form 10-K)
(10)(n) 1-9513 (19)(d)* -- Environmental Agreement dated as of June 1, 1990 made by
CMS Energy to The Connecticut National Bank and Others
(1990 Form 10-K)
(10)(o) 1-9513 (10)(z)* -- Indemnity Agreement dated as of June 1, 1990 made by CMS
Energy to Midland Cogeneration Venture Limited
Partnership (1990 Form 10-K)
(10)(p) 1-9513 (10)(aa)* -- Environmental Agreement dated as of June 1, 1990 made by
CMS Energy to United States Trust Company of New York,
Meridian Trust Company, each Subordinated Collateral
Trust Trustee and Holders from time to time of Senior
Bonds and Subordinated Bonds and Participants from time
to time in Senior Bonds and Subordinated Bonds (1990 Form
10-K)
CO-7
PREVIOUSLY FILED
--------------------------
WITH FILE AS EXHIBIT
EXHIBITS NUMBER NUMBER DESCRIPTION
-------- --------- ---------- -----------
(10)(q) 33-37977 10.4 -- Amended and Restated Participation Agreement dated as of
June 1, 1990 among MCV Partnership, Owner Participant,
The Connecticut National Bank, United States Trust
Company, Meridian Trust Company, Midland Funding
Corporation I, Midland Funding Corporation II, MEC
Development Corporation and Institutional Senior Bond
Purchasers (MCV Partnership)
(10)(r) 33-3797 10.4 -- Power Purchase Agreement dated as of July 17, 1986
between MCV Partnership and Consumers (MCV Partnership)
Amendments thereto:
33-37977 10.5 -- Amendment No. 1 dated September 10, 1987 (MCV
Partnership)
33-37977 10.6 -- Amendment No. 2 dated March 18, 1988 (MCV Partnership)
33-37977 10.7 -- Amendment No. 3 dated August 28, 1989 (MCV Partnership)
33-37977 10.8 -- Amendment No. 4A dated May 25, 1989 (MCV Partnership)
(10)(s) 1-5611 (10)(y) -- Unwind Agreement dated as of December 10, 1991 by and
among CMS Energy, Midland Group, Ltd., Consumers, CMS
Midland, Inc., MEC Development Corp. and CMS Midland
Holdings Company (1991 Form 10-K)
(10)(t) 1-5611 (10)(z) -- Stipulated AGE Release Amount Payment Agreement dated as
of June 1, 1990, among CMS Energy, Consumers and The Dow
Chemical Company (1991 Form 10-K)
(10)(u) 1-5611 (10)(aa)* -- Parent Guaranty dated as of June 14, 1990 from CMS Energy
to MCV, each of the Owner Trustees, the Indenture
Trustees, the Owner Participants and the Initial
Purchasers of Senior Bonds in the MCV Sale Leaseback
transaction, and MEC Development (1991 Form 10-K)
(10)(v) 1-8157 10.41 -- Contract for Firm Transportation of Natural Gas between
Consumers Power Company and Trunkline Gas Company, dated
November 1, 1989, and Amendment, dated November 1, 1989
(1989 Form 10-K of PanEnergy Corp.)
(10)(w) 1-8157 10.41 -- Contract for Firm Transportation of Natural Gas between
Consumers Power Company and Trunkline Gas Company, dated
November 1, 1989 (1991 Form 10-K of PanEnergy Corp.)
(10)(x) 1-2921 10.03 -- Contract for Firm Transportation of Natural Gas between
Consumers Power Company and Trunkline Gas Company, dated
September 1, 1993 (1993 Form 10-K)
(10)(y) -- Purchase Agreement dated July 9, 2003 between CMS Energy
and the Initial Purchasers, as defined therein
(10)(z) -- Purchase Agreement dated July 9, 2003 between CMS Energy
and the Initial Purchasers, as defined therein
(10)(aa) -- Purchase Agreement dated December 1, 2003 between CMS
Energy and the Initial Purchasers, as defined therein
(10)(bb) 1-5611 10 -- First Amended and Restated Employment Agreement between
Kenneth Whipple and CMS Energy Corporation effective as
of September 1, 2003 (8-K dated October 24, 2003)
(10)(cc) -- Annual Management Incentive Compensation Plan for CMS
Energy Corporation and its Subsidiaries effective January
1, 2003
(10)(dd) -- Annual Employee Incentive Compensation Plan for CMS
Energy Corporation and its Subsidiaries effective January
1, 2003
(12)(a) -- Statement regarding computation of CMS Energy's Ratio of
Earnings to Fixed Charges
CO-8
PREVIOUSLY FILED
--------------------------
WITH FILE AS EXHIBIT
EXHIBITS NUMBER NUMBER DESCRIPTION
-------- --------- ---------- -----------
(12)(b) -- Statement regarding computation of Consumers' Ratio of
Earnings to Fixed Charges and Preferred Securities
Dividends and Distributions
(16) 1-5611 16.1 -- Letter from Arthur Andersen LLP to the Securities and
Exchange Commission dated April 29, 2002 regarding change
in certifying accountant (Form 8-K filed April 29, 2002)
(21) 1-9513 -- Subsidiaries of CMS Energy (Form U-3A-2 filed February
27, 2004)
(23)(a) -- Consent of Ernst & Young LLP for CMS Energy
(23)(b) -- Consent of PricewaterhouseCoopers LLP for CMS Energy re:
MCV
(23)(c) -- Consent of Price Waterhouse for CMS Energy re: Jorf
Lasfar
(23)(d) -- Consent of Ernst & Young for CMS Energy re: Emirates CMS
Power Company PJSC
(23)(e) -- Consent of Ernst & Young LLP for Consumers
(23)(f) -- Consent of PricewaterhouseCoopers LLP for Consumers re:
MCV
(24)(a) -- Power of Attorney for CMS Energy
(24)(b) -- Power of Attorney for Consumers
(31)(a) -- CMS Energy's certification of the CEO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(b) -- CMS Energy's certification of the CFO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(c) -- Consumers' certification of the CEO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(d) -- Consumers' certification of the CFO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(32)(a) -- CMS Energy's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
(32)(b) -- Consumers' certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(99)(a) -- Financial Statements for Midland Cogeneration Venture
Limited Partnership for the years ended December 31,
2001, 2002, and 2003
(99)(b) -- Financial Statements for Jorf Lasfar for the years ended
December 31, 2001, 2002, and 2003
(99)(c) -- Financial Statements for Emirates CMS Power Company for
the years ended December 31, 2001, 2002, and 2003
(99)(d) -- Representation regarding SCP Investments (1) PTY. LTD.
financial statements for the years ended June 30, 2002,
2003 and 2004
-------------------------
* Obligations of only CMS Holdings and CMS Midland, second tier subsidiaries of
Consumers, and of CMS Energy but not of Consumers.
Exhibits listed above that have heretofore been filed with the Securities
and Exchange Commission pursuant to various acts administered by the Commission,
and which were designated as noted above, are hereby incorporated herein by
reference and made a part hereof with the same effect as if filed herewith.
CO-9
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
----
Schedule II
Valuation and Qualifying Accounts and Reserves 2003, 2002
and 2001:
CMS Energy Corporation................................. CO-11
Consumers Energy Company............................... CO-12
Report of Independent Auditors
CMS Energy Corporation................................. CMS-120
Consumers Energy Company............................... CE-84
Schedules other than those listed above are omitted because they are either
not required, not applicable or the required information is shown in the
financial statements or notes thereto.
Columns omitted from schedules filed have been omitted because the
information is not applicable.
CO-10
CMS ENERGY CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
CHARGED/
BALANCE AT ACCRUED BALANCE
BEGINNING CHARGED TO OTHER AT END
DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- ---------- -------- ---------- ---------
(IN MILLIONS)
Accumulated provision for uncollectible
accounts:
2003...................................... $23 $28 $ 4 $15 $40
2002...................................... $23 $22 (3) $19 $23
2001...................................... $16 $22 (1) $14 $23
CO-11
CONSUMERS ENERGY COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
CHARGED/
BALANCE AT ACCRUED BALANCE
BEGINNING CHARGED TO OTHER AT END
DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- ---------- -------- ---------- ---------
(IN MILLIONS)
Accumulated provision for uncollectible
accounts:
2003...................................... $5 $16 -- $13 $8
2002...................................... $4 $17 -- $16 $5
2001...................................... $3 $13 -- $12 $4
CO-12
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, CMS
Energy Corporation has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CMS ENERGY CORPORATION
By: /s/ THOMAS J. WEBB
------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
Dated: July 21, 2004
CO-13
CMS ENERGY AND CONSUMERS EXHIBITS
2003 Form 10-K/A-1
EXHIBITS DESCRIPTION
-------- -----------
(23)(a) -- Consent of Ernst & Young LLP for CMS Energy
(23)(b) -- Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV
(23)(c) -- Consent of Price Waterhouse for CMS Energy re: Jorf Lasfar
(23)(d) -- Consent of Ernst & Young for CMS Energy re: Emirates CMS
Power Company PJSC
(23)(e) -- Consent of Ernst & Young LLP for Consumers
(23)(f) -- Consent of PricewaterhouseCoopers LLP for Consumers re: MCV
(31)(a) -- CMS Energy's certification of the CEO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(b) -- CMS Energy's certification of the CFO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(c) -- Consumers' certification of the CEO pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
(31)(d) -- Consumers' certification of the CFO pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
(32)(a) -- CMS Energy's certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(32)(b) -- Consumers' certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(99)(a) -- Report of Independent Auditors on Financial Statements for
Midland Cogeneration Venture Limited Partnership for the
years ended December 31, 2001, 2002, and 2003.
(99)(c) -- Financial Statements for Emirates CMS Power Company for the
years ended December 31, 2001, 2002, and 2003