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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_____to
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification No.
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1-9513 CMS ENERGY CORPORATION 38-2726431
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
1-5611 CONSUMERS ENERGY COMPANY 38-0442310
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
Indicate by check mark whether the Registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the Registrants are accelerated filers (as
defined in Rule 12b-2 of the Exchange Act).
CMS ENERGY CORPORATION: Yes [X] No [ ]
CONSUMERS ENERGY COMPANY: Yes [ ] No [X]
Number of shares outstanding of each of the issuer's classes of common stock at
July 31, 2004:
CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 161,277,622
CONSUMERS ENERGY COMPANY, $10 par value, privately held by CMS
Energy Corporation 84,108,789
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CMS ENERGY CORPORATION
AND
CONSUMERS ENERGY COMPANY
QUARTERLY REPORTS ON FORM 10-Q TO THE
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FOR THE QUARTER ENDED JUNE 30, 2004
This combined Form 10-Q is separately filed by CMS Energy Corporation and
Consumers Energy Company. Information contained herein relating to each
individual registrant is filed by such registrant on its own behalf.
Accordingly, except for its subsidiaries, Consumers Energy Company makes no
representation as to information relating to any other companies affiliated with
CMS Energy Corporation.
TABLE OF CONTENTS
Page
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Glossary.................................................................................................. 4
PART I: FINANCIAL INFORMATION
CMS Energy Corporation
Management's Discussion and Analysis
Executive Overview.............................................................................. CMS - 1
Restatement of 2003 Financial Statements........................................................ CMS - 2
Consolidation of Variable Interest Entities..................................................... CMS - 2
Forward-Looking Statements and Risk Factors..................................................... CMS - 2
Results of Operations........................................................................... CMS - 4
Critical Accounting Policies.................................................................... CMS - 12
Capital Resources and Liquidity................................................................. CMS - 24
Outlook......................................................................................... CMS - 27
New Accounting Standards........................................................................ CMS - 39
Consolidated Financial Statements
Consolidated Statements of Income (Loss)........................................................ CMS - 42
Consolidated Statements of Cash Flows........................................................... CMS - 44
Consolidated Balance Sheets..................................................................... CMS - 46
Consolidated Statements of Common Stockholders' Equity.......................................... CMS - 48
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................................................ CMS - 49
2. Discontinued Operations, Other Asset Sales, Impairments, and Restructuring................. CMS - 52
3. Uncertainties.............................................................................. CMS - 57
4. Financings and Capitalization.............................................................. CMS - 81
5. Earnings Per Share and Dividends........................................................... CMS - 85
6. Financial and Derivative Instruments....................................................... CMS - 87
7. Retirement Benefits........................................................................ CMS - 92
8. Equity Method Investments.................................................................. CMS - 94
9. Reportable Segments........................................................................ CMS - 95
10. Asset Retirement Obligations............................................................... CMS - 96
11. Implementation of New Accounting Standards................................................. CMS - 98
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TABLE OF CONTENTS
(CONTINUED)
Page
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Consumers Energy Company
Management's Discussion and Analysis
Executive Overview.............................................................................. CE - 1
Consolidation of the MCV Partnership and the FLMP............................................... CE - 2
Forward-Looking Statements and Risk Factors..................................................... CE - 2
Results of Operations......................................................................... CE - 4
Critical Accounting Policies.................................................................... CE - 8
Capital Resources and Liquidity................................................................. CE - 16
Outlook......................................................................................... CE - 19
New Accounting Standards........................................................................ CE - 28
Consolidated Financial Statements
Consolidated Statements of Income............................................................... CE - 31
Consolidated Statements of Cash Flows........................................................... CE - 32
Consolidated Balance Sheets..................................................................... CE - 34
Consolidated Statements of Common Stockholder's Equity.......................................... CE - 36
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................................................. CE - 39
2. Uncertainties............................................................................... CE - 42
3. Financings and Capitalization............................................................... CE - 60
4. Financial and Derivative Instruments........................................................ CE - 63
5. Retirement Benefits......................................................................... CE - 67
6. Asset Retirement Obligations................................................................ CE - 68
7. Implementation of New Accounting Standards.................................................. CE - 70
Quantitative and Qualitative Disclosures about Market Risk................................................ CO - 1
Controls and Procedures................................................................................... CO - 1
PART II: OTHER INFORMATION
Item 1. Legal Proceedings............................................................................ CO - 1
Item 4. Submission of Matters to a Vote of Security Holders.......................................... CO - 5
Item 5. Other Information............................................................................ CO - 6
Item 6. Exhibits and Reports on Form 8-K............................................................. CO - 6
Signatures........................................................................................... CO - 8
3
GLOSSARY
Certain terms used in the text and financial statements are defined below
Accumulated Benefit Obligation..................... The liabilities of a pension plan based on service and pay to
date. This differs from the Projected Benefit Obligation
that is typically disclosed in that it does not reflect
expected future salary increases.
AEP................................................ American Electric Power, a non-affiliated company
ALJ................................................ Administrative Law Judge
Alliance RTO....................................... Alliance Regional Transmission Organization
Alstom............................................. Alstom Power Company
APB................................................ Accounting Principles Board
APB Opinion No. 18................................. APB Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock"
APT................................................ Australian Pipeline Trust
ARO................................................ Asset retirement obligation
Articles........................................... Articles of Incorporation
Attorney General................................... Michigan Attorney General
bcf................................................ Billion cubic feet
Big Rock........................................... Big Rock Point nuclear power plant, owned by Consumers
Board of Directors................................. Board of Directors of CMS Energy
Btu................................................ British thermal unit
CEO................................................ Chief Executive Officer
CFO................................................ Chief Financial Officer
Clean Air Act...................................... Federal Clean Air Act, as amended
CMS Electric and Gas............................... CMS Electric and Gas Company, a subsidiary of Enterprises
CMS Energy......................................... CMS Energy Corporation, the parent of Consumers and
Enterprises
CMS Energy Common Stock or
common stock..................................... Common stock of CMS Energy, par value $.01 per share
CMS ERM............................................ CMS Energy Resource Management Company, formerly CMS MST, a
subsidiary of Enterprises
CMS Field Services................................. CMS Field Services, formerly a wholly owned subsidiary of CMS
Gas Transmission. The sale of this subsidiary closed in July
2003.
CMS Gas Transmission............................... CMS Gas Transmission Company, a subsidiary of Enterprises
CMS Generation..................................... CMS Generation Co., a subsidiary of Enterprises
CMS Holdings....................................... CMS Midland Holdings Company, a subsidiary of Consumers
CMS Midland........................................ CMS Midland Inc., a subsidiary of Consumers
CMS MST............................................ CMS Marketing, Services and Trading Company, a wholly owned
subsidiary of Enterprises, whose name was changed to CMS ERM
effective January 2004
4
CMS Oil and Gas.................................... CMS Oil and Gas Company, formerly a subsidiary of Enterprises
CMS PEPS........................................... CMS Energy Premium Equity Participating Security Units (CMS
Energy Trust III)
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
EBITDA............................................. Earnings before income taxes, depreciation, and amortization
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
El Chocon.......................................... Hidroelectrica El Chocon, S.A., a 1,320 MW hydroelectric generating complex in
Argentina, in which CMS Energy 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
5
FASB Staff Position, No. 106-1..................... Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act
of 2003 (January 12, 2004)
FASB Staff Position, No. 106-2..................... Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act
of 2003 (May 19, 2004)
FERC............................................... Federal Energy Regulatory Commission
FMB................................................ First Mortgage Bonds
FMLP............................................... First Midland Limited Partnership, a partnership that holds a
lessor interest in the MCV facility
Ford............................................... Ford Motor Company
GasAtacama......................................... An integrated natural gas pipeline and electric generation
project located in Argentina and Chile which includes 702
miles of natural gas pipeline and a 720 MW gross capacity power
plant
GCR................................................ Gas cost recovery
GEII............................................... General Electric International Inc.
Goldfields......................................... A pipeline business located in Australia, in which CMS Energy
holds a 39.7 percent ownership interest
Guardian........................................... Guardian Pipeline, LLC, in which CMS Gas Transmission owned a
one-third interest
Health Care Plan................................... The medical, dental, and prescription drug programs offered
to eligible employees of Consumers and CMS Energy
HL Power........................................... H.L. Power Company, a California Limited Partnership, owner
of the Honey Lake generation project in Wendel, California
Integrum........................................... Integrum Energy Ventures, LLC
IPP................................................ Independent Power Production
JOATT.............................................. Joint Open Access Transmission Tariff
Jorf Lasfar........................................ The 1,356 MW coal-fueled power plant in Morocco, jointly
owned by CMS Generation and ABB Energy Ventures, Inc.
Karn............................................... D.E Karn/J.C. Weadock Generating Complex, which is owned by
Consumers Energy
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 held a 50 percent ownership interest
LNG................................................ Liquefied natural gas
Ludington.......................................... Ludington pumped storage plant, jointly owned by Consumers and
Detroit Edison
6
Marysville......................................... CMS Marysville Gas Liquids Company, a Michigan corporation and
a former 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 and now an indirect subsidiary of
Trans-Elect
Michigan Power..................................... CMS Generation Michigan Power, LLC, owner of the Kalamazoo
River Generating Station and the Livingston Generating Station
MISO............................................... Midwest Independent System Operator
Moody's............................................ Moody's Investors Service, Inc.
MPSC............................................... Michigan Public Service Commission
MSBT............................................... Michigan Single Business Tax
MTH................................................ Michigan Transco Holdings, Limited Partnership
MW................................................. Megawatts
NEIL............................................... Nuclear Electric Insurance Limited, an industry mutual insurance
company owned by member utility companies
NMC................................................ Nuclear Management Company, LLC, formed in 1999 by Northern
States Power Company (now Xcel Energy Inc.), Alliant Energy,
Wisconsin Electric Power Company, and Wisconsin Public Service
Company to operate and manage nuclear generating facilities
owned by the four utilities
NERC............................................... North American Electric Reliability Council
NRC................................................ Nuclear Regulatory Commission
NYMEX.............................................. New York Mercantile Exchange
OATT............................................... Open Access Transmission Tariff
OPEB............................................... Postretirement benefit plans other than pensions for retired
employees
Palisades.......................................... Palisades nuclear power plant, which is owned by Consumers
7
Panhandle.......................................... Panhandle Eastern Pipe Line Company, including its
subsidiaries Trunkline, Pan Gas Storage, Panhandle Storage,
and Panhandle Holdings. Panhandle was a wholly owned
subsidiary of CMS Gas Transmission. The sale of this
subsidiary closed in June 2003.
Parmelia........................................... A business located in Australia comprised of a pipeline,
processing facilities, and a gas storage facility, a
subsidiary of CMS Gas Transmission
PCB................................................ Polychlorinated biphenyl
Pension Plan....................................... The trusteed, non-contributory, defined benefit pension plan
of Panhandle, Consumers and CMS Energy
PJM RTO............................................ Pennsylvania-Jersey-Maryland Regional Transmission
Organization
Powder River....................................... CMS Oil & Gas previously owned a significant interest in
coalbed methane fields or projects developed within the
Powder River Basin which spans the border between Wyoming and
Montana. The Powder River properties have been sold.
PPA................................................ The Power Purchase Agreement between Consumers and the
MCV Partnership with a 35-year term commencing in March 1990,
as amended, and as interpreted by the Settlement Agreement
dated as of January 1, 1999 between the MCV and Consumers.
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
RCP................................................ Resource Conservation Plan
ROA................................................ Retail Open Access
RTO................................................ Regional Transmission Organization
Rouge.............................................. Rouge Steel Industries
SCP................................................ Southern Cross Pipeline in Australia, in which CMS Gas
Transmission holds a 45 percent ownership interest
SEC................................................ U.S. Securities and Exchange Commission
Securitization..................................... A financing method authorized by statute and approved by the
MPSC which allows a utility to sell its right to receive a
portion of the rate payments received from its customers for
the repayment of Securitization bonds issued by a special
purpose entity affiliated with such utility
SENECA............................................. Sistema Electrico del Estado Nueva Esparta, C.A., a subsidiary of Enterprises
SERP............................................... Supplemental Executive Retirement Plan
SFAS............................................... Statement of Financial Accounting Standards
SFAS No. 5......................................... SFAS No. 5, "Accounting for Contingencies"
SFAS No. 52........................................ SFAS No. 52, "Foreign Currency Translation"
8
SFAS No. 71........................................ SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation"
SFAS No. 87........................................ SFAS No. 87, "Employers' Accounting for Pensions"
SFAS No. 88........................................ SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for
Termination Benefits"
SFAS No. 98 ....................................... SFAS No. 98, "Accounting for Leases"
SFAS No. 106....................................... SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS No. 107....................................... Disclosures about Fair Value of Financial Instruments
SFAS No. 115....................................... SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities"
SFAS No. 123....................................... SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS No. 128....................................... SFAS No. 128, "Earnings per Share"
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 40 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
9
Trunkline.......................................... Trunkline Gas Company, LLC, formerly a subsidiary of CMS
Panhandle Holdings, LLC
Trunkline LNG...................................... Trunkline LNG Company, LLC, formerly a subsidiary of LNG
Holdings, LLC
Trust Preferred Securities......................... Securities representing an undivided beneficial interest in
the assets of statutory business trusts, the interests of
which have a preference with respect to certain trust
distributions over the interests of either CMS Energy or
Consumers, as applicable, as owner of the common beneficial
interests of the trusts
VEBA Trusts........................................ VEBA (voluntary employees' beneficiary association) trust
accounts established to specifically set aside employer
contributed assets to pay for future expenses of the OPEB plan
10
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CMS Energy Corporation
CMS ENERGY CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS
This MD&A is a combined report of CMS Energy and Consumers. The terms "we" and
"our" as used in this report refer to CMS Energy and its subsidiaries as a
combined entity, except where it is made clear that such term means only CMS
Energy.
EXECUTIVE OVERVIEW
CMS Energy is an integrated energy company with a business strategy focused
primarily in Michigan. We are the parent holding company of Consumers and
Enterprises. Consumers is a combination electric and gas utility company serving
Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity
investments, is engaged in domestic and international diversified energy
businesses including: independent power production and natural gas transmission,
storage and processing. We manage our businesses by the nature of services each
provides and operate principally in three business segments: electric utility,
gas utility, and enterprises.
We earn our revenue and generate cash from operations by providing electric and
natural gas utility services, electric power generation, gas transmission,
storage, and processing. 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 and service. Over the next few years, we
expect this strategy to reduce our parent company debt substantially, improve
our debt ratings, grow earnings at a mid-single digit rate, restore a meaningful
dividend, and position the company to make new investments consistent with our
strengths. In the near term, our new investments will focus on the utility.
We face important challenges in the future. We continue to lose industrial and
commercial customers to alternative electric suppliers without receiving
compensation for stranded costs caused by the lost sales. As of July 2004, we
have lost 858 MW or 11 percent of our electric load to these alternative
electric suppliers. Based on current trends, we predict load loss by year-end to
be in the range of 900 MW to 1,100 MW. However, no assurance can be made that
the actual load loss will be greater or less than that range. 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 seek
resolution of this issue. In July 2004, several bills were introduced into the
Michigan Senate that could change Michigan's Customer Choice Act.
Further, higher natural gas prices have harmed the economics of the MCV
Partnership and we are seeking approval from the MPSC to change the way the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV Partnership'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.
Our gas business faces market and regulatory uncertainties relating to gas
costs. We attempt to minimize these uncertainties by fully recovering what we
spend to purchase the gas through the GCR process. We
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CMS Energy Corporation
currently have a GCR year 2003-2004 reconciliation on file with the MPSC.
We 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 engaged in 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. We are also working to resolve outstanding litigation that stemmed
from energy trading and gas index price reporting activities in 2001 and
earlier.
Our business plan is targeted at predictable earnings growth and debt reduction.
We are now over a year into our plan to reduce, by about half, the debt of CMS
Energy over a five-year period. The result of these efforts will be a strong,
reliable energy company that will be poised to take advantage of opportunities
for further growth.
RESTATEMENT OF 2003 FINANCIAL STATEMENTS
Our financial statements as of and for the three and six months ended June 30,
2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales,
- certain derivative accounting corrections at our equity affiliates,
and
- 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.
CONSOLIDATION OF VARIABLE INTEREST ENTITIES
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
several entities, most notably the MCV Partnership and the FMLP. As a result, we
have consolidated the assets, liabilities, and activities of these entities into
our financial statements as of and for the three and six months ended June 30,
2004. These entities are reported as equity method investments in our financial
statements as of and for the three and six months ended June 30, 2003.
Therefore, the consolidation of these entities had no impact on our consolidated
net income for the three and six months ended June 30, 2004. For additional
details, see Note 11, Implementation of New Accounting Standards.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 of the Exchange Act, as
amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal
decisions. Our intention with the use of such words as "may," "could,"
"anticipates," "believes," "estimates," "expects," "intends," "plans," and other
similar words is to identify forward-looking statements that involve risk and
uncertainty. We designed this discussion of potential
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CMS Energy Corporation
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,
- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and availability of financing to CMS
Energy, Consumers, or any of their affiliates, and the energy
industry,
- ability to access the capital markets successfully,
- market perception of the energy industry, CMS Energy, Consumers, or
any of their affiliates,
- credit ratings of CMS Energy, Consumers, or any of their affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- factors affecting utility and diversified energy operations such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs,
environmental incidents, or electric transmission or gas pipeline
system constraints,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including environmental laws
and regulations,
- the impact of adverse natural gas prices on the MCV Partnership
investment, regulatory decisions concerning the MCV Partnership RCP,
and regulatory decisions that limit our recovery of capacity and
fixed energy payments,
- federal regulation of electric sales and transmission of electricity
including re-examination by federal regulators of the market-based
sales authorizations by which our subsidiaries participate in
wholesale power markets without price restrictions, and proposals by
the FERC to change the way it currently lets our subsidiaries and
other public utilities and natural gas companies interact with each
other,
- energy markets, including the timing and extent of unanticipated
changes in commodity prices for oil, coal, natural gas, natural gas
liquids, electricity, and certain related products due to lower or
higher demand, shortages, transportation problems, or other
developments,
- potential disruption, expropriation or interruption of facilities or
operations due to accidents, war, terrorism, or changing political
conditions and the ability to obtain or maintain insurance coverage
for such events,
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CMS Energy Corporation
- nuclear power plant performance, decommissioning, policies,
procedures, incidents, and regulation, including the availability of
spent nuclear fuel storage,
- technological developments in energy production, delivery, and
usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or
policies,
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims, including
particularly claims, damages, and fines resulting from round-trip
trading and inaccurate commodity price reporting, including
investigations by the DOJ regarding round-trip trading and price
reporting,
- 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
Our business plan focuses on strengthening our balance sheet and improving
financial liquidity through debt reduction and aggressive cost management. The
sale of non-strategic and under-performing assets has generated cash to reduce
debt, reduced business risk, and will provide for more predictable future
earnings.
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for per share amounts)
- --------------------------------------------------------------------------------
Restated
Three months ended June 30 2004 2003 Change
- --------------------------------------------------------------------------------
Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 81
Basic Earnings (Loss) Per Share $0.10 $(0.45) $0.55
Diluted Earnings (Loss) Per Share $0.10 $(0.45) $0.55
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Electric utility $ 27 $ 35 $ (8)
Gas utility 1 5 (4)
Enterprises 38 8 30
Corporate interest and other (50) (60) 10
Discontinued operations - (53) 53
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CMS Energy Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 81
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CMS Energy Corporation
For the three months ended June 30, 2004, our net income was $16 million,
compared to a loss of $65 million for the three months ended June 30, 2003. The
$81 million increase in net income primarily reflects:
- the absence of a $53 million loss from discontinued operations
recorded in 2003, comprised mainly of the loss on the sale of
Panhandle,
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003,
- an $11 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts, and
- a $6 million reduction in funded benefits expense primarily due to
the OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive impact
of prior year pension plan contributions on pension plan asset
returns.
These increases were partially offset by:
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003, and
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
For further information, see the individual results of operations for each CMS
Energy business segment within this MD&A.
In Millions (except for per share amounts)
- --------------------------------------------------------------------------------
Restated
Six months ended June 30 2004 2003 Change
- --------------------------------------------------------------------------------
Net Income Available to Common Stock $ 9 $ 17 $ (8)
Basic Earnings Per Share $0.06 $0.12 $(0.06)
Diluted Earnings Per Share $0.06 $0.14 $(0.08)
- --------------------------------------------------------------------------------
Electric utility $ 75 $ 86 $ (11)
Gas utility 57 59 (2)
Enterprises (23) 29 (52)
Corporate interest and other (98) (111) 13
Discontinued operations (2) (22) 20
Accounting changes - (24) 24
- --------------------------------------------------------------------------------
CMS Energy Net Income Available to Common Stock $ 9 $ 17 $ (8)
================================================================================
For the six months ended June 30, 2004, our net income was $9 million, compared
to net income of $17 million for the six months ended June 30, 2003. The $8
million decrease in income reflects:
- an $81 million charge to earnings related to the sale of Loy Yang,
- the absence of a $30 million Michigan Single Business Tax refund
received in 2003, and
- a reduction in the Utility's net income resulting primarily from
industrial and commercial customers choosing different electricity
suppliers and decreased gas deliveries caused primarily by milder
weather.
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CMS Energy Corporation
These decreases were partially offset by:
- the exclusion in 2004 of a $24 million charge for changes in
accounting that occurred in the first quarter of 2003,
- the absence of a $31 million deferred tax asset valuation reserve
established in 2003,
- the decrease of $20 million in the net loss from discontinued
operations resulting from the sale of Panhandle and other businesses
in 2003,
- a $31 million increase in mark-to-market valuation adjustments on
interest rate swaps and power contracts, and
- a $13 million reduction in funded benefits expense primarily due to
the OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive impact
of prior year pension plan contributions on pension plan asset
returns.
For further information, see the individual results of operations for each CMS
Energy business segment within this MD&A.
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
- --------------------------------------------------------------------------------------
June 30 2004 2003 Change
- --------------------------------------------------------------------------------------
Three months ended $27 $35 $ (8)
Six months ended $75 $86 $(11)
======================================================================================
Three Months Ended Six Months Ended
Reasons for the change: June 30, 2004 vs. 2003 June 30, 2004 vs. 2003
- --------------------------------------------------------------------------------------
Electric deliveries $(10) $(20)
Power supply costs and related revenue (2) (8)
Other operating expenses, non-commodity
revenue and other income 13 26
General taxes (14) (10)
Fixed charges - (6)
Income taxes 5 7
- --------------------------------------------------------------------------------------
Total change $ (8) $(11)
======================================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other
wholesale marketers, other electric utilities, and customers choosing
alternative suppliers increased 0.7 billion kWh or 7.2 percent and 1.0 billion
kWh or 5.4 percent for the three and six months ended June 30, 2004 versus the
same periods in 2003. The corresponding increases in electric delivery revenue
for both periods were offset by tariff revenue reductions and decreased sales
margins from deliveries to customers choosing alternative electric suppliers.
The tariff revenue reductions, which began January 1, 2004, were equivalent to
the Big Rock nuclear decommissioning surcharge in effect when our electric
retail rates were frozen from June 2000 through December 31, 2003. The tariff
revenue reductions were reclassified for capped customers as increases to PSCR
revenues. The increased PSCR revenues helped negate possible losses attributable
to the
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CMS Energy Corporation
underrecovery of PSCR costs for these customers, primarily the residential and
small commercial classes. In fact, the revenue reclassification contributed to
the overrecovery of PSCR revenues in excess of PSCR costs in these customer
classes for the three and six months ended June 30, 2004. In 2004, to the extent
we have PSCR overrecoveries, the overrecovery must be reserved for possible
future refund. The tariff revenue reductions have decreased electric delivery
revenues by approximately $9 million in the second quarter of 2004, and $18
million in the first six months of 2004 versus 2003. The tariff revenue
reductions are expected to decrease electric delivery revenues by $35 million
for the full year of 2004 versus the full year of 2003.
For the three and six months ended June 30, 2004, the overall decline in
electric delivery revenues was offset partially by increased sales to
residential customers due to warmer weather versus the same periods in 2003.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of
recovery was a fixed amount per kWh, as required under the Customer Choice Act.
Therefore, power supply-related revenue in excess of actual power supply costs
increased operating income. By contrast, if power supply-related revenues had
been less than actual power supply costs, the impact would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenues are in excess of actual power supply costs, this former
benefit is reserved for possible future refund. This change in the treatment of
excess power supply revenues over power supply costs decreased operating income
for the three and six months ended June 30, 2004 versus the same periods in
2003.
OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three
months ended June 30, 2004, other operating expenses decreased $1 million,
non-commodity revenue increased $1 million, and other income increased $11
million versus the same period in 2003. The increase in other income relates
primarily to interest income recognized in relation to capital expenditures in
excess of depreciation as allowed by the Customer Choice Act. This Act also
enabled us to defer depreciation expense on the excess of capital expenditures
over our depreciation base, contributing to a reduction in operating expenses
for the second quarter of 2004 versus the same period in 2003. Higher other
operating expenses substantially offset the reduction in electric depreciation
expense.
In the six months ended June 30, 2004, other operating expenses decreased $6
million and other income increased $20 million versus the same period in 2003.
The increase in other income relates primarily to interest income recognized in
relation to capital expenditures in excess of depreciation, as allowed by the
Customer Choice Act. Operating expense decreases reflect lower benefit costs and
our ability to defer depreciation expense on the excess of capital expenditures
over our depreciation base, as allowed by the Customer Choice Act.
GENERAL TAXES: General taxes increased in the three and six months ended June
30, 2004 versus the same periods in 2003 primarily due to reductions in the MSBT
expense in 2003. The 2003 reduction was primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
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FIXED CHARGES: Fixed charges increased in the six months ended June 30, 2004
versus the same periods in 2003 due to higher average debt levels, partially
offset by a reduction in the average rates of interest. The average rate of
interest dropped 79 basis points and 60 basis points for the three and six month
periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: In the three and six months ended June 30, 2004, income taxes
decreased versus the same periods in 2003 primarily due to lower earnings by the
electric utility, and the OPEB Medicare Part D federal subsidy that is exempt
from federal taxation.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
- ----------------------------------------------------------------------------------------------
June 30 2004 2003 Change
- ----------------------------------------------------------------------------------------------
Three months ended $ 1 $ 5 $ (4)
Six months ended $57 $59 $ (2)
==============================================================================================
Three Months Ended Six Months Ended
Reasons for the change: June 30, 2004 vs. 2003 June 30, 2004 vs. 2003
- ----------------------------------------------------------------------------------------------
Gas deliveries $(7) $(21)
Gas rate increase 2 11
Gas wholesale and retail services and other gas
revenues 1 3
Operation and maintenance - (2)
General taxes, depreciation, and other income (3) 3
Fixed charges (2) (6)
Income taxes 5 10
- ----------------------------------------------------------------------------------------------
Total change $(4) $(2)
==============================================================================================
GAS DELIVERIES: For the three months ended June 30, 2004, the more profitable
non-transportation gas deliveries decreased 4.9 bcf or 13.6 percent primarily
due to milder weather. The less profitable transportation gas deliveries
increased 5.2 bcf or 21.0 percent due to increased MCV Facility generation.
Overall, gas deliveries, including miscellaneous transportation, increased 0.3
bcf or 0.5 percent versus the same period in 2003.
For the six months ended June 30, 2004, gas deliveries, including miscellaneous
transportation, decreased 6.7 bcf or 2.9 percent versus the same period in 2003
primarily due to milder weather.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, gas revenues increased for the three and six months ended June 30,
2004 versus the same periods in 2003.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the three and six
months ended June 30, 2004, wholesale and retail services and other gas revenues
increased primarily due to increased gas transportation and storage revenues
versus the same periods in 2003.
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CMS Energy Corporation
OPERATION AND MAINTENANCE: For the six months ended June 30, 2004, increased
expenditures on safety, reliability, and customer service were offset partially
by reduced benefit costs compared to the same period in 2003.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: For the three months ended June
30, 2004 versus the same period in 2003, general tax expense increased $5
million due to higher MSBT expense and depreciation expense decreased $2
million. The increase in MSBT expense is primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
The reduced depreciation expense relates to decreases in depreciation rates
authorized by the MPSC's December 2003 interim rate order.
For the six months ended June 30, 2004, general tax expense increased $4 million
due to higher MSBT expense, depreciation expense decreased $8 million, and other
income decreased $1 million versus the same period in 2003. The increase in MSBT
expense is primarily due to CMS Energy having received approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003. The reduced depreciation
expense relates to decreases in depreciation rates authorized by the MPSC's
December 2003 interim rate order.
FIXED CHARGES: Fixed charges increased in the three and six months ended June
30, 2004 versus the same periods in 2003 due to higher average debt levels,
partially offset by a reduction in the average rate of interest. The average
rate of interest dropped 79 basis points and 60 basis points for the three and
six month periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: For the three and six months ended June 30, 2004 versus the same
periods in 2003, income taxes decreased due to the income tax treatment of items
related to plant, property, and equipment as required by past MPSC rulings, the
decreased earnings of the gas utility, and the OPEB Medicare Part D federal
subsidy that is exempt from federal taxation.
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ENTERPRISES RESULTS OF OPERATIONS
In Millions
- --------------------------------------------------------------------------------------------------
June 30 2004 2003 Change
- --------------------------------------------------------------------------------------------------
Three months ended $ 38 $ 8 $ 30
Six months ended $(23) $29 $ (52)
==================================================================================================
Three Months Ended Six Months Ended
Reasons for the change: June 30, 2004 vs. 2003 June 30, 2004 vs. 2003
- --------------------------------------------------------------------------------------------------
Results of FASB Interpretation No. 46 Entities $ (5) $(11)
Reasons for change excluding FIN No. 46:
Operating revenues (50) (403)
Cost of gas and purchased power 61 436
Earnings from equity method investees 10 (2)
Operation and maintenance 8 9
General taxes, depreciation, and other income (3) 2
Asset impairment charges 3 (127)
Fixed charges 19 18
Income taxes (13) 26
- --------------------------------------------------------------------------------------------------
Total change $ 30 $(52)
==================================================================================================
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: Due to
the implementation of FIN No. 46, certain equity investments included in equity
earnings in 2003, were determined to be variable interest entities and are now
consolidated in our results of operations for 2004. The net decrease in
earnings, due to the results of these entities, was $5 million for the three
months ended June 30, 2004 and $11 million for the six months ended June 30,
2004. These decreases were primarily due to increased fuel and dispatch costs
for 2004.
OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For the three months
ended June 30, 2004, operating revenues and related cost of gas and purchased
power decreased versus the same period in 2003 due to the continued streamlining
of CMS ERM.
For the six months ended June 30, 2004, operating revenues and related cost of
gas and purchased power decreased versus the same period in 2003. The decrease
was primarily the result of the sale of CMS ERM Wholesale Gas and Power
contracts and the absence of mark-to-market valuation adjustments associated
with these contracts.
EARNINGS FROM EQUITY METHOD INVESTEES: Earnings from equity method investees
increased due to mark-to-market valuation adjustments related to interest rate
swaps of $21 million for the three months ended June 30, 2004 and $15 million
for the six months ended June 30, 2004 versus the same periods in 2003. The
increase from interest rate swaps was offset partially by the impact of the
Argentine government's natural gas export restrictions on the results of
GasAtacama, and a deferred tax credit at Jorf Lasfar in 2003.
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CMS Energy Corporation
OPERATION AND MAINTENANCE: For the three and six months ended June 30, 2004,
operation and maintenance expense decreased versus the same period of 2003.
Lower expenses in 2004 were primarily due to streamlining and business reduction
at CMS ERM.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME, NET: For the three months ended
June 30, 2004, general tax, depreciation and other income decreased operating
income versus the same period in 2003, primarily as a result of foreign exchange
losses offset partially by lower depreciation and general taxes due to the
streamlining and business reduction at CMS ERM.
For the six months ended June 30, 2004, general tax, depreciation and other
income increased operating income versus the same period in 2003, as a result of
lower depreciation and general taxes due to the streamlining and business
reduction at CMS ERM.
ASSET IMPAIRMENT CHARGES: For the three months ended June 30, 2004, there were
no asset impairment charges versus the same period in 2003, which included $3
million of asset impairment charges primarily at International Energy
Distribution.
For the six months ended June 30, 2004, asset impairment charges increased
versus the same period in 2003 due to an impairment charge recorded in 2004 to
recognize the reduction in fair value of Loy Yang.
FIXED CHARGES: For the three and six months ended June 30, 2004, versus the same
periods in 2003, fixed charges decreased due to lower average debt levels and
lower average interest rates primarily resulting from the payoff of a short-term
revolving credit line held by CMS Enterprises during 2003.
INCOME TAXES: For the three months ended June 30, 2004, income taxes increased
versus the same period in 2003 primarily due to higher earnings.
For the six months ended June 30, 2004, income taxes decreased versus the same
period in 2003 due to the impairment charge for Loy Yang.
OTHER RESULTS OF OPERATIONS
In Millions
- ----------------------------------------------------------------------------
June 30 2004 2003 Change
- ----------------------------------------------------------------------------
Three months ended $(50) $ (60) $ 10
Six months ended $(98) $(111) $ 13
============================================================================
For the three months ended June 30, 2004, corporate interest expense and other
net expenses were $50 million, a decrease of $10 million from the three months
ended June 30, 2003. The decrease reflects the absence of a $24 million deferred
tax asset valuation reserve established in 2003 and also reflects $10 million of
lower interest expense. This decrease was offset partially by the absence in
2004 of a $20 million MSBT refund amount that we received in 2003 and a $4
million increase in operating expenses that were not billed to subsidiaries.
For the six months ended June 30, 2004, corporate interest and other net
expenses were $98 million, a decrease of $13 million from the six months ended
June 30, 2003. The decrease reflects the absence of a $24 million deferred tax
asset valuation reserve established in 2003 and $8 million of lower interest
expense. This decrease was offset partially by the absence of a $20 million MSBT
refund in 2003.
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CMS Energy Corporation
OTHER: At June 30, 2004, Discontinued Operations includes Parmelia. At June 30,
2003, Discontinued Operations included CMS Field Services, Marysville, and
Parmelia. For additional details, see Note 2, Discontinued Operations, Other
Asset Sales, Impairments, and Restructuring.
A $24 million loss for the cumulative effect of changes in accounting principle
was recognized in the first quarter of 2003; $23 million was due to EITF Issue
No. 02-03; $1 million was due to SFAS No. 143.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A:
- use of estimates in accounting for long-lived assets, contingencies,
and equity method investments,
- accounting for the effects of industry regulation,
- accounting for financial and derivative instruments,
- accounting for international operations and foreign currency,
- 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 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, foreign exchange,
regulatory decisions, and lawsuits.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. Tests of impairment are performed periodically if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $15.307
billion at June 30, 2004, 61 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- domestic and foreign regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
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CMS Energy Corporation
If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.
We also assess our ability to recover the carrying amounts of our equity method
investments. This assessment requires us to determine the fair values of our
equity method investments. The determination of fair value is based on valuation
methodologies including discounted cash flows and the ability of the investee to
sustain an earnings capacity that justifies the carrying amount of the
investment. 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 our financial
statements.
In March 2004, we reduced the carrying amount of our investment in Loy Yang to
reflect its fair value. We completed the sale of Loy Yang in April 2004. For
additional details on asset sales, see Note 2, Discontinued Operations, Other
Asset Sales, Impairments, and Restructuring. We are still pursuing the sale of
our remaining non-strategic and under-performing assets, including some assets
that were not determined to be impaired. Upon the sale of these assets, the
proceeds realized may be materially different from the remaining carrying
values. Even though these assets have been identified for sale, we cannot
predict when, or make any assurances that, these asset sales will occur.
Further, we cannot predict the amount of cash or the value of consideration that
may be received.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence is probable and,
where determinable, an estimate of the liability amount. The recording of
estimated liabilities for contingencies is guided by the principles in SFAS No.
5. We consider many factors in making these assessments, including 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 PPA with the MCV Partnership, we pay a capacity charge based on the
availability of the MCV Facility whether or not electricity is actually
delivered to us; a variable energy charge for kWh delivered to us; and a fixed
energy charge based on availability up to 915 MW and based on delivery for the
remaining 325 MW of contract capacity. The cost that we incur under the MCV
Partnership PPA exceeds the
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CMS Energy Corporation
recovery amount allowed by the MPSC. As a result, we estimate cash
underrecoveries of capacity and fixed energy payments will aggregate $206
million from 2004 through 2007. For capacity and fixed energy payments billed by
the MCV Partnership after September 15, 2007, and not recovered from customers,
we expect to claim relief under a regulatory out provision under the MCV
Partnership PPA. This provision obligates Consumers to pay the MCV Partnership
only those capacity and energy charges that the MPSC has authorized for recovery
from electric customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and
- eliminate our underrecoveries for capacity and fixed energy
payments.
Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned in our coal plants and our operations and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been affected adversely.
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be affected adversely.
In February 2004, we filed the RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our investment in the MCV Partnership,
without raising the costs paid by our electric customers. The plan's primary
objective is to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas 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. Presently, we are in settlement discussions with the parties to
the RCP filing. However, in July 2004, several qualifying facilities filed for a
stay on the RCP proceeding in the Ingham County Circuit Court after their
previous attempt to intervene on the proceeding was denied by the MPSC. Hearings
on the stay are scheduled for August 11, 2004. We cannot predict if or when the
MPSC will approve the RCP or the outcome of the Ingham County Circuit Court
hearings.
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
20 years and the MPSC's decision in 2007 or beyond related to limiting our
recovery of capacity and fixed energy payments. Natural gas prices have been
volatile historically. Presently, there is no consensus in the marketplace on
the price or range of future prices of natural gas. Even with an approved RCP,
if gas prices continue at present levels or increase, the economics of operating
the MCV Facility may be adverse enough to require us to recognize an impairment
of our investment in the MCV Partnership. We presently cannot predict the impact
of these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
For additional details on the MCV Partnership, see Note 3, Uncertainties, "Other
Consumers' Electric Utility Uncertainties - The Midland Cogeneration Venture."
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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 debt securities are classified as held-to-maturity securities and are
reported at cost. 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 reflected in Regulatory
Liabilities. The fair value of our equity securities 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. 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.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas fuel futures and options, gas fuel contracts containing volume optionality,
fixed priced weather-based gas supply call options, fixed price gas supply call
and put options, gas futures, gas and power swaps, and forward purchases and
sales. We generally do not account for electric capacity and energy contracts,
gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders
for numerous supply items as derivatives.
The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives because there is not an active market for the commodity.
Certain of our electric capacity and energy contracts are not accounted for as
derivatives due to the lack of an active energy market in the state of Michigan,
as defined by SFAS No. 133, and the significant transportation costs that would
be incurred to deliver the power under the contracts to the closest active
energy market at the Cinergy hub in Ohio. If an active market develops in the
future, we may be required to account for these contracts as derivatives. The
mark-to-market impact on earnings related to these contracts could be material
to our financial statements.
Additionally, the MCV Partnership uses natural gas fuel contracts to buy gas as
fuel for generation, and to manage gas fuel costs. The MCV Partnership believes
that its long-term natural gas contracts, which do not contain volume
optionality, qualify under SFAS No. 133 for the normal purchases and normal
sales exception. Therefore, these contracts are currently not recognized at fair
value on the balance sheet. Should significant changes in the level of the MCV
Facility operational dispatch or purchases of long-term gas occur, the MCV
Partnership would be required to re-evaluate its accounting treatment for these
long-
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CMS Energy Corporation
term gas contracts. This re-evaluation may result in recording mark-to-market
activity on some contracts, which could add to earnings volatility.
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 June 30, 2004, we assumed a market-based interest rate of
1 percent (a rate that is not significantly different than the LIBOR rate) and
volatility rates ranging between 54 percent and 161 percent to calculate the
fair value of our electric and gas options. At June 30, 2004, we assumed
market-based interest rates ranging between 1.37 percent and 4.50 percent and
volatility rates ranging between 24 percent and 44 percent to calculate the fair
value of the gas fuel derivative contracts held by the MCV Partnership.
TRADING ACTIVITIES: CMS ERM enters into and owns energy contracts that are
related to activities considered an integral part of CMS Energy's ongoing
operations. The intent of holding these energy contracts is to optimize the
financial performance of our owned generating assets and to fulfill contractual
obligations. These contracts are classified as trading activities in accordance
with EITF Issue No. 02-03 and are accounted for using the criteria defined in
SFAS No. 133. Energy trading contracts that meet the definition of a derivative
are recorded as assets or liabilities in the financial statements at the fair
value of the contracts. Gains or losses arising from changes in fair value of
these contracts are recognized into earnings in the period in which the changes
occur. Energy trading contracts that do not meet the definition of a derivative
are accounted for as executory contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.
In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to our counterparties.
Determination of our counterparties' credit quality is based upon a number of
factors, including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
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The following tables provide a summary of the fair value of our energy trading
contracts as of June 30, 2004:
In Millions
- -------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of December 31, 2003 $ 15
Fair value of new contracts when entered into during the period (a) (3)
Changes in fair value attributable to changes in valuation techniques and assumptions -
Contracts realized or otherwise settled during the period (11)
Other changes in fair value (b) 9
- -------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of June 30, 2004 $ 10
=================================================================================================
(a) Reflects only the initial premium payments/(receipts) for new contracts. No
unrealized gains or losses were recognized at the inception of any new
contracts.
(b) Reflects changes in price and net increase/(decrease) of forward positions
as well as changes to mark-to-market and credit reserves.
Fair Value of Contracts at June 30, 2004 In Millions
- ------------------------------------------------------------------------------------------
Total Maturity (in years)
-----------------------------------------------
Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5
- ------------------------------------------------------------------------------------------
Prices actively quoted $ (28) $ (1) $ (12) $ (15) $-
Prices based on models and
other valuation methods 38 8 18 12 -
- ------------------------------------------------------------------------------------------
Total $ 10 $ 7 $ 6 $ (3) $-
==========================================================================================
MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks, including swaps, options, futures, and forward contracts.
Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We
intend that any gains or losses on these contracts will be offset by an opposite
movement in the value of the item at risk. Risk management contracts are
classified as either trading or other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
We perform sensitivity analyses to assess the potential loss in fair value, cash
flows, or future earnings based upon a hypothetical 10 percent adverse change in
market rates or prices. We do not believe that sensitivity analyses alone
provide an accurate or reliable method for monitoring and controlling risks.
Therefore, we use our experience and judgment to revise strategies and modify
assessments. Changes in excess of the amounts determined in sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity
Price Risk," "Trading Activity Commodity Price Risk," "Currency Exchange Risk,"
and "Equity Securities Price Risk" within this section.
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Interest Rate Risk: We are exposed to interest rate risk resulting from issuing
fixed-rate and variable-rate financing instruments, and from interest rate swap
agreements. We use a combination of these instruments to manage this risk as
deemed appropriate, based upon market conditions. These strategies are designed
to provide and maintain a balance between risk and the lowest cost of capital.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in
market interest rates):
In Millions
- -------------------------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -------------------------------------------------------------------------------------------------------------
Variable-rate financing - before tax annual earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in fair value (a) 240 242
=============================================================================================================
(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.
Commodity Price Risk: For purposes other than trading, we enter into electric
call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call options are
purchased 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. Purchased electric call options give us the right, but not the
obligation, to purchase electricity at predetermined fixed prices. Purchases of
gas supply call options and weather-based gas supply call options, coupled with
the sale of gas supply put options, are used to purchase reasonably priced gas
supply. Purchases of gas supply call options give us the right, but not the
obligation, to purchase gas supply at predetermined fixed prices. Gas supply put
options sold give third-party suppliers the right, but not the obligation, to
sell gas supply to us at predetermined fixed prices. At June 30, 2004, we held
fixed-priced weather-based gas supply call options and fixed-price gas supply
call and put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. Some of these contracts contain volume
optionality and, therefore, are treated as derivative instruments. Also, the MCV
Partnership enters into natural gas futures contracts, option contracts, and
over-the-counter swap transactions in order to hedge against unfavorable
changes in the market price of natural gas in future months when gas is expected
to be needed. These financial instruments are being used principally to secure
anticipated natural gas requirements necessary for projected electric and steam
sales, and to lock in sales prices of natural gas previously obtained in order
to optimize the MCV Partnership's existing gas supply, storage, and
transportation arrangements.
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Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
- -------------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -------------------------------------------------------------------------------------------------
Potential reduction in fair value:
Gas supply option contracts $ 7 $ 1
Derivative contracts associated with Consumers' investment in
the MCV Partnership:
Gas fuel contracts 21 N/A
Gas fuel futures, options, and swaps 38 N/A
=================================================================================================
During the six months ended June 30, 2004, we entered into additional
weather-based gas supply call options, as well as gas supply call and put option
contracts. As a result, the potential reduction in the fair value increased from
December 31, 2003 as shown in the table above. We did not perform a sensitivity
analysis for the derivative contracts held by the MCV Partnership as of December
31, 2003 because the MCV Partnership was not consolidated into our financial
statements until March 31, 2004, as discussed in Note 11, Implementation of New
Accounting Standards.
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 the commodities.
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):
In Millions
- -------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -------------------------------------------------------------------------------
Potential reduction in fair value:
Gas-related swaps and forward contracts $ 3 $ 3
Electricity-related forward contracts 2 2
Electricity-related call option contracts 2 1
===============================================================================
Currency Exchange Risk: We are exposed to currency exchange risk arising from
investments in foreign operations as well as various international projects in
which we have an equity interest and which have debt denominated in U.S.
dollars. We typically use forward exchange contracts and other risk mitigating
instruments to hedge currency exchange rates. The impact of hedges on our
investments in foreign operations is reflected in accumulated other
comprehensive income as a component of the foreign currency translation
adjustment on the Consolidated Balance Sheets. Gains or losses from the
settlement of these hedges are maintained in the foreign currency translation
adjustment until we sell or liquidate the investments on which the hedges were
taken. At June 30, 2004, we had no foreign exchange hedging contracts
outstanding. As of June 30, 2004, the total foreign currency translation
adjustment was a net loss of $327 million, which included a net hedging loss of
$25 million, net of tax, 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
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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 reflected in
Regulatory Liabilities. Our debt securities are classified as held-to-maturity
securities and have original maturity dates of approximately one year or less.
Because of the short maturity of these instruments, their carrying amounts
approximate their fair values.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market prices):
In Millions
- ------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- ------------------------------------------------------------------------------------
Potential reduction in fair value:
Nuclear decommissioning investments $ 54 $ 57
Other available-for-sale investments 7 7
====================================================================================
For additional details on market risk and derivative activities, see Note 6,
Financial and Derivative Instruments.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects in selected markets around the
world. As a result of a change in business strategy, we have been selling
certain foreign investments. For additional details on the divestiture of
foreign investments, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
BALANCE SHEET: Our subsidiaries and affiliates whose functional currency is
other than the U.S. dollar translate their assets and liabilities into U.S.
dollars at the exchange rates in effect at the end of the fiscal period. Gains
or losses that result from this translation and gains or losses on long-term
intercompany foreign currency transactions are reflected as a component of
stockholders' equity in our Consolidated Balance Sheets as "Foreign Currency
Translation." As of June 30, 2004, cumulative foreign currency translation
decreased stockholders' equity by $327 million. We translate the revenue and
expense accounts of these subsidiaries and affiliates into U.S. dollars at the
average exchange rate during the period.
Australia: The Foreign Currency Translation component of stockholders' equity at
December 31, 2003 included an approximate $110 million unrealized net foreign
currency translation loss related to our investment in Loy Yang. In March 2004,
we recognized the foreign currency translation loss in earnings as a component
of the Loy Yang impairment of approximately $81 million, recorded as a result of
the sale of Loy Yang that was completed in April 2004.
At June 30, 2004, 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 1.45 Australian dollars per U.S.
dollar was $4 million. This foreign currency translation loss relates primarily
to our SCP and Parmelia investments. We are currently pursuing the sale of these
investments.
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CMS Energy Corporation
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 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 used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect
that these non-cash charges reduce substantially the risk of further material
balance sheet impacts when combined with anticipated proceeds from international
arbitration currently in progress, political risk insurance, and the eventual
sale of these assets. At June 30, 2004, the net foreign currency loss due to the
unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 2.97
pesos per U.S. dollar was $263 million. This amount also reflects the effect of
recording, at December 31, 2002, U.S. income taxes on temporary differences
between the book and tax bases of foreign investments, including the foreign
currency translation associated with our Argentine investments.
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
June 30, 2004, we had $1.125 billion recorded as regulatory assets and $1.502
billion recorded as regulatory liabilities.
For additional details on industry regulation, see Note 1, Corporate Structure
and Accounting Policies, "Utility Regulation."
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CMS Energy Corporation
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. We have implemented a cash balance plan for certain employees hired after
June 30, 2003. We use SFAS No. 87 to account for pension costs.
401(k): In our efforts to reduce costs, the employer's match for the 401(k) plan
was suspended effective September 1, 2002. The employer's match for the 401(k)
plan is scheduled to resume on January 1, 2005.
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 cost, OPEB cost, and
cash contributions for the next three years:
In Millions
- ----------------------------------------------------------------------------------
Expected Costs Pension Cost OPEB Cost Contributions
- ----------------------------------------------------------------------------------
2004 $21 $30 $ 63
2005 55 38 80
2006 75 34 114
==================================================================================
Actual future pension cost and contributions will depend on future investment
performance, changes in future discount rates, and various other factors related
to the populations participating in the Pension Plan. As of June 30, 2004, we
have a prepaid pension asset of $398 million, $20 million of which is in Other
current assets on our Consolidated Balance Sheet.
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 cost 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 cost for
2004 by $4 million.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the
Act) was signed into law in December 2003. The Act establishes a prescription
drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is
exempt from federal taxation, to sponsors of retiree health care benefit plans
that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the
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effects of the subsidy into our financial statements as of June 30, 2004 in
accordance with FASB Staff Position No. SFAS 106-2. We remeasured our obligation
as of December 31, 2003 to incorporate the impact of the Act, which resulted in
a reduction to the accumulated postretirement benefit obligation of $158
million. The remeasurement resulted in a reduction of OPEB cost of $6 million
for the three months ended June 30, 2004, $12 million for the six months ended
June 30, 2004, and an expected total reduction of $24 million for 2004.
For additional details on postretirement benefits, see Note 7, Retirement
Benefits and Note 11, Implementation of New Accounting Standards.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143 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 regulatory assets and liabilities for regulated entities
instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions, such as costs, inflation,
and profit margin that third parties would consider to assume the settlement of
the obligation. Fair value, to the extent possible, should include a market risk
premium for unforeseeable circumstances. No market risk premium was included in
our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period the ARO is
incurred, such as for assets with indeterminate lives, the liability is
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 and there is a low probability of a retirement date.
Therefore, no liability has been recorded for these assets. Also, no liability
has been recorded for assets that have insignificant cumulative disposal costs,
such as substation batteries. The measurement of the ARO liabilities for
Palisades and Big Rock are based on decommissioning studies, which largely
utilize third-party cost estimates. For additional details on ARO, see Note 10,
Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. We have established external trust funds to
finance the decommissioning of both plants. We record the trust fund balances as
a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop
decommissioning cost estimates. Various inflation rates for labor, non-labor,
and contaminated equipment disposal costs are used to escalate these cost
estimates to the future decommissioning cost. A portion of future
decommissioning
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CMS Energy Corporation
cost will result from the failure of the DOE to remove fuel from the sites, as
required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income investments.
Equities will be converted to fixed income investments during decommissioning,
and fixed income investments are converted to cash as needed. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The funds provided by the
trusts, additional customer surcharges, and potential funds from the DOE
litigation are all required to cover fully the decommissioning costs. The costs
of decommissioning these sites and the adequacy of the trust funds could be
affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from
customers, and
- changes in decommissioning technology, regulations, estimates, or
assumptions.
Based on current projections, the current level of funds provided by the trusts
is not adequate to fully fund the decommissioning of Big Rock or Palisades. This
is due in part to the DOE's failure to accept the spent nuclear fuel on
schedule, and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation. We will also
seek additional relief from the MPSC. For additional details on nuclear
decommissioning, see Note 3, Uncertainties, "Other Consumers' Electric Utility
Uncertainties - Nuclear Plant Decommissioning" and "Nuclear Matters."
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. 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.
Our current financial plan includes controlling our operating expenses and
capital expenditures, evaluating market conditions for financing opportunities,
and selling assets that are not consistent with our strategy. The sale of assets
is expected to generate cash in 2004; however, it is not critical to the
maintenance of sufficient corporate liquidity. 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. We have not made a specific determination concerning the reinstatement of
the payment of common stock dividends. The Board of Directors may reconsider or
revise its dividend policy based upon certain conditions, including our results
of operations, financial condition, and capital requirements, as well as other
relevant factors.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At June 30, 2004, $909 million consolidated cash was on hand, which includes
$213 million of restricted cash. For additional details on cash equivalents and
restricted cash, see Note 1, Corporate Structure and Accounting Policies.
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CMS Energy Corporation
Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries, including proceeds from asset sales. For the first six months of
2004, Consumers paid $105 million in common stock dividends and Enterprises paid
$133 million in common stock dividends and other distributions to CMS Energy.
SUMMARY OF CASH FLOWS:
In Millions
- -----------------------------------------------------------------------------------
Six months ended June 30 2004 2003
- -----------------------------------------------------------------------------------
Net cash provided by (used in):
Operating activities $ 481 $147
Investing activities (214) 292
Financing activities (276) 125
Effect of exchange rates on cash (1) 2
- -----------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents $ (10) $566
===================================================================================
OPERATING ACTIVITIES:
For the six months ended June 30, 2004, net cash provided by operating
activities increased $334 million compared to the six months ended June 30, 2003
primarily due to an increase in accounts payable and accrued expenses of $364
million. The increase in accounts payable is mainly a result of the purchase of
natural gas at higher prices and fewer suppliers requiring advanced payments for
gas purchases. Also, CMS ERM had a minimal change in accounts payable in 2004
versus a large decrease in 2003 resulting from the sale of the wholesale gas and
power books. Accrued expenses increased as a result of the Revised FASB
Interpretation No. 46 consolidation of the MCV Partnership and the FMLP, a
smaller decrease in accrued taxes, and an increase in accrued refunds relating
to our 2002-2003 GCR case and potential overrecoveries from our return to the
PSCR process. For additional details regarding the PSCR process refer to
"Electric Utility Business Uncertainties - PSCR" within this MD&A.
Additionally, net cash provided by operating activities increased as a result of
a decrease in inventories of $83 million primarily resulting from gas sales at
higher prices combined with lower volumes of gas purchased. This was offset by a
greater increase in accounts receivable and accrued revenue of $43 million
largely due to lower sales of accounts receivable resulting from our improved
liquidity.
INVESTING ACTIVITIES:
For the six months ended June 30, 2004, net cash from investing activities
decreased $506 million primarily due to a decrease in asset sale proceeds of
$660 million. This change was offset by a decrease in capital expenditures of
$24 million and a decrease in the amount of cash restricted of $155 million. In
2004, $12 million in cash was restricted compared to $167 million restricted in
2003. For additional details on restricted cash, see Note 1, Corporate Structure
and Accounting Policies, "Cash Equivalents and Restricted Cash."
FINANCING ACTIVITIES:
For the six months ended June 30, 2004, net cash from financing activities
decreased $401 million primarily due to a decrease of $397 million in net
proceeds from borrowings. For additional details on long-term debt activity, see
Note 4, Financings and Capitalization.
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CMS Energy Corporation
OBLIGATIONS AND COMMITMENTS
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short and long-term
securities under the FERC's authorization. For additional details of Consumers'
existing authorization, see Note 4, Financings and Capitalization.
LONG-TERM DEBT: The components of long-term debt are presented in Note 4,
Financings and Capitalization.
SHORT-TERM FINANCINGS: At June 30, 2004, CMS Energy had $207 million available,
Consumers had $376 million available, and the MCV Partnership had $50 million
available in short-term credit facilities. The facilities are available for
general corporate purposes, working capital, and letters of credit. As of
August 3, 2004, CMS Energy obtained an amended and restated $300 million secured
revolving credit facility to replace both their $190 million facility and $185
million letter of credit facility. As of August 3, 2004, Consumers obtained an
amended and restated $500 million secured revolving credit facility to replace
their $400 million facility. The amended facilities carry three-year terms and
provide for lower interest rates. Additional details on short-term financings
are presented in Note 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS:
Non-recourse Debt: Our share of unconsolidated debt associated with partnerships
and joint ventures in which we have a minority interest is non-recourse and
totals $1.491 billion at June 30, 2004. The reduction in this amount from March
31, 2004 is primarily due to the sale of Loy Yang, whose non-recourse debt
totaled $1.226 billion. The timing of the payments of non-recourse debt only
affects the cash flow and liquidity of the partnerships and joint ventures.
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 4, Financings and Capitalization.
CONTINGENT COMMITMENTS: Our contingent commitments include guarantees,
indemnities, and letters of credit. Guarantees represent our guarantees of
performance, commitments, and liabilities of our consolidated and unconsolidated
subsidiaries, partnerships, and joint ventures. Indemnities are agreements to
reimburse other companies, such as an insurance company, if those companies have
to complete our contractual performance in a third-party contract. Banks, on our
behalf, issue letters of credit guaranteeing payment to a third party. Letters
of credit substitute the bank's credit for ours and reduce credit risk for the
third-party beneficiary. We monitor and approve these obligations and believe it
is unlikely that we would be required to perform or otherwise incur any material
losses associated with these guarantees. Our off-balance sheet commitments at
June 30, 2004, expire as follows:
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Commercial Commitments In Millions
- ----------------------------------------------------------------------------------------------------------------------
Commitment Expiration
- ----------------------------------------------------------------------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 Beyond
- ----------------------------------------------------------------------------------------------------------------------
Off-balance sheet:
Guarantees $ 199 $ 6 $ 36 $ 5 $ - $ - $ 152
Surety bonds and other
indemnifications (a) 28 1 - - - - 27
Letters of Credit (b) 235 23 184 5 5 5 13
- ----------------------------------------------------------------------------------------------------------------------
Total $ 462 $ 30 $ 220 $ 10 $ 5 $ 5 $ 192
======================================================================================================================
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.
(b) At June 30, 2004, we had $169 million of cash held as collateral for letters
of credit. The cash that collateralizes the letters of credit is included in
Restricted cash on the Consolidated Balance Sheets.
DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at
June 30, 2004, Consumers had $396 million of unrestricted retained earnings
available to pay common stock dividends. However, covenants in Consumers' debt
facilities cap common stock dividend payments at $300 million in a calendar
year. Consumers is also under an annual dividend cap of $190 million imposed by
the MPSC during the current interim gas rate relief period. For the six months
ended June 30, 2004, CMS Energy received $105 million of common stock dividends
from Consumers.
Our amended and restated $300 million credit facility restricts payments of
dividends on our common stock during a 12-month period to $75 million, dependent
on the aggregate amounts of unrestricted cash and unused commitments under the
facility.
For additional details on the cap on common stock dividends payable during the
current interim gas rate relief period, see Note 3, Uncertainties, "Consumers'
Gas Utility Rate Matters - 2003 Gas Rate Case."
OUTLOOK
CORPORATE OUTLOOK
During 2004, we are continuing to implement a utility-plus strategy that focuses
on growing a healthy utility and divesting under-performing or other
non-strategic assets. The strategy is designed to generate cash to pay down
debt, reduce business risk, and provide for more predictable future operating
revenues and earnings.
Consistent with our utility-plus strategy, we are pursuing the sale of
non-strategic and under-performing assets. Some of these assets are recorded at
estimates of their current fair value. Upon the sale of these assets, the
proceeds realized may be different from the recorded values if market conditions
have changed. Even though these assets have been identified for sale, we cannot
predict when, nor make any assurance that, these sales will occur. We anticipate
that the cash proceeds from these sales, if any, will be used to retire existing
debt.
As we continue to implement our utility-plus strategy and further reduce our
ownership of non-utility assets, the percentage of our future earnings relating
to our larger equity method investments, including
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Jorf Lasfar, may increase and our total future earnings may depend more
significantly upon the performance of those investments. For additional details,
see Note 8, Equity Method Investments.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect electric deliveries to grow at an
average rate of approximately two percent per year based primarily on a steadily
growing customer base and economy. This growth rate includes both full service
sales and delivery service to customers who choose to buy generation service
from an alternative electric supplier, but excludes transactions with other
wholesale market participants and other electric utilities. This growth rate
reflects a long-range expected trend of growth. Growth from year to year may
vary from this trend due to customer response to fluctuations in weather
conditions and changes in economic conditions, including utilization and
expansion of manufacturing facilities. We experienced less growth than expected
in 2003 as a result of cooler than normal summer weather and a decline in
manufacturing activity in Michigan. In 2004, we project electric deliveries to
grow approximately two percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
during the remainder of the year.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner.
Regulatory
- effects of recommendations as a result of the August 14, 2003
blackout, including increased regulatory requirements and new
legislation,
- effects of the FERC supply margin assessment requirements for
electric market-based rate authority,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel, and
- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" within this MD&A.
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Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities, and
- other pending litigation.
For additional details about these trends or uncertainties, see Note 3,
Uncertainties.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.
Compliance with the federal Clean Air Act and resulting regulations has been,
and will continue to be, a significant focus for us. The Title I provisions of
the Clean Air Act require significant reductions in nitrogen oxide emissions. To
comply with the regulations, we expect to incur capital expenditures totaling
$771 million. The key assumptions included in the capital expenditure estimate
include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.9 percent. As of June 30, 2004, we have
incurred $489 million in capital expenditures to comply with these regulations
and anticipate that the remaining $282 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology at some 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 EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally the viability of certain plants remaining in operation could be
called into question.
The EPA has proposed a Clean Air Interstate Rule that would require additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury and nickel from
coal-fired and oil-fired electric plants. Until the proposed environmental rules
are finalized, an accurate cost of compliance cannot be determined.
Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas
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emission reduction rules ultimately will be enacted, or the specific
requirements of any such rules if they were to become law.
To the extent that greenhouse gas emission reduction rules come into effect,
such mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments and will continue to assess and respond
to their potential implications on our business operations.
In March 2004, the EPA changed the rules that govern generating plant cooling
water intake systems. The new rules require significant reduction in fish killed
by operating equipment. Some of our facilities will be required to comply by
2006. We are studying the rules to determine the most cost-effective solutions
for compliance.
For additional details on electric environmental matters, see Note 3,
Uncertainties, "Consumers' Electric Utility Contingencies - Electric
Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and
other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of July 2004, alternative electric suppliers are providing 858 MW of
generation supply to ROA customers. This amount represents 11 percent of our
distribution load and an increase of 49 percent compared to July 2003. Based on
current trends, we predict load loss by year-end to be in the range of 900 MW to
1,100 MW. However, no assurance can be made that the actual load loss will not
be greater or less than that range.
In July 2004, as a result of legislative hearings, several bills were introduced
into the Michigan Senate that could change Michigan's Customer Choice Act. The
proposals include:
- requiring that rates be based on cost of service,
- establishing a defined Stranded Cost calculation method,
- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return,
- establishing reliability standards that all electric suppliers must
follow,
- requiring utilities and alternative suppliers to maintain a 15
percent power reserve margin,
- creating a service charge to fund the Low Income and Energy
Efficiency Fund,
- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates, and
- authorizing a service charge payable by all customers for meeting
Clean Air Act requirements.
Securitization: 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. We filed for rehearing and clarification on a number of
features in the financing order. If and when the MPSC issues an order with
favorable terms, then the order will become effective upon our acceptance.
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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 offset fully any associated
margin loss.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002, including the cost of
money, are estimated to be $47 million with the issuance of Securitization bonds
that include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. Once the MPSC
issues a final financing order on Securitization, we will know the amount of our
request for net Stranded Cost recovery for 2002. In July 2004, the ALJ issued a
proposal for decision in our 2002 net Stranded Cost case, which recommended that
the MPSC find that we incurred net Stranded Costs of $12 million. This
recommendation includes the cost of money through July 2004 and excludes Clean
Air Act investments.
In April 2004, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2003. We also requested interim relief for 2003 net
Stranded Costs, but the ALJ declined to set a schedule that would allow
consideration of the interim request. In July 2004, we revised our request for
approval of 2003 Stranded Costs incurred, including the cost of money, to $69
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $128 million without the issuance of Securitization bonds that
include Clean Air Act investments. In July 2004, the MPSC Staff issued a
position on our 2003 net Stranded Cost application, which resulted in a Stranded
Cost calculation of $52 million. The amount includes the cost of money, but
excludes Clean Air Act investments.
We cannot predict how the MPSC will rule on our requests for the recovery of
Stranded Costs. Therefore, we have not recorded regulatory assets to recognize
the future recovery of such costs.
Implementation Costs: Following an appeal and remand of initial MPSC orders
relating to 1999 implementation costs, the MPSC authorized the recovery of all
previously approved implementation costs for the years 1997 through 2001 by
surcharges on all customers' bills phased in as rate caps expire. Authorized
recoverable implementation costs totaled $88 million. This total includes
carrying costs through 2003. Additional carrying costs will be added until
collection occurs. For additional information on rate caps, see "Rate Caps"
within this section.
Our applications for $7 million of implementation costs for 2002 and $1 million
for 2003 are presently pending approval by the MPSC. Included in the 2002
request is $5 million related to our former participation in the development of
the Alliance RTO. Although we believe these implementation costs and associated
cost of money are fully recoverable in accordance with the Customer Choice Act,
we cannot predict the amounts the MPSC will approve as recoverable.
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by
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the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for $25 million
of costs for which regulatory treatment has not yet been granted through other
means. The requested amount includes reasonable and prudent security
enhancements through December 31, 2005. As of June 30, 2004, we have $7 million
in security costs recorded as a regulatory asset. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. In July
2004, a settlement was reached with the parties to the case, which would provide
for full recovery of the requested security costs over a five-year period
beginning in 2004. We are presently awaiting approval from the MPSC. We cannot
predict how the MPSC will rule on our request for the recoverability of
security costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates
that could result in us being unable to collect our full cost of conducting
business from electric customers. Such limitations include:
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and
- rate caps effective through December 31, 2005 for residential
customers.
As a result, we may be unable to maintain our profit margins in our electric
utility business during the rate cap periods. In particular, if we need to
purchase power supply from wholesale suppliers while retail rates are capped,
the rate restrictions may preclude full recovery of purchased power and
associated transmission costs.
PSCR: The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process provides for recovery of all
reasonable and prudent power supply costs actually incurred by us, including the
actual cost for fuel, and purchased and interchange power. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this reconciliation proceeding.
Special Contracts: We entered into multi-year electric supply contracts with
certain industrial and commercial customers. The contracts provide electricity
at specially negotiated prices, usually at a discount from tariff prices. As of
July 2004, special contracts for approximately 630 MW of load are in place, most
of which are in effect through 2005. These include, new special contracts with
Dow Corning
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and Hemlock Semi-Conductor for 101 MW of load, which received final approval
from the MPSC in May 2004 and special contracts with several hospitals totaling
52 MW of load, which received approval from the MPSC in July 2004. We cannot
predict whether additional special contracts will be necessary, advisable, or
approved.
Transmission Sale: In May 2002, we sold our electric transmission system for
$290 million to MTH. We are currently in arbitration with MTH regarding property
tax items used in establishing the selling price of our electric transmission
system. An unfavorable outcome could result in a reduction of sale proceeds
previously recognized by approximately $2 million to $3 million.
There are multiple proceedings and a proposed rulemaking pending before the FERC
regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemakings could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking, and trends are not
quantifiable currently. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings. For example, Commonwealth Edison Company
received approval from the FERC to join the PJM RTO effective May 1, 2004 and
American Electric Power Service Corporation received approval from the FERC to
join the PJM RTO effective October 1, 2004. These integrations could create
different patterns of flow and power within the Midwest area and could affect
adversely our ability to provide reliable service to our customers.
August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid
serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
As a result, federal and state investigations regarding the cause of the
blackout were conducted. These investigations resulted in the NERC and the U.S.
and Canadian Power System Outage Task Force releasing electric operations
recommendations. Few of the recommendations apply directly to us, since we are
not a transmission owner. However, the recommendations could result in increased
transmission costs to us and require upgrades to our distribution system. The
financial impacts of these recommendations are not quantifiable currently.
We have complied with an MPSC order requiring Michigan utilities and
transmission companies to submit a report concerning relay settings on their
systems by May 10, 2004. In July 2004, the MPSC closed the docket concerning the
investigation into the August 14, 2003 blackout. Also, we have complied with the
FERC order requiring entities that own, operate, or control designated
transmission facilities to report on their vegetation management practices by
June 17, 2004. This FERC order affected a total of six miles of high voltage
lines located on or adjacent to some generating plant properties.
For additional details and material changes relating to the rate matters and
restructuring of the electric utility industry, see Note 3, Uncertainties,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in
Essexville, Michigan experienced a failure on the exciter. The exciter is a
device that provides the magnetic field to the main
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electric generator. Replacement of the exciter is expected to take several
months. In the interim we have installed a temporary replacement, which is
rented from Detroit Edison. However, under the agreement, Detroit Edison can
recall the exciter at any time. To hedge against 235 MW of this risk and ensure
adequate reserve margins during the summer peak periods, we have entered into
two short-term capacity contracts. As of July 2004, the rented exciter has been
installed and the Karn unit is operating effectively. The financial impacts of
the unit outage are not currently quantifiable.
FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new
generation market power screens and modified measures to mitigate market power
where it is found. The screens will apply to all initial market-based rate
applications and reviews on an interim basis, which occur every three years.
Based on preliminary reviews, we believe that we will pass the established
screens.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of June 2004, we are in compliance
with the acceptable level of performance. We are a member of an industry
coalition that has appealed the customer credit portion of the performance
standards to the Michigan Court of Appeals. We cannot predict the likely effects
of the financial penalties, if any, nor can we predict the outcome of the
appeal. Likewise, we cannot predict our ability to meet the standards in the
future or the cost of future compliance.
For additional details on performance standards, see Note 3, Uncertainties,
"Consumers' Electric Utility Rate Matters - Performance Standards."
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an average
rate of less than one percent per year. Actual gas deliveries in future periods
may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the MPSC for a Certificate of
public convenience and necessity for the construction of a 25-mile gas
transmission pipeline in northern Oakland County. The project is necessary to
meet peak load beginning in the winter of 2005 through 2006. If we are unable to
construct the pipeline due to local opposition, we will need to pursue more
costly alternatives or possibly curtail serving the system's load growth in that
area.
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GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results
and conditions. These trends or uncertainties could have a material impact on
net sales, revenues, or income from gas operations. The trends and uncertainties
include:
Environmental
- potential environmental remediation costs at a number of sites,
including sites formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pipeline integrity maintenance and replacement costs, and
- other pending litigation.
We sell gas to retail customers under tariffs approved by the MPSC. These
tariffs measure the volume of gas delivered to customers (i.e. mcf). However, we
purchase gas for resale on a heating value (i.e. Btu) basis. The Btu content of
the gas purchased fluctuates and may result in customers using less gas for the
same heating requirement. We fully recover our cost to purchase gas through the
approved GCR. However, since the customer may use less gas on a volumetric
basis, the revenue from the distribution charge (the non-gas cost portion of the
customer bill) could be reduced. This could affect adversely our gas utility
earnings. The amount of any possible earnings loss due to fluctuating Btu
content in future periods cannot be estimated at this time.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order, the FERC
indicated that its December 2003 order was in error. It directed us to file
within 30 days a fair and equitable title-tracking fee and to make refunds, with
interest, to customers based on the difference between the accepted fee and the
fee paid. In response to the FERC's April 2004 order, we filed a Request for
Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further
Consideration in June 2004. We expect the FERC to issue an order on the merits
of this proceeding in the third quarter of 2004. We believe that with respect to
the FERC jurisdictional transportation, we have not charged any customers title
transfer fees, so no refunds are due. At this time, we cannot predict the
outcome of this proceeding.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 3, Uncertainties, "Consumers' Gas Utility
Contingencies - Gas Environmental Matters."
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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.
GCR YEAR 2002-2003: In March 2004, a settlement agreement was approved by the
MPSC that resulted in a GCR disallowance of $11 million for the GCR period. For
additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Rate
Matters - Gas Cost Recovery."
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. The second quarter GCR adjustment resulted in a GCR ceiling
price of $6.57. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement, which included a quarterly mechanism for setting a GCR
ceiling price. The mechanism did not change the current ceiling price of $6.57.
Actual gas costs and revenues will be subject to an annual reconciliation
proceeding. Our GCR factor for the billing month of August is $6.39 per mcf.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim rate
order, Consumers agreed to restrict dividend payments to its parent company, CMS
Energy, to a maximum of $190 million annually during the period of 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,
which was supported by the MPSC Staff and the ALJ further recommended that the
application be dismissed. In response to the Proposal for Decision, the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
The June 2001 depreciation case 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, would result in an annual increase of $12 million in depreciation
expense based on December 2002 plant balances. In June 2004, the ALJ issued a
Proposal for Decision recommending adoption of the Michigan Attorney General's
proposal to reduce our annual depreciation expense by $52 million. In response
to the Proposal for Decision, the parties filed exceptions
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CMS Energy Corporation
and are expected to file replies to exceptions. In our exceptions, we proposed
alternative depreciation rates that would result in an annual decrease of $7
million in depreciation expense. The MPSC is not bound by the ALJ's
recommendation and will review the exceptions and replies to exceptions prior to
issuing an order on final depreciation rates.
OTHER CONSUMERS' OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:
- retail gas business energy related services,
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business. In June 2004, the MPSC directed the parties to a
pending complaint case involving Consumers to file briefs discussing whether the
case is affected by the legislation.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our IPP
business by narrowing the focus of our operations to primarily North America and
the Middle East/North Africa. We will continue to sell designated assets and
investments that are under-performing or are not consistent with this focus.
CMS ERM: CMS ERM has streamlined its portfolio in order to reduce business risk
and outstanding credit guarantees. Our future activities will be centered on
fuel procurement activities and merchant power marketing in such a way as to
optimize the earnings from our IPP generation assets.
CMS-37
CMS Energy Corporation
CMS GAS TRANSMISSION: CMS Gas Transmission continues to narrow its scope of
existing operations. We plan to continue to sell most of our international
assets and businesses. Future operations will be conducted mainly in Michigan.
In July 2004, we entered into a definitive agreement to sell our interests in
Parmelia and Goldfields to APT for approximately $208 million Australian
(approximately $145 million in U.S. dollars). The sale is subject to customary
closing conditions. We expect the sale to close in the third quarter of 2004.
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., which is not included in our consolidated financial
statements. 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. The financial performance is dependent primarily
on the number of new wells connected and transportation volumes, with certain
EBITDA thresholds required to be achieved in order for us to receive payments on
the note. There may not be enough new wells connected in 2004 to achieve the
annual threshold and thus trigger a payment on the note for 2004.
UNCERTAINTIES: The results of operations and the financial position of our
diversified energy businesses may be affected by a number of trends or
uncertainties. Those that could have a material impact on our income, cash
flows, or balance sheet and credit improvement include:
- our ability to sell or to improve the performance of assets and
businesses in accordance with our business plan,
- changes in exchange rates or in local economic or political
conditions, particularly in Argentina, Venezuela, Brazil,
and the Middle East,
- changes in foreign laws or in governmental or regulatory policies
that could reduce significantly the tariffs charged and revenues
recognized by certain foreign subsidiaries, or increase expenses,
- imposition of stamp taxes on South American contracts that could
increase project expenses substantially,
- impact of any future rate cases, FERC actions, or orders on
regulated businesses,
- impact of ratings downgrades on our liquidity, operating costs, and
cost of capital, and
- impact of restrictions by the Argentine government on natural gas
exports to our GasAtacama plant.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation
by the DOJ regarding round-trip trading transactions by CMS MST. Additionally,
we are named as a party in various litigation including a shareholder derivative
lawsuit, a securities class action lawsuit, a class action lawsuit alleging
ERISA violations, several lawsuits regarding alleged false natural gas price
reporting, and a lawsuit surrounding the possible sale of CMS Pipeline Assets.
For additional details regarding these investigations and litigation, see Note
3, Uncertainties.
CMS-38
CMS Energy Corporation
NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership
and the FMLP. We have a 49 percent partnership interest in the MCV Partnership
and a 46.4 percent partnership interest in the FMLP. Consumers is the primary
purchaser of power from the MCV Partnership through a long-term power purchase
agreement. In addition, the FMLP holds a 75.5 percent lessor interest in the MCV
Facility, which results in Consumers holding a 35 percent lessor interest in the
MCV Facility. Collectively, these interests make us the primary beneficiary of
these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $728 million at June 30, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.453 billion at
June 30, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of three
other entities that are determined to be variable interest entities. We have 50
percent partnership interest in the T.E.S. Filer City Station Limited
Partnership, the Grayling Generating Station Limited Partnership, and the
Genesee Power Station Limited Partnership. Additionally, we have operating and
management contracts and are the primary purchaser of power from each
partnership through long-term power purchase agreements. Collectively, these
interests make us the primary beneficiary as defined by the Interpretation.
Therefore, we consolidated these partnerships into our consolidated financial
statements for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $118 million at June 30, 2004. Property, plant,
and equipment serving as collateral for these obligations has a carrying value
of $169 million as of June 30, 2004. Other than outstanding letters of credit
and guarantees of $5 million, the creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to restate prior periods for the impact of this accounting
change.
Additionally, we have variable interest entities in which we are not the primary
beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at June 30, 2004:
CMS-39
CMS Energy Corporation
Investment Total
Name (Ownership Nature of the Involvement Balance Operating Agreement Generating
Interest) Entity Country Date (In Millions) with CMS Energy Capacity
- ------------------------------------------------------------------------------------------------------------------------
Generator United Arab
Taweelah (40%) Emirates 1999 $ 93 Yes 777 MW
Generator -
Under Saudi
Jubail (25%) Construction Arabia 2001 $ - Yes 250 MW
Generator -
Under United Arab
Shuweihat (20%) Construction Emirates 2001 $ (16)(a) Yes 1,500 MW
- ------------------------------------------------------------------------------------------------------------------------
Total $ 77 2,527 MW
========================================================================================================================
(a) At June 30, 2004, we carried a negative investment in Shuweihat. The balance
is comprised of our investment of $3 million reduced by our proportionate share
of the negative fair value of derivative instruments of $19 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 $77 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$129 million. Included in that total 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.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million, or
CMS-40
CMS Energy Corporation
$0.03 per share, for the three months ended June 30, 2004, $9 million, or $0.05
per share, for the six months ended June 30, 2004, and an expected total net
expense reduction of $17 million for 2004.
EITF NO. 03-6, PARTICIPATING SECURITIES AND THE TWO-CLASS METHOD UNDER SFAS NO.
128: EITF No. 03-6, effective June 30, 2004, addresses the treatment of
participating securities in earnings per share calculations. This EITF defines
participating securities and describes their treatment using a two-class method
of calculating earnings per share. Since we have not issued any participating
securities, as defined by EITF No. 03-6 and SFAS No. 128, there was no impact on
earnings per share upon adoption.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED EITF NO. 04-8, THE EFFECT OF CONTINGENTLY CONVERTIBLE DEBT ON DILUTED
EARNINGS PER SHARE: The Issue addresses when the dilutive effect of contingently
convertible debt instruments should be included in diluted earnings per share
calculations. At its July 1, 2004 meeting, the EITF reached a consensus that
contingently convertible debt instruments should be included in the diluted
earnings per share computation (if dilutive) regardless of whether the market
price trigger or other contingent features have been met.
We currently have a contingently convertible debt instrument and a contingently
convertible preferred stock instrument outstanding. Both securities include
similar contingent conversion provisions. Including the dilutive effect of these
instruments could reduce our diluted earnings per share. For further information
on these securities, refer to Note 4, Financings and Capitalization,
"Contingently Convertible Securities."
The proposed Issue is open for public comment and will be discussed by the EITF
at its September 2004 meeting. The tentative effective date for this EITF Issue
is for reporting periods ending after December 15, 2004. Prior period earnings
per share amounts would be required to be restated.
CMS-41
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------
In Millions, Except Per Share Amounts
OPERATING REVENUE $ 1,093 $ 1,126 $ 2,847 $ 3,094
EARNINGS FROM EQUITY METHOD INVESTEES 41 50 60 97
OPERATING EXPENSES
Fuel for electric generation 184 98 356 206
Purchased and interchange power 80 102 157 341
Purchased power - related parties - 124 - 260
Cost of gas sold 263 298 1,024 1,135
Other operating expenses 224 217 442 415
Maintenance 65 61 122 119
Depreciation, depletion and amortization 108 90 252 218
General taxes 62 7 136 76
Assets impairment charges - 3 125 9
----------------------------------------
986 1,000 2,614 2,779
- ---------------------------------------------------------------------------------------------------------
OPERATING INCOME 148 176 293 412
OTHER INCOME (DEDUCTIONS)
Accretion expense (6) (9) (12) (16)
Gain (loss) on asset sales, net 1 (3) 3 (8)
Interest and dividends 7 7 14 11
Foreign currency gains (losses), net (3) 5 (6) 11
Other income 15 3 27 6
Other expense (2) (1) (4) (3)
----------------------------------------
12 2 22 1
- ---------------------------------------------------------------------------------------------------------
FIXED CHARGES
Interest on long-term debt 126 128 256 225
Interest on long-term debt - related parties 14 - 29 -
Other interest 7 11 12 18
Capitalized interest (1) (3) (3) (5)
Preferred dividends of subsidiaries 1 1 2 1
Preferred securities distributions - 18 - 36
----------------------------------------
147 155 296 275
- ---------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS 13 23 19 138
INCOME TAX EXPENSE (BENEFIT) (7) 34 (10) 73
MINORITY INTERESTS 1 1 12 2
----------------------------------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 19 (12) 17 63
LOSS FROM DISCONTINUED OPERATIONS, NET OF $- AND $1
TAX BENEFIT IN 2004 AND $3 AND $21 TAX EXPENSE IN 2003 - (53) (2) (22)
----------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING 19 (65) 15 41
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13
TAX BENEFIT IN 2003:
DERIVATIVES (NOTE 6) - - - (23)
ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - - - (1)
----------------------------------------
- - - (24)
----------------------------------------
NET INCOME (LOSS) 19 (65) 15 17
PREFERRED DIVIDENDS 3 - 6 -
----------------------------------------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK $ 16 $ (65) $ 9 $ 17
========================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-42
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------
In Millions, Except Per Share Amounts
CMS ENERGY
NET INCOME (LOSS)
Net Income (Loss) Available to Common Stock $ 16 $ (65) $ 9 $ 17
======================================
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ 0.10 $ (0.08) $ 0.07 $ 0.43
Loss from Discontinued Operations - (0.37) (0.01) (0.15)
Loss from Changes in Accounting - - - (0.16)
--------------------------------------
Net Income (Loss) Attributable to Common Stock $ 0.10 $ (0.45) $ 0.06 $ 0.12
======================================
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ 0.10 $ (0.08) $ 0.07 $ 0.43
Loss from Discontinued Operations - (0.37) (0.01) (0.14)
Loss from Changes in Accounting - - - (0.15)
--------------------------------------
Net Income (Loss) Attributable to Common Stock $ 0.10 $ (0.45) $ 0.06 $ 0.14
======================================
DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ - $ -
- ------------------------------------------------------------------------------------------------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-43
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SIX MONTHS ENDED
RESTATED
JUNE 30 2004 2003
- -----------------------------------------------------------------------------------------------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 15 $ 17
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $3 and $3, respectively) 252 218
Loss on disposal of discontinued operations 1 49
Asset impairments (Note 2) 125 9
Capital lease and debt discount amortization 14 12
Accretion expense 12 16
Bad debt expense 5 8
Undistributed earnings from related parties (44) (69)
Loss (gain) on the sale of assets (3) 8
Cumulative effect of accounting changes - 24
Changes in other assets and liabilities:
Increase in accounts receivable and accrued revenues (112) (69)
Decrease (increase) in inventories 81 (2)
Increase (decrease) in accounts payable and accrued expenses 66 (298)
Deferred income taxes and investment tax credit 44 169
Decrease in other assets 16 91
Increase (decrease) in other liabilities 9 (36)
---------------------
Net cash provided by operating activities $ 481 $ 147
- -------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (237) $ (261)
Cost to retire property (37) (35)
Restricted cash (12) (167)
Investment in Electric Restructuring Implementation Plan (3) (4)
Investments in nuclear decommissioning trust funds (3) (3)
Proceeds from nuclear decommissioning trust funds 23 18
Maturity of MCV restricted investment securities held-to-maturity 300 -
Purchase of MCV restricted investment securities held-to-maturity (300) -
Proceeds from sale of assets 66 726
Other investing (11) 18
---------------------
Net cash provided by (used in) investing activities $ (214) $ 292
- -------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 9 $ 1,449
Retirement of bonds and other long-term debt (274) (830)
Payment of preferred stock dividends (6) -
Decrease in notes payable - (487)
Payment of capital lease obligations (5) (7)
---------------------
Net cash provided by (used in) financing activities $ (276) $ 125
- -------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATES ON CASH (1) 2
- -------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $ (10) $ 566
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB INTERPRETATION NO. 46 174 -
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 532 351
---------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 696 $ 917
=================================================================================================
CMS-44
SIX MONTHS ENDED
RESTATED
JUNE 30 2004 2003
- ----------------------------------------------------------------------------------------------
In Millions
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 246 $ 233
Income taxes paid (net of refunds) - (33)
OPEB cash contribution 33 40
NON-CASH TRANSACTIONS
Other assets placed under capital leases $ 1 $ 10
==============================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-45
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
JUNE 30
JUNE 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------
In Millions
PLANT AND PROPERTY (AT COST)
Electric utility $ 7,776 $ 7,600 $ 7,465
Gas utility 2,898 2,875 2,805
Enterprises 3,392 895 706
Other 28 32 37
-------------------------------------
14,094 11,402 11,013
Less accumulated depreciation, depletion and amortization 5,958 4,846 4,777
-------------------------------------
8,136 6,556 6,236
Construction work-in-progress 392 388 438
-------------------------------------
8,528 6,944 6,674
- ---------------------------------------------------------------------------------------------------------
INVESTMENTS
Enterprises 754 724 740
Midland Cogeneration Venture Limited Partnership - 419 422
First Midland Limited Partnership - 224 263
Other 24 23 2
-------------------------------------
778 1,390 1,427
- ---------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 696 532 917
Restricted cash 213 201 205
Accounts receivable, notes receivable and accrued revenue, less
allowances of $28, $29 and $17, respectively 531 367 473
Accounts receivable - Energy Resource Management,
less allowances of $10, $11 and $9, respectively 36 36 145
Accounts receivable and notes receivable - related parties 60 73 182
Inventories at average cost:
Gas in underground storage 665 741 460
Materials and supplies 107 110 102
Generating plant fuel stock 60 41 42
Assets held for sale 14 24 79
Price risk management assets 99 102 101
Regulatory assets 19 19 19
Derivative instruments 114 2 2
Prepayments and other 238 246 308
-------------------------------------
2,852 2,494 3,035
- ---------------------------------------------------------------------------------------------------------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 627 648 669
Postretirement benefits 151 162 174
Abandoned Midland Project 10 10 11
Other 318 266 255
Assets held for sale - 2 213
Price risk management assets 192 177 213
Nuclear decommissioning trust funds 559 575 553
Prepaid pension costs 378 388 -
Goodwill 23 25 36
Notes receivable - related parties 231 242 147
Notes receivable 125 125 126
Other 535 390 406
-------------------------------------
3,149 3,010 2,803
-------------------------------------
TOTAL ASSETS $ 15,307 $ 13,838 $ 13,939
=========================================================================================================
CMS-46
STOCKHOLDERS' INVESTMENT AND LIABILITIES
JUNE 30
JUNE 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
In Millions
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares; outstanding 161.3 shares,
161.1 shares and 144.1 shares, respectively $ 2 $ 2 $ 1
Other paid-in-capital 3,848 3,846 3,608
Accumulated other comprehensive loss (313) (419) (690)
Retained deficit (1,835) (1,844) (1,783)
---------------------------------------
1,702 1,585 1,136
Preferred stock of subsidiary 44 44 44
Preferred stock 261 261 -
Company-obligated convertible Trust Preferred Securities
of subsidiaries - - 393
Company-obligated mandatorily redeemable Trust Preferred Securities
of Consumers' subsidiaries - - 490
Long-term debt 5,816 6,020 6,062
Long-term debt - related parties 684 684 -
Non-current portion of capital and finance lease obligations 338 58 119
---------------------------------------
8,845 8,652 8,244
- ---------------------------------------------------------------------------------------------------------------
MINORITY INTERESTS 740 73 43
- ---------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt, capital and finance leases 903 519 544
Accounts payable 358 296 334
Accounts payable - Energy Resource Management 21 21 52
Accounts payable - related parties 2 40 47
Accrued interest 170 130 126
Accrued taxes 239 285 180
Liabilities held for sale 2 2 66
Price risk management liabilities 93 89 93
Current portion of purchase power contracts 13 27 26
Current portion of gas supply contract obligations 30 29 28
Deferred income taxes 29 27 32
Other 301 185 185
---------------------------------------
2,161 1,650 1,713
- ---------------------------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Cost of removal 1,016 983 950
Income taxes, net 321 312 313
Other 165 172 155
Postretirement benefits 252 265 791
Deferred income taxes 651 615 487
Deferred investment tax credit 82 85 87
Asset retirement obligation 407 359 364
Liabilities held for sale - - 45
Price risk management liabilities 188 175 206
Gas supply contract obligations 190 208 221
Power purchase agreement - MCV Partnership - - 14
Other 289 289 306
---------------------------------------
3,561 3,463 3,939
- ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,307 $ 13,838 $ 13,939
===============================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-47
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
RESTATED RESTATED
JUNE 30 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
In Millions
COMMON STOCK
At beginning and end of period $ 2 $ 1 $ 2 $ 1
- ---------------------------------------------------------------------------------------------------------------------------
OTHER PAID-IN CAPITAL
At beginning of period 3,846 3,605 3,846 3,605
Common stock reacquired (1) (1) (1) (1)
Common stock issued 3 4 3 4
------------------------------------------
At end of period 3,848 3,608 3,848 3,608
- ---------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (241) - (241)
Minimum pension liability adjustments (a) - (20) - (20)
------------------------------------------
At end of period - (261) - (261)
------------------------------------------
Investments
At beginning of period 9 2 8 2
Unrealized gain (loss) on investments (a) (1) 3 - 3
------------------------------------------
At end of period 8 5 8 5
------------------------------------------
Derivative Instruments
At beginning of period (13) (29) (8) (31)
Unrealized gain (loss) on derivative instruments (a) 22 (14) 19 (7)
Reclassification adjustments included in consolidated net income (loss) (a) (3) 21 (5) 16
------------------------------------------
At end of period 6 (22) 6 (22)
------------------------------------------
Foreign Currency Translation
At beginning of period (313) (445) (419) (458)
Change in foreign currency translation (a) (14) 33 92 46
------------------------------------------
At end of period (327) (412) (327) (412)
------------------------------------------
At end of period (313) (690) (313) (690)
- ---------------------------------------------------------------------------------------------------------------------------
RETAINED DEFICIT
At beginning of period (1,851) (1,718) (1,844) (1,800)
Net income (loss) (a) 19 (65) 15 17
Preferred stock dividends declared (3) - (6) -
Common stock dividends declared - - - -
------------------------------------------
At end of period (1,835) (1,783) (1,835) (1,783)
------------------------------------------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,702 $ 1,136 $ 1,702 $ 1,136
===========================================================================================================================
(A) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum Pension Liability
Minimum pension liability adjustments, net of tax benefit of
$-, $(10), $- and $(10), respectively $ - $ (20) $ - $ (20)
Investments
Unrealized gain (loss) on investments, net of tax of $-, $1,
$- and $1, respectively (1) 3 - 3
Derivative Instruments
Unrealized loss on derivative instruments, net of tax (tax benefit)
of $2, $(3), $7 and $2, respectively 22 (14) 19 (7)
Reclassification adjustments included in net income (loss),
net of tax (tax benefit) of $(2), $14, $(3) and $11, respectively (3) 21 (5) 16
Foreign currency translation, net (14) 33 92 46
Net income (loss) 19 (65) 15 17
------------------------------------------
Total Other Comprehensive Income (Loss) $ 23 $ (42) $ 121 $ 55
==========================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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CMS ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by CMS Energy
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. Certain prior year amounts have been reclassified to
conform to the presentation in the current year. In management's opinion, the
unaudited information contained in this report reflects all adjustments of a
normal recurring nature necessary to assure the fair presentation of financial
position, results of operations and cash flows for the periods presented. The
Condensed Notes to Consolidated Financial Statements and the related
Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
contained in CMS Energy's Form 10-K/A for the year ended December 31, 2003. Due
to the seasonal nature of CMS Energy's operations, the results as presented for
this interim period are not necessarily indicative of results to be achieved for
the fiscal year.
RESTATEMENT OF 2003 FINANCIAL STATEMENTS
Our financial statements as of and for the three and six months ended June 30,
2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales,
- certain derivative accounting corrections at our equity affiliates,
and
- 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.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: CMS Energy is an integrated energy company with a business
strategy focused primarily in Michigan. We are the parent holding company of
Consumers and Enterprises. Consumers is a combination electric and gas utility
company serving Michigan's Lower Peninsula. Enterprises, through various
subsidiaries and equity investments, is engaged in domestic and international
diversified energy businesses including: independent power production and
natural gas transmission, storage and processing. We manage our businesses by
the nature of services each provides and operate principally in three business
segments: electric utility, gas utility, and enterprises.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the
accounts of CMS Energy, Consumers, Enterprises, and all other entities in which
we have a controlling financial interest or are the primary beneficiary, in
accordance with Revised FASB Interpretation No. 46. The primary beneficiary of a
variable interest entity is the party that absorbs or receives a majority of the
entity's expected losses or expected residual returns or both as a result of
holding variable interests, which are ownership, contractual, or other economic
interests. In 2004, we consolidated the MCV
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Partnership and the FMLP in accordance with Revised FASB Interpretation No. 46.
For additional details, see Note 11, Implementation of New Accounting Standards.
We use the equity method of accounting for investments in companies and
partnerships that are not consolidated, where we have significant influence over
operations and financial policies, but are not the primary beneficiary.
Intercompany transactions and balances have been eliminated.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. 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 an amount can be reasonably estimated. We have used this
accounting principle to record estimated liabilities as discussed in Note 3,
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
June 30, 2004, our restricted cash on hand was $213 million. Restricted cash
primarily includes cash collateral for letters of credit to satisfy certain debt
agreements and cash dedicated for repayment of Securitization bonds. It is
classified as a current asset as the related letters of credit mature within one
year and the payments on the related Securitization bonds occur within one year.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the
weighted average number of shares of common stock and dilutive potential common
stock outstanding during the period. Potential common stock, for purposes of
determining diluted earnings per share, includes the effects of dilutive stock
options, warrants and convertible securities. The effect on number of shares of
such potential common stock is computed using the treasury stock method or the
if-converted method, as applicable. For earnings per share computation, see Note
5, Earnings Per Share and Dividends.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. 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
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from changes in the fair value of our nuclear decommissioning investments are
reflected in Regulatory Liabilities. The fair value of our equity securities is
determined from quoted market prices. For additional details regarding financial
instruments, see Note 6, Financial and Derivative Instruments.
FOREIGN CURRENCY TRANSLATION: Our subsidiaries and affiliates whose functional
currency is not the U.S. dollar translate their assets and liabilities into U.S.
dollars at the exchange rates in effect at the end of the fiscal period. We
translate revenue and expense accounts of such subsidiaries and affiliates into
U.S. dollars at the average exchange rates that prevailed during the period. The
gains or losses that result from this process, and gains and losses on
intercompany foreign currency transactions that are long-term in nature that we
do not intend to settle in the foreseeable future, are shown in the
stockholders' equity section in the Consolidated Balance Sheets. For
subsidiaries operating in highly inflationary economies, the U.S. dollar is
considered to be the functional currency, and transaction gains and losses are
included in determining net income. Gains and losses that arise from exchange
rate fluctuations on transactions denominated in a currency other than the
functional currency, except those that are hedged, are included in determining
net income.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate potential
impairments of our investments in long-lived assets other than goodwill based on
various analyses, including the projection of undiscounted cash flows, whenever
events or changes in circumstances indicate that the carrying amount of the
assets may not be recoverable. If the carrying amount of the asset exceeds its
estimated undiscounted future cash flows, an impairment loss is recognized and
the asset is written down to its estimated fair value.
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the
quantity of heat produced for electric generation. For nuclear fuel used after
April 6, 1983, we charge disposal costs to nuclear fuel expense, recover these
costs through electric rates, and remit them to the DOE quarterly. We elected to
defer payment for disposal of spent nuclear fuel burned before April 7, 1983. As
of June 30, 2004, we have recorded a liability to the DOE for $140 million,
including interest, which is payable upon the first delivery of spent nuclear
fuel to the DOE. The amount of this liability, excluding a portion of interest,
was recovered through electric rates. For additional details on disposal of
spent nuclear fuel, see Note 3, Uncertainties, "Other Consumers' Electric
Utility Uncertainties - Nuclear Matters."
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:
In Millions
- -----------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
--------------------------------------
June 30 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Other income
Interest and dividends - related parties $ 1 $ 1 $ 2 $ 2
PA141 Return on capital expenditures 9 - 18 -
Electric restructuring return 1 2 3 3
Investment sale gain 1 - 1 -
All other 3 - 3 1
- -----------------------------------------------------------------------------------------
Total other income $ 15 $ 3 $ 27 $ 6
=========================================================================================
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In Millions
- -----------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
--------------------------------------
June 30 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Other expense
Loss on SERP investment $ (1) $ - $ (1) $ (1)
Civic and political expenditures - - (1) (1)
All other (1) (1) (2) (1)
- -----------------------------------------------------------------------------------------
Total other expense $ (2) $ (1) $ (4) $ (3)
=========================================================================================
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 10, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.
2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING
Our continued focus on financial improvement has led to discontinuing
operations, completing many asset sales, impairing some assets, and incurring
costs to restructure our business. Gross cash proceeds received from the sale of
assets totaled $66 million for the six months ended June 30, 2004 and $726
million for the six months ended June 30, 2003.
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DISCONTINUED OPERATIONS
We have discontinued the following operations:
In Millions
- -----------------------------------------------------------------------------
Pretax After-tax
Business/Project Discontinued Gain(Loss) Gain(Loss) Status
- -----------------------------------------------------------------------------
CMS Viron June 2002 $ (14) $ (9) Sold June 2003
Panhandle December 2002 (39) (44) Sold June 2003
CMS Field Services December 2002 (5) (1) Sold July 2003
Marysville June 2003 2 1 Sold November 2003
Parmelia (a) December 2003 -- -- Held for sale
- -----------------------------------------------------------------------------
(a) We expect the sale of Parmelia to occur in 2004. In December 2003, we
reduced the carrying amount of our Parmelia business by $26 million to reflect
fair value. This after-tax loss was reported in discontinued operations in
December 2003.
At June 30, 2004, "Assets held for sale" includes Parmelia. At December 31,
2003, "Assets held for sale" includes Parmelia, Bluewater Pipeline, and our
investment in the American Gas Index Fund. At June 30, 2003, "Assets held for
sale" includes CMS Field Services, Marysville, and Parmelia. The major classes
of assets and liabilities held for sale on our Consolidated Balance Sheet are as
follows:
In Millions
- ---------------------------------------------------------------------------------------------------
Restated
June 30, 2004 December 31, 2003 June 30, 2003
- ---------------------------------------------------------------------------------------------------
Assets
Cash $ 8 $ 7 $ 2
Accounts receivable 3 2 71
Property, plant and equipment - net - 2 197
Other 3 15 22
- ---------------------------------------------------------------------------------------------------
Total assets held for sale $ 14 $ 26 $ 292
===================================================================================================
Liabilities
Accounts payable $ 1 $ 2 $ 61
Minority interest - - 44
Other 1 - 6
- ---------------------------------------------------------------------------------------------------
Total liabilities held for sale $ 2 $ 2 $ 111
===================================================================================================
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The following amounts are reflected in the Consolidated Statements of Income, in
the Loss From Discontinued Operations line:
In Millions
- -----------------------------------------------------------------------------
Restated
Three months ended June 30 2004 2003
- -----------------------------------------------------------------------------
Revenues $ 5 $ 250
=============================================================================
Discontinued operations:
Pretax income from discontinued operations $ - $ 6
Income tax expense - 4
-----------------------
Income from discontinued operations - 2
Pretax loss on disposal of discontinued operations - (56)
Income tax benefit - (1)
-----------------------
Loss on disposal of discontinued operations - (55)
- -----------------------------------------------------------------------------
Loss from discontinued operations $ - $ (53)
=============================================================================
In Millions
- -----------------------------------------------------------------------------
Restated
Six months ended June 30 2004 2003
- -----------------------------------------------------------------------------
Revenues $ 10 $ 496
=============================================================================
Discontinued operations:
Pretax income (loss) from discontinued operations $ (1) $ 46
Income tax expense - 19
-----------------------
Income (loss) from discontinued operations (1) 27
Pretax loss on disposal of discontinued operations (2) (47)
Income tax expense (benefit) (1) 2
-----------------------
Loss on disposal of discontinued operations (1) (49)
- -----------------------------------------------------------------------------
Loss from discontinued operations $ (2) $ (22)
=============================================================================
The loss from discontinued operations includes a reduction in asset values, a
provision for anticipated closing costs, and a portion of CMS Energy's interest
expense. Interest expense of less than $1 million for the six months ended June
30, 2004 and $21 million for the six months ended June 30, 2003 has been
allocated based on a ratio of the expected proceeds for the asset to be sold
divided by CMS Energy's total capitalization of each discontinued operation
times CMS Energy's interest expense.
OTHER ASSET SALES
Our other asset sales include the following non-strategic and under-performing
assets. The impacts of these sales are included in "Gain (loss) on asset sales,
net" in the Consolidated Statements of Income (Loss).
For the six months ended June 30, 2004, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:
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CMS Energy Corporation
In Millions
- --------------------------------------------------------------
Pretax After-tax
Date sold Business/Project Gain Gain
- --------------------------------------------------------------
February Bluewater Pipeline (a) $ 1 $ 1
April Loy Yang (b) - -
May American Gas Index fund (c) 1 1
Various Other 1 -
- --------------------------------------------------------------
Total gain on asset sales $ 3 $ 2
==============================================================
(a) Bluewater Pipeline is a 24.9 mile pipeline that extends from Marysville,
Michigan to Armada, Michigan.
(b) In April 2004, we and our partners sold the 2,000 MW Loy Yang power plant
and adjacent coal mine in Victoria, Australia for about A$3.5 billion
($2.6 billion in U.S. dollars), including A$145 million for the project
equity. Our share of the proceeds, net of transaction costs and closing
adjustments, was $44 million. In anticipation of the sale, we recorded an
impairment in the first quarter as discussed in "Asset Impairments" within
this Note.
(c) In May 2004, we sold our interest in the American Gas Index fund for $7
million.
For the six months ended June 30, 2003, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:
In Millions
- --------------------------------------------------------------
Pretax After-tax
Date sold Business/Project Gain(Loss) Gain(Loss)
- --------------------------------------------------------------
January CMS MST Wholesale Gas $ (6) $ (4)
March CMS MST Wholesale Power 2 1
June Guardian Pipeline (4) (3)
- --------------------------------------------------------------
Total loss on asset sales $ (8) $ (6)
==============================================================
SUBSEQUENT EVENT: In July 2004, we entered into a definitive agreement to sell
our interests in Parmelia and Goldfields to APT for approximately $208 million
Australian (approximately $145 million in U.S. dollars). The sale is subject to
customary closing conditions. We expect the sale to close in the third quarter
of 2004.
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.
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The table below summarizes our asset impairments:
In Millions
- -------------------------------------------------------------------------------------------------
Six months ended June 30 Pretax 2004 After-tax 2004 Pretax 2003 After-tax 2003
- -------------------------------------------------------------------------------------------------
Asset impairments:
Enterprises (a) $ - $ - $ 7 $ 4
International Energy Distribution - - 2 1
Loy Yang (b) 125 81 - -
- -------------------------------------------------------------------------------------------------
Total asset impairments $ 125 $ 81 $ 9 $ 5
=================================================================================================
(a) Primarily represents an impairment recorded to reflect the fair value of
two generators.
(b) In the first quarter of 2004, an impairment charge was recorded to
recognize the reduction in fair value as a result of the sale of Loy Yang,
completed in April 2004, which included a cumulative net foreign currency
translation loss of approximately $110 million.
RESTRUCTURING AND OTHER COSTS
In June 2002, we announced a series of initiatives to reduce our annual
operating costs by an estimated $50 million. As such, we:
- relocated CMS Energy's corporate headquarters from Dearborn,
Michigan to a new combined CMS Energy and Consumers headquarters in
Jackson, Michigan in July 2003,
- implemented changes to our 401(k) savings program,
- implemented changes to our health care plan, and
- completed the termination of numerous employees, including five
officers.
The following tables shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs for the six
months ended June 30, 2004 and June 30, 2003.
In Millions
- ------------------------------------------------------------------------------------------------
Involuntary Lease
Termination Termination Total
- ------------------------------------------------------------------------------------------------
Beginning accrual balance, January 1, 2004 $ 3 $ 6 $ 9
Expense - - -
Payments (1) (2) (3)
- ------------------------------------------------------------------------------------------------
Ending accrual balance at June 30, 2004 $ 2 $ 4 $ 6
=================================================================================================
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In Millions
- -----------------------------------------------------------------------------------
Involuntary Lease
Termination Termination Total
- -----------------------------------------------------------------------------------
Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20
Expense 3 - 3
Payments (8) - (8)
- -----------------------------------------------------------------------------------
Ending accrual balance at June 30, 2003 $ 7 $ 8 $ 15
===================================================================================
3: UNCERTAINTIES
Several 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 net sales, revenues, or income from continuing
operations. Such trends and uncertainties are discussed in detail below.
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by
CMS MST, CMS Energy's Board of Directors established a Special Committee to
investigate matters surrounding the transactions and retained outside counsel to
assist in the investigation. The Special Committee completed its investigation
and reported its findings to the Board of Directors in October 2002. The Special
Committee concluded, based on an extensive investigation, that the round-trip
trades were undertaken to raise CMS MST's profile as an energy marketer with the
goal of enhancing its ability to promote its services to new customers. The
Special Committee found no effort to manipulate the price of CMS Energy Common
Stock or affect energy prices. The Special Committee also made recommendations
designed to prevent any recurrence of this practice. Previously, CMS Energy
terminated its speculative trading business and revised its risk management
policy. The Board of Directors adopted, and CMS Energy has implemented the
recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading. CMS Energy is unable to predict the outcome of this matter and what
effect, if any, this investigation will have on its business. In March 2004, the
SEC approved a cease-and-desist order settling an administrative action against
CMS Energy related to round-trip trading. The order did not assess a fine and
CMS Energy neither admitted to nor denied the order's findings. The settlement
resolved the SEC investigation involving CMS Energy and CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It generally seeks unspecified damages based on allegations that the
defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. The judge issued an opinion
and order dated March 31, 2004 in connection with various pending motions,
including plaintiffs' motion to amend the complaint and the motions to dismiss
the complaint filed by CMS Energy, Consumers and other defendants. The judge
directed plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend, which was held on May 12, 2004. At the
hearing, the judge ordered plaintiffs to file a Second Amended Consolidated
Class Action complaint deleting Counts III and
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CMS Energy Corporation
IV relating to purchasers of CMS PEPS, which the judge ordered dismissed with
prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS Energy,
Consumers, and the individual defendants filed new motions to dismiss on June
21, 2004. A hearing on those motions occurred on August 2, 2004 and the judge
has taken the matter under advisement. CMS Energy, Consumers and the individual
defendants will defend themselves vigorously but cannot predict the outcome of
this litigation.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board of
Directors of CMS Energy received a demand, on behalf of a shareholder of CMS
Energy Common Stock, that it commence civil actions (i) to remedy alleged
breaches of fiduciary duties by certain CMS Energy officers and directors in
connection with round-trip trading by CMS MST, and (ii) to recover damages
sustained by CMS Energy as a result of alleged insider trades alleged to have
been made by certain current and former officers of CMS Energy and its
subsidiaries. In December 2002, two new directors were appointed to the Board.
The Board formed a special litigation committee in January 2003 to determine
whether it is in CMS Energy's best interest to bring the action demanded by the
shareholder. The disinterested members of the Board appointed the two new
directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to September 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. CMS Energy cannot predict the outcome of this
matter.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST,
and certain named and unnamed officers and directors, in two lawsuits brought as
purported class actions on behalf of participants and beneficiaries of the CMS
Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July
2002 in United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution
on behalf of the Plan with respect to a decline in value of the shares of CMS
Energy Common Stock held in the Plan. Plaintiffs also seek other equitable
relief and legal fees. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants filed
answers to the amended complaint on May 14, 2004. A trial date has not been set,
but is expected to be no earlier than late in 2005. CMS Energy and Consumers
will defend themselves vigorously but cannot predict the outcome of this
litigation.
GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified appropriate
regulatory and governmental agencies that some employees at CMS MST and CMS
Field Services appeared to have provided inaccurate information regarding
natural gas trades to various energy industry publications which compile and
report index prices. CMS Energy is cooperating with an ongoing investigation by
the DOJ regarding this matter. CMS Energy is unable to predict the outcome of
the DOJ investigation and what effect, if any, this investigation will have on
its business.
GAS INDEX PRICE REPORTING LITIGATION: In August 2003, Cornerstone Propane
Partners, L.P. (Cornerstone) filed a putative class action complaint in the
United States District Court for the Southern District of New York against CMS
Energy and dozens of other energy companies. The court ordered the Cornerstone
complaint to be consolidated with similar complaints filed by Dominick Viola and
Roberto Calle Gracey. The plaintiffs filed a consolidated complaint on January
20, 2004. The consolidated
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complaint alleges that false natural gas price reporting by the defendants
manipulated the prices of NYMEX natural gas futures and options. The complaint
contains two counts under the Commodity Exchange Act, one for manipulation and
one for aiding and abetting violations. CMS Energy is no longer a defendant,
however, CMS MST and CMS Field Services are named as defendants. (CMS Energy
sold CMS Field Services to Cantera Natural Gas, Inc. but is required to
indemnify Cantera Natural Gas, Inc. with respect to this action).
In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a putative
class action lawsuit in the United States District Court for the Eastern
District of California against a number of energy companies engaged in the sale
of natural gas in the United States. CMS Energy is named as a defendant. The
complaint alleges defendants entered into a price-fixing conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair and deceptive business practices. There is currently pending
in the Nevada federal district court a multi-district court litigation (MDL)
matter involving seven complaints originally filed in various state courts in
California. These complaints make allegations similar to those in the Texas-Ohio
case regarding price reporting, although none contain a Sherman Act claim and
some of the defendants in the MDL matter are also defendants in the Texas-Ohio
case. Those defendants successfully argued to have the Texas-Ohio case
transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case agreed
to extend the time for all defendants to answer or otherwise respond until May
28, 2004 and on that date a number of defendants filed motions to dismiss. In
order to negotiate possible dismissal and/or substitution of defendants, CMS
Energy and two other parent holding company defendants were given further
extensions to answer or otherwise respond to the complaint until August 16,
2004.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court, which was
granted, and had it transferred to the MDL proceeding in Nevada. However, the
plaintiff is seeking to have the case remanded back to California and until the
issue is resolved, no further action will be taken.
Three new, virtually identical actions were filed in San Diego Superior Court in
July 2004, one by the County of Santa Clara (Santa Clara), one by the County of
San Diego (San Diego) and one by the City of and County of San Francisco and the
San Francisco City Attorney (collectively San Francisco). Defendants, consisting
of a number of energy companies including CMS Energy, CMS MS&T, Cantera Natural
Gas and Cantera Gas Company, are alleged to have engaged in false reporting of
natural gas price and volume information and sham sales to artificially inflate
natural gas retail prices in California. All three complaints allege claims for
unjust enrichment and violations of the Cartwright Act, and the San Francisco
action also alleges a claim for violation of the California Business and
Profession Code relating to unlawful, unfair and deceptive business practices.
CMS Energy and the other CMS defendants will defend themselves vigorously, but
cannot predict the outcome of these matters.
CMS-59
CMS Energy Corporation
CONSUMERS' UNCERTAINTIES
Several 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 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
expense 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,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an electric
transmission owner.
Regulatory
- recovery of nuclear decommissioning costs,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- other pending litigation.
CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws
and regulations. Costs to operate our facilities in compliance with these laws
and regulations generally have been recovered in customer rates.
Clean Air: The EPA and the state regulations require us to make significant
capital expenditures estimated to be $771 million. As of June 30, 2004, we have
incurred $489 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $282 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology at some of our coal-fired electric plants. Based on the
Customer Choice Act, beginning January 2004, an annual return of and on these
types of capital expenditures, to the extent they are above depreciation levels,
is expected to be recoverable from customers, subject to the MPSC prudency
hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to
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information requests from the EPA on this subject. We believe that we have
properly interpreted the requirements of "routine maintenance." If our
interpretation is found to be incorrect, we may be required to install
additional pollution controls at some or all of our coal-fired electric plants
and potentially pay fines. Additionally, the viability of certain plants
remaining in operation could be called into question.
In addition to modifying the coal-fired electric plants, we expect to purchase
nitrogen oxide emissions credits for years 2004 through 2008. The cost of these
credits is estimated to average $8 million per year and is accounted for as
inventory. The credit inventory is expensed as the coal-fired electric plants
generate electricity. The price for nitrogen oxide emissions credits is volatile
and could change substantially.
The EPA has proposed a Clean Air Interstate Rule that would require additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury and nickel from
coal-fired and oil-fired electric plants. Until the proposed environmental rules
are finalized, an accurate cost of compliance cannot be determined.
Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that greenhouse gas emission reduction rules come into effect,
such mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments, and will continue to assess and respond
to their potential implications on our business operations.
Water: In March 2004, the EPA changed the rules that govern generating plant
cooling water intake systems. The new rules require significant reduction in
fish killed by operating equipment. Some of our facilities will be required to
comply by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental
Protection Act, we expect that we will ultimately incur investigation and
remedial action costs at a number of sites. We believe that these costs will be
recoverable in rates under current ratemaking policies.
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 June 30, 2004, we have recorded
a liability for the minimum amount of our estimated Superfund liability.
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In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at the Ludington Pumped
Storage facility. We removed and replaced part of the PCB material. We have
proposed a plan to deal with the remaining materials and are awaiting a response
from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made pursuant
to power purchase agreements with qualifying facilities. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants. We believe we
have been performing the calculation in the manner prescribed by the power
purchase agreements, and have filed a request with the MPSC (as a supplement to
the PSCR plan) that asks the MPSC to review this issue and to confirm that our
method of performing the calculation is correct. We filed a motion to dismiss
the lawsuit in the Ingham County Circuit Court due to the pending request at the
MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
resulted in a dismissal of the circuit court case without prejudice. Although
only eight qualifying facilities have raised the issue, the same energy charge
methodology is used in the PPA with the MCV Partnership and in approximately 20
additional power purchase agreements with us, representing a total of 1,670 MW
of electric capacity. The eight plaintiff qualifying facilities have appealed
the dismissal of the circuit court case to the Michigan Court of Appeals. We
cannot predict the outcome of this matter.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: The Michigan legislature passed electric
utility restructuring legislation known as the Customer Choice Act. This Act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the act,
- 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 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
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Act. We have completed the transmission capacity projects identified in the plan
and have submitted verification of this fact to the MPSC. We believe we are in
full compliance. Lastly, in September 2003, the MPSC issued an order finding
that we are in compliance with the market power supply test set forth in the
Customer Choice Act.
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms,
and conditions under which retail customers are permitted to choose an electric
supplier. These revised tariffs allow ROA customers, upon as little as 30 days
notice to us, to return to our generation service at current tariff rates. If
any class of customers' (residential, commercial, or industrial) ROA load
reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods. We cannot predict the total amount of electric supply load that may be
lost to alternative electric suppliers. As of July 2004, alternative electric
suppliers are providing 858 MW of load. This amount represents 11 percent of the
total distribution load and an increase of 49 percent compared to July 2003.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs,
- security costs, and
- transmission rates.
The following chart summarizes the filings with the MPSC. For additional details
related to these proceedings, see related sections within this Note.
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Years Years Requested
Proceeding Filed Covered Amounts Status
- ---------------------------------------------------------------------------------------------
Securitization 2003 N/A $1.083 billion Received order from the MPSC
authorizing the issuance of
Securitization bonds in the
amount of $554 million. Pending
MPSC order resolving outstanding
issues.
Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced
zero Stranded Costs for 2000
through 2001, which we are
appealing. Filings for 2002 and
2003 in the amount of $116
million are still pending MPSC
approval.
Implementation 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the
Costs years 1997-2001, plus $20 million
for the cost of money through
2003. Implementation cost
filings for 2002 and 2003 in the
amount of $8 million, which
includes the cost of money
through 2003, are still pending
MPSC approval.
Security Costs 2004 2001-2005 $25 million Pending MPSC approval. As of
June 30, 2004, we have recorded
$7 million of costs incurred as a
regulatory asset.
=============================================================================================
(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes the issuance of Securitization bonds
in an amount that includes Clean Air Act investments. If Clean Air Act
investments were not included in the issuance of Securitization bonds, Stranded
Costs requested would total $304 million.
(b) Amounts include the cost of money through year incurred.
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 before the last scheduled bond maturity date, and no more than
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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, $25
million for the six months ended June 30, 2004, and $25 million for the six
months ended June 30, 2003, are remitted to a trustee. Securitization charge
collections are restricted to the repayment of the principal and interest on the
Securitization bonds and payment of the ongoing expenses of Consumers Funding.
Consumers Funding is legally separate from Consumers. The assets and income of
Consumers Funding, including the securitized property, are not available to
creditors of Consumers or CMS Energy.
In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
This amount relates to Clean Air Act expenditures and associated return on those
expenditures through December 31, 2002, ROA implementation costs and previously
authorized return on those expenditures through December 31, 2000, and other up
front qualified costs related to issuance of the Securitization bonds. In July
2003, we filed for rehearing and clarification on a number of features in the
financing order.
In December 2003, the MPSC ordered remanded hearings in response to our request
for rehearing and clarification. In March 2004, the MPSC conducted the remanded
hearings and the matter is presently before the MPSC awaiting a decision.
In May 2004, we withdrew our request for approved implementation costs incurred
for the years 1998 through 2000 from the Securitization case, as we chose
recovery of the approved implementation costs through the use of a surcharge, as
described in "Implementation Costs" within this section. However, qualified
Clean Air Act costs, after taking out implementation costs, still exceed the
$554 million MPSC limit on the amount of securitized bonds. As a result, we did
not request a decrease to allowable securitized costs. If and when the MPSC
issues an order with favorable terms, then the order will become effective upon
our acceptance.
Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. The Act directs the MPSC to
establish a method of calculating net Stranded Costs and of conducting related
true-up adjustments. In December 2001, the MPSC Staff recommended a methodology,
which calculated net Stranded Costs as the shortfall between:
- - the revenue required to cover the costs associated with fixed generation
assets and capacity payments associated with purchase power agreements, and
- - the revenues received from customers under existing rates available to cover
the revenue requirement.
The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost transition
charge. However, the MPSC has not yet allowed such a transition charge. The MPSC
has 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. As a result, we have not recorded regulatory assets to recognize
the future recovery of such costs.
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The following table outlines the applications filed by us with the MPSC and the
status of recovery for these costs:
In Millions
- --------------------------------------------------------------------------------------
Requested, without the
Requested, with the issuance issuance of Securitization
of Securitization bonds that bonds that include Clean Air
Year Year include Clean Air Act Act investment and cost of Recoverable
Filed Incurred investment and cost of money money amount
- --------------------------------------------------------------------------------------
2002 2000 $12 $ 26 $ -
2002 2001 9 46 -
2003 2002 47 104 Pending
2004 2003 69 128 Pending
======================================================================================
We are currently in the process of appealing the MPSC orders regarding Stranded
Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan
Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded
Cost application. Once a final financing order on Securitization is reached, we
will know the amount of our request for net Stranded Cost recovery for 2002. In
July 2004, the ALJ issued a proposal for decision in our 2002 net Stranded Cost
case, which recommended that the MPSC find that we incurred net Stranded Costs
of $12 million. This recommendation includes the cost of money through July 2004
and excludes Clean Air Act investments.
The MPSC has scheduled hearings for our 2003 Stranded Cost application for
August 2004. In July 2004, the MPSC Staff issued a position on our 2003 net
Stranded Cost application, which resulted in a Stranded Cost calculation of $52
million. The amount includes the cost of money, but excludes Clean Air Act
investments. We cannot predict how the MPSC will rule on our requests for
recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a
Stranded Cost recovery method that will offset fully any associated margin loss
from ROA.
Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines the
applications filed by us with the MPSC and the status of recovery for these
costs:
In Millions
- --------------------------------------------------------------------------------
Recoverable, including
(b) cost of money through
Year Filed Year Incurred Requested Disallowed Allowed 2003
- --------------------------------------------------------------------------------
1999 1997 & 1998 $ 20 $ 5 $ 15 $22
2000 1999 30 5 25 33
2001 2000 25 5 20 24
2002 2001 8 - 8 9
2003 & 2004 (a) 2002 7 Pending Pending Pending
2004 2003 1 Pending Pending Pending
================================================================================
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.
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(b) Amounts include the cost of money through year incurred.
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. As of
June 30, 2004, we incurred and deferred as a regulatory asset $94 million of
implementation costs, which includes $25 million associated with the cost of
money. We believe the implementation costs and associated cost of money are
fully recoverable in accordance with the Customer Choice Act.
In June 2004, following an appeal and remand of initial MPSC orders relating to
1999 implementation costs, the MPSC authorized the recovery of all previously
approved implementation costs for the years 1997 through 2001 totaling $88
million. This total includes carrying costs through 2003. Additional carrying
costs will be added until collection occurs. The implementation costs will be
recovered through surcharges over 36-month collection periods and phased in as
applicable rate caps expire. We cannot predict the amounts the MPSC will approve
as recoverable costs for 2002 and 2003.
Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for costs for
which recovery has not yet been granted through other means. The requested
amount includes reasonable and prudent security enhancements through December
31, 2005. The costs are for enhanced security and insurance because of federal
and state regulatory security requirements imposed after the September 11 2001
terrorist attacks. In July 2004, a settlement was reached with the parties to
the case, which would provide for full recovery of the requested security costs
over a five-year period beginning in 2004. We are presently awaiting approval
from the MPSC. We cannot predict how the MPSC will rule on our request for the
recoverability of security costs. The following table outlines the applications
filed by us with the MPSC and the status of recovery for these costs:
In Millions
- --------------------------------------------------------------------------------
Regulatory asset as of
Year Filed Years Incurred Requested June 30, 2004 Disallowed Allowed
- --------------------------------------------------------------------------------
2004 2001-2005 $ 25 $7 Pending Pending
================================================================================
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 to MTH,
a non-affiliated limited partnership whose general partner is a subsidiary of
Trans-Elect, Inc. We are currently in
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arbitration with MTH regarding property tax items used in establishing the
selling price of our electric transmission system. An unfavorable outcome could
result in a reduction of sale proceeds previously recognized of approximately $2
million to $3 million.
Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to the FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges, which
we estimate to be $10 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of June 2004, we are in compliance
with the acceptable level of performance. We are a member of an industry
coalition that has appealed the customer credit portion of the performance
standards to the Michigan Court of Appeals. We cannot predict the likely effects
of the financial penalties, if any, nor can we predict the outcome of the
appeal. Likewise, we cannot predict our ability to meet the standards in the
future or the cost of future compliance.
POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.
To reduce the risk of high electric prices during peak demand periods and to
achieve our reserve margin target, we employ a strategy of purchasing electric
call options and capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. As of June 30, 2004, we purchased capacity and energy contracts
partially covering the estimated reserve margin requirements for 2004 through
2007. As a result, we have recognized an asset of $18 million for unexpired
capacity and energy contracts. In March 2004, we filed a summer assessment for
meeting 2004 peak load demand as required by the MPSC, stating that our summer
2004 reserve margin target is 11 percent or supply resources equal to 111
percent of projected summer peak load. Presently, we have a reserve margin of 14
percent, or supply resources equal to 114 percent of projected summer peak load
for summer 2004. Of the 114 percent, approximately 102 percent is from owned
electric generating plants and long-term contracts, and approximately 12 percent
is from short-term contracts. This reserve margin met our summer 2004 reserve
margin target. The total premium costs of electricity call options and capacity
and energy contracts for 2004 is expected to be approximately $12 million, as of
July 2004.
PSCR: As a result of meeting the transmission capability expansion requirements
and the market power test, as discussed within this Note, we have met the
requirements under the Customer Choice Act to return to the PSCR process. The
PSCR process provides for the reconciliation of actual power supply costs with
power supply revenues. This process assures recovery of all reasonable and
prudent power supply costs actually incurred by us. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers, and subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR
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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 reconciliation proceeding.
OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES
THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and operates
the MCV Facility, contracted to sell electricity to Consumers for a 35-year
period beginning in 1990 and to supply electricity and steam to Dow. We hold,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:
- - CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, and
- - CMS Holdings holds, through the FMLP, a 35 percent lessor interest in the MCV
Facility.
In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated
financial statements in accordance with Revised FASB Interpretation No. 46. For
additional details, see Note 11, Implementation of New Accounting Standards.
Our consolidated retained earnings include undistributed earnings from the MCV
Partnership, which at June 30, 2004 are $246 million and at June 30, 2003 are
$243 million.
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 capacity payments
made on the basis of availability that may be billed by the MCV Partnership at a
maximum 98.5 percent availability level.
Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $13 million at June 30, 2004 and $40 million at June 30, 2003.
We expect the PPA liability to be depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004 will be
charged to the PPA liability, with the remaining portion charged to operating
expense as a result of our 49 percent ownership in the MCV Partnership. We will
expense all cash underrecoveries directly to income once the PPA liability is
depleted. If the MCV Facility's generating availability remains at the maximum
98.5 percent level, our cash underrecoveries associated with the PPA could be as
follows:
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In Millions
- -----------------------------------------------------------------------
2004 2005 2006 2007
- -----------------------------------------------------------------------
Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
=======================================================================
Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV's Partnership's financial performance and our investment
in the MCV Partnership is and will be affected adversely.
Under the PPA, variable energy payments to the MCV Partnership are based on the
cost of coal burned at our coal plants and our operation and maintenance
expenses. However, the MCV Partnership's costs of producing electricity are tied
to the cost of natural gas. Because natural gas prices have increased
substantially in recent years and the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 2007, we expect to
claim relief under the regulatory out provision in the PPA, limiting our
capacity and fixed energy payments to the MCV Partnership to the amount
collected from our customers. The MPSC's future actions on the capacity and
fixed energy payments recoverable from customers subsequent to September 2007
may affect negatively the earnings of the MCV Partnership and the value of our
investment in the MCV Partnership.
Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC
that is intended to help conserve natural gas and thereby improve our investment
in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The RCP will reduce the MCV Facility's annual production of electricity and, as
a result, reduce the MCV Facility's consumption of natural gas 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. The amount of PPA capacity and fixed energy payments recovered from
retail
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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. Presently, we
are in settlement discussions with the parties to the RCP filing. However, in
July 2004, several qualifying facilities filed for a stay on the RCP proceeding
in the Ingham County Circuit Court after their previous attempt to intervene on
the proceeding was denied by the MPSC. Hearings on the stay are scheduled for
August 11, 2004. We cannot predict if or when the MPSC will approve the RCP or
the outcome of the Ingham County Circuit Court hearings.
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
20 years and the MPSC's decision in 2007 or beyond related to limiting our
recovery of capacity and fixed energy payments. Natural gas prices have been
volatile historically. Presently, there is no consensus in the marketplace on
the price or range of future prices of natural gas. Even with an approved RCP,
if gas prices continue at present levels or increase, the economics of operating
the MCV Facility may be adverse enough to require us to recognize an impairment
of our investment in the MCV Partnership. We presently cannot predict the impact
of these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
Decommissioning funding practices approved by the MPSC require us to file a
report on the adequacy of funds for decommissioning at three-year intervals. We
prepared and filed updated cost estimates for each plant on March 31, 2004.
Excluding additional costs for spent nuclear fuel storage, due to the DOE's
failure to accept this spent nuclear fuel on schedule, these reports show a
decommissioning cost of $361 million for Big Rock and $868 million for
Palisades. Since Big Rock is currently in the process of being decommissioned,
the estimated cost includes historical expenditures in nominal dollars and
future costs in 2003 dollars, with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding
the decommissioning trust funds for both sites. In December 2000, funding of the
Big Rock trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. The MPSC order set the annual
decommissioning surcharge for Palisades at $6 million through 2007. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
However, based on current projections, the current levels of funds provided by
the trusts are not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
in "Nuclear Matters".
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We will also seek additional relief from the MPSC.
In the case of Big Rock, excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept this spent fuel on schedule, we are currently
projecting that the level of funds provided by the trust will fall short of the
amount needed to complete the decommissioning by $25 million. At this point in
time, we plan to provide the additional amounts needed from our corporate funds
and, subsequent to the completion of radiological decommissioning work, seek
recovery of such expenditures at the MPSC. We cannot predict how the MPSC will
rule on our request.
In the case of Palisades, again excluding additional nuclear fuel storage costs
due to the DOE's failure to accept this spent fuel on schedule, we have
concluded that the existing surcharge needs to be increased to $25 million
annually, beginning January 1, 2006, and continue through 2011, our current
license expiration date. In June 2004, we filed an application with the MPSC
seeking approval to increase the surcharge for recovery of decommissioning costs
related to Palisades beginning in 2006. We cannot predict how the MPSC will rule
on our request.
NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. The restoration project is on
schedule to return approximately 530 acres of the site, including the area
formerly occupied by the nuclear plant, to a natural setting for unrestricted
use in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
The NRC and the Michigan Department of Environmental Quality continue to find
all decommissioning activities at Big Rock are being performed in accordance
with applicable regulations including license requirements.
Palisades: In March 2004, the NRC completed its end-of-cycle plant performance
assessment of Palisades. The assessment for Palisades covered the period from
January 1, 2003 through December 31, 2003. The NRC determined that Palisades was
operated in a manner that preserved public health and safety and fully met all
cornerstone objectives. As of June 2004, all inspection findings were classified
as having very low safety significance and all performance indicators indicated
performance at a level requiring no additional oversight. Based on the plant's
performance, only regularly scheduled inspections are planned through September
2005.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of June
30, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled
to load additional dry casks this summer in order to continue operation.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE
was to begin accepting deliveries of spent nuclear fuel for disposal by January
1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
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There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. In July 2004, the DOE filed an amended answer and motion to
dismiss the complaint. 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. We expect that
the DOE will submit, by December 2004, an application to the NRC for a license
to begin construction of the repository. The application and review process is
estimated to take several years.
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council,
the Public Interest Research Group in Michigan, and the Michigan Consumer
Federation filed a complaint with the MPSC, which was served on us by the MPSC
in April 2003. The complaint asks the MPSC to initiate a generic investigation
and contested case to review all facts and issues concerning costs associated
with spent nuclear fuel storage and disposal. The complaint seeks a variety of
relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric
Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
We are unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $27 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily
injury and off-site property damage resulting from a nuclear hazard for up to
approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide program where owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $10
million.
We also maintain insurance under a program that covers tort claims for bodily
injury to nuclear workers caused by nuclear hazards. The policy contains a $300
million nuclear industry aggregate limit. Under a previous insurance program
providing coverage for claims brought by nuclear workers, we remain responsible
for a maximum assessment of up to $6 million.
Big Rock remains insured for nuclear liability by a combination of insurance and
a NRC indemnity totaling $544 million and a nuclear property insurance policy
from NEIL.
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Insurance policy terms, limits, and conditions are subject to change during the
year as we renew our policies.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2005, and total an
estimated $147 million. Our coal transportation contracts expire through 2007,
and total an estimated $108 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is not finalized at
this time, we believe that it will be within the historic 60 to 90 percent
range.
Power Supply, Capacity, and Transmission: As of June 30, 2004, 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. These contracts require monthly
capacity payments based on the plants' availability or deliverability. These
payments for 2004 through 2030 total an estimated $3.033 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant was not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.
CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial costs
at a number of sites under the Michigan Natural Resources and Environmental
Protection Act, a Michigan statute that covers environmental activities
including remediation. These sites include 23 former manufactured gas plant
facilities. We operated the facilities on these sites for some part of their
operating lives. For some of these sites, we have no current ownership or may
own only a portion of the original site. We have completed initial
investigations at the 23 sites. We will continue to implement remediation plans
for sites where we have received MDEQ remediation plan approval. We will also
work toward resolving environmental issues at sites as studies are completed.
We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-year average of U.S. Treasury bond rates reduced for increases in the
consumer price index. We expect to fund most of these costs through insurance
proceeds and through the MPSC approved rates charged to our customers. As of
June 30, 2004, we have recorded a regulatory liability of $42 million, net of
$41 million of expenditures incurred to date, and a regulatory asset of $66
million. Any significant change in assumptions, such as an increase in the
number of sites, different remediation techniques, nature and extent of
contamination, and legal and regulatory requirements, could affect our estimate
of remedial action costs.
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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.
GCR YEAR 2002-2003: 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 underrecovered gas costs using a roll-in
methodology. The roll-in methodology incorporates the GCR underrecovery 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 2002-2003 GCR case.
Their positions were that not all of our gas purchasing decisions were prudent
during April 2002 through March 2003 and they proposed disallowances. In 2003,
we reserved $11 million for a settlement agreement associated with the 2002-2003
GCR disallowance. Interest on the disallowed amount from April 1, 2003 through
February 2004, at Consumers' authorized rate of return, increased the cost of
the settlement by $1 million. The interest was recorded as an expense in 2003.
In February 2004, the parties in the case reached a settlement agreement that
resulted in a GCR disallowance of $11 million for the GCR period. The settlement
agreement was approved by the MPSC in March 2004. The disallowance is included
in our 2003-2004 GCR reconciliation filed in June 2004.
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. The second quarter GCR adjustment resulted in a GCR ceiling
price of $6.57. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement, which included a quarterly mechanism for setting a GCR
ceiling price. The mechanism did not change the current ceiling price of $6.57.
Actual gas costs and revenues will be subject to an annual reconciliation
proceeding. Our GCR factor for the billing month of August is $6.39 per mcf.
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
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effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim order,
Consumers agreed to restrict dividend payments to its parent company, CMS
Energy, to a maximum of $190 million annually during the period of 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,
which was supported by the MPSC Staff and the ALJ further recommended that the
application be dismissed. In response to the Proposal for Decision, the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order that reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
The June 2001 depreciation case 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, would result in an annual increase of $12 million in depreciation
expense based on December 2002 plant balances. In June 2004, the ALJ issued a
Proposal for Decision recommending adoption of the Michigan Attorney General's
proposal to reduce our annual depreciation expense by $52 million. In response
to the Proposal for Decision, the parties filed exceptions and are expected to
file replies to exceptions. In our exceptions, we proposed alternative
depreciation rates that would result in an annual decrease of $7 million in
depreciation expense. The MPSC is not bound by the ALJ's recommendation and will
review the exceptions and replies to exceptions prior to issuing an order on
final depreciation rates.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order, the FERC
indicated that its December 2003 order was in error. It directed us to file
within 30 days a fair and equitable title-tracking fee and to make refunds, with
interest, to customers based on the difference between the accepted fee and the
fee paid. In response to the FERC's April 2004 order, we filed a Request for
Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further
Consideration in June 2004. We expect the FERC to issue an order on the merits
of this proceeding in the third quarter of 2004. We believe that with respect to
the FERC jurisdictional transportation, we have not charged any customers title
transfer fees, so no refunds are due. At this time, we cannot predict the
outcome of this proceeding.
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OTHER UNCERTAINTIES
INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan Circuit
Court in July 2003 against CMS Energy, Enterprises and APT. Integrum alleges
several causes of action against APT, CMS Energy, and Enterprises in connection
with an offer by Integrum to purchase the CMS Pipeline Assets. In addition to
seeking unspecified money damages, Integrum is seeking an order enjoining CMS
Energy and Enterprises from selling, and APT from purchasing, the CMS Pipeline
Assets and an order of specific performance mandating that CMS Energy,
Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT and
Integrum. A certain officer and director of Integrum is a former officer and
director of CMS Energy, Consumers, and their subsidiaries. The individual was
not employed by CMS Energy, Consumers, or their subsidiaries when Integrum made
the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed
a motion to change venue from Wayne County to Jackson County, which was granted.
The parties are now awaiting transfer of the file from Wayne County to Jackson
County. CMS Energy and Enterprises believe that Integrum's claims are without
merit. CMS Energy and Enterprises intend to defend vigorously against this
action but they cannot predict the outcome of this litigation.
CMS GENERATION-OXFORD TIRE RECYCLING: In an administrative order, the California
Regional Water Control Board of the state of California named CMS Generation as
a potentially responsible party for the clean up of the waste from the fire that
occurred in September 1999 at the Filbin Tire Pile, which the state claims was
owned by Oxford Tire Recycling of North Carolina, Inc. CMS Generation reached a
settlement with the state, which the court approved, pursuant to which CMS
Generation paid the state $5.5 million, $1.6 million of which it had paid the
state prior to the settlement. CMS Generation continues to negotiate to have the
insurance company pay a portion of the settlement amount, as well as a portion
of its attorney fees.
At the request of the DOJ in San Francisco, CMS Energy and other parties
contacted by the DOJ in San Francisco entered into separate Tolling Agreements
with the DOJ in San Francisco in September 2002. The Tolling Agreement stops the
running of any statute of limitations during the ninety-day period between
September 13, 2002 and (through several extensions of the tolling period) March
30, 2004, to facilitate settlement discussions between all the parties in
connection with federal claims arising from the fire at the Filbin Tire Pile. On
September 23, 2002, CMS Energy received a written demand from the U.S. Coast
Guard for reimbursement of approximately $3.5 million in costs incurred by the
U.S. Coast Guard in fighting the fire. It is CMS Energy's understanding that
these costs, together with any accrued interest, are the sole basis of any
federal claims. CMS Energy has entered into a consent judgment with the U.S.
Coast Guard to settle this matter for $475,000 that is awaiting final court
approval.
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD)
presented DIG with a change order to their construction contract and filed an
action in Michigan state court claiming damages in the amount of $110 million,
plus interest and costs, which DFD states represents the cumulative amount owed
by DIG for delays DFD believes DIG caused and for prior change orders that DIG
previously rejected. DFD also filed a construction lien for the $110 million.
DIG, in addition to drawing down on three letters of credit totaling $30 million
that it obtained from DFD, has filed an arbitration claim against DFD asserting
in excess of an additional $75 million in claims against DFD. The judge in the
Michigan state court case entered an order staying DFD's prosecution of its
claims in the court case and permitting the arbitration to proceed. DFD has
appealed the decision by the judge in the Michigan state court case to stay the
litigation. DIG will continue to defend itself vigorously and pursue its claims.
DIG cannot predict the outcome of this matter.
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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 sought
damages "in excess of $25,000" and injunctive relief based upon allegations of
excessive noise and vibration created by operation of the power plant. The first
amended complaint was filed on behalf of six named plaintiffs, all alleged to be
adjacent or nearby residents or property owners. The damages alleged were injury
to persons and property of the landowners. Certification of a class of
"potentially thousands" who have been similarly affected was requested. The
parties entered into a settlement agreement on June 25, 2004, whereby DIG will
remediate the sound emitted from various pieces of plant equipment to a level
below the ambient noise level and pay a substantial portion of plaintiffs'
attorney fees and costs. A class will be certified for settlement purposes only
and remediation will take approximately 280 days. DIG is seeking proposals for
remediation and testing but DIG cannot predict the cost associated with the
settlement 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. Terra has appealed this judgment. Enterprises has an indemnity
obligation with regard to losses to Terra that might result from this
litigation.
GASATACAMA: On March 24, 2004, the Argentine Government authorized the
restriction of exports of natural gas to Chile giving priority to domestic
demand in Argentina. This restriction could have a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-fired power plant is located in
Chile and uses Argentine gas for fuel. On April 21, 2004, Argentina and Bolivia
signed an agreement in which Bolivian gas producers agreed to supply natural gas
to Argentina for six months. Bolivian gas began flowing to Argentina in mid-June
and will continue to flow through October 2004. The government of Argentina has
also approved an agreement with Argentine producers that should help solve
Argentina's long-term gas shortage problems. Additionally, on May 11, 2004, the
Argentine Government announced the creation of a state-owned and operated energy
company, which intends to make investments in domestic natural gas and
electricity infrastructure projects. Currently, management of GasAtacama is
working with government officials of Chile and Argentina, as well as meeting
with its electricity customers and gas producers, to attempt to mitigate the
impact of this situation. At this point, it is not possible to predict the
outcome of these events and their effect on the earnings of GasAtacama.
ARGENTINA ECONOMIC SITUATION: In January 2002, the Republic of Argentina enacted
the Public Emergency and Foreign Exchange System Reform Act. This law repealed
the fixed exchange rate of one U.S. dollar to one Argentine peso, converted all
dollar-denominated utility tariffs and energy contract obligations into pesos at
the same one-to-one exchange rate, and directed the President of Argentina to
renegotiate such tariffs.
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Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect
that these non-cash charges reduce substantially the risk of further material
balance sheet impacts when combined with anticipated proceeds from international
arbitration currently in progress, political risk insurance, and the eventual
sale of these assets. At June 30, 2004, the net foreign currency loss due to the
unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 2.97
pesos per U.S. dollar was $263 million. This amount also reflects the effect of
recording, at December 31, 2002, U.S. income taxes on temporary differences
between the book and tax bases of foreign investments, including the foreign
currency translation associated with our Argentine investments.
LEONARD FIELD DISPUTE: Pursuant to a Consent Judgment entered in Oakland County,
Michigan Circuit Court in September 2001, CMS Gas Transmission had 18 months to
extract approximately one bcf of pipeline quality natural gas held in the
Leonard Field in Addison Township. The Consent Judgment provided for an
extension of that period upon certain circumstances. CMS Gas Transmission has
complied with the requirements of the Consent Judgment. Addison Township filed a
lawsuit in Oakland County Circuit Court against CMS Gas Transmission in February
2004 alleging the Leonard Field was discharging odors in violation of the
Consent Judgment. Pursuant to a Stipulated Order entered April 1, 2004, CMS Gas
Transmission agreed to certain undertakings to address the odor complaints and
further agreed to temporarily cease operations at the Leonard Field during the
month of April 2004, the last month provided for in the Consent Judgment. Also,
Addison Township was required to grant CMS Gas Transmission an extension to
withdraw its natural gas if certain conditions were met. Addison Township denied
CMS Gas Transmission's request for an extension on April 5, 2004. CMS Gas
Transmission is pursuing its legal remedies and filed a complaint against
Addison Township in June 2004. CMS Gas Transmission cannot predict the outcome
of this matter, and unless an extension is provided, it will be unable to
extract approximately 500,000 mcf of gas remaining in the Leonard Field.
CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase agreement,
CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La
Plata, Argentina. As a result of the so-called "Emergency Laws," payments by YPF
Repsol under the power purchase agreement have been converted to pesos at the
exchange rate of one U.S. dollar to one Argentine peso. Such payments are
currently insufficient to cover CMS Ensenada's operating costs, including
quarterly debt service payments to the Overseas Private Investment Corporation
(OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which
Enterprises has guaranteed CMS Ensenada's debt service payments to the OPIC up
to an amount which is in dispute, but which Enterprises estimated to be
approximately $9 million at June 30, 2004. Following a payment made to the OPIC
in July 2004, Enterprises now believes this amount to be approximately $7
million.
An interim arrangement, which provided CMS Ensenada with payments under the
power purchase agreement that covered most, but not all, of CMS Ensenada's
operating costs, was agreed to with YPF Repsol in 2002 but expired on December
31, 2003. Efforts to negotiate a new agreement with YPF Repsol have been
unsuccessful.
As a result, CMS Ensenada initiated two legal actions: (1) an ex parte action in
the Argentine commercial
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CMS Energy Corporation
courts, requesting injunctive relief in the form of a temporary increase in the
payments by YPF Repsol under the power purchase agreement that would allow CMS
Ensenada to continue to operate while seeking a final and permanent resolution;
and (2) an arbitration administered by the International Chamber of Commerce
seeking a ruling that the application of the Emergency Laws to the power
purchase agreement is unconstitutional, or, alternatively, that the arbitral
panel reestablish the economic equilibrium of the power purchase agreement, as
required by the Emergency Laws taking into account that a significant portion of
CMS Ensenada's operating costs are payable in U.S. dollars. In April 2004, the
injunctive relief was granted on appeal, but in an amount lower than requested
by CMS Ensenada. The injunctive relief expired at the end of May, but the court
recently extended the term of relief until the end of the arbitration.
OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in Argentina
received notice from various Argentine provinces claiming stamp taxes and
associated penalties and interest arising from various gas transportation
transactions. Although these claims total approximately $24 million, we believe
the claims are without merit and will continue to contest them vigorously.
CMS Generation does not currently expect to incur significant capital costs at
its power facilities for compliance with current U.S. environmental regulatory
standards.
In addition to the matters disclosed within this Note, Consumers and certain
other subsidiaries of CMS Energy are parties to certain lawsuits and
administrative proceedings before various courts and governmental agencies
arising from the ordinary course of business. These lawsuits and proceedings may
involve personal injury, property damage, contractual matters, environmental
issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this
Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
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4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
- -----------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -----------------------------------------------------------------------------------------------
CMS ENERGY CORPORATION
Senior notes $ 2,063 $ 2,063
General term notes 236 496
Extendible tenor rate adjusted securities and other 186 187
------------- -----------------
Total - CMS Energy Corporation 2,485 2,746
------------- -----------------
CONSUMERS ENERGY COMPANY
First mortgage bonds 1,483 1,483
Senior notes 1,254 1,254
Bank debt and other 468 469
Securitization bonds 412 426
FMLP debt 411 -
------------- -----------------
Total - Consumers Energy Company 4,028 3,632
------------- -----------------
OTHER SUBSIDIARIES 200 191
------------- -----------------
Principal amounts outstanding 6,713 6,569
Current amounts (860) (509)
Net unamortized discount (37) (40)
- -----------------------------------------------------------------------------------------------
Total consolidated long-term debt $ 5,816 $ 6,020
===============================================================================================
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At June 30, 2004, long-term debt of the FMLP consists of:
In Millions
- ------------------------------------------------------------------
Maturity 2004
- ------------------------------------------------------------------
11.75% subordinated secured notes 2005 $185
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
- ------------------------------------------------------------------
Total amount outstanding $411
==================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV
Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy
and Consumers.
DEBT MATURITIES: At June 30, 2004, the aggregate annual maturities for long-term
debt for the six months ending December 31, 2004 and the next four years are:
In Millions
- -----------------------------------------------------
Payments Due
- -----------------------------------------------------
2004 2005 2006 2007 2008
- ----------------------------------------------------
Long-term debt $342 $789 $549 $550 $1,053
=====================================================
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REGULATORY AUTHORIZATION FOR FINANCINGS: Effective July 1, 2004, Consumers
received new FERC authorization to issue or guarantee up to $1.1 billion of
short-term securities and up to $1.1 billion of short-term first mortgage bonds
as collateral for such short-term securities. Effective July 1, 2004, Consumers
received new FERC authorization to issue up to $1 billion of long-term
securities for refinancing or refunding purposes, $1.5 billion of long-term
securities for general corporate purposes, and $2.5 billion of long-term first
mortgage bonds to be issued solely as collateral for other long-term securities.
SHORT-TERM FINANCINGS: At June 30, 2004, CMS Energy had a $190 million secured
revolving credit facility with banks and a $185 million cash-collateralized
letter of credit facility with banks. At June 30, 2004, all of the $190 million
is available for general corporate purposes and $17 million is available for
letters of credit. At June 30, 2004, Consumers had a $400 million secured
revolving credit facility with banks. At June 30, 2004, $24 million of letters
of credit are issued and outstanding under this facility and $376 million is
available for general corporate purposes, working capital, and letters of
credit. The MCV Partnership had a $50 million working capital facility
available.
As of August 3, 2004, CMS Energy obtained an amended and restated $300 million
secured revolving credit facility to replace both the $190 million and the $185
million facilities. As of August 3, 2004, Consumers obtained an amended and
restated $500 million secured revolving credit facility to replace their $400
million facility. The amended facilities carry three-year terms and provide for
lower interest rates.
FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds by a mortgage
and lien on substantially all of its property. Its ability to issue and sell
securities is restricted by certain provisions in the first mortgage bond
indenture, its articles of incorporation, and the need for regulatory approvals
under federal law.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. As of June 30, 2004, capital
lease obligations totaled $64 million. In order to obtain permanent financing
for the MCV Facility, the MCV Partnership entered into a sale and lease back
agreement with a lessor group, which includes the FMLP, for substantially all of
the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV
Partnership accounted for the transaction as a financing arrangement. As of June
30, 2004, finance lease obligations totaled $317 million, which represents the
third-party portion of the MCV Partnership's finance lease obligation.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. We sold no receivables at June 30, 2004 and we sold $50 million at
June 30, 2003. The Consolidated Balance Sheets exclude these sold amounts from
accounts receivable. We continue to service the receivables sold. The purchaser
of the receivables has no recourse against our other assets for failure of a
debtor to pay when due and the purchaser has no right to any receivables not
sold. No gain or loss has been recorded on the receivables sold and we retain no
interest in the receivables sold.
Certain cash flows received from and paid to us under our accounts receivable
sales program are shown below:
In Millions
- -------------------------------------------------------------------------------------
Six Months Ended June 30 2004 2003
- -------------------------------------------------------------------------------------
Proceeds from sales (remittance of collections) under the program $ (297) $ (275)
Collections reinvested under the program $ 2,645 $2,459
=====================================================================================
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DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at
June 30, 2004, Consumers had $396 million of unrestricted retained earnings
available to pay common stock dividends. However, covenants in Consumers' debt
facilities cap common stock dividend payments at $300 million in a calendar
year. Consumers is also under an annual dividend cap of $190 million imposed by
the MPSC during the current interim gas rate relief period. For the six months
ended June 30, 2004, CMS Energy received $105 million of common stock dividends
from Consumers.
Our amended and restated $300 million secured revolving credit facility
restricts payments of dividends on our common stock during a 12-month period to
$75 million, dependent on the aggregate amounts of unrestricted cash and unused
commitments under the facility.
For additional details on the cap on common stock dividends payable during the
current interim gas rate relief period, see Note 3, Uncertainties, "Consumers'
Gas Utility Rate Matters - 2003 Gas Rate Case."
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS
FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: This
Interpretation became effective January 2003. It describes the disclosure to be
made by a guarantor about its obligations under certain guarantees that it has
issued. At the beginning of a guarantee, it requires a guarantor to recognize a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as warranties,
derivatives, or guarantees between either parent and subsidiaries or
corporations under common control, although disclosure of these guarantees is
required. For contracts that are within the recognition and measurement
provision of this Interpretation, the provisions were to be applied to
guarantees issued or modified after December 31, 2002.
The following table describes our guarantees at June 30, 2004:
In Millions
- -------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount(b) Provision(c)
- -------------------------------------------------------------------------------------------------------
Indemnifications from asset sales and
other agreements(a) Various Various $ 1,147 $ 4 $ -
Letters of credit Various Various 235 - -
Surety bonds and other indemnifications Various Various 28 - -
Other guarantees Various Various 199 - -
Nuclear insurance retrospective premiums Various Various 134 - -
=======================================================================================================
(a) The majority of this amount arises from routine provisions in stock and
asset sales agreements under which we indemnify the purchaser for losses
resulting from events such as failure of title to the assets or stock sold by us
to the purchaser. We believe the likelihood of a loss for any remaining
indemnifications to be remote.
(b) The carrying amount represents the fair market value of guarantees and
indemnities recorded on our balance sheet that are entered into subsequent to
January 1, 2003.
(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
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The following table provides additional information regarding our guarantees:
Events That Would Require
Guarantee Description How Guarantee Arose Performance
- -------------------------------------------------------------------------------------------------
Indemnifications from asset Stock and asset sales Findings of misrepresentation,
sales and other agreements agreements 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
Other guarantees Normal operating activity Nonperformance or non-payment
by a subsidiary under a
related contract
Nuclear insurance retrospective Normal operations of nuclear Call by NEIL and
premiums plants Price-Anderson Act for nuclear
incident
==================================================================================================
We have entered into typical tax indemnity agreements in connection with a
variety of transactions including transactions for the sale of subsidiaries and
assets, equipment leasing, and financing agreements. These indemnity agreements
generally are not limited in amount and, while a maximum amount of exposure
cannot be identified, the 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 $462 million as of June 30, 2004. We monitor and approve
these obligations and believe it is unlikely that we would be required to
perform or otherwise incur any material losses associated with the above
obligations. The off-balance sheet commitments expire as follows:
Commercial Commitments In Millions
- ------------------------------------------------------------------------------
Commitment Expiration
- ------------------------------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 Beyond
- ------------------------------------------------------------------------------
Off-balance sheet:
Guarantees $ 199 $ 6 $ 36 $ 5 $ - $ - $ 152
Surety bonds and other 28 1 - - - - 27
indemnifications (a)
Letters of Credit (b) 235 23 184 5 5 5 13
- -----------------------------------------------------------------------------
Total $ 462 $ 30 $220 $ 10 $ 5 $ 5 $ 192
=============================================================================
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.
(b) At June 30, 2004, we had $169 million of cash held as collateral for letters
of credit. The cash that collateralizes the letters of credit is included in
Restricted cash on the Consolidated Balance Sheets.
CONTINGENTLY CONVERTIBLE SECURITIES: At June 30, 2004, we have contingently
convertible debt and equity securities outstanding. The significant terms of
these securities are as follows:
Convertible Senior Notes: Our $150 million 3.375 percent convertible senior
notes are putable to CMS Energy by the note holders at par on July 15, 2008,
July 15, 2013 and July 15, 2018. The notes are convertible to Common Stock at
the option of the holder if the price of our Common Stock remains at or
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CMS Energy Corporation
above $12.81 per share for 20 of 30 consecutive trading days ending on the last
trading day of a quarter. The $12.81 price per share may be adjusted if there is
a payment or distribution to our Common Stockholders. If conversion were to
occur, the notes would be converted into 14.1 million shares of Common Stock
based on the initial conversion rate.
Convertible Preferred Stock: Our $250 million 4.50 percent cumulative
convertible perpetual preferred stock has a liquidation value of $50.00 per
share. The security is convertible to Common Stock at the option of the holder
if the price of our Common Stock remains at or above $11.87 per share for 20 of
30 consecutive trading days ending on the last trading day of a quarter. On or
after December 5, 2008, we may cause the Preferred Stock to convert into Common
Stock if the closing price of our Common Stock remains at or above $12.86 for 20
of any 30 consecutive trading days. The $11.87 and $12.86 prices per share may
be adjusted if there is a payment or distribution to our Common Stockholders. If
conversion were to occur, the securities would be converted into 25.3 million
shares of Common Stock based on the initial conversion rate.
5: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share
computations.
In Millions, Except Per Share Amounts
- ---------------------------------------------------------------------------------------------------
Restated
Three Months Ended June 30 2004 2003
- ---------------------------------------------------------------------------------------------------
EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income (Loss) from Continuing Operations $ 19 $ (12)
Less Preferred Dividends (3) -
-----------------------------
Income (Loss) from Continuing Operations attributable
to Common Stock - Basic $ 16 $ (12)
Add conversion of Trust Preferred Securities (net of tax) -(a) -(a)
-----------------------------
Income (Loss) from Continuing Operations attributable
to Common Stock - Diluted $ 16 $ (12)
=============================
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.2 144.1
Add conversion of Trust Preferred Securities -(a) -(a)
Add dilutive Stock Options and Warrants 0.5(b) -(b)
-----------------------------
Average Shares - Diluted 161.7 144.1
=============================
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.10 $ (0.08)
Diluted $ 0.10 $ (0.08)
===================================================================================================
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CMS Energy Corporation
In Millions, Except Per Share Amounts
- -----------------------------------------------------------------------------------------------------------
Restated
Six Months Ended June 30 2004 2003
- -----------------------------------------------------------------------------------------------------------
EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income from Continuing Operations $ 17 $ 63
Less Preferred Dividends (6) -
---------------------------------
Income from Continuing Operations attributable
to Common Stock - Basic $ 11 $ 63
Add conversion of Trust Preferred Securities (net of tax) -(a) 5(a)
---------------------------------
Income from Continuing Operations attributable
to Common Stock - Diluted $ 11 $ 68
=================================
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.2 144.1
Add conversion of Trust Preferred Securities -(a) 16.6(a)
Add dilutive Stock Options and Warrants 0.5(b) -(b)
---------------------------------
Average Shares - Diluted 161.7 160.7
=================================
EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.07 $ 0.43
Diluted $ 0.07 $ 0.43
==========================================================================================================
(a) Due to antidilution, the computation of diluted earnings per share excluded
the conversion of Trust Preferred Securities into 4.2 million shares of Common
Stock and a $2.2 million reduction of interest expense, net of tax, for the
three months ended June 30, 2004 and the three months ended June 30, 2003 and a
$4.3 million reduction of interest expense, net of tax, for the six months ended
June 30 2004 and the six months ended June 30, 2003. Effective July 2001, we can
revoke the conversion rights if certain conditions are met.
(b) Since the exercise price was greater than the average market price of the
Common Stock, options and warrants to purchase 5.4 million and 5.1 million
shares of Common Stock were excluded from the computation of diluted EPS for the
three and six months ended June 30, 2004 and the three and six months ended June
30, 2003, respectively.
Computation of diluted earnings per share for the three months and the six
months ended June 30, 2004 excluded conversion of our $150 million 3.375 percent
convertible senior notes and our 5 million shares of 4.50 percent cumulative
convertible preferred stock. Both are "contingently convertible" securities and,
as of June 30, 2004, none of the stated contingencies have been met. For
additional details on these securities, see Note 4, Financings and
Capitalization.
In January 2003, the Board of Directors suspended the payment of common stock
dividends.
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6: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and
current liabilities approximate their fair values because of their short-term
nature. We estimate the fair values of long-term financial instruments based on
quoted market prices or, in the absence of specific market prices, on quoted
market prices of similar instruments or other valuation techniques. The carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of June 30,
2004. These securities represent funds restricted primarily for future lease
payments and are classified as Other Assets on the Consolidated Balance Sheets.
These investments have original maturity dates of approximately one year or less
and, because of their short maturities, their carrying amounts approximate their
fair values. For additional details, see Note 1, Corporate Structure and
Accounting Policies.
In Millions
- ---------------------------------------------------------------------------------------------------------------------------------
June 30 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain(Loss) Cost Value Gain
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term debt (a) $6,676 $6,834 $ (158) $6,594 $6,813 $ (219)
Long-term debt - related parties (b) 684 644 40 - - -
Trust Preferred Securities (b) - - - 883 769 114
Available-for-sale securities:
Nuclear decommissioning (c) 434 559 125 453 553 100
SERP 54 66 12 55 61 6
===============================================================================================================================
(a) Includes a principal amount of $860 million at June 30, 2004 and $532
million at June 30, 2003 relating to current maturities. Settlement of long-term
debt is generally not expected until maturity.
(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities have been deconsolidated as of
December 31, 2003. Company Obligated Trust Preferred Securities totaling $663
million that were previously included in mezzanine equity, have been eliminated
due to deconsolidation and are reflected in Long-term debt - related parties on
the Consolidated Balance Sheets. For additional details, see Note 11,
Implementation of New Accounting Standards. In addition, company obligated Trust
Preferred Securities totaling $220 million have been converted to Common Stock
as of August 2003.
(c) On January 1, 2003, we adopted SFAS No. 143 and began classifying our
unrealized gains and losses on nuclear decommissioning investments as regulatory
liabilities. We previously included 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, futures 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. Risk management contracts
are classified as either trading or other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
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CMS Energy Corporation
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. 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.
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 significant transportation costs that would
be incurred to deliver the power under the contracts to the closest active
energy market at the Cinergy hub in Ohio. If an active market develops in the
future, we may be required to account for these contracts as derivatives. The
mark-to-market impact on earnings related to these contracts could be material
to the financial statements.
Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk and interest rate risk. The following table
reflects the fair value of all contracts requiring derivative accounting:
CMS-88
CMS Energy Corporation
In Millions
- -------------------------------------------------------------------------------------------------------------------------
June 30 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- -------------------------------------------------------------------------------------------------------------------------
Other than trading
Electric - related contracts $ - $ - $ - $ 8 $ - $ (8)
Gas contracts 3 6 3 2 1 (1)
Interest rate risk contracts - (2) (2) - - -
Derivative contracts associated with
Consumers' investment in the MCV
Partnership:
Prior to consolidation - - - - 20 20
After consolidation:
Gas fuel contracts - 80 80 - - -
Gas fuel futures, options, and swaps - 54 54 - - -
Trading
Electric / gas contracts (5) 10 15 - 15 15
Derivative contracts associated with
equity investments in:
Shuweihat - (19) (19) - (39) (39)
Taweelah (35) (19) 16 - (36) (36)
Jorf Lasfar - (10) (10) - (14) (14)
Other - (1) (1) - (4) (4)
=======================================================================================================================
The fair value of our other than trading derivative contracts is included in
Derivative Instruments, Other Assets, or Other Liabilities on the Consolidated
Balance Sheets. The fair value of our trading derivative contracts is included
in either Price Risk Management Assets or Price Risk Management Liabilities on
the Consolidated Balance Sheets. The fair value of derivative contracts
associated with our equity investments is included in Enterprises Investments on
the Consolidated Balance Sheets. The fair value of derivative contracts
associated with our investment in the MCV Partnership for 2003 is included in
Investments - Midland Cogeneration Venture Limited Partnership on the
Consolidated Balance Sheets.
ELECTRIC CONTRACTS: Our electric utility business uses purchased electric call
option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods.
GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt and to reduce
the impact of interest rate fluctuations. Most of our interest rate swaps are
designated as cash flow hedges. As such, we record changes 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 changes in the fair value of these
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CMS Energy Corporation
contracts in Other income.
The following table reflects the outstanding floating-to-fixed interest rates
swaps:
In Millions
- ---------------------------------------------------------------------------------
Floating to Fixed Notional Maturity Fair
Interest Rate Swaps Amount Date Value
- ---------------------------------------------------------------------------------
June 30, 2004 $ 26 2005-2006 $ (2)
June 30, 2003 3 2006 -
=================================================================================
Notional amounts reflect the volume of transactions but do not represent the
amount exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not necessarily reflect our exposure to credit or market
risks. The weighted average interest rate associated with outstanding swaps was
approximately 7.3 percent at June 30, 2004 and 9.0 percent at June 30, 2003.
There was no ineffectiveness associated with any of the interest rate swaps that
qualified for hedge accounting treatment. As of June 30, 2004, we have recorded
an unrealized loss of $1 million, net of tax, in accumulated other comprehensive
income related to interest rate risk contracts accounted for as cash flow
hedges. We expect to reclassify $1 million of this amount as a decrease to
earnings during the next 12 months primarily to offset the variable-rate
interest expense on hedged debt.
Certain equity method investees have issued interest rate swaps to hedge the
risk associated with variable-rate debt, as listed in the table under
"Derivative Instruments" within this Note. These instruments are not included in
this analysis, but can have an impact on financial results. The accounting for
these instruments depends on whether they qualify for cash flow hedge accounting
treatment. The interest rate swap held by Taweelah and certain interest rate
swaps held by Shuweihat do not qualify as cash flow hedges, and therefore, we
record our proportionate share of the change in the fair value of these
contracts in Earnings from Equity Method Investees. The remainder of these
instruments do qualify as cash flow hedges, and we record our proportionate
share of the change in the fair value of these contracts in accumulated other
comprehensive income.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP:
Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy
gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership
believes that its long-term natural gas contracts, which do not contain volume
optionality, qualify under SFAS No. 133 for the normal purchases and normal
sales exception. Therefore, these contracts are currently not recognized at fair
value on the balance sheet. Should significant changes in the level of the MCV
Facility operational dispatch or purchases of long-term gas occur, the MCV
Partnership would be required to re-evaluate its accounting treatment for these
long-term gas contracts. This re-evaluation may result in recording
mark-to-market activity on some contracts, which could add to earnings
volatility.
At June 30, 2004, the MCV Partnership had six long-term gas contracts that
contained both an option and forward component. Because of the option component,
these contracts do not qualify for the normal purchases and sales exception and
are accounted for as derivatives, with changes in fair value recorded in
earnings each quarter. The MCV Partnership expects future earnings volatility on
these six contracts, since gains or losses will be recorded on a quarterly basis
during the remaining life of approximately four years for these gas contracts.
For the six months ended June 30, 2004, the MCV Partnership recorded in Fuel for
electric generation a $6 million net gain in earnings associated with these
contracts.
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CMS Energy Corporation
Gas Fuel Futures, Options, and Swaps: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. The MCV Partnership enters into natural gas futures contracts, option
contracts, and over-the-counter swap transactions in order to hedge against
unfavorable changes in the market price of natural gas in future months when gas
is expected to be needed. These financial instruments are being used principally
to secure anticipated natural gas requirements necessary for projected electric
and steam sales, and to lock in sales prices of natural gas previously obtained
in order to optimize the MCV Partnership's existing gas supply, storage, and
transportation arrangements.
These financial instruments are accounted for as derivatives under SFAS No. 133.
The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. The MCV Partnership also engages in cost mitigation
activities to offset the fixed charges the MCV Partnership incurs in operating
the MCV Facility. These cost mitigation activities include the use of futures
and options contracts to purchase and/or sell natural gas to maximize the use of
the transportation and storage contracts when it is determined that they will
not be needed for the MCV Facility operation. Although these cost mitigation
activities do serve to offset the fixed monthly charges, these cost mitigation
activities are not considered a normal course of business for the MCV
Partnership and do not qualify as hedges under SFAS No. 133. Therefore, the
mark-to-market gains and losses from these cost mitigation activities are
recorded in earnings each quarter.
For the six months ended June 30, 2004, the MCV Partnership has recorded an
unrealized gain of $24 million in other comprehensive income on those futures
contracts that qualify as cash flow hedges, which resulted in a cumulative net
gain of $55 million in other comprehensive income as of June 30, 2004. This
balance represents natural gas futures, options, and swaps with maturities
ranging from July 2004 to December 2009, of which $34 million of this gain is
expected to be reclassified as an increase to earnings within the next 12
months. As of June 30, 2004, Consumers' pretax proportionate share of the MCV
Partnership's $55 million net gain recorded in other comprehensive income is $27
million, of which $17 million is expected to be reclassified as an increase to
earnings within the next 12 months. In addition, for the six months ended June
30, 2004, the MCV Partnership has recorded a net gain of $16 million in earnings
from hedging activities related to natural gas requirements for the MCV Facility
operations and a net gain of $1 million in earnings from cost mitigation
activities.
TRADING ACTIVITIES: Through December 31, 2002, our wholesale power and gas
trading activities were accounted for under the mark-to-market method of
accounting in accordance with EITF Issue No. 98-10. Effective January 1, 2003,
EITF Issue No. 98-10 was rescinded and replaced by EITF Issue No. 02-03. As a
result, only energy contracts that meet the definition of a derivative under
SFAS No. 133 are to 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 the three month period ended March 31, 2003.
During 2003, we sold a majority of our wholesale natural gas and power-trading
portfolio, and exited the energy services and retail customer choice business.
As a result, our trading activities have been significantly reduced. Our current
activities center around entering into energy contracts that are related to the
activities considered to be an integral part of our ongoing operations. The
intent of holding these energy contracts is to optimize the financial
performance of our owned generating assets and to fulfill contractual
obligations. These contracts are classified as trading activities in accordance
with EITF No. 02-03 and are accounted for using the criteria defined in SFAS No.
133. Energy trading contracts that meet the definition of a derivative are
recorded as assets or liabilities in the financial statements at the fair value
of the contracts. Gains or losses arising from changes in fair value of these
contracts are recognized in earnings as a component of operating revenues 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
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CMS Energy Corporation
contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.
In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to our counterparties.
Determination of our counterparties' credit quality is based upon a number of
factors, including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option contracts
to hedge certain receivables, payables, long-term debt, and equity value
relating to foreign investments. The purpose of our foreign currency hedging
activities is to protect the company from the risk associated with adverse
changes in currency exchange rates that could affect cash flow materially. These
contracts would not subject us to risk from exchange rate movements because
gains and losses on such contracts offset losses and gains, respectively, on
assets and liabilities being hedged. At June 30, 2004 and June 30, 2003, we had
no outstanding foreign exchange contracts.
As of June 30, 2004, Taweelah, one of our equity method investees, held a
foreign exchange contract that hedged the foreign currency risk associated with
payments to be made under an operating and maintenance service agreement. This
contract did not qualify as a cash flow hedge; and therefore, we record our
proportionate share of the change in the fair value of the contract in Earnings
from Equity Method Investees.
7: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after
June 30, 2003,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.
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CMS Energy Corporation
As of June 30, 2004, we have recorded a prepaid pension asset of $398 million,
$20 million of which is in Other current assets on our Consolidated Balance
Sheet.
OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers
recorded a liability of $466 million for the accumulated transition obligation
and a corresponding regulatory asset for anticipated recovery in utility rates.
For additional details, see Note 1, Corporate Structure and Accounting Policies,
"Utility Regulation." In 1994, the MPSC authorized recovery of the electric
utility portion of these costs over 18 years and in 1996, the MPSC authorized
recovery of the gas utility portion of these costs over 16 years. We have made
contributions of $33 million to our 401(h) and VEBA trust funds in 2004. We plan
to make additional contributions of $30 million in 2004.
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
- ------------------------------------------------------------------------------------------------------------------
Pension
Three Months Ended Six Months Ended
- ------------------------------------------------------------------------------------------------------------------
June 30 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------
Service cost $ 9 $ 9 $ 19 $ 19
Interest expense 18 18 36 37
Expected return on plan assets (27) (21) (54) (41)
Amortization of:
Net loss 4 3 7 5
Prior service cost 2 2 3 4
-------------------------------------------
Net periodic pension cost $ 6 $ 11 $ 11 $ 24
==================================================================================================================
In Millions
- -----------------------------------------------------------------------------------------------------------------
OPEB
Three Months Ended Six Months Ended
- -----------------------------------------------------------------------------------------------------------------
June 30 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------
Service cost $ 5 $ 6 $ 10 $ 11
Interest expense 14 16 29 33
Expected return on plan assets (12) (10) (24) (21)
Amortization of:
Net loss 3 5 5 10
Prior service cost (2) (2) (5) (4)
-------------------------------------------
Net periodic postretirement benefit cost $ 8 $ 15 $ 15 $ 29
=================================================================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the
Act) was signed into law in December 2003. The Act establishes a prescription
drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is
exempt from federal taxation, to sponsors of retiree health care benefit plans
that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. The reduction of $24 million includes $7
million in capitalized OPEB costs. For additional details, see Note 11,
Implementation of New Accounting Standards.
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CMS Energy Corporation
8: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we account for
certain investments in other companies, partnerships and joint ventures by the
equity method of accounting in accordance with APB Opinion No. 18. Net income
from these investments included undistributed earnings of $38 million for the
three months ended June 30, 2004 and $36 million for the three months ended June
30, 2003 and $44 million for the six months ended June 30, 2004 and $69 million
for the six months ended June 30, 2003. The most significant of these
investments is our 50 percent interest in Jorf Lasfar, our 45 percent interest
in SCP, and our 40 percent interest in Taweelah. Summarized income statement
information for our most significant equity method investments is as follows:
Income Statement Data
In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Three Months Ended June 30, 2004 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------
Operating revenue $ 102 $ 18 $ 26 $ 146
Operating expenses (56) (5) (12) (73)
-----------------------------------------------
Operating income 46 13 14 73
Other income (expense), net (14) (5) 33 14
-----------------------------------------------
Net income $ 32 $ 8 $ 47 $ 87
=========================================================================================================
In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Three Months Ended June 30, 2003 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------
Operating revenue $ 91 $ 13 $ 25 $ 129
Operating expenses (43) (4) (9) (56)
-----------------------------------------------
Operating income 48 9 16 73
Other expense, net (5) (5) (24) (34)
-----------------------------------------------
Net income (loss) $ 43 $ 4 $ (8) $ 39
=========================================================================================================
Income Statement Data
In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Six Months Ended June 30, 2004 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------
Operating revenue $ 212 $ 37 $ 48 $ 297
Operating expenses (121) (10) (22) (153)
-----------------------------------------------
Operating income 91 27 26 144
Other income (expense), net (29) (12) 8 (33)
-----------------------------------------------
Net income $ 62 $ 15 $ 34 $ 111
=========================================================================================================
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CMS Energy Corporation
In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Six Months Ended June 30, 2003 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------
Operating revenue $ 181 $ 25 $ 48 $ 254
Operating expenses (86) (8) (18) (112)
-----------------------------------------------
Operating income 95 17 30 142
Other expense, net (24) (9) (26) (59)
-----------------------------------------------
Net income $ 71 $ 8 $ 4 $ 83
=========================================================================================================
9: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by their
products and services. We evaluate performance based upon the net income of each
segment. We operate principally in three reportable segments: electric utility,
gas utility, and enterprises.
The electric utility segment consists of the generation and distribution of
electricity in the state of Michigan through our subsidiary, Consumers. The gas
utility segment consists of regulated activities associated with the
transportation, storage, and distribution of natural gas in the state of
Michigan through our subsidiary, Consumers. The enterprises segment consists of:
- investing in, acquiring, developing, constructing, managing, and
operating non-utility power generation plants and natural gas
facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
The following tables show our financial information by reportable segment. The
"Other" net income segment includes corporate interest and other, discontinued
operations, and the cumulative effect of accounting changes.
REVENUES In Millions
- --------------------------------------------------------------------------------
Restated
Three Months Ended June 30 2004 2003
- --------------------------------------------------------------------------------
Electric utility $ 611 $ 602
Gas utility 300 299
Enterprises 182 225
--------------------
$1,093 $1,126
================================================================================
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions
- --------------------------------------------------------------------------------
Restated
Three Months Ended June 30 2004 2003
- --------------------------------------------------------------------------------
Electric utility $ 27 $ 35
Gas utility 1 5
Enterprises 38 8
Other (50) (113)
-------------------
$ 16 $ (65)
================================================================================
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CMS Energy Corporation
REVENUES In Millions
- -----------------------------------------------------------------------------------------
Restated
Six Months Ended June 30 2004 2003
- -----------------------------------------------------------------------------------------
Electric utility $1,241 $1,252
Gas utility 1,205 1,088
Enterprises 401 754
--------------------
$2,847 $3,094
========================================================================================
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions
- -------------------------------------------------------------------------------
Restated
Six Months Ended June 30 2004 2003
- -------------------------------------------------------------------------------
Electric utility $ 75 $ 86
Gas utility 57 59
Enterprises (23) 29
Other (100) (157)
-------------------
$ 9 $ 17
==============================================================================
TOTAL ASSETS In Millions
- ----------------------------------------------------------------------------------
Restated
June 30 2004 2003
- ----------------------------------------------------------------------------------
Electric utility $ 6,935 $ 6,603
Gas utility 2,886 2,586
Enterprises 5,030 4,277
Other 456 473
----------------------
$15,307 $13,939
==================================================================================
10: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: 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 a:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities instead of a cumulative effect of a change in accounting
principle.
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions, such as costs, inflation,
and profit margin that third parties would
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CMS Energy Corporation
consider to assume the settlement of the obligation. Fair value, to the extent
possible, should include a market risk premium for unforeseeable circumstances.
No market risk premium was included in our ARO fair value estimate since a
reasonable estimate could not be made. If a five percent market risk premium
were assumed, our ARO liability would increase by $22 million.
If a reasonable estimate of fair value cannot be made in the period the ARO is
incurred, such as for assets with indeterminate lives, the liability is to be
recognized when a reasonable estimate of fair value can be made. Generally,
transmission and distribution assets have indeterminate lives. Retirement cash
flows cannot be determined and there is a low probability of a retirement date.
Therefore, no liability has been recorded for these assets. Also, no liability
has been recorded for assets that have insignificant cumulative disposal costs,
such as substation batteries. The measurement of the ARO liabilities for
Palisades and Big Rock are based on decommissioning studies that largely utilize
third-party cost estimates.
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 following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
June 30, 2004 In Millions
- ---------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- ---------------------------------------------------------------------------------------------------------------------
Palisades-decommission plant site 1972 Palisades nuclear plant $495
Big Rock-decommission plant site 1962 Big Rock nuclear plant 64
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 -
=====================================================================================================================
June 30, 2004 In Millions
- ------------------------------------------------------------------------- --------------------------------------------------------
ARO Liability ARO
------------------- Cash Flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 6/30/04
- ------------------------------------------------------------------------------------------------------------------------------------
Palisades-decommission $249 $268 $ - $ - $ 10 $ 31 $309
Big Rock-decommission 61 35 - (24) 6 22 39
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - (1) 3 - 54
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
Closure of gas pipelines (a) 8 - - - - - -
Natural gas-fired power plant 1 1 - - 1 - 2
------------------------------------------------------------------------------------
Total $373 $359 $ - $(25) $ 20 $ 53 $407
==================================================================================================================================
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and
CMS Field Services.
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CMS Energy Corporation
The Palisades and Big Rock cash flow revisions resulted from new decommissioning
reports filed with the MPSC in March 2004. For additional details, see Note 3,
Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Plant
Decommissioning."
Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
cost of removal obligations have been accrued through depreciation charges. We
estimate that we had $1.016 billion at June 30, 2004 and $950 million at June
30, 2003 of previously accrued asset removal costs related to our regulated
operations arising from other than legal obligations. These obligations, which
were previously classified as a component of accumulated depreciation, are now
classified as regulatory liabilities in the accompanying Consolidated Balance
Sheets.
11: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership
and the FMLP. We have a 49 percent partnership interest in the MCV Partnership
and a 46.4 percent partnership interest in the FMLP. Consumers is the primary
purchaser of power from the MCV Partnership through a long-term power purchase
agreement. In addition, the FMLP holds a 75.5 percent lessor interest in the MCV
Facility, which results in Consumers holding a 35 percent lessor interest in the
MCV Facility. Collectively, these interests make us the primary beneficiary of
these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $728 million at June 30, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.453 billion at
June 30, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of three
other entities that are determined to be variable interest entities. We have 50
percent partnership interest in the T.E.S. Filer City Station Limited
Partnership, the Grayling Generating Station Limited Partnership, and the
Genesee Power Station Limited Partnership. Additionally, we have operating and
management contracts and are the primary purchaser of power from each
partnership through long-term power purchase agreements. Collectively, these
interests make us the primary beneficiary as defined by the Interpretation.
Therefore, we consolidated these partnerships into our consolidated financial
statements for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $118 million at June 30, 2004. Property, plant,
and equipment serving as collateral for these obligations has a carrying value
of $169 million as of June 30, 2004. Other than outstanding letters of credit
and guarantees of $5 million, the creditors of these partnerships do not have
recourse to the general credit of CMS Energy.
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CMS Energy Corporation
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to restate prior periods for the impact of this accounting
change.
Additionally, we have variable interest entities in which we are not the primary
beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at June 30, 2004:
- ---------------------------------------------------------------------------------------------------------------------------------
Name (Ownership Nature of the Involvement Investment Balance Operating Agreement Total Generating
Interest) Entity Country Date (In Millions) with CMS Energy Capacity
- ---------------------------------------------------------------------------------------------------------------------------------
Taweelah (40%) Generator United Arab 1999 $ 93 Yes 777 MW
Emirates
Generator -
Under
Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW
Generator -
Under United Arab
Shuweihat (20%) Construction Emirates 2001 $ (16)(a) Yes 1,500 MW
- -------------------------------------------------------------------------------------------------------------------------------
Total $ 77 2,527 MW
================================================================================================================================
(a) At June 30, 2004, we carried a negative investment in Shuweihat. The balance
is comprised of our investment of $3 million reduced by our proportionate share
of the negative fair value of derivative instruments of $19 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 $77 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$129 million. Included in that total 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.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are
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CMS Energy Corporation
actuarially equivalent to Medicare Part D, employers' measures of accumulated
postretirement benefit obligations and postretirement benefit costs should
reflect the effects of the Act.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$12 million for the six months ended June 30, 2004, and an expected total
reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million, or $0.03 per share, for the three
months ended June 30, 2004, $9 million, or $0.05 per share, for the six months
ended June 30, 2004, and an expected total net expense reduction of $17 million
for 2004.
EITF NO. 03-6, PARTICIPATING SECURITIES AND THE TWO-CLASS METHOD UNDER SFAS NO.
128: EITF No. 03-6, effective June 30, 2004, addresses the treatment of
participating securities in earnings per share calculations. This EITF defines
participating securities and describes their treatment using a two-class method
of calculating earnings per share. Since we have not issued any participating
securities, as defined by EITF No. 03-6 and SFAS No. 128, there was no impact on
earnings per share upon adoption.
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Consumers Energy Company
CONSUMERS ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS
In this MD&A, Consumers Energy, which includes Consumers Energy Company and all
of its subsidiaries, is at times referred to in the first person as "we," "our"
or "us."
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 include the purchase,
transportation, storage, distribution, and sale of natural gas.
We earn our revenue and generate cash from operations by providing electric and
natural gas services, electric power generation, gas transmission and storage,
and other energy related services. Our businesses are affected by weather,
especially during the traditional heating and cooling seasons, economic
conditions, regulation and regulatory issues, interest rates, our debt credit
rating, and energy commodity prices.
Our strategy involves rebuilding our balance sheet and refocusing on our core
strength: superior utility operation and service. Over the next few years, we
expect this strategy to improve our debt ratings, grow earnings at a mid-single
digit rate, and position the company to make new investments.
Despite strong financial and operational performance in 2003, we face important
challenges in the future. We continue to lose industrial and commercial
customers to alternative electric suppliers without receiving compensation for
stranded costs caused by the lost sales. As of July 2004, we have lost 858 MW or
11 percent of our electric load to these alternative electric suppliers. Based
on current trends, we predict load loss by year-end to be in the range of 900 MW
to 1,100 MW. However, no assurance can be made that the actual load loss will
not be greater or less than that range. 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 seek resolution of this
issue. In July 2004, several bills were introduced into the Michigan Senate that
could change Michigan's Customer Choice Act.
Further, higher natural gas prices have harmed the economics of the MCV
Partnership and we are seeking approval from the MPSC to change the way the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV Partnership'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.
Our gas business faces market and regulatory uncertainties relating to gas
costs. We attempt to minimize these uncertainties by fully recovering what we
spend to purchase the gas through the GCR process. We currently have a GCR year
2003-2004 reconciliation on file with the MPSC.
CE-1
Consumers Energy Company
We are focused on further reducing our business, financial, and regulatory
risks, while growing the equity base of our company. Finally, we are planning to
devote more attention to improving business growth. Our business plan is
targeted at predictable earnings growth. The result of these efforts will be a
strong, reliable utility company that will be poised to take advantage of
opportunities for further growth.
CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the
MCV Partnership and the FMLP. As a result, we have consolidated the assets,
liabilities, and activities of these entities into our financial statements as
of and for the three and six months ended June 30, 2004. These entities are
reported as equity method investments in our financial statements as of and for
the three and six months ended June 30, 2003. Therefore, the consolidation of
these entities had no impact on our consolidated net income for the three and
six months ended June 30, 2004. For additional details, see Note 7,
Implementation of New Accounting Standards.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 of the Securities Exchange
Act of 1934, as amended, Rule 175 of the Securities Act of 1933, as amended, and
relevant legal decisions. Our intention with the use of words such as "may,"
"could," "anticipates," "believes," "estimates," "expects," "intends," "plans,"
and other similar words is to identify forward-looking statements that involve
risk and uncertainty. We designed this discussion of potential risks and
uncertainties to highlight important factors that may impact our business and
financial outlook. We have no obligation to update or revise forward-looking
statements regardless of whether new information, future events, or any other
factors affect the information contained in the statements. These
forward-looking statements are subject to various factors that could cause our
actual results to differ materially from the results anticipated in these
statements. Such factors include our inability to predict and/or control:
- capital and financial market conditions, including the current price
of CMS Energy Common Stock and the effect of such market conditions
on the Pension Plan, interest rates and availability of financing to
Consumers, CMS Energy, or any of their affiliates and the energy
industry,
- ability to access the capital markets successfully,
- market perception of the energy industry, Consumers, CMS Energy, or
any of their affiliates,
- credit ratings of Consumers, CMS Energy, or any of their affiliates,
- factors affecting utility and diversified energy operations such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs,
environmental incidents, or electric transmission or gas pipeline
system constraints,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
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- adverse regulatory or legal decisions, including environmental laws
and regulations,
- the impact of adverse natural gas prices on the MCV Partnership
investment, regulatory decisions concerning the MCV Partnership RCP,
and regulatory decisions that limit our recovery of capacity and
fixed energy payments,
- 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 without price
restrictions, and proposals by the FERC to change the way public
utilities and natural gas companies, and their subsidiaries and
affiliates, interact with each other,
- energy markets, including the timing and extent of unanticipated
changes in commodity prices for oil, coal, natural gas, natural gas
liquids, electricity, and certain related products due to lower or
higher demand, shortages, transportation problems, or other
developments,
- potential disruption or interruption of facilities or operations due
to accidents or terrorism, and the ability to obtain or maintain
insurance coverage for such events,
- nuclear power plant performance, decommissioning, policies,
procedures, incidents, and regulation, including the availability of
spent nuclear fuel storage,
- technological developments in energy production, delivery, and
usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or
policies,
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims,
- limitations on our ability to control the development or operation
of projects in which our subsidiaries have a minority interest,
- disruptions in the normal commercial insurance and surety bond
markets that may increase costs or reduce traditional insurance
coverage, particularly terrorism and sabotage insurance and
performance bonds,
- other business or investment considerations that may be disclosed
from time to time in Consumers' or CMS Energy's SEC filings, or in
other publicly issued written documents, and
- other uncertainties that are difficult to predict, and many of which
are beyond our control.
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RESULTS OF OPERATIONS
NET INCOME AVAILABLE TO COMMON STOCKHOLDER
In Millions
- -------------------------------------------------------------------------------
June 30 2004 2003 Change
- -------------------------------------------------------------------------------
Three months ended $ 23 $ 40 $(17)
Six months ended $128 $139 $(11)
===============================================================================
2004 COMPARED TO 2003: For the three months ended June 30, 2004, our net income
decreased $17 million versus the same period in 2003 primarily due to higher
MSBT expense, a reduction in electric and gas revenues, and decreased earnings
from our investment in the MCV Partnership. Increased MSBT expense lowered net
income by $12 million due to a 2003 reduction to reflect CMS Energy receiving
approval to file consolidated tax returns for the years 2000 and 2001. These
returns were filed during the second quarter of 2003. Decreased electric
delivery revenues further reduced net income by $7 million primarily due to
tariff revenue reductions and the continued loss of commercial and industrial
customers switching to alternative electric suppliers as allowed by the Customer
Choice Act. Decreased gas delivery revenues due to warmer weather further
reduced net income by $5 million. Also contributing to the decline in net income
were lower earnings from the MCV Partnership, reducing net income $4 million.
The reduction in the MCV Partnership earnings reflects an increase in
non-recoverable fuel costs incurred at the MCV Facility and a decrease in the
fair value of certain long-term gas contracts.
Partially offsetting these reductions to net income were $10 million in benefits
primarily relating to reduced depreciation expense and additional interest
income. The Customer Choice Act authorized us to defer electric depreciation on
the excess of capital expenditures over our depreciation base and recognize
interest income on the excess capital expenditures. Gas depreciation expense
also declined in the second quarter of 2004 due to the interim MPSC gas rate
order issued in December 2003.
For the six months ended June 30, 2004, our net income decreased $11 million
versus the same period in 2003. Warmer weather reduced gas delivery revenues,
decreasing net income by $14 million. The warmer weather improved electric
delivery sales to the higher margin residential sector; however, tariff revenue
reductions and the continued loss of customers to alternative electric suppliers
as allowed by the Customer Choice Act more than offset this benefit. Electric
delivery revenues decreased net income by $13 million. Earnings from our
investment in the MCV Partnership declined $10 million primarily due to
increases in non-recoverable fuel costs incurred at the MCV Facility and
decreases in the fair value of certain long-term gas contracts. Higher general
taxes decreased net income $9 million due to a 2003 reduction in MSBT expense to
reflect the benefit of CMS Energy receiving approval to file consolidated tax
returns for the years 2000 and 2001. Net income was further decreased $8 million
due to greater average borrowings, partially offset by a reduction in our
average interest rate. In 2003, under provisions of the Customer Choice Act, the
excess, or overrecovery of PSCR revenues over PSCR costs benefited net income.
In contrast, in 2004 PSCR overrecoveries must be reserved for possible future
refund and consequently do not benefit net income. This change in the treatment
of PSCR overrecoveries reduced net income $5 million.
Partially offsetting these reductions to net income were $27 million in benefits
relating primarily to reduced depreciation expense and increases in interest
income. The Customer Choice Act authorized us to defer electric depreciation on
the excess of capital expenditures over our depreciation base and recognize
interest income on the excess capital expenditures. Gas depreciation expense
also declined in 2004 due to the interim MPSC gas rate order issued in December
2003. This interim order also authorized a gas rate
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increase that benefited net income by $7 million. Non-commodity gas revenues
further increased net income $2 million due to increased gas transportation and
storage revenues. Finally, net income benefited from the absence of a $12
million charge taken in 2003. The 2003 charge reflects a decline in the market
value of CMS Energy stock held by us.
For additional details, see "Electric Utility Results of Operations" and "Gas
Utility Results of Operations" within this section and Note 2, Uncertainties.
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
- ------------------------------------------------------------------------------------------------------
June 30 2004 2003 Change
- ------------------------------------------------------------------------------------------------------
Three months ended $ 27 $35 $ (8)
Six months ended $75 $86 $(11)
======================================================================================================
Three Months Ended Six Months Ended
Reasons for the change: June 30, 2004 vs. 2003 June 30, 2004 vs. 2003
- ------------------------------------------------------------------------------------------------------
Electric deliveries $(10) $(20)
Power supply costs and related revenue (2) (8)
Other operating expenses, non-commodity
revenue and other income 13 26
General taxes (14) (10)
Fixed charges -- (6)
Income taxes 5 7
-----------------------------------------
Total change $ (8) $(11)
======================================================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other
wholesale marketers, other electric utilities, and customers choosing
alternative suppliers increased 0.7 billion kWh or 7.2 percent and 1.0 billion
kWh or 5.4 percent for the three and six months ended June 30, 2004 versus the
same periods in 2003. The corresponding increases in electric delivery revenue
for both periods were offset by tariff revenue reductions and decreased sales
margins from deliveries to customers choosing alternative electric suppliers.
The tariff revenue reductions, which began January 1, 2004, were equivalent to
the Big Rock nuclear decommissioning surcharge in effect when our electric
retail rates were frozen from June 2000 through December 31, 2003. The tariff
revenue reductions were reclassified for capped customers as increases to PSCR
revenues. The increased PSCR revenues helped negate possible losses attributable
to the underrecovery of PSCR costs for these customers, primarily the
residential and small commercial classes. In fact, the revenue reclassification
contributed to the overrecovery of PSCR revenues in excess of PSCR costs in
these customer classes for the three and six months ended June 30, 2004. In
2004, to the extent we have PSCR overrecoveries, the overrecovery must be
reserved for possible future refund. The tariff revenue reductions have
decreased electric delivery revenues by approximately $9 million in the second
quarter of 2004, and $18 million in the first six months of 2004 versus 2003.
The tariff revenue reductions are expected to decrease electric delivery
revenues by $35 million for the full year of 2004 versus the full year of 2003.
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For the three and six months ended June 30, 2004, the overall decline in
electric delivery revenues was offset partially by increased sales to
residential customers due to warmer weather versus the same periods in 2003.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of
recovery was a fixed amount per kWh, as required under the Customer Choice Act.
Therefore, power supply-related revenue in excess of actual power supply costs
increased operating income. By contrast, if power supply-related revenues had
been less than actual power supply costs, the impact would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenues are in excess of actual power supply costs, this former
benefit is reserved for possible future refund. This change in the treatment of
excess power supply revenues over power supply costs decreased operating income
for the three and six months ended June 30, 2004 versus the same periods in
2003.
OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three
months ended June 30, 2004, other operating expenses decreased $1 million,
non-commodity revenue increased $1 million, and other income increased $11
million versus the same period in 2003. The increase in other income relates
primarily to interest income recognized in relation to capital expenditures in
excess of depreciation, as allowed by the Customer Choice Act. This Act also
enabled us to defer depreciation expense on the excess of capital expenditures
over our depreciation base, contributing to a reduction in operating expenses
for the second quarter of 2004 versus the same period in 2003. Higher other
operating expenses substantially offset the reduction in electric depreciation
expense.
In the six months ended June 30, 2004, other operating expenses decreased $6
million and other income increased $20 million versus the same period in 2003.
The increase in other income relates primarily to interest income recognized in
relation to capital expenditures in excess of depreciation, as allowed by the
Customer Choice Act. Operating expense decreases reflect lower benefit costs and
our ability to defer depreciation expense on the excess of capital expenditures
over our depreciation base, as allowed by the Customer Choice Act.
GENERAL TAXES: General taxes increased in the three and six months ended June
30, 2004 versus the same periods in 2003 primarily due to reductions in the MSBT
expense in 2003. The 2003 reduction was primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
FIXED CHARGES: Fixed charges increased in the six months ended June 30, 2004
versus the same periods in 2003 due to higher average debt levels, partially
offset by a reduction in the average rates of interest. The average rate of
interest dropped 79 basis points and 60 basis points for the three and six month
periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: In the three and six months ended June 30, 2004, income taxes
decreased versus the same periods in 2003 primarily due to lower earnings by the
electric utility, and the OPEB Medicare Part D federal subsidy that is exempt
from federal taxation.
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GAS UTILITY RESULTS OF OPERATIONS
In Millions
- -------------------------------------------------------------------------------------------------------------
June 30 2004 2003 Change
- -------------------------------------------------------------------------------------------------------------
Three months ended $ 1 $ 5 $ (4)
Six months ended $57 $59 $ (2)
=============================================================================================================
Three Months Ended Six Months Ended
Reasons for the change: June 30, 2004 vs. 2003 June 30, 2004 vs. 2003
- -------------------------------------------------------------------------------------------------------------
Gas deliveries $ (7) $(21)
Gas rate increase 2 11
Gas wholesale and retail services and other gas
revenues 1 3
Operation and maintenance - (2)
General taxes, depreciation, and other income (3) 3
Fixed charges (2) (6)
Income taxes 5 10
---------------------------------------------------------
Total change $ (4) $ (2)
=============================================================================================================
GAS DELIVERIES: For the three months ended June 30, 2004, the more profitable
non-transportation gas deliveries decreased 4.9 bcf or 13.6 percent primarily
due to milder weather. The less profitable transportation gas deliveries
increased 5.2 bcf or 21.0 percent due to increased MCV Facility generation.
Overall, gas deliveries, including miscellaneous transportation, increased 0.3
bcf or 0.5 percent versus the same period in 2003.
For the six months ended June 30, 2004, gas deliveries, including miscellaneous
transportation, decreased 6.7 bcf or 2.9 percent versus the same period in 2003
primarily due to milder weather.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, gas revenues increased for the three and six months ended June 30,
2004 versus the same periods in 2003.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the three and six
months ended June 30, 2004, wholesale and retail services and other gas revenues
increased primarily due to increased gas transportation and storage revenues
versus the same periods in 2003.
OPERATION AND MAINTENANCE: For the six months ended June 30, 2004, increased
expenditures on safety, reliability, and customer service were offset partially
by reduced benefit costs compared to the same period in 2003.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: For the three months ended June
30, 2004 versus the same period in 2003, general tax expense increased $5
million due to higher MSBT expense and depreciation expense decreased $2
million. The increase in MSBT expense is primarily due to CMS Energy having
received approval to file consolidated tax returns for the years 2000 and 2001.
The taxable income for these years was lower than the amount used to make
estimated MSBT payments. These returns were filed in the second quarter of 2003.
The reduced depreciation expense relates to decreases in
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depreciation rates authorized by the MPSC's December 2003 interim rate order.
For the six months ended June 30, 2004, general tax expense increased $4 million
due to higher MSBT expense, depreciation expense decreased $8 million, and other
income decreased $1 million versus the same period in 2003. The increase in MSBT
expense is primarily due to CMS Energy having received approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003. The reduced depreciation
expense relates to decreases in depreciation rates authorized by the MPSC's
December 2003 interim rate order.
FIXED CHARGES: Fixed charges increased in the three and six months ended June
30, 2004 versus the same periods in 2003 due to higher average debt levels,
partially offset by a reduction in the average rate of interest. The average
rate of interest dropped 79 basis points and 60 basis points for the three and
six month periods ended June 30, 2004 versus the same periods in 2003.
INCOME TAXES: For the three and six months ended June 30, 2004 versus the same
periods in 2003, income taxes decreased due to the income tax treatment of items
related to plant, property and equipment as required by past MPSC rulings, the
decreased earnings of the gas utility, and the OPEB Medicare Part D federal
subsidy that is exempt from federal taxation.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A:
- use of estimates in accounting for contingencies and equity method
investments,
- accounting for the effects of regulatory accounting,
- accounting for financial and derivative instruments,
- accounting for pension and postretirement benefits,
- accounting for asset retirement obligations,
- accounting for nuclear decommissioning costs, and
- accounting for related party transactions.
For additional accounting policies, see Note 1, Corporate Structure and
Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions that may
affect reported amounts and disclosures. Accounting estimates are used for asset
valuations, depreciation, amortization, financial and derivative instruments,
employee benefits, and contingencies. For example, we estimate the rate of
return on plan assets and the cost of future health-care benefits to determine
our annual pension and other postretirement benefit costs. There are risks and
uncertainties that may cause actual results to differ from estimated results,
such as changes in the regulatory environment, competition, regulatory
decisions, and lawsuits.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence is probable and,
where determinable, an estimate of the liability amount. The recording of
estimated liabilities for contingencies is guided by the principles in SFAS No.
5. We consider many factors in making these assessments, including history and
the specifics of each matter. The most
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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 PPA with the MCV Partnership, we pay a capacity charge based on the
availability of the MCV Facility whether or not electricity is actually
delivered to us; a variable energy charge for kWh delivered to us; and a fixed
energy charge based on availability up to 915 MW and based on delivery for the
remaining 325 MW of contract capacity. The cost that we incur under the MCV
Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we
estimate cash underrecoveries of capacity and fixed energy payments will
aggregate $206 million from 2004 through 2007. For capacity and fixed energy
payments billed by the MCV Partnership after September 15, 2007, and not
recovered from customers, we expect to claim relief under a regulatory out
provision under the MCV Partnership PPA. This provision obligates Consumers to
pay the MCV Partnership only those capacity and energy charges that the MPSC has
authorized for recovery from electric customers. The effect of any such action
would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and
- eliminate our underrecoveries for capacity and fixed energy
payments.
Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned at our coal plants and our operation and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been impacted negatively.
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be affected adversely.
In February 2004, we filed the RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our investment in the MCV Partnership,
without raising the costs paid by our electric customers. The plan's primary
objective is to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas 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. Presently, we are in settlement discussions with the parties to
the RCP filing. However, in July 2004, several qualifying facilities filed for a
stay on the RCP proceeding in the Ingham County Circuit Court after their
previous attempt to intervene on the proceeding was denied by the MPSC.
Hearings on the stay are scheduled for August 11, 2004. We cannot predict if or
when the MPSC will approve the RCP or the outcome of the Ingham County Circuit
Court hearings.
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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
20 years and the MPSC's decision in 2007 or beyond related to limiting our
recovery of capacity and fixed energy payments. Natural gas prices have been
volatile historically. Presently, there is no consensus in the marketplace on
the price or range of future prices of natural gas. Even with an approved RCP,
if gas prices continue at present levels or increase, the economics of operating
the MCV Facility may be adverse enough to require us to recognize an impairment
of our investment in the MCV Partnership. We presently cannot predict the impact
of these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
For additional details on the MCV Partnership, see Note 2, Uncertainties, "Other
Electric Uncertainties - The Midland Cogeneration Venture."
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
June 30, 2004, we had $1.125 billion recorded as regulatory assets and $1.502
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 debt securities are classified as held-to-maturity securities and are
reported at cost. 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 reflected in Regulatory
Liabilities. The fair value of our equity securities 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.
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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. 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.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, electric call options, gas fuel futures and options, gas
fuel contracts containing volume optionality, fixed priced weather-based gas
supply call options, and fixed price gas supply call and put options. We
generally do not account for electric capacity and energy contracts, gas supply
contracts, coal and nuclear fuel supply contracts, or purchase orders for
numerous supply items as derivatives.
The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives because there is not an active market for the commodity. Our
electric capacity and energy contracts are not accounted for as derivatives due
to the lack of an active energy market in the state of Michigan, as defined by
SFAS No. 133, and the significant transportation costs that would be incurred to
deliver the power under the contracts to the closest active energy market at the
Cinergy hub in Ohio. If an active market develops in the future, we may be
required to account for these contracts as derivatives. The mark-to-market
impact on earnings related to these contracts could be material to our financial
statements.
Additionally, the MCV Partnership uses natural gas fuel contracts to buy gas as
fuel for generation, and to manage gas fuel costs. The MCV Partnership believes
that its long-term natural gas contracts, which do not contain volume
optionality, qualify under SFAS No. 133 for the normal purchases and normal
sales exception. Therefore, these contracts are currently not recognized at fair
value on the balance sheet. Should significant changes in the level of the MCV
Facility operational dispatch or purchases of long-term gas occur, the MCV
Partnership would be required to re-evaluate its accounting treatment for these
long-term gas contracts. This re-evaluation may result in recording
mark-to-market activity on some contracts, which could add to earnings
volatility.
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 June 30, 2004, we assumed a market-based interest rate of
1 percent (a rate that is not significantly different than the LIBOR rate) and
volatility rates ranging between 60 percent and 71 percent to calculate the fair
value of our gas options. At June 30, 2004, we assumed market-based interest
rates ranging between 1.37 percent and 4.50 percent and volatility rates ranging
between 24 percent and 44 percent to calculate the fair value of the gas fuel
derivative contracts held by the MCV Partnership.
MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, and equity security
prices. We manage these risks using established policies and procedures, under
the direction of both an executive oversight committee consisting of senior
management representatives and a risk committee consisting of business-unit
managers. We may use various contracts to manage these risks, including swaps,
options, futures, and forward contracts.
Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We
intend that any gains or losses on these contracts will be offset by an opposite
movement in the value of the item at risk. We enter into all risk
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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):
In Millions
- -----------------------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -----------------------------------------------------------------------------------------------------------
Variable-rate financing - before tax annual earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in fair value (a) 154 154
===========================================================================================================
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
As discussed in "Electric Business Uncertainties - Competition and Regulatory
Restructuring - Securitization" within this MD&A, we have filed an application
with the MPSC to securitize certain expenditures. Upon final approval, we intend
to use the proceeds from the Securitization to retire higher-cost debt, which
could include a portion of our current fixed-rate debt. We do not believe that
any adverse change in debt price and interest rates would have a material
adverse effect on either our consolidated financial position, results of
operations, or cash flows.
Commodity Price Risk: For purposes other than trading, we enter into electric
call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call options are
purchased 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. Purchased electric call options give us the right, but not the
obligation, to purchase electricity at predetermined fixed prices. Purchases of
gas supply call options and weather-based gas supply call options, coupled with
the sale of gas supply put options, are used to purchase reasonably priced gas
supply. Purchases of gas supply call options give us the right, but not the
obligation, to purchase gas supply at predetermined fixed prices. Gas supply put
options sold give third-party suppliers the right, but not the obligation, to
sell gas supply to us at predetermined fixed prices. At June 30, 2004, we held
fixed-priced weather-based gas supply call options and fixed-price gas supply
call and put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation and to manage gas fuel costs. Some of these contracts contain volume
optionality and, therefore, are treated as derivative instruments. Also, the MCV
Partnership enters into natural gas futures contracts, option contracts, and
over-the-counter swap transactions in order to hedge against
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unfavorable changes in the market price of natural gas in future months when gas
is expected to be needed. These financial instruments are being used principally
to secure anticipated natural gas requirements necessary for projected electric
and steam sales, and to lock in sales prices of natural gas previously obtained
in order to optimize the MCV Partnership's existing gas supply, storage, and
transportation arrangements.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
- -------------------------------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -------------------------------------------------------------------------------------------------
Potential reduction in fair value:
Gas supply option contracts $ 7 $ 1
Derivative contracts associated with Consumers' investment
in the MCV Partnership:
Gas fuel contracts 21 N/A
Gas fuel futures, options, and swaps 38 N/A
=================================================================================================
During the six months ended June 30, 2004, we entered into additional
weather-based gas supply call options, as well as gas supply call and put option
contracts. As a result, the potential reduction in the fair value increased from
December 31, 2003, as shown in the table above. We did not perform a sensitivity
analysis for the derivative contracts held by the MCV Partnership as of December
31, 2003 because the MCV Partnership was not consolidated into our financial
statements until March 31, 2004, as discussed in Note 7, Implementation of New
Accounting Standards.
Equity Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reflected in Regulatory
Liabilities. Our debt securities are classified as held-to-maturity securities
and have original maturity dates of approximately one year or less. Because of
the short maturity of these instruments, their carrying amounts approximate
their fair values.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market prices):
In Millions
- --------------------------------------------------------------------------
June 30, 2004 December 31, 2003
- --------------------------------------------------------------------------
Potential reduction in fair value:
Nuclear decommissioning investments $ 54 $ 57
Other available-for-sale investments 4 4
==========================================================================
For additional details on market risk and derivative activities, see Note 4,
Financial and Derivative Instruments.
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ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. We implemented a cash balance plan for certain employees hired after June
30, 2003. We use SFAS No. 87 to account for pension costs.
401(k): In our effort to reduce costs, the employer's match for the 401(k) plan
was suspended effective September 1, 2002. The employer's match for the 401(k)
plan is scheduled to resume on January 1, 2005.
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 cost, OPEB cost, and
cash contributions for the next three years:
In Millions
- -----------------------------------------------------------------------------------------
Expected Costs Pension Cost OPEB Cost Contributions
- -----------------------------------------------------------------------------------------
2004 $20 $30 $ 62
2005 52 38 78
2006 71 35 110
========================================================================================
Actual future pension cost and contributions will depend on future investment
performance, changes in future discount rates, and various other factors related
to the populations participating in the Pension Plan. As of June 30, 2004, we
have a prepaid pension asset of $373 million, $20 million of which is in Other
current assets on our Consolidated Balance Sheet.
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 cost 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 cost for
2004 by $4 million.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the
Act) was signed into law in December 2003. The Act establishes a prescription
drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is
exempt from federal taxation, to sponsors of retiree health care benefit plans
that provide a benefit that is actuarially equivalent to Medicare Part D.
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We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $148 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$11 million for the six months ended June 30, 2004, and an expected total
reduction of $23 million for 2004.
For additional details on postretirement benefits, see Note 5, Retirement
Benefits, and Note 7, Implementation of New Accounting Standards.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143 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 regulatory assets and liabilities instead of a cumulative
effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions, such as costs, inflation,
and profit margin that third parties would consider to assume the settlement of
the obligation. Fair value, to the extent possible, should include a market risk
premium for unforeseeable circumstances. No market risk premium was included in
our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period the ARO is
incurred, such as for assets with indeterminate lives, the liability is
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 and there is a low probability of a retirement date.
Therefore, no liability has been recorded for these assets. Also, no liability
has been recorded for assets that have insignificant cumulative disposal costs,
such as substation batteries. The measurement of the ARO liabilities for
Palisades and Big Rock are based on decommissioning studies, which largely
utilize third-party cost estimates. For additional details on ARO, see Note 6,
Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. We have established external trust funds to
finance the decommissioning of both plants. We record the trust fund balances as
a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop
decommissioning cost estimates. Various inflation rates for labor, non-labor,
and contaminated equipment disposal costs are used to escalate these cost
estimates to the future decommissioning cost. A portion of future
decommissioning
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cost will result from the failure of the DOE to remove fuel from the sites, as
required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income investments.
Equities will be converted to fixed income investments during decommissioning,
and fixed income investments are converted to cash as needed. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The funds provided by the
trusts, additional customer surcharges, and potential funds from the DOE
litigation are all required to cover fully the decommissioning costs. The costs
of decommissioning these sites and the adequacy of the trust funds could be
affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery
from customers, and
- changes in decommissioning technology, regulations, estimates,
or assumptions.
Based on current projections, the current level of funds provided by the trusts
is not adequate to fully fund the decommissioning of Big Rock or Palisades. This
is due in part to the DOE's failure to accept the spent nuclear fuel on
schedule, and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation. We will also
seek additional relief from the MPSC. For additional details on nuclear
decommissioning, see Note 2, Uncertainties, "Other Electric Uncertainties -
Nuclear Plant Decommissioning" and "Nuclear Matters."
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties. These
transactions include:
- issuance of trust preferred securities with Consumers' affiliated
companies,
- purchases and sales of electricity and gas for generation from
Enterprises,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates are generally based on
regulated prices, market prices, or competitive bidding. Transactions involving
the power supply purchases from certain affiliates of Enterprises are based upon
avoided costs under PURPA and competitive bidding. The payment of parent company
overhead costs is based on the use of accepted industry allocation
methodologies.
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. The market price for natural gas has increased. Although our natural gas
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory could require additional liquidity due to the timing of the
cost recoveries. In addition, a few of our commodity suppliers have requested
advance payment or other forms of assurances, including margin calls, in
connection with maintenance of ongoing deliveries of gas and electricity.
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Our current financial plan includes monitoring our operating expenses and
capital expenditures and evaluating market conditions for financing
opportunities. 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
SUMMARY OF CASH FLOWS:
In Millions
- -------------------------------------------------------------------------------
Six Months Ended June 30 2004 2003
- -------------------------------------------------------------------------------
Net cash provided by (used in):
Operating activities $ 564 $ 189
Investing activities (254) (225)
Financing activities (125) (22)
----------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 185 $ (58)
================================================================================
OPERATING ACTIVITIES:
For the six months ended June 30, 2004, net cash provided by operating
activities increased $375 million compared to the six months ended June 30, 2003
due to an increase of other liabilities of $174 million resulting from an
increase in accrued interest, accrued refunds, and other current liabilities.
Accrued interest and other current liabilities increased as a result of the
Revised FASB Interpretation No. 46 consolidation of the MCV Partnership and the
FMLP. The increase in accrued refunds relates to the $11 million settlement in
our 2002-2003 GCR case and potential overrecoveries primarily from our large
commercial and industrial customers resulting from our return to the PSCR
process. For additional details regarding the PSCR process, refer to "Electric
Business Uncertainties - Competition and Regulatory Restructuring - PSCR" within
this MD&A. There was an increase in accounts payable of $85 million resulting
from the purchase of natural gas at higher prices and fewer suppliers requiring
advance payments for gas purchases. In addition, there was a greater decrease in
gas inventory of $55 million resulting from sales at higher prices combined with
lower volumes of gas purchased.
INVESTING ACTIVITIES:
For the six months ended June 30, 2004, net cash from investing activities
decreased $29 million due to an increase in 2004 versus 2003 capital
expenditures of $17 million and a decrease in asset sale proceeds of $15 million
resulting from higher 2003 asset sales.
FINANCING ACTIVITIES:
For the six months ended June 30, 2004, net cash from financing activities
decreased $103 million primarily due to a decrease of $131 million in net
proceeds from borrowings. For additional details on long-term debt activity, see
Note 3, Financings and Capitalization.
OBLIGATIONS AND COMMITMENTS
REGULATORY AUTHORIZATION FOR FINANCINGS: We issue short and long-term securities
under the FERC's authorization. For additional details of our existing
authorization, see Note 3, Financings and Capitalization.
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LONG-TERM DEBT: The components of long-term debt are presented in Note 3,
Financings and Capitalization.
SHORT-TERM FINANCINGS: At June 30, 2004, we had $376 million available and the
MCV Partnership had $50 million available in short-term credit facilities. The
facilities are available for general corporate purposes, working capital, and
letters of credit. As of August 3, 2004, we obtained an amended and restated
$500 million secured revolving credit facility to replace our $400 million
facility. The amended facility carries a three-year term and provides for lower
interest rates. Additional details on short-term financings are presented in
Note 3, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS:
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 3, Financings and Capitalization.
CONTINGENT COMMITMENTS: Our contingent commitments include indemnities and
letters of credit. Indemnities are agreements to reimburse other companies, such
as an insurance company, if those companies have to complete our contractual
performance in a third-party contract. Banks, on our behalf, issue letters of
credit guaranteeing payment to a third party. Letters of credit substitute the
bank's credit for ours and reduce credit risk for the third-party beneficiary.
We monitor and approve these obligations and believe it is unlikely that we
would be required to perform or otherwise incur any material losses associated
with these guarantees. Our off-balance sheet commitments at June 30, 2004 expire
as follows:
Contingent Commitments In Millions
- ----------------------------------------------------------------------------------------------------------------
Commitment Expiration
--------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 beyond
- ----------------------------------------------------------------------------------------------------------------
Off-balance sheet:
Surety bonds and
other indemnifications
(a) $ 8 $ 1 $ - $ - $ - $ - $ 7
Letters of credit 24 8 16 - - - -
================================================================================================================
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
June 30, 2004, we had $396 million of unrestricted retained earnings available
to pay common stock dividends. However, covenants in our debt facilities cap
common stock dividend payments at $300 million in a calendar year. We are also
under an annual dividend cap of $190 million imposed by the MPSC during the
current interim gas rate relief period. In February 2004, we paid $78 million
and in May 2004, we paid $27 million in common stock dividends to CMS Energy.
For additional details on the cap on common stock dividends payable during the
current interim gas rate relief period, see Note 2, Uncertainties, "Gas Rate
Matters - 2003 Gas Rate Case."
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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 fluctuations in weather
conditions and changes in economic conditions, including utilization and
expansion of manufacturing facilities. We experienced less growth than expected
in 2003 as a result of cooler than normal summer weather and a decline in
manufacturing activity in Michigan. In 2004, we project electric deliveries to
grow approximately two percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
during the remainder of the year.
ELECTRIC BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner.
Regulatory
- effects of recommendations as a result of the August 14, 2003
blackout, including increased regulatory requirements and new
legislation,
- effects of the FERC supply margin assessment requirements for
electric market-based rate authority,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel, and
- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" within this MD&A.
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Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities, and
- other pending litigation.
For additional details about these trends or uncertainties, see Note 2,
Uncertainties.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.
Compliance with the federal Clean Air Act and resulting regulations has been,
and will continue to be, a significant focus for us. The Title I provisions of
the Clean Air Act require significant reductions in nitrogen oxide emissions. To
comply with the regulations, we expect to incur capital expenditures totaling
$771 million. The key assumptions included in the capital expenditure estimate
include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.9 percent. As of June 30, 2004, we have
incurred $489 million in capital expenditures to comply with these regulations
and anticipate that the remaining $282 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology at some 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 EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.
The EPA has proposed a Clean Air Interstate Rule that would require additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury and nickel from
coal-fired and oil-fired electric plants. Until the proposed environmental rules
are finalized, an accurate cost of compliance cannot be determined.
Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
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To the extent that greenhouse gas emission reduction rules come into effect,
such mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments and will continue to assess and respond
to their potential implications on our business operations.
In March 2004, the EPA changed the rules that govern generating plant cooling
water intake systems. The new rules require significant reduction in fish killed
by operating equipment. Some of our facilities will be required to comply by
2006. We are studying the rules to determine the most cost-effective solutions
for compliance.
For additional details on electric environmental matters, see Note 2,
Uncertainties, "Electric Contingencies - Electric Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and
other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of July 2004, alternative electric suppliers are providing 858 MW of
generation supply to ROA customers. This amount represents 11 percent of our
distribution load and an increase of 49 percent compared to July 2003. Based on
current trends, we predict load loss by year-end to be in the range of 900 MW to
1,100 MW. However, no assurance can be made that the actual load loss will not
be greater or less than that range.
In July 2004, as a result of legislative hearings, several bills were introduced
into the Michigan Senate that could change Michigan's Customer Choice Act. The
proposals include:
- requiring that rates be based on cost of service,
- establishing a defined Stranded Cost calculation method,
- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return,
- establishing reliability standards that all electric suppliers must
follow,
- requiring utilities and alternative suppliers to maintain a 15
percent power reserve margin,
- creating a service charge to fund the Low Income and Energy
Efficiency Fund,
- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates, and
- authorizing a service charge payable by all customers for meeting
Clean Air Act requirements.
Securitization: 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. We filed for rehearing and clarification on a number of
features in the financing order. If and when the MPSC issues an order with
favorable terms, then the order will become effective upon our acceptance.
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
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method adopted by the MPSC will be applied in a manner that will offset fully
any associated margin loss.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002, including the cost of
money, are estimated to be $47 million with the issuance of Securitization bonds
that include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. Once the MPSC
issues a final financing order on Securitization, we will know the amount of our
request for net Stranded Cost recovery for 2002. In July 2004, the ALJ issued a
proposal for decision in our 2002 net Stranded Cost case, which recommended that
the MPSC find that we incurred net Stranded Costs of $12 million. This
recommendation includes the cost of money through July 2004 and excludes Clean
Air Act investments.
In April 2004, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2003. We also requested interim relief for 2003 net
Stranded Costs, but the ALJ declined to set a schedule that would allow
consideration of the interim request. In July 2004, we revised our request for
approval of 2003 Stranded Costs incurred, including the cost of money, to $69
million with the issuance of Securitization bonds that include Clean Air Act
investments, or $128 million without the issuance of Securitization bonds that
include Clean Air Act investments. In July 2004, the MPSC Staff issued a
position on our 2003 net Stranded Cost application, which resulted in a Stranded
Cost calculation of $52 million. The amount includes the cost of money, but
excludes Clean Air Act investments.
We cannot predict how the MPSC will rule on our requests for the recovery of
Stranded Costs. Therefore, we have not recorded regulatory assets to recognize
the future recovery of such costs.
Implementation Costs: Following an appeal and remand of initial MPSC orders
relating to 1999 implementation costs, the MPSC authorized the recovery of all
previously approved implementation costs for the years 1997 through 2001 by
surcharges on all customers' bills phased in as rate caps expire. Authorized
recoverable implementation costs totaled $88 million. This total includes
carrying costs through 2003. Additional carrying costs will be added until
collection occurs. For additional information on rate caps, see "Rate Caps"
within this section.
Our applications for $7 million of implementation costs for 2002 and $1 million
for 2003 are presently pending approval by the MPSC. Included in the 2002
request is $5 million related to our former participation in the development of
the Alliance RTO. Although we believe these implementation costs and associated
cost of money are fully recoverable in accordance with the Customer Choice Act,
we cannot predict the amounts the MPSC will approve as recoverable.
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if
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any, we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for $25 million
of costs for which regulatory treatment has not yet been granted through other
means. The requested amount includes reasonable and prudent security
enhancements through December 31, 2005. As of June 30, 2004, we have $7 million
in security costs recorded as a regulatory asset. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. In July
2004, a settlement was reached with the parties to the case, which would provide
for full recovery of the requested security costs over a five-year period
beginning in 2004. We are presently awaiting approval from the MPSC. We cannot
predict how the MPSC will rule on our request for the recoverability of security
costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates
that could result in us being unable to collect our full cost of conducting
business from electric customers. Such limitations include:
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and
- rate caps effective through December 31, 2005 for residential
customers.
As a result, we may be unable to maintain our profit margins in our electric
utility business during the rate cap periods. In particular, if we need to
purchase power supply from wholesale suppliers while retail rates are capped,
the rate restrictions may preclude full recovery of purchased power and
associated transmission costs.
PSCR: The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process provides for recovery of all
reasonable and prudent power supply costs actually incurred by us, including the
actual cost for fuel, and purchased and interchange power. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this reconciliation proceeding.
Special Contracts: We entered into multi-year electric supply contracts with
certain industrial and commercial customers. The contracts provide electricity
at specially negotiated prices, usually at a discount from tariff prices. As of
July 2004, special contracts for approximately 630 MW of load are in place, most
of which are in effect through 2005. These include, new special contracts with
Dow Corning and Hemlock Semi-Conductor for 101 MW of load, which received final
approval from the MPSC in May 2004 and special contracts with several hospitals
totaling 52 MW of load, which received approval from the MPSC in July 2004. We
cannot predict whether additional special contracts will be necessary,
advisable, or approved.
CE-23
CMS Energy Corporation
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. An unfavorable outcome could result in a reduction of sale proceeds
previously recognized by approximately $2 million to $3 million.
There are multiple proceedings and a proposed rulemaking pending before the FERC
regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemakings could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking, and trends are not
quantifiable currently. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings. For example, Commonwealth Edison Company
received approval from the FERC to join the PJM RTO effective May 1, 2004 and
American Electric Power Service Corporation received approval from the FERC to
join the PJM RTO effective October 1, 2004. These integrations could create
different patterns of flow and power within the Midwest area and could affect
adversely our ability to provide reliable service to our customers.
August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid
serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
As a result, federal and state investigations regarding the cause of the
blackout were conducted. These investigations resulted in the NERC and the U.S.
and Canadian Power System Outage Task Force releasing electric operations
recommendations. Few of the recommendations apply directly to us, since we are
not a transmission owner. However, the recommendations could result in increased
transmission costs to us and require upgrades to our distribution system. The
financial impacts of these recommendations are not quantifiable currently.
We have complied with an MPSC order requiring Michigan utilities and
transmission companies to submit a report concerning relay settings on their
systems by May 10, 2004. In July 2004, the MPSC closed the docket concerning the
investigation into the August 14, 2003 blackout. Also, we have complied with the
FERC order requiring entities that own, operate, or control designated
transmission facilities to report on their vegetation management practices by
June 17, 2004. This FERC order affected a total of six miles of high voltage
lines located on or adjacent to some generating plant properties.
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."
UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in
Essexville, Michigan experienced a failure on the exciter. The exciter is a
device that provides the magnetic field to the main electric generator.
Replacement of the exciter is expected to take several months. In the interim we
have installed a temporary replacement, which is rented from Detroit Edison.
However, under the agreement, Detroit Edison can recall the exciter at any time.
To hedge against 235 MW of this risk and ensure adequate reserve margins during
the summer peak periods, we have entered into two short-term capacity contracts.
As of July 2004, the rented exciter has been installed and the Karn unit is
operating effectively. The financial impacts of the unit outage are not
currently quantifiable.
CE-24
Consumers Energy Company
FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new
generation market power screens and modified measures to mitigate market power
where it is found. The screens will apply to all initial market-based rate
applications and reviews on an interim basis, which occur every three years.
Based on preliminary reviews, we believe that we will pass the established
screens.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of June 2004, we are in compliance
with the acceptable level of performance. We are a member of an industry
coalition that has appealed the customer credit portion of the performance
standards to the Michigan Court of Appeals. We cannot predict the likely effects
of the financial penalties, if any, nor can we predict the outcome of the
appeal. Likewise, we cannot predict our ability to meet the standards in the
future or the cost of future compliance.
For additional details on performance standards, see Note 2, Uncertainties,
"Electric Rate Matters -Performance Standards."
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:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the MPSC for a Certificate of
public convenience and necessity for the construction of a 25-mile gas
transmission pipeline in northern Oakland County. The project is necessary to
meet peak load beginning in the winter of 2005 through 2006. If we are unable to
construct the pipeline due to local opposition, we will need to pursue more
costly alternatives or possibly curtail serving the system's load growth in that
area.
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results
and conditions. These trends or uncertainties could have a material impact on
net sales, revenues, or income from gas operations. The trends and uncertainties
include:
Environmental
- potential environmental remediation costs at a number of sites,
including sites formerly housing manufactured gas plant facilities.
CE-25
Consumers Energy Company
Regulatory
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pipeline integrity maintenance and replacement costs, and
- other pending litigation.
We sell gas to retail customers under tariffs approved by the MPSC. These
tariffs measure the volume of gas delivered to customers (i.e. mcf). However, we
purchase gas for resale on a heating value (i.e. Btu) basis. The Btu content of
the gas purchased fluctuates and may result in customers using less gas for the
same heating requirement. We fully recover our cost to purchase gas through the
approved GCR. However, since the customer may use less gas on a volumetric
basis, the revenue from the distribution charge (the non-gas cost portion of the
customer bill) could be reduced. This could affect adversely our gas utility
earnings. The amount of any possible earnings loss due to fluctuating Btu
content in future periods cannot be estimated at this time.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order, the FERC
indicated that its December 2003 order was in error. It directed us to file
within 30 days a fair and equitable title-tracking fee and to make refunds, with
interest, to customers based on the difference between the accepted fee and the
fee paid. In response to the FERC's April 2004 order, we filed a Request for
Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further
Consideration in June 2004. We expect the FERC to issue an order on the merits
of this proceeding in the third quarter of 2004. We believe that with respect to
the FERC jurisdictional transportation, we have not charged any customers title
transfer fees, so no refunds are due. At this time, we cannot predict the
outcome of this proceeding.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 2, Uncertainties, "Gas Contingencies - Gas
Environmental Matters."
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding.
GCR YEAR 2002-2003: In March 2004, a settlement agreement was approved by the
MPSC that resulted in a GCR disallowance of $11 million for the GCR period. For
additional details, see Note 2, Uncertainties, "Gas Rate Matters - Gas Cost
Recovery."
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and
CE-26
Consumers Energy Company
required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. The second quarter GCR adjustment resulted in a GCR ceiling
price of $6.57. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement, which included a quarterly mechanism for setting a GCR
ceiling price. The mechanism did not change the current ceiling price of $6.57.
Actual gas costs and revenues will be subject to an annual reconciliation
proceeding. Our GCR factor for the billing month of August is $6.39 per mcf.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim rate
order, we agreed to restrict dividend payments to our parent company, CMS
Energy, to a maximum of $190 million annually during the period of 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,
which was supported by the MPSC Staff and the ALJ further recommended that the
application be dismissed. In response to the Proposal for Decision, the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
The June 2001 depreciation case 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, would result in an annual increase of $12 million in depreciation
expense based on December 2002 plant balances. In June 2004, the ALJ issued a
Proposal for Decision recommending adoption of the Michigan Attorney General's
proposal to reduce our annual depreciation expense by $52 million. In response
to the Proposal for Decision, the parties filed exceptions and are expected to
file replies to exceptions. In our exceptions, we proposed alternative
depreciation rates that would result in an annual decrease of $7 million in
depreciation expense. The MPSC is not bound by the ALJ's recommendation and will
review the exceptions and replies to exceptions prior to issuing an order on
final depreciation rates.
CE-27
Consumers Energy Company
OTHER OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:
- retail gas business energy related services,
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business. In June 2004, the MPSC directed the parties to a
pending complaint case involving Consumers to file briefs discussing whether the
case is affected by the legislation.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
LITIGATION AND REGULATORY INVESTIGATION: CMS Energy is the subject of various
investigations as a result of round-trip trading transactions by CMS MST,
including an investigation by the DOJ. Additionally, CMS Energy and Consumers
are named as parties in various litigation including a shareholder derivative
lawsuit, a securities class action lawsuit, and a class action lawsuit alleging
ERISA violations. For additional details regarding these investigations and
litigation, see Note 2, Uncertainties.
NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not
CE-28
Consumers Energy Company
previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No.
46 provided an implementation deferral until the first quarter of 2004. As of
and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation
No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership
and the FMLP. We have a 49 percent partnership interest in the MCV Partnership
and a 46.4 percent partnership interest in the FMLP. Consumers is the primary
purchaser of power from the MCV Partnership through a long-term power purchase
agreement. In addition, the FMLP holds a 75.5 percent lessor interest in the MCV
Facility, which results in Consumers holding a 35 percent lessor interest in the
MCV Facility. Collectively, these interests make us the primary beneficiary of
these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $728 million at June 30, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.453 billion at
June 30, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.
We are not required to restate prior periods for the impact of this accounting
change.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $148 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$11 million for the six months ended June 30, 2004, and an expected total
reduction of $23 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million for the three months ended June
30, 2004, $8 million for the six months ended June 30, 2004, and an expected
total net expense reduction of $16 million for 2004.
CE-29
Consumers Energy Company
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CE-30
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------
In Millions
OPERATING REVENUE $ 923 $ 902 $ 2,470 $ 2,344
EARNINGS FROM EQUITY METHOD INVESTEES - 18 - 34
OPERATING EXPENSES
Fuel for electric generation 170 76 324 156
Purchased and interchange power 50 75 100 157
Purchased power - related parties 15 120 31 252
Cost of gas sold 195 184 858 703
Cost of gas sold - related parties -- -- 1 25
Other operating expenses 177 167 348 327
Maintenance 57 56 107 108
Depreciation, depletion and amortization 98 79 231 195
General taxes 50 24 112 83
----------------------------------------------
812 781 2,112 2,006
- ----------------------------------------------------------------------------------------------------
OPERATING INCOME 111 139 358 372
OTHER INCOME (DEDUCTIONS)
Accretion expense (1) (2) (2) (4)
Interest and dividends 4 2 7 5
Other income 11 2 22 4
Other expense (1) (1) (2) (14)
----------------------------------------------
13 1 25 (9)
- ----------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 72 51 145 93
Interest on long-term debt - related parties 11 -- 22 --
Other interest 4 3 7 8
Capitalized interest (1) (3) (3) (5)
----------------------------------------------
86 51 171 96
- ----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 38 89 212 267
INCOME TAXES 13 37 72 105
MINORITY INTERESTS 1 -- 11 --
----------------------------------------------
NET INCOME 24 52 129 162
PREFERRED STOCK DIVIDENDS 1 1 1 1
PREFERRED SECURITIES DISTRIBUTIONS -- 11 -- 22
----------------------------------------------
NET INCOME AVAILABLE TO COMMON STOCKHOLDER $ 23 $ 40 $ 128 $ 139
====================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-31
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30 2004 2003
- --------------------------------------------------------------------------------------------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 129 $ 162
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $3 and $3, respectively) 231 195
Capital lease and other amortization 13 13
Loss on CMS Energy stock - 12
Distributions from related parties less than earnings - (35)
Changes in assets and liabilities:
Increase in accounts receivable and accrued revenue (106) (124)
Increase (decrease) in accounts payable 44 (41)
Decrease in inventories 75 20
Deferred income taxes and investment tax credit 72 74
Decrease in other assets 52 33
Increase (Decrease) in other liabilities 54 (120)
--------------------
Net cash provided by operating activities $ 564 $ 189
- --------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (232) $ (215)
Cost to retire property (37) (36)
Restricted cash on hand (a) (2) -
Investments in Electric Restructuring Implementation Plan (3) (4)
Investments in nuclear decommissioning trust funds (3) (3)
Proceeds from nuclear decommissioning trust funds 23 18
Maturity of MCV restricted investment securities held-to-maturity 300 -
Purchase of MCV restricted investment securities held-to-maturity (300) -
Cash proceeds from sale of assets - 15
--------------------
Net cash used in investing activities $ (254) $ (225)
- --------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt $ - $ 1,148
Retirement of long-term debt (14) (574)
Payment of common stock dividends (105) (109)
Preferred securities distributions - (22)
Payment of preferred stock dividends (1) (1)
Payment of capital lease obligations (5) (7)
Decrease in notes payable, net - (457)
--------------------
Net cash used in financing activities $ (125) $ (22)
- --------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 185 $ (58)
Cash and Cash Equivalents from Effect of Revised FASB
Interpretation No. 46 174 -
Cash and Cash Equivalents, Beginning of Period 46 244
--------------------
Cash and Cash Equivalents, End of Period (a) $ 405 $ 186
============================================================================================
CE-32
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
In Millions
Six Months Ended
June 30 2004 2003
- ------------------------------------------------------------------
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $119 $ 93
Income taxes paid 5 29
OPEB cash contribution 33 36
NON-CASH TRANSACTIONS
Other assets placed under capital lease 1 10
=================================================================
(a) Cash and Cash Equivalents decreased $18 million for the six months ended
June 30, 2003 from the amount previously reported due to the
reclassification of restricted cash. The change in restricted cash is now
reflected as an investing activity.
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-33
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
JUNE 30 JUNE 30
2004 DECEMBER 31 2003
(UNAUDITED) 2003 (UNAUDITED)
- --------------------------------------------------------------------------------------------------------------------
In Millions
PLANT (AT ORIGINAL COST)
Electric $ 7,776 $ 7,600 $ 7,465
Gas 2,898 2,875 2,805
Other 2,517 15 21
---------------------------------------
13,191 10,490 10,291
Less accumulated depreciation, depletion and amortization 5,520 4,417 4,357
---------------------------------------
7,671 6,073 5,934
Construction work-in-progress 379 375 427
---------------------------------------
8,050 6,448 6,361
- --------------------------------------------------------------------------------------------------------------------
INVESTMENTS
Stock of affiliates 22 20 19
First Midland Limited Partnership - 224 263
Midland Cogeneration Venture Limited Partnership - 419 422
Other 18 18 2
---------------------------------------
40 681 706
- --------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 405 46 186
Restricted cash 20 18 18
Accounts receivable, notes receivable and accrued revenue, less allowances
of $8, $8 and $5 respectively 395 257 346
Accounts receivable - related parties 12 4 22
Inventories at average cost
Gas in underground storage 664 739 458
Materials and supplies 72 70 74
Generating plant fuel stock 60 41 42
Deferred property taxes 141 143 103
Regulatory assets 19 19 19
Derivative instruments 114 2 2
Other 62 78 87
---------------------------------------
1,964 1,417 1,357
- --------------------------------------------------------------------------------------------------------------------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 627 648 669
Postretirement benefits 151 162 174
Abandoned Midland Project 10 10 11
Other 318 266 255
Nuclear decommissioning trust funds 559 575 553
Prepaid pension costs 353 364 -
Other 337 174 178
---------------------------------------
2,355 2,199 1,840
---------------------------------------
TOTAL ASSETS $ 12,409 $ 10,745 $ 10,264
====================================================================================================================
CE-34
STOCKHOLDER'S EQUITY AND LIABILITIES
JUNE 30 JUNE 30
2004 DECEMBER 31 2003
(UNAUDITED) 2003 (UNAUDITED)
- --------------------------------------------------------------------------------------------------------------
In Millions
CAPITALIZATION
Common stockholder's equity
Common stock, authorized 125.0 shares; outstanding
84.1 shares for all periods $ 841 $ 841 $ 841
Paid-in capital 682 682 682
Accumulated other comprehensive income (loss) 26 17 (183)
Retained earnings since December 31, 1992 544 521 522
---------------------------------------
2,093 2,061 1,862
Preferred stock 44 44 44
Company-obligated mandatorily redeemable preferred securities
of subsidiaries - - 490
Long-term debt 3,564 3,583 3,338
Long-term debt - related parties 506 506 -
Non-current portion of capital and finance lease obligations 338 58 119
---------------------------------------
6,545 6,252 5,853
- --------------------------------------------------------------------------------------------------------------
MINORITY INTERESTS 669 - -
- --------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt, capital leases and finance leases 487 38 40
Notes payable - related parties 200 200 -
Accounts payable 270 200 233
Accrued taxes 161 209 129
Accounts payable - related parties 11 75 62
Current portion of purchase power contract 13 27 26
Deferred income taxes 29 33 39
Other 354 185 206
---------------------------------------
1,525 967 735
- --------------------------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES
Deferred income taxes 1,307 1,233 993
Regulatory Liabilities
Cost of removal 1,016 983 950
Income taxes, net 321 312 313
Other 165 172 155
Postretirement benefits 178 190 597
Asset retirement obligations 405 358 363
Deferred investment tax credit 82 85 87
Power purchase agreement - MCV Partnership - - 14
Other 196 193 204
---------------------------------------
3,670 3,526 3,676
- --------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 1, 2, and 5)
TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $ 12,409 $ 10,745 $ 10,264
==============================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-35
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)
Three Months Ended Six Months Ended
JUNE 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
In Millions
COMMON STOCK
At beginning and end of period (a) $ 841 $ 841 $ 841 $ 841
- -------------------------------------------------------------------------------------------------------------------------
OTHER PAID-IN CAPITAL
At beginning and end of period 682 682 682 682
- -------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (185) - (185)
Minimum liability pension adjustment (b) - (17) - (17)
-------------------------------------------------
At end of period - (202) - (202)
-------------------------------------------------
Investments
At beginning of period 10 1 9 1
Unrealized gain on investments (c) - 7 1 7
-------------------------------------------------
At end of period 10 8 10 8
-------------------------------------------------
Derivative Instruments
At beginning of period 15 9 8 5
Unrealized gain on derivative instruments (c) 4 6 13 13
Reclassification adjustments included in consolidated net (loss) (c) (3) (4) (5) (7)
-------------------------------------------------
At end of period 16 11 16 11
- -------------------------------------------------------------------------------------------------------------------------
Total Accumulated Other Comprehensive Income (Loss) 26 (183) 26 (183)
- -------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
At beginning of period 548 535 521 545
Net Income 24 52 129 162
Cash dividends declared - Common Stock (27) (53) (105) (162)
Cash dividends declared - Preferred Stock (1) (1) (1) (1)
Preferred securities distributions - (11) - (22)
-------------------------------------------------
At end of period 544 522 544 522
- -------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON STOCKHOLDER'S EQUITY $ 2,093 $ 1,862 $ 2,093 $ 1,862
=========================================================================================================================
CE-36
THREE MONTHS ENDED SIX MONTHS ENDED
(UNAUDITED) 2004 2003 2004 2003
- ------------------------------------------------------------------------------ --------- --------- --------- ---------
(a) Number of shares of common stock outstanding was 84,108,789 for all
periods presented
(b) Because of the significant change in the makeup of the pension plan due
to the sale of Panhandle, SFAS No. 87 required a remeasurement of the
obligation at the date of sale. The remeasurement resulted in an
additional charge to Accumulated Other Comprehensive Income of
approximately $27 million ($17 million after tax) in 2003 as a result of
the increase in the additional minimum pension liability
(c) Disclosure of Comprehensive Income (Loss):
Minimum pension liability adjustment (b) $ - $ (17) $ - $ (17)
Investments
Unrealized gain on investments, net of tax of
$-, $4, $- and $3, respectively - 7 1 7
Derivative Instruments
Unrealized gain on derivative instruments, net of tax
$3, $3, $7, and $7, respectively 4 6 13 13
Reclassification adjustments included in net income,
net of tax benefit $2, $2, $3 and $4, respectively (3) (4) (5) (7)
Net income 24 52 129 162
--------- --------- --------- ---------
Total Comprehensive Income $ 25 $ 44 $ 138 $ 158
========= ========= ========= =========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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Consumers Energy Company
CONSUMERS ENERGY COMPANY
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by Consumers
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. Certain prior year amounts have been reclassified to
conform to the presentation in the current year. In management's opinion, the
unaudited information contained in this report reflects all adjustments of a
normal recurring nature necessary to assure the fair presentation of financial
position, results of operations and cash flows for the periods presented. The
Condensed Notes to Consolidated Financial Statements and the related
Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
contained in the Consumers' Form 10-K for the year ended December 31, 2003. Due
to the seasonal nature of Consumers' operations, the results as presented for
this interim period are not necessarily indicative of results to be achieved for
the fiscal year.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: Consumers, 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.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
Consumers, and all other entities in which we have a controlling financial
interest or are the primary beneficiary, in accordance with Revised FASB
Interpretation No. 46. The primary beneficiary of a variable interest entity is
the party that absorbs or receives a majority of the entity's expected losses or
expected residual returns or both as a result of holding variable interests,
which are ownership, contractual, or other economic interests. In 2004, we
consolidated the MCV Partnership and the FMLP in accordance with Revised FASB
Interpretation No. 46. For additional details, see Note 7, Implementation of New
Accounting Standards. We use the equity method of accounting for investments in
companies and partnerships that are not consolidated, where we have significant
influence over operations and financial policies, but are not the primary
beneficiary. Intercompany transactions and balances have been eliminated.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. We are required
to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.
We are required to record estimated liabilities in the financial statements when
it is probable that a loss will be incurred in the future as a result of a
current event, and when the amount can be reasonably estimated. We have used
this accounting principle to record estimated liabilities as discussed in Note
2, Uncertainties.
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Consumers Energy Company
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas, and the storage of natural gas when services are provided.
Sales taxes are recorded as liabilities and are not included in revenues.
CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred. Our regulated businesses are permitted to
capitalize an allowance for funds used during construction on regulated
construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents. At
June 30, 2004, our restricted cash on hand was $20 million. Restricted cash
primarily includes cash dedicated for repayment of Securitization bonds. It is
classified as a current asset as the payments on the related Securitization
bonds occur within one year.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. 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 reflected in Regulatory Liabilities. The fair value of our
equity securities is determined from quoted market prices. For additional
details regarding financial instruments, see Note 4, Financial and Derivative
Instruments.
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the
quantity of heat produced for electric generation. For nuclear fuel used after
April 6, 1983, we charge disposal costs to nuclear fuel expense, recover these
costs through electric rates, and remit them to the DOE quarterly. We elected to
defer payment for disposal of spent nuclear fuel burned before April 7, 1983. As
of June 30, 2004, we have recorded a liability to the DOE for $140 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."
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:
In Millions
- ------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
---------------------------------------------
June 30 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------
Other income
PA 141 Return on Capital Expenditures $ 9 $ - $ 18 $ -
Electric restructuring return 1 2 3 3
All other 1 - 1 1
- ------------------------------------------------------------------------------------------
Total other income $ 11 $ 2 $ 22 $ 4
==========================================================================================
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Consumers Energy Company
In Millions
- ----------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
------------------------------------------------
June 30 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------
Other expense
Loss on CMS Energy stock $ - $ - $ - $ (12)
Civic and political expenditures - - (1) (1)
All other (1) (1) (1) (1)
- ----------------------------------------------------------------------------------------
Total other expense $ (1) $ (1) $ (2) $ (14)
===================================== ========= ========= ========= =========
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 6, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
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 this Note.
Our financial statements reflect the assets, liabilities, revenues, and expenses
directly related to the electric and gas segment where it is appropriate. We
allocate accounts between the electric and gas segments where common accounts
are attributable to both segments. The allocations are based on certain measures
of business activities such as revenue, labor dollars, customers, other
operation and maintenance and construction expense, leased property, taxes, or
functional surveys. For example, customer receivables are allocated based on
revenue. Pension provisions are allocated based on labor dollars.
The following table shows our financial information by reportable segment. We
account for inter-segment sales and transfers at current market prices and
eliminate them in consolidated net income available to common stockholder by
segment. The "Other" segment includes our consolidated special purpose entity
for the sale of trade receivables and our variable interest entities.
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Consumers Energy Company
In Millions
- --------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
---------------------- ----------------------
June 30 2004 2003 2004 2003
- ------------------------------------------ --------- --------- --------- ---------
Operating revenue
Electric $ 612 $ 603 $ 1,243 $ 1,256
Gas 300 299 1,205 1,088
Other 11 - 22 -
--------- --------- --------- ---------
Total Operating Revenue $ 923 $ 902 $ 2,470 $ 2,344
========= ========= ========= =========
Net income available to common stockholder
Electric $ 27 $ 35 $ 75 $ 86
Gas 1 5 57 59
Other (5) - (4) (6)
--------- --------- --------- ---------
Total Net Income $ 23 $ 40 $ 128 $ 139
========= ========= ========= =========
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.
2: UNCERTAINTIES
Several 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 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
expense 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,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an electric
transmission owner.
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Consumers Energy Company
Regulatory
- recovery of nuclear decommissioning costs,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- other pending litigation.
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by
CMS MST, CMS Energy's Board of Directors established a Special Committee to
investigate matters surrounding the transactions and retained outside counsel to
assist in the investigation. The Special Committee completed its investigation
and reported its findings to the Board of Directors in October 2002. The Special
Committee concluded, based on an extensive investigation, that the round-trip
trades were undertaken to raise CMS MST's profile as an energy marketer with the
goal of enhancing its ability to promote its services to new customers. The
Special Committee found no effort to manipulate the price of CMS Energy Common
Stock or affect energy prices. The Special Committee also made recommendations
designed to prevent any recurrence of this practice. Previously, CMS Energy
terminated its speculative trading business and revised its risk management
policy. The Board of Directors adopted, and CMS Energy has implemented the
recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading. CMS Energy is unable to predict the outcome of this matter and what
effect, if any, this investigation will have on its business. In March 2004, the
SEC approved a cease-and-desist order settling an administrative action against
CMS Energy related to round-trip trading. The order did not assess a fine and
CMS Energy neither admitted nor denied the order's findings. The settlement
resolved the SEC investigation involving CMS Energy and CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It generally seeks unspecified damages based on allegations that the
defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. The judge issued an opinion
and order dated March 31, 2004 in connection with various pending motions,
including plaintiffs' motion to amend the complaint and the motions to dismiss
the complaint filed by CMS Energy, Consumers and other defendants. The judge
directed plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend, which was held on May 12, 2004. At the
hearing, the judge ordered plaintiffs to file a Second Amended Consolidated
Class Action complaint deleting Counts III and IV relating to purchasers of CMS
PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this
complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants
filed new motions to dismiss on June 21, 2004. A hearing on those motions
occurred on August 2, 2004 and the judge has taken the matter under advisement.
CMS Energy, Consumers and the individual defendants will
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Consumers Energy Company
defend themselves vigorously but cannot predict the outcome of this litigation.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST,
and certain named and unnamed officers and directors, in two lawsuits brought as
purported class actions on behalf of participants and beneficiaries of the CMS
Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July
2002 in United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution
on behalf of the Plan with respect to a decline in value of the shares of CMS
Energy Common Stock held in the Plan. Plaintiffs also seek other equitable
relief and legal fees. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants filed
answers to the amended complaint on May 14, 2004. A trial date has not been set,
but is expected to be no earlier than late in 2005. 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: The EPA and the state regulations require us to make significant
capital expenditures estimated to be $771 million. As of June 30, 2004, we have
incurred $489 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $282 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology at some of our coal-fired electric plants. Based on the
Customer Choice Act, beginning January 2004, an annual return of and on these
types of capital expenditures, to the extent they are above depreciation levels,
is expected to be recoverable from customers, subject to the MPSC prudency
hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.
In addition to modifying the coal-fired electric plants, we expect to purchase
nitrogen oxide emissions credits for years 2004 through 2008. The cost of these
credits is estimated to average $8 million per year and is accounted for as
inventory. The credit inventory is expensed as the coal-fired electric plants
generate electricity. The price for nitrogen oxide emissions credits is volatile
and could change substantially.
The EPA has proposed a Clean Air Interstate Rule that would require additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. If implemented, this rule would potentially require expenditures
equivalent to those efforts in progress required to reduce nitrogen oxide
emissions under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the
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Consumers Energy Company
EPA also proposed two alternative sets of rules to reduce emissions of mercury
and nickel from coal-fired and oil-fired electric plants. Until the proposed
environmental rules are finalized, an accurate cost of compliance cannot be
determined.
Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that greenhouse gas emission reduction rules come into effect,
such mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. We stay abreast of and engage in
the greenhouse gas policy developments, and will continue to assess and respond
to their potential implications on our business operations.
Water: In March 2004, the EPA changed the rules that govern generating plant
cooling water intake systems. The new rules require significant reduction in
fish killed by operating equipment. Some of our facilities will be required to
comply by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental
Protection Act, we expect that we will ultimately incur investigation and
remedial action costs at a number of sites. We believe that these costs will be
recoverable in rates under current ratemaking policies.
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 June 30, 2004, we have recorded
a liability for the minimum amount of our estimated Superfund liability.
In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at the Ludington Pumped
Storage facility. We removed and replaced part of the PCB material. We have
proposed a plan to deal with the remaining materials and are awaiting a response
from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made pursuant
to power purchase agreements with qualifying facilities. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants. We believe we
have been performing the calculation in the manner prescribed by the power
purchase agreements, and have filed a request with the MPSC (as a supplement to
the PSCR plan) that asks the MPSC to review this issue and to confirm that our
method of performing the calculation is correct. We filed a motion to dismiss
the lawsuit in the Ingham County Circuit Court due to the pending request at the
MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
resulted in a dismissal of the circuit court case without prejudice. Although
only eight qualifying facilities have raised the issue, the same energy charge
methodology is used in the PPA with the MCV Partnership and in
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Consumers Energy Company
approximately 20 additional power purchase agreements with us, representing a
total of 1,670 MW of electric capacity. The eight plaintiff qualifying
facilities have appealed the dismissal of the circuit court case to the Michigan
Court of Appeals. We cannot predict the outcome of this matter.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: The Michigan legislature passed electric
utility restructuring legislation known as the Customer Choice Act. This Act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
- 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 to comply with the Customer
Choice Act; for additional details regarding the sale of the transmission
facility, see "Transmission Sale" within this section. Second, in July 2002, the
MPSC issued an order approving our plan to achieve the increased transmission
capacity required under the Customer Choice Act. We have completed the
transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms,
and conditions under which retail customers are permitted to choose an electric
supplier. These revised tariffs allow ROA customers, upon as little as 30 days
notice to us, to return to our generation service at current tariff rates. If
any class of customers' (residential, commercial, or industrial) ROA load
reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods. We cannot predict the total amount of electric supply load that may be
lost to alternative electric suppliers. As of July 2004, alternative electric
suppliers are providing 858 MW of load. This amount represents 11 percent of the
total distribution load and an increase of 49 percent compared to July 2003.
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Consumers Energy Company
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs,
- security costs, and
- transmission rates.
The following chart summarizes the filings with the MPSC. For additional details
related to these proceedings, see related sections within this Note.
- ---------------------------------------------------------------------------------------------------
Years Years Requested
Proceeding Filed Covered Amounts Status
- ---------------------------------------------------------------------------------------------------
Securitization 2003 N/A $1.083 billion Received order from the MPSC
authorizing the issuance of
Securitization bonds in the amount of
$554 million. Pending MPSC order
resolving outstanding issues.
Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero
Stranded Costs for 2000 through 2001,
which we are appealing. Filings for
2002 and 2003 in the amount of
$116 million are still pending MPSC
approval.
Implementation 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the
Costs years 1997-2001, plus $20 million for
the cost of money through 2003.
Implementation cost filings for 2002
and 2003 in the amount of $8 million,
which includes the cost of money
through 2003, are still pending MPSC
approval.
Security Costs 2004 2001-2005 $25 million Pending MPSC approval. As of
June 30, 2004, we have recorded
$7 million of costs incurred as a
regulatory asset.
===================================================================================================
(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes the issuance of Securitization bonds
in an amount that includes Clean Air Act investments. If Clean Air Act
investments were not included in the issuance of Securitization bonds, Stranded
Costs requested would total $304 million.
(b) Amounts include the cost of money through year incurred.
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Consumers Energy Company
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 before the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2003 true up modified the total
Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills
per kWh. There will be no impact on customer bills from Securitization for most
of our electric customers until the Customer Choice Act cap period expires, and
an electric rate case is processed. Securitization charge collections, $25
million for the six months ended June 30, 2004, and $25 million for the six
months ended June 30, 2003, are remitted to a trustee. Securitization charge
collections are restricted to the repayment of the principal and interest on the
Securitization bonds and payment of the ongoing expenses of Consumers Funding.
Consumers Funding is legally separate from Consumers. The assets and income of
Consumers Funding, including the securitized property, are not available to
creditors of Consumers or CMS Energy.
In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
This amount relates to Clean Air Act expenditures and associated return on those
expenditures through December 31, 2002, ROA implementation costs and previously
authorized return on those expenditures through December 31, 2000, and other up
front qualified costs related to issuance of the Securitization bonds. In July
2003, we filed for rehearing and clarification on a number of features in the
financing order.
In December 2003, the MPSC ordered remanded hearings in response to our request
for rehearing and clarification. In March 2004, the MPSC conducted the remanded
hearings and the matter is presently before the MPSC awaiting a decision.
In May 2004, we withdrew our request for approved implementation costs incurred
for the years 1998 through 2000 from the Securitization case, as we chose
recovery of the approved implementation costs through the use of a surcharge, as
described in "Implementation Costs" within this section. However, qualified
Clean Air Act costs, after taking out implementation costs, still exceed the
$554 million MPSC limit on the amount of securitized bonds. As a result, we did
not request a decrease to allowable securitized costs. If and when the MPSC
issues an order with favorable terms, then the order will become effective upon
our acceptance.
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Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. The Act directs the MPSC to
establish a method of calculating net Stranded Costs and of conducting related
true-up adjustments. In December 2001, the MPSC Staff recommended a methodology,
which calculated net Stranded Costs as the shortfall between:
- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and
- the revenues received from customers under existing rates available
to cover the revenue requirement.
The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost transition
charge. However, the MPSC has not yet allowed such a transition charge. The MPSC
has 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. As a result, we have not recorded regulatory assets to recognize
the future recovery of such costs.
The following table outlines the applications filed by us with the MPSC and the
status of recovery for these costs:
In Millions
- --------------------------------------------------------------------------------------------
Requested, without the
Requested, with the issuance issuance of Securitization
of Securitization bonds that bonds that include Clean Air
Year Year include Clean Air Act Act investment and cost of Recoverable
Filed Incurred investment and cost of money money amount
- --------------------------------------------------------------------------------------------
2002 2000 $12 $ 26 $ -
2002 2001 9 46 -
2003 2002 47 104 Pending
2004 2003 69 128 Pending
============================================================================================
We are currently in the process of appealing the MPSC orders regarding Stranded
Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan
Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded
Cost application. Once a final financing order on Securitization is reached, we
will know the amount of our request for net Stranded Cost recovery for 2002. In
July 2004, the ALJ issued a proposal for decision in our 2002 net Stranded Cost
case, which recommended that the MPSC find that we incurred net Stranded Costs
of $12 million. This recommendation includes the cost of money through July 2004
and excludes Clean Air Act investments.
The MPSC has scheduled hearings for our 2003 Stranded Cost application for
August 2004. In July 2004, the MPSC Staff issued a position on our 2003 net
Stranded Cost application, which resulted in a Stranded Cost calculation of $52
million. The amount includes the cost of money, but excludes Clean Air Act
investments. We cannot predict how the MPSC will rule on our requests for
recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a
Stranded Cost recovery method that will offset fully any associated margin loss
from ROA.
Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines the
applications filed by us with the MPSC and the status of recovery for these
costs:
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In Millions
- -----------------------------------------------------------------------------------------------
Recoverable, including
(b) cost of money through
Year Filed Year Incurred Requested Disallowed Allowed 2003
- -----------------------------------------------------------------------------------------------
1999 1997 & 1998 $20 $5 $15 $22
2000 1999 30 5 25 33
2001 2000 25 5 20 24
2002 2001 8 - 8 9
2003 & 2004 (a) 2002 7 Pending Pending Pending
2004 2003 1 Pending Pending Pending
===============================================================================================
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.
(b) Amounts include the cost of money through year incurred.
In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million, for implementation costs related to our former participation in the
development of the Alliance RTO which includes the $5 million pending approval
by the MPSC as part of 2002 implementation costs recovery. These costs have
generally either been expensed or approved as recoverable implementation costs
by the MPSC. The FERC has denied our request for reimbursement and we are
appealing the FERC ruling at the United States Court of Appeals for the District
of Columbia. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. As of
June 30, 2004, we incurred and deferred as a regulatory asset $94 million of
implementation costs, which includes $25 million associated with the cost of
money. We believe the implementation costs and associated cost of money are
fully recoverable in accordance with the Customer Choice Act.
In June 2004, following an appeal and remand of initial MPSC orders relating to
1999 implementation costs, the MPSC authorized the recovery of all previously
approved implementation costs for the years 1997 through 2001 totaling $88
million. This total includes carrying costs through 2003. Additional carrying
costs will be added until collection occurs. The implementation costs will be
recovered through surcharges over 36-month collection periods and phased in as
applicable rate caps expire. We cannot predict the amounts the MPSC will approve
as recoverable costs for 2002 and 2003.
Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs, as a result of federal and state regulatory
security requirements incurred before January 1, 2006. All retail customers,
except customers of alternative electric suppliers, would pay these charges. In
April 2004, we filed a security cost recovery case with the MPSC for costs for
which recovery has not yet been granted through other means. The requested
amount includes reasonable and prudent security enhancements through December
31, 2005. The costs are for enhanced security and insurance because of federal
and state regulatory security requirements imposed after the September 11, 2001
terrorist attacks. In July 2004, a settlement was reached with the parties to
the case, which would provide for full recovery of the requested security costs
over a five-year period beginning in
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2004. We are presently awaiting approval from the MPSC. We cannot predict how
the MPSC will rule on our request for the recoverability of security costs. The
following table outlines the applications filed by us with the MPSC and the
status of recovery for these costs:
In Millions
- -----------------------------------------------------------------------------
Year Years Regulatory asset as of
Filed Incurred Requested June 30, 2004 Disallowed Allowed
- -----------------------------------------------------------------------------
2004 2001-2005 $25 $7 Pending Pending
=============================================================================
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 to MTH,
a non-affiliated limited partnership whose general partner is a subsidiary of
Trans-Elect, Inc. We are currently in arbitration with MTH regarding property
tax items used in establishing the selling price of our electric transmission
system. An unfavorable outcome could result in a reduction of sale proceeds
previously recognized of approximately $2 million to $3 million.
Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to the FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges, which
we estimate to be $10 million in 2004.
ELECTRIC RATE MATTERS
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of June 2004, we are in compliance
with the acceptable level of performance. We are a member of an industry
coalition that has appealed the customer credit portion of the performance
standards to the Michigan Court of Appeals. We cannot predict the likely effects
of the financial penalties, if any, nor can we predict the outcome of the
appeal. Likewise, we cannot predict our ability to meet the standards in the
future or the cost of future compliance.
POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.
To reduce the risk of high electric prices during peak demand periods and to
achieve our reserve margin target, we employ a strategy of purchasing electric
call options and capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. As of June 30, 2004, we purchased capacity and energy contracts
partially covering the estimated reserve margin requirements for 2004 through
2007. As a result, we have recognized an asset of $18 million for unexpired
capacity and energy contracts. In March 2004, we filed a summer assessment for
meeting 2004 peak load demand as required by the MPSC, stating that our summer
2004 reserve margin target is 11 percent or supply resources equal to 111
percent of projected summer peak load. Presently, we have a reserve margin of 14
percent, or supply resources equal to 114 percent of
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projected summer peak load for summer 2004. Of the 114 percent, approximately
102 percent is from owned electric generating plants and long-term contracts,
and approximately 12 percent is from short-term contracts. This reserve margin
met our summer 2004 reserve margin target. The total premium costs of
electricity call options and capacity and energy contracts for 2004 is expected
to be approximately $12 million, as of July 2004.
PSCR: As a result of meeting the transmission capability expansion requirements
and the market power test, as discussed with in this Note, we have met the
requirements under the Customer Choice Act to return to the PSCR process. The
PSCR process provides for the reconciliation of actual power supply costs with
power supply revenues. This process assures recovery of all reasonable and
prudent power supply costs actually incurred by us. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers, and subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this reconciliation proceeding.
OTHER ELECTRIC UNCERTAINTIES
THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and operates
the MCV Facility, contracted to sell electricity to Consumers for a 35-year
period beginning in 1990 and to supply electricity and steam to Dow. We hold,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and
- CMS Holdings holds, through the FMLP, a 35 percent lessor interest
in the MCV Facility.
In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated
financial statements in accordance with Revised FASB Interpretation No. 46. For
additional details, see Note 7, Implementation of New Accounting Standards.
Our consolidated retained earnings include undistributed earnings from the MCV
Partnership, which at June 30, 2004 are $246 million and at June 30, 2003 are
$243 million.
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 capacity 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
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and thereafter. However, due to the frozen retail rates required by the Customer
Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents per kWh
until December 31, 2003. Recovery of both the 915 MW and 325 MW portions of the
PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $13 million at June 30, 2004 and $40 million at June 30, 2003.
We expect the PPA liability to be depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004 will be
charged to the PPA liability, with the remaining portion charged to operating
expense as a result of our 49 percent ownership in the MCV Partnership. We will
expense all cash underrecoveries directly to income once the PPA liability is
depleted. If the MCV Facility's generating availability remains at the maximum
98.5 percent level, our cash underrecoveries associated with the PPA could be as
follows:
In Millions
- ------------------------------------------------------------------
2004 2005 2006 2007
- ------------------------------------------------------------------
Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
==================================================================
Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV's Partnership's financial performance and our investment
in the MCV Partnership is and will be affected adversely.
Under the PPA, variable energy payments to the MCV Partnership are based on the
cost of coal burned at our coal plants and our operation and maintenance
expenses. However, the MCV Partnership's costs of producing electricity are tied
to the cost of natural gas. Because natural gas prices have increased
substantially in recent years and the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 2007, we expect to
claim relief under the regulatory out provision in the PPA, limiting our
capacity and fixed energy payments to the MCV Partnership to the amount
collected from our customers. The MPSC's future actions on the capacity and
fixed energy payments recoverable from customers subsequent to September 2007
may affect negatively the earnings of the MCV Partnership and the value of our
investment in the MCV Partnership.
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Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC
that is intended to help conserve natural gas and thereby improve our investment
in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The RCP will reduce the MCV Facility's annual production of electricity and, as
a result, reduce the MCV Facility's consumption of natural gas 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. 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. Presently, we
are in settlement discussions with the parties to the RCP filing. However, in
July 2004, several qualifying facilities filed for a stay on the RCP proceeding
in the Ingham County Circuit Court after their previous attempt to intervene on
the proceeding was denied by the MPSC. Hearings on the stay are scheduled for
August 11, 2004. We cannot predict if or when the MPSC will approve the RCP or
the outcome of the Ingham County Circuit Court hearings.
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
20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Natural gas prices have been volatile
historically. Presently, there is no consensus in the marketplace on the price
or range of future prices of natural gas. Even with an approved RCP, if gas
prices continue at present levels or increase, the economics of operating the
MCV Facility may be adverse enough to require us to recognize an impairment of
our investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision
has been appealed to the Michigan Court of Appeals by the City of Midland and
the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals.
The MCV Partnership also has a pending case with the Michigan Tax Tribunal for
tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of
these proceedings; therefore, the above refund (net of approximately $15 million
of deferred expenses) has not been recognized in year-to-date 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
Decommissioning funding practices approved by the MPSC require us to file a
report on the adequacy of funds for decommissioning at three-year intervals. We
prepared and filed updated cost estimates for each plant on March 31, 2004.
Excluding additional costs for spent nuclear fuel storage, due to the DOE's
failure to accept this spent nuclear fuel on schedule, these reports show a
decommissioning cost
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of $361 million for Big Rock and $868 million for Palisades. Since Big Rock is
currently in the process of being decommissioned, the estimated cost includes
historical expenditures in nominal dollars and future costs in 2003 dollars,
with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding
the decommissioning trust funds for both sites. In December 2000, funding of the
Big Rock trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. The MPSC order set the annual
decommissioning surcharge for Palisades at $6 million through 2007. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
However, based on current projections, the current levels of funds provided by
the trusts are not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
in "Nuclear Matters". We will also seek additional relief from the MPSC.
In the case of Big Rock, excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept this spent fuel on schedule, we are currently
projecting that the level of funds provided by the trust will fall short of the
amount needed to complete the decommissioning by $25 million. At this point in
time, we plan to provide the additional amounts needed from our corporate funds
and, subsequent to the completion of radiological decommissioning work, seek
recovery of such expenditures at the MPSC. We cannot predict how the MPSC will
rule on our request.
In the case of Palisades, again excluding additional nuclear fuel storage costs
due to the DOE's failure to accept this spent fuel on schedule, we have
concluded that the existing surcharge needs to be increased to $25 million
annually, beginning January 1, 2006, and continue through 2011, our current
license expiration date. In June 2004, we filed an application with the MPSC
seeking approval to increase the surcharge for recovery of decommissioning costs
related to Palisades beginning in 2006. We cannot predict how the MPSC will rule
on our request.
NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. The restoration project is on
schedule to return approximately 530 acres of the site, including the area
formerly occupied by the nuclear plant, to a natural setting for unrestricted
use in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
The NRC and the Michigan Department of Environmental Quality continue to find
all decommissioning activities at Big Rock are being performed in accordance
with applicable regulations including license requirements.
Palisades: In March 2004, the NRC completed its end-of-cycle plant performance
assessment of Palisades. The assessment for Palisades covered the period from
January 1, 2003 through December 31, 2003. The NRC determined that Palisades was
operated in a manner that preserved public health and safety and fully met all
cornerstone objectives. As of June 2004, all inspection findings were classified
as having very low safety significance and all performance indicators indicated
performance at
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a level requiring no additional oversight. Based on the plant's performance,
only regularly scheduled inspections are planned through September 2005.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of June
30, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled
to load additional dry casks this summer in order to continue operation.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE
was to begin accepting deliveries of spent nuclear fuel for disposal by January
1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. In July 2004, the DOE filed an amended answer and motion to
dismiss the complaint. 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. We expect that
the DOE will submit, by December 2004, an application to the NRC for a license
to begin construction of the repository. The application and review process is
estimated to take several years.
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council,
the Public Interest Research Group in Michigan, and the Michigan Consumer
Federation filed a complaint with the MPSC, which was served on us by the MPSC
in April 2003. The complaint asks the MPSC to initiate a generic investigation
and contested case to review all facts and issues concerning costs associated
with spent nuclear fuel storage and disposal. The complaint seeks a variety of
relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric
Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
We are unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $27 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily
injury and off-site property damage resulting from a nuclear hazard for up to
approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide
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program where owners of nuclear generating facilities could be assessed if a
nuclear incident occurs at any nuclear generating facility. The maximum
assessment against us could be $101 million per occurrence, limited to maximum
annual installment payments of $10 million.
We also maintain insurance under a program that covers tort claims for bodily
injury to nuclear workers caused by nuclear hazards. The policy contains a $300
million nuclear industry aggregate limit. Under a previous insurance program
providing coverage for claims brought by nuclear workers, we remain responsible
for a maximum assessment of up to $6 million.
Big Rock remains insured for nuclear liability by a combination of insurance and
a NRC indemnity totaling $544 million and a nuclear property insurance policy
from NEIL.
Insurance policy terms, limits, and conditions are subject to change during the
year as we renew our policies.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2005, and total an
estimated $147 million. Our coal transportation contracts expire through 2007,
and total an estimated $108 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is not finalized at
this time, we believe that it will be within the historic 60 to 90 percent
range.
Power Supply, Capacity, and Transmission: As of June 30, 2004, 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. These contracts require monthly
capacity payments based on the plants' availability or deliverability. These
payments for 2004 through 2030 total an estimated $4.537 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant was not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.
GAS CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur 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.
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We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-year average of U.S. Treasury bond rates reduced for increases in the
consumer price index. We expect to fund most of these costs through insurance
proceeds and through the MPSC approved rates charged to our customers. As of
June 30, 2004, we have recorded a regulatory liability of $42 million, net of
$41 million of expenditures incurred to date, and a regulatory asset of $66
million. Any significant change in assumptions, such as an increase in the
number of sites, different remediation techniques, nature and extent of
contamination, and legal and regulatory requirements, could affect our estimate
of remedial action costs.
In its November 2002 gas distribution rate order, the MPSC authorized us to
continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.
GAS RATE MATTERS
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding.
GCR YEAR 2002-2003: 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 underrecovered gas costs using a roll-in
methodology. The roll-in methodology incorporates the GCR underrecovery 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 2002-2003 GCR case.
Their positions were that not all of our gas purchasing decisions were prudent
during April 2002 through March 2003 and they proposed disallowances. In 2003,
we reserved $11 million for a settlement agreement associated with the 2002-2003
GCR disallowance. Interest on the disallowed amount from April 1, 2003 through
February 2004, at Consumers' authorized rate of return, increased the cost of
the settlement by $1 million. The interest was recorded as an expense in 2003.
In February 2004, the parties in the case reached a settlement agreement that
resulted in a GCR disallowance of $11 million for the GCR period. The settlement
agreement was approved by the MPSC in March 2004. The disallowance is included
in our 2003-2004 GCR reconciliation filed in June 2004.
GCR YEAR 2003-2004: In June 2004, we filed a reconciliation of GCR for the
12-months ended March 2004. We proposed to refund to our customers $28 million
of overrecovered gas cost, plus interest. The refund will be included in the
2004-2005 GCR plan year. The overrecovery includes the $11 million refund
settlement for the 2002-2003 GCR year, as well as refunds received by us from
our suppliers and required by the MPSC to be refunded to our customers.
GCR PLAN FOR YEAR 2004-2005: In December 2003, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. The second quarter GCR adjustment resulted in a GCR ceiling
price of $6.57. In June 2004, the MPSC issued a final Order
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Consumers Energy Company
in our GCR plan approving a settlement, which included a quarterly mechanism for
setting a GCR ceiling price. The mechanism did not change the current ceiling
price of $6.57. Actual gas costs and revenues will be subject to an annual
reconciliation proceeding. Our GCR factor for the billing month of August is
$6.39 per mcf.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim order, we
agreed to restrict dividend payments to our parent company, CMS Energy, to a
maximum of $190 million annually during the period of 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, which was
supported by the MPSC Staff and the ALJ further recommended that the application
be dismissed. In response to the Proposal for Decision, the parties have filed
exceptions and replies to exceptions. The MPSC is not bound by the ALJ's
recommendation and will review the exceptions and replies to exceptions prior to
issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order that reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief.
The June 2001 depreciation case 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, would result in an annual increase of $12 million in depreciation
expense based on December 2002 plant balances. In June 2004, the ALJ issued a
Proposal for Decision recommending adoption of the Michigan Attorney General's
proposal to reduce our annual depreciation expense by $52 million. In response
to the Proposal for Decision, the parties filed exceptions and are expected to
file replies to exceptions. In our exceptions, we proposed alternative
depreciation rates that would result in an annual decrease of $7 million in
depreciation expense. The MPSC is not bound by the ALJ's recommendation and will
review the exceptions and replies to exceptions prior to issuing an order on
final depreciation rates.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we provide. In
December 2003, the FERC ruled that no refunds were at issue and we reversed $4
million related to this matter. In January 2004, three companies filed with the
FERC for clarification or rehearing of the FERC's December 2003 order. In April
2004, the FERC issued its Order Granting Clarification. In that Order, the FERC
indicated that its December 2003 order was in error. It directed us to file
within 30 days a fair and equitable title-tracking fee and to make refunds, with
interest, to customers based on the difference between the accepted fee and the
fee paid. In response to the FERC's April 2004 order, we filed a Request for
Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further
Consideration in June 2004. We expect the FERC to issue an order on the merits
of this proceeding in the third quarter of 2004. We believe that with respect to
the FERC jurisdictional transportation, we have not charged any customers title
transfer fees, so no refunds are due. At this time, we cannot predict the
outcome of this proceeding.
CE-59
Consumer Energy Company
OTHER UNCERTAINTIES
In addition to the matters disclosed within 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 within
this Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
3: FINANCINGS AND CAPITALIZATION
LONG-TERM DEBT:
Long-term debt is summarized as follows:
In Millions
- -------------------------------------------------------------------
June 30, 2004 December 31, 2003
- -------------------------------------------------------------------
First mortgage bonds $ 1,483 $ 1,483
Senior notes 1,254 1,254
Bank debt and other 468 469
Securitization bonds 412 426
FMLP debt 411 -
--------------------------------
Principal amounts outstanding 4,028 3,632
Current amounts (444) (28)
Net unamortized discount (20) (21)
- -------------------------------------------------------------------
Total Long-term debt $ 3,564 $ 3,583
===================================================================
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At June 30, 2004, long-term debt of the FMLP consists of:
In Millions
- -------------------------------------------------------------------
Maturity 2004
- -------------------------------------------------------------------
11.75% subordinated secured notes 2005 $185
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
- -------------------------------------------------------------------
Total amount outstanding $411
===================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV
Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy
and Consumers.
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Consumer Energy Company
DEBT MATURITIES: At June 30, 2004, the aggregate annual maturities for long-term
debt for six months ending December 31, 2004 and the next four years are:
In Millions
- ------------------------------------------------------------
Payments Due
-------------------------------------
December 31 2004 2005 2006 2007 2008
- ------------------------------------------------------------
Long-term debt $ 129 $ 559 $ 478 $ 59 $ 504
============================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: Effective July 1, 2004, we received new
FERC authorization to issue or guarantee up to $1.1 billion of short-term
securities and up to $1.1 billion of short-term first mortgage bonds as
collateral for such short-term securities. Effective July 1, 2004, we received
new FERC authorization to issue up to $1 billion of long-term securities for
refinancing or refunding purposes, $1.5 billion of long-term securities for
general corporate purposes, and $2.5 billion of long-term first mortgage bonds
to be issued solely as collateral for other long-term securities.
SHORT-TERM FINANCINGS: At June 30, 2004, we had a $400 million secured revolving
credit facility with banks. At June 30, 2004, $24 million of letters of credit
were issued and outstanding under this facility and $376 million was available
for general corporate purposes, working capital, and letters of credit. The MCV
Partnership had a $50 million working capital facility available.
As of August 3, 2004, we obtained an amended and restated $500 million secured
revolving credit facility to replace our $400 million facility. The amended
facility carries a three-year term and provides for lower interest rates.
FIRST MORTGAGE BONDS: We secure our first mortgage bonds by a mortgage and lien
on substantially all of our property. Our ability to issue and sell securities
is restricted by certain provisions in the first mortgage bond indenture, our
articles of incorporation, and the need for regulatory approvals under federal
law.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. As of June 30, 2004, capital
lease obligations totaled $64 million. In order to obtain permanent financing
for the MCV Facility, the MCV Partnership entered into a sale and lease back
agreement with a lessor group, which includes the FMLP, for substantially all of
the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV
Partnership accounted for the transaction as a financing arrangement. As of June
30, 2004, finance lease obligations totaled $317 million, which represents the
third-party portion of the MCV Partnership's finance lease obligation.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently sell certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. We sold no receivables at June 30, 2004 and we sold $50 million at
June 30, 2003. The Consolidated Balance Sheets exclude these sold 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.
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Consumer Energy Company
Certain cash flows received from and paid to us under our accounts receivable
sales program are shown below:
In Millions
- ------------------------------------------------------------------------------------------
Six Months Ended June 30 2004 2003
- ------------------------------------------------------------------------------------------
Proceeds from sales (remittance of collections) under the program $ (297) $ (275)
Collections reinvested under the program $ 2,645 $ 2,459
==========================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
June 30, 2004, we had $396 million of unrestricted retained earnings available
to pay common stock dividends. However, covenants in our debt facilities cap
common stock dividend payments at $300 million in a calendar year. We are also
under an annual dividend cap of $190 million imposed by the MPSC during the
current interim gas rate relief period. In February 2004, we paid $78 million
and in May 2004, we paid $27 million in common stock dividends to CMS Energy.
For additional details on the cap on common stock 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.
The following tables describe our guarantees at June 30, 2004:
In Millions
- --------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount Provision (a)
- --------------------------------------------------------------------------------------------------------
Standby letters of credit Various Various $ 24 $ - $ -
Surety bonds and other indemnifications Various Various 8 - -
Nuclear insurance retrospective premiums Various Various 134 - -
========================================================================================================
(a) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
CE-62
Consumer Energy Company
- ---------------------------------------------------------------------------------------------------------------------
Events That Would Require
Guarantee Description How Guarantee Arose Performance
- ---------------------------------------------------------------------------------------------------------------------
Standby letters of credit Normal operations of coal power Noncompliance with environmental
plants regulations
Natural gas transportation Nonperformance
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, permits Nonperformance
and license
Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price-Anderson Act
for nuclear incident
======================================================================================================================
4: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and
current liabilities approximate their fair values because of their short-term
nature. We estimate the fair values of long-term financial instruments based on
quoted market prices or, in the absence of specific market prices, on quoted
market prices of similar instruments or other valuation techniques. The carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of June 30,
2004. These securities represent funds restricted primarily for future lease
payments and are classified as Other Assets on the Consolidated Balance Sheets.
These investments have original maturity dates of approximately one year or less
and, because of their short maturities, their carrying amounts approximate their
fair values. For additional details, see Note 1, Corporate Structure and
Accounting Policies.
In Millions
- ----------------------------------------------------------------------------------------------------
June 30 2004 2003
- ------------------------------------------------------------------------ ---------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain (Loss) Cost Value Gain (Loss)
- ------------------------------------------------------------------------ ---------------------------
Long-term debt (a) $4,008 $4,088 $ (80) $3,365 $3,529 $ (164)
Long-term debt - related parties (b) 506 512 (6) - - -
Trust Preferred Securities (b) - - - 490 512 (22)
Available-for-sale securities:
Common stock of CMS Energy (c) 10 22 12 10 19 9
SERP 17 22 5 17 20 3
Nuclear decommissioning
investments (d) 434 559 125 453 553 100
====================================================================================================
(a) Includes a principal amount of $444 million at June 30, 2004 and $27 million
at June 30, 2003 relating to current maturities. Settlement of long-term debt is
generally not expected until maturity.
(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities have been deconsolidated as of
December 31, 2003 and are reflected in Long-term debt - related parties on the
Consolidated Balance Sheets. For additional details, see Note 7, Implementation
of New Accounting Standards.
(c) As of June 30, 2004, we held 2.4 million shares of CMS Energy Common Stock.
CE-63
Consumer Energy Company
(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 included 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. 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. Our
electric capacity and energy contracts are not accounted for as derivatives due
to the lack of an active energy market in the state of Michigan, as defined by
SFAS No. 133, and the significant transportation costs that would be incurred to
deliver the power under the contracts to the closest active energy market at the
Cinergy hub in Ohio. If an active market develops in the future, we may be
required to account for these contracts as derivatives. The mark-to-market
impact on earnings related to these contracts could be material to the financial
statements.
CE-64
Consumer Energy Company
Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk and interest rate risk. The following table
reflects the fair value of all contracts requiring derivative accounting:
In Millions
- -------------------------------------------------------------------------------------------------------
June 30 2004 2003
- -------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- -------------------------------------------------------------------------------------------------------
Electric - related contracts $ - $ - $ - $ 8 $ - $ (8)
Gas contracts 3 6 3 2 1 (1)
Derivative contracts associated with
Consumers' investment in the MCV
Partnership:
Prior to consolidation - - - - 20 20
After consolidation:
Gas fuel contracts - 80 80 - - -
Gas fuel futures, options, and swaps - 54 54 - - -
=======================================================================================================
The fair value of our derivative contracts is included in Derivative
Instruments, Other Assets, or Other Liabilities on the Consolidated Balance
Sheets. The fair value of derivative contracts associated with our investment in
the MCV Partnership for 2003 is included in Investments - Midland Cogeneration
Venture Limited Partnership on the Consolidated Balance Sheets.
ELECTRIC CONTRACTS: Our electric utility business uses purchased electric call
option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods.
GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process.
INTEREST RATE RISK CONTRACTS: We frequently use interest rate swaps to hedge the
risk associated with forecasted interest payments on variable-rate debt and to
reduce the impact of interest rate fluctuations. These interest rate swaps are
generally designated as cash flow hedges. As such, we record changes in the fair
value of these contracts in accumulated other comprehensive income unless the
swaps are sold. As of June 30, 2004 and June 30, 2003, we did not have any
interest rate swaps outstanding.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP:
Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy
gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership
believes that its long-term natural gas contracts, which do not contain volume
optionality, qualify under SFAS No. 133 for the normal purchases and normal
sales exception. Therefore, these contracts are currently not recognized at fair
value on the balance sheet. Should significant changes in the level of the MCV
Facility operational dispatch or purchases of long-term gas occur, the MCV
Partnership would be required to re-evaluate its accounting treatment for these
long-term gas contracts. This re-evaluation may result in recording
mark-
CE-65
Consumer Energy Company
to-market activity on some contracts, which could add to earnings volatility.
At June 30, 2004, the MCV Partnership had six long-term gas contracts that
contained both an option and forward component. Because of the option component,
these contracts do not qualify for the normal purchases and sales exception and
are accounted for as derivatives, with changes in fair value recorded in
earnings each quarter. The MCV Partnership expects future earnings volatility on
these six contracts, since gains or losses will be recorded on a quarterly basis
during the remaining life of approximately four years for these gas contracts.
For the six months ended June 30, 2004, the MCV Partnership recorded in Fuel for
electric generation a $6 million net gain in earnings associated with these
contracts.
Gas Fuel Futures, Options, and Swaps: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. The MCV Partnership enters into natural gas futures contracts, option
contracts, and over-the-counter swap transactions in order to hedge against
unfavorable changes in the market price of natural gas in future months when gas
is expected to be needed. These financial instruments are being used principally
to secure anticipated natural gas requirements necessary for projected electric
and steam sales, and to lock in sales prices of natural gas previously obtained
in order to optimize the MCV Partnership's existing gas supply, storage, and
transportation arrangements.
These financial instruments are accounted for as derivatives under SFAS No. 133.
The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. The MCV Partnership also engages in cost mitigation
activities to offset the fixed charges the MCV Partnership incurs in operating
the MCV Facility. These cost mitigation activities include the use of futures
and options contracts to purchase and/or sell natural gas to maximize the use of
the transportation and storage contracts when it is determined that they will
not be needed for the MCV Facility operation. Although these cost mitigation
activities do serve to offset the fixed monthly charges, these cost mitigation
activities are not considered a normal course of business for the MCV
Partnership and do not qualify as hedges under SFAS No. 133. Therefore, the
mark-to-market gains and losses from these cost mitigation activities are
recorded in earnings each quarter.
For the six months ended June 30, 2004, the MCV Partnership has recorded an
unrealized gain of $24 million in other comprehensive income on those futures
contracts that qualify as cash flow hedges, which resulted in a cumulative net
gain of $55 million in other comprehensive income as of June 30, 2004. This
balance represents natural gas futures, options, and swaps with maturities
ranging from July 2004 to December 2009, of which $34 million of this gain is
expected to be reclassified as an increase to earnings within the next 12
months. As of June 30, 2004, Consumers' pretax proportionate share of the MCV
Partnership's $55 million net gain recorded in other comprehensive income is $27
million, of which $17 million is expected to be reclassified as an increase to
earnings within the next 12 months. In addition, for the six months ended June
30, 2004, the MCV Partnership has recorded a net gain of $16 million in earnings
from hedging activities related to natural gas requirements for the MCV Facility
operations and a net gain of $1 million in earnings from cost mitigation
activities.
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Consumer Energy Company
5: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after
June 30, 2003,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.
As of June 30, 2004, we have recorded a prepaid pension asset of $373 million,
$20 million of which is in Other current assets on our Consolidated Balance
Sheet.
OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992. We
recorded a liability of $466 million for the accumulated transition obligation
and a corresponding regulatory asset for anticipated recovery in utility rates.
For additional details, see Note 1, Corporate Structure and Accounting Policies,
"Utility Regulation." In 1994, the MPSC authorized recovery of the electric
utility portion of these costs over 18 years and in 1996, the MPSC authorized
recovery of the gas utility portion of these costs over 16 years. We have made
contributions of $33 million to our 401(h) and VEBA trust funds in 2004. We plan
to make additional contributions of $30 million in 2004.
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
- ----------------------------------------------------------------------------------
Pension
Three Months Ended Six Months Ended
- ----------------------------------------------------------------------------------
June 30 2004 2003 2004 2003
- ----------------------------------------------------------------------------------
Service cost $ 9 $ 9 $ 19 $ 19
Interest expense 18 18 36 37
Expected return on plan assets (27) (21) (54) (41)
Amortization of:
Net loss 4 3 7 5
Prior service cost 2 2 3 4
-------------------------------------
Net periodic pension cost $ 6 $ 11 $ 11 $ 24
==================================================================================
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Consumer Energy Company
In Millions
- -----------------------------------------------------------------------------------------
OPEB
Three Months Ended Six Months Ended
- -----------------------------------------------------------------------------------------
June 30 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Service cost $ 4 $ 5 $ 9 $ 9
Interest expense 14 16 27 31
Expected return on plan assets (11) (10) (23) (20)
Amortization of:
Net loss 3 4 6 9
Prior service cost (2) (2) (4) (3)
-------------------------------------
Net periodic postretirement benefit cost $ 8 $ 13 $ 15 $ 26
=========================================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the
Act) was signed into law in December 2003. The Act establishes a prescription
drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is
exempt from federal taxation, to sponsors of retiree health care benefit plans
that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $148 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$11 million for the six months ended June 30, 2004, and an expected total
reduction of $23 million for 2004. The reduction of $23 million includes $7
million in capitalized OPEB costs. For additional details, see Note 7,
Implementation of New Accounting Standards.
6: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: 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 a:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities instead of a cumulative effect of a change in accounting
principle.
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions, such as costs, inflation,
and profit margin that third parties would consider to assume the settlement of
the obligation. Fair value, to the extent possible, should include a
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Consumer Energy Company
market risk premium for unforeseeable circumstances. No market risk premium was
included in our ARO fair value estimate since a reasonable estimate could not be
made. If a five percent market risk premium were assumed, our ARO liability
would increase by $22 million.
If a reasonable estimate of fair value cannot be made in the period the ARO is
incurred, such as for assets with indeterminate lives, the liability is to be
recognized when a reasonable estimate of fair value can be made. Generally,
transmission and distribution assets have indeterminate lives. Retirement cash
flows cannot be determined and there is a low probability of a retirement date.
Therefore, no liability has been recorded for these assets. Also, no liability
has been recorded for assets that have insignificant cumulative disposal costs,
such as substation batteries. The measurement of the ARO liabilities for
Palisades and Big Rock are based on decommissioning studies that largely utilize
third-party cost estimates.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
June 30, 2004 In Millions
- -----------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- -----------------------------------------------------------------------------------------------------------------------
Palisades - decommission plant site 1972 Palisades nuclear plant $495
Big Rock - decommission plant site 1962 Big Rock nuclear plant 64
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 -
=======================================================================================================================
June 30, 2004 In Millions
- -------------------------------------------------------------------------------------------------------------
ARO Liability ARO
------------- Cash flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 6/30/04
- -------------------------------------------------------------------------------------------------------------
Palisades - decommission $249 $268 $ - $ - $ 10 $ 31 $309
Big Rock - decommission 61 35 - (24) 6 22 39
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - (1) 3 - 54
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
-------------------------------------------------------------------
Total $364 $358 $ - $(25) $ 19 $ 53 $405
=============================================================================================================
The Palisades and Big Rock cash flow revisions resulted from new decommissioning
reports filed with the MPSC in March 2004. For additional details, see Note 2,
Uncertainties, "Other Electric Uncertainties - Nuclear Plant Decommissioning."
Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
cost of removal obligations have been accrued through depreciation charges. We
estimate that we had $1.016 billion at June 30, 2004 and $950 million at June
30, 2003 of previously accrued asset removal costs related to our regulated
operations arising from other than legal obligations. These obligations, which
were previously classified as a component of accumulated
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Consumer Energy Company
depreciation, are now classified as regulatory liabilities in the accompanying
Consolidated Balance Sheets.
7: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership
and the FMLP. We have a 49 percent partnership interest in the MCV Partnership
and a 46.4 percent partnership interest in the FMLP. Consumers is the primary
purchaser of power from the MCV Partnership through a long-term power purchase
agreement. In addition, the FMLP holds a 75.5 percent lessor interest in the MCV
Facility, which results in Consumers holding a 35 percent lessor interest in the
MCV Facility. Collectively, these interests make us the primary beneficiary of
these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $728 million at June 30, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.453 billion at
June 30, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.
We are not required to restate prior periods for the impact of this accounting
change.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.
The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.
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Consumer Energy Company
We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $148 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended June 30, 2004,
$11 million for the six months ended June 30, 2004, and an expected total
reduction of $23 million for 2004. Consumers capitalizes a portion of OPEB cost
in accordance with regulatory accounting. As such, the remeasurement resulted in
a net reduction of OPEB expense of $4 million for the three months ended June
30, 2004, $8 million for the six months ended June 30, 2004, and an expected
total net expense reduction of $16 million for 2004.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
CMS ENERGY
Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: CMS Energy Corporation's Management's Discussion and Analysis, which is
incorporated by reference herein.
CONSUMERS
Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: Consumers Energy Company's Management's Discussion and Analysis, which is
incorporated by reference herein.
ITEM 4. CONTROLS AND PROCEDURES
CMS ENERGY
Disclosure Controls and Procedures: CMS Energy's management, with the
participation of its CEO and CFO, has evaluated the effectiveness of its
disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, CMS Energy's CEO and CFO have concluded
that, as of the end of such period, its disclosure controls and procedures are
effective.
Internal Control Over Financial Reporting: There have not been any changes in
CMS Energy's internal control over financial reporting (as such term is defined
in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.
CONSUMERS
Disclosure Controls and Procedures: Consumers' management, with the
participation of its CEO and CFO, has evaluated the effectiveness of its
disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, Consumers' CEO and CFO have concluded
that, as of the end of such period, its disclosure controls and procedures are
effective.
Internal Control Over Financial Reporting: There have not been any changes in
Consumers' internal control over financial reporting (as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The discussion below is limited to an update of developments that have occurred
in various judicial and administrative proceedings, many of which are more fully
described in CMS Energy's and Consumers' Forms 10-K/A for the year ended
December 31, 2003. Reference is also made to the CONDENSED NOTES TO THE
CONSOLIDATED FINANCIAL STATEMENTS, in particular, Note 3, Uncertainties for CMS
Energy and Note 2, Uncertainties for Consumers, included herein for additional
information regarding various pending administrative and judicial proceedings
involving rate, operating, regulatory and environmental matters.
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CMS ENERGY
SEC REQUEST
On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy
voluntarily produce all documents and data relating to the SEC's inquiry into
payments made to the government and officials of the government of Equatorial
Guinea. CMS Energy will fully cooperate with the SEC in its inquiry. From 1991
through January 3, 2002, subsidiaries of CMS Energy held interests in, and
beginning in 1995 operated, hydrocarbon production and processing facilities
and a methanol plant in Equatorial Guinea. On January 3, 2002, CMS Energy sold
all its Equatorial Guinea holdings. The SEC's inquiry follows an investigation
and public hearing conducted by the United States Senate Permanent Subcommittee
on Investigations, which reviewed the U.S. banking transactions of various
foreign governments, including that of Equatorial Guinea. The investigation and
hearing also reviewed the operations of certain U.S. oil companies in
Equatorial Guinea. There were no findings of violations of the U.S. Foreign
Corrupt Practices Act by the U.S. oil companies in the report of the Minority
Staff of the Subcommittee, the only report issued to date as a result of the
hearing. The Subcommittee did find that oil companies operating in Equatorial
Guinea may have contributed to corrupt practices in that country.
SEC INVESTIGATION
In March 2004, the SEC approved a cease-and-desist order settling an
administrative action against CMS Energy related to round-trip trading. The
order did not assess a fine and CMS Energy neither admitted nor denied the
order's findings. The settlement resolved the SEC investigation involving CMS
Energy and CMS MST. In March 2004, the SEC also filed an action against three
former employees related to round-trip trading by CMS MST. One of the
individuals has settled with the SEC. CMS Energy is currently advancing legal
defense costs for the remaining two individuals in accordance with existing
indemnification policies.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS
In May 2002, the Board of Directors of CMS Energy received a demand, on behalf
of a shareholder of CMS Energy Common Stock, that it commence civil actions (i)
to remedy alleged breaches of fiduciary duties by certain CMS Energy officers
and directors in connection with round-trip trading by CMS MST, and (ii) to
recover damages sustained by CMS Energy as a result of alleged insider trades
alleged to have been made by certain current and former officers of CMS Energy
and its subsidiaries. In December 2002, two new directors were appointed to the
Board. The Board formed a special litigation committee in January 2003 to
determine whether it is in CMS Energy's best interest to bring the action
demanded by the shareholder. The disinterested members of the Board appointed
the two new directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to September 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. CMS Energy cannot predict the outcome of this
matter.
INTEGRUM LAWSUIT
Integrum filed a complaint in Wayne County, Michigan Circuit Court in July 2003
against CMS Energy, Enterprises and APT. Integrum alleges several causes of
action against APT, CMS Energy, and Enterprises in connection with an offer by
Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified
money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises
from selling, and APT from purchasing, the CMS Pipeline Assets and an order of
specific performance mandating that CMS Energy, Enterprises, and APT complete
the sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and
director of Integrum is a former officer and director of CMS Energy, Consumers,
and their subsidiaries. The individual was not employed by CMS Energy,
Consumers, or their subsidiaries when Integrum made the offer to purchase the
CMS Pipeline Assets. CMS Energy and Enterprises filed a motion to change venue
from Wayne County to Jackson County, which was granted. The parties are now
awaiting transfer of the file from Wayne County to Jackson County. CMS Energy
and Enterprises believe that Integrum's claims are without merit. CMS Energy and
Enterprises intend to defend vigorously against this action but they cannot
predict the outcome of this litigation.
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GAS INDEX PRICE REPORTING LITIGATION
In August 2003, Cornerstone Propane Partners, L.P. ("Cornerstone") filed a
putative class action complaint in the United States District Court for the
Southern District of New York against CMS Energy and dozens of other energy
companies. The court ordered the Cornerstone complaint to be consolidated with
similar complaints filed by Dominick Viola and Roberto Calle Gracey. The
plaintiffs filed a consolidated complaint on January 20, 2004. The consolidated
complaint alleges that false natural gas price reporting by the defendants
manipulated the prices of NYMEX natural gas futures and options. The complaint
contains two counts under the Commodity Exchange Act, one for manipulation and
one for aiding and abetting violations. CMS Energy is no longer a defendant,
however, CMS MST and CMS Field Services are named as defendants. (CMS Energy
sold CMS Field Services to Cantera Natural Gas, Inc. but is required to
indemnify Cantera Natural Gas, Inc. with respect to this action.)
In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a putative
class action lawsuit in the United States District Court for the Eastern
District of California against a number of energy companies engaged in the sale
of natural gas in the United States. CMS Energy is named as a defendant. The
complaint alleges defendants entered into a price-fixing conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair and deceptive business practices. There is currently pending
in the Nevada federal district court a multi district court litigation ("MDL")
matter involving seven complaints originally filed in various state courts in
California. These complaints make allegations similar to those in the Texas-Ohio
case regarding price reporting, although none contain a Sherman Act claim and
some of the defendants in the MDL matter are also defendants in the Texas-Ohio
case. Those defendants successfully argued to have the Texas-Ohio case
transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case agreed
to extend the time for all defendants to answer or otherwise respond until May
28, 2004 and on that date a number of defendants filed motions to dismiss. In
order to negotiate possible dismissal and/or substitution of defendants, CMS
Energy and two other parent holding company defendants were given further
extensions to answer or otherwise respond to the complaint to August 16, 2004.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court, which was
granted, and had it transferred to the MDL proceeding in Nevada. However, the
plaintiff is seeking to have the case remanded back to California and until the
issue is resolved, no further action will be taken.
Three new, virtually identical actions were filed in San Diego Superior Court in
July, 2004, one by the County of Santa Clara ("Santa Clara"), one by the County
of San Diego (San Diego) and one by the City of and County of San Francisco and
the San Francisco City Attorney (collectively "San Francisco"). Defendants,
consisting of a number of energy companies including CMS Energy, CMS MS&T,
Cantera Natural Gas and Cantera Gas Company, are alleged to have engaged in
false reporting of natural gas price and volume information and sham sales to
artificially inflate natural gas retail prices in California. All three
complaints allege claims for unjust enrichment and violations of the Cartwright
Act, and the San Francisco action also alleges a claim for violation of the
California Business and Profession Code relating to unlawful, unfair and
deceptive business practices.
CMS Energy and the other CMS defendants will defend themselves vigorously but
cannot predict the outcome of these matters.
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LEONARD FIELD DISPUTE
Pursuant to a Consent Judgment entered in Oakland County, Michigan Circuit Court
in September 2001, CMS Gas Transmission had 18 months to extract approximately
one bcf of pipeline quality natural gas held in the Leonard Field in Addison
Township. The Consent Judgment provided for an extension of that period upon
certain circumstances. CMS Gas Transmission has complied with the requirements
of the Consent Judgment. Addison Township filed a lawsuit in Oakland County
Circuit Court against CMS Gas Transmission in February 2004 alleging the Leonard
Field was discharging odors in violation of the Consent Judgment. Pursuant to a
Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain
undertakings to address the odor complaints and further agreed to temporarily
cease operations at the Leonard Field during the month of April 2004, the last
month provided for in the Consent Judgment. Also, Addison Township was required
to grant CMS Gas Transmission an extension to withdraw its natural gas if
certain conditions were met. Addison Township denied CMS Gas Transmission's
request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its
legal remedies and filed a complaint against Addison Township in June 2004. CMS
Gas Transmission cannot predict the outcome of this matter, and unless an
extension is provided, it will be unable to extract approximately 500,000 mcf of
gas remaining in the Leonard Field.
CMS ENERGY AND CONSUMERS
ERISA LAWSUITS
CMS Energy is a named defendant, along with Consumers, CMS MST, and certain
named and unnamed officers and directors, in two lawsuits brought as purported
class actions on behalf of participants and beneficiaries of the CMS Employees'
Savings and Incentive Plan (the "Plan"). The two cases, filed in July 2002 in
United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution
on behalf of the Plan with respect to a decline in value of the shares of CMS
Energy Common Stock held in the Plan. Plaintiffs also seek other equitable
relief and legal fees. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants filed
answers to the amended complaint on May 14, 2004. A trial date has not been set,
but is expected to be no earlier than late in 2005. CMS Energy and Consumers
will defend themselves vigorously but cannot predict the outcome of this
litigation.
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of securities class action complaints were
filed against CMS Energy, Consumers, and certain officers and directors of CMS
Energy and its affiliates. The complaints were filed as purported class actions
in the United States District Court for the Eastern District of Michigan, by
shareholders who allege that they purchased CMS Energy's securities during a
purported class period. The cases were consolidated into a single lawsuit and an
amended and consolidated class action complaint was filed on May 1, 2003. The
consolidated complaint contains a purported class period beginning on May 1,
2000 and running through March 31, 2003. It generally seeks unspecified damages
based on allegations that the defendants violated United States securities laws
and regulations by making allegedly false and misleading statements about CMS
Energy's business and financial condition, particularly with respect to revenues
and expenses recorded in connection with round-trip trading by CMS MST. The
judge issued an opinion and order dated March 31, 2004 in connection with
various pending motions, including plaintiffs' motion to amend the complaint and
the motions to dismiss the complaint
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filed by CMS Energy, Consumers and other defendants. The judge directed
plaintiffs to file an amended complaint under seal and ordered an expedited
hearing on the motion to amend, which was held on May 12, 2004. At the hearing,
the judge ordered plaintiffs to file a Second Amended Consolidated Class Action
complaint deleting Counts III and IV relating to purchasers of CMS PEPS, which
the judge ordered dismissed with prejudice. Plaintiffs filed this complaint on
May 26, 2004. CMS Energy, Consumers, and the individual defendants filed new
motions to dismiss on June 21, 2004 and a hearing on those motions is scheduled
for August 2004. CMS Energy, Consumers and the individual defendants will defend
themselves vigorously but cannot predict the outcome of this litigation.
ENVIRONMENTAL MATTERS
CMS Energy, Consumers and their subsidiaries and affiliates are subject to
various federal, state and local laws and regulations relating to the
environment. Several of these companies have been named parties to various
actions involving environmental issues. Based on their present knowledge and
subject to future legal and factual developments, CMS Energy and Consumers
believe that it is unlikely that these actions, individually or in total, will
have a material adverse effect on their financial condition. See CMS Energy's
and Consumers' MANAGEMENT'S DISCUSSION AND ANALYSIS and CMS Energy's and
Consumers' CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the CMS Energy Annual Meeting of Shareholders held on May 28, 2004, the CMS
Energy shareholders voted upon five proposals, as follows:
- Ratification of the appointment of Ernst & Young LLP as independent
auditors of CMS Energy for the year ending December 31, 2004, with a
vote of 135,549,550 shares in favor, 2,206,503 against and 1,148,674
abstentions;
- Amendments to the Performance Incentive Stock Plan, with a vote of
85,615,290 shares in favor, 17,204,621 against and 1,794,973
abstentions;
- Permitting awards under the Incentive Compensation Plans and related
contractual arrangements to become income tax deductible by the
company, with a vote of 124,938,186 shares in favor, 12,172,123
against and 1,794,735 abstentions;
- Amending the Restated Articles of Incorporation to increase the
number of authorized shares of common stock and re-designate
authorized but unissued Class G common stock into shares of common
stock, with a vote of 130,280,753 shares in favor, 6,673,547 against
and 1,950,741 abstentions;
- Election of eleven members to the Board of Directors. The votes for
individual nominees were as follows:
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CMS ENERGY
Number of Votes: For Withheld Total
- ----------------------- ----------- ---------- -----------
Merribel S. Ayres 134,750,679 4,137,455 138,888,134
Earl D. Holton 132,968,087 5,920,047 138,888,134
David W. Joos 134,215,407 4,672,727 138,888,134
Michael T. Monahan 134,251,381 4,636,753 138,888,134
Joseph F. Paquette, Jr. 110,514,698 28,373,436 138,888,134
William U. Parfet 133,106,221 5,781,913 138,888,134
Percy A. Pierre 133,725,594 5,162,540 138,888,134
S. Kinnie Smith, Jr. 134,179,371 4,708,763 138,888,134
Kenneth L. Way 133,340,836 5,547,298 138,888,134
Kenneth Whipple 134,312,812 4,575,322 138,888,134
John B. Yasinsky 132,916,761 5,971,373 138,888,134
CONSUMERS
Consumers did not solicit proxies for the matters submitted to votes at the
contemporaneous May 28, 2004 Consumers' Annual Meeting of Shareholders. All
84,108,789 shares of Consumers Common Stock were voted in favor of electing the
above-named individuals as directors of Consumers and in favor of the remaining
proposals for Consumers. None of the 441,599 shares of Consumers Preferred Stock
were voted at the Annual Meeting.
ITEM 5. OTHER INFORMATION
A shareholder who wishes to submit a proposal for consideration at the CMS
Energy 2005 Annual Meeting pursuant to the applicable rules of the SEC must send
the proposal to reach CMS Energy's Corporate Secretary on or before December 24,
2004. In any event if CMS Energy has not received written notice of any matter
to be proposed at that meeting by March 9, 2005, the holders of the proxies may
use their discretionary voting authority on any such matter. The proposals
should be addressed to:
Corporate Secretary, CMS Energy, One Energy Plaza, Jackson, Michigan 49201.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) LIST OF EXHIBITS
(10)(a) General Waiver and Release Agreement
(10)(b) CMS Energy Corporation Policy on Change In Control Agreements and
Employment Contracts
(31)(a) CMS Energy Corporation's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(b) CMS Energy Corporation's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(c) Consumers Energy Company's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d) Consumers Energy Company's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
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(32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
(32)(b) Consumers Energy Company's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
(B) REPORTS ON FORM 8-K
CMS ENERGY
During the second quarter of 2004, CMS Energy filed or furnished the
following Current Reports on Form 8-K:
- 8-K filed on April 14, 2004 covering matters pursuant to Item
5, Other Events;
- 8-K furnished on May 6, 2004 covering matters pursuant to Item
12, Results of Operations and Financial Condition (including a
Summary of Consolidated Earnings, Summarized Comparative
Balance Sheets, Summarized Statements of Cash Flows, and a
Summary of Consolidated Earnings - Reconciliations of GAAP Net
Income (Loss) to Non-GAAP Ongoing Net Income); and
- 8-K filed on June 3, 2004 covering matters pursuant to Item 5,
Other Events.
CONSUMERS
During the second quarter of 2004, Consumers filed or furnished the
following Current Reports on Form 8-K:
- 8-K furnished on May 6, 2004 covering matters pursuant to Item
12, Results of Operations and Financial Condition (including a
Summary of Consolidated Earnings, Summarized Comparative
Balance Sheets, Summarized Statements of Cash Flows, and a
Summary of Consolidated Earnings - Reconciliations of GAAP Net
Income (Loss) to Non-GAAP Ongoing Net Income); and
- 8-K filed on June 3, 2004 covering matters pursuant to Item 5,
Other Events.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company or its subsidiary.
CMS ENERGY CORPORATION
(Registrant)
Dated: August 5, 2004 By: /s/ Thomas J. Webb
--------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
CONSUMERS ENERGY COMPANY
(Registrant)
Dated: August 5, 2004 By: /s/ Thomas J. Webb
--------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
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CMS ENERGY AND CONSUMERS EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
(10)(a) General Waiver and Release Agreement
(10)(b) CMS Energy Corporation Policy on Change In Control Agreements and
Employment Contracts
(31)(a) CMS Energy Corporation's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(b) CMS Energy Corporation's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(c) Consumers Energy Company's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d) Consumers Energy Company's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
(32)(b) Consumers Energy Company's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002