Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report for Period Ended September 30, HTML 1.04M 2007
2: EX-3.(B) Cms Energy Corporation Bylaws HTML 38K
3: EX-3.(D) Consumers Energy Company Bylaws HTML 39K
4: EX-10.(A) Form of Indemnification Agreement Between Cms HTML 46K
Energy Corporation & Its Directors
5: EX-10.(B) Form of Indemnification Agreement Between HTML 46K
Consumers Energy Company & Its Directors
6: EX-31.(A) Cms Energy Corporation's Certification of the CEO HTML 12K
Pursuant to Section 302
7: EX-31.(B) Cms Energy Corporation's Certification of the CFO HTML 13K
Pursuant to Section 302
8: EX-31.(C) Consumers Energy Corporation's Certification of HTML 13K
the CEO Pursuant to Section 302
9: EX-31.(D) Consumers Energy Corporation's Certification of HTML 13K
the CFO Pursuant to Section 302
10: EX-32.(A) Cms Energy Corporation's Certifications Pursuant HTML 10K
to Section 906
11: EX-32.(B) Consumers Energy Corporation's Certifications HTML 10K
Pursuant to Section 906
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 þ No o
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in
Rule 12b-2 of the Exchange Act. CMS Energy Corporation: Large accelerated filer þ Accelerated filer o Non-Accelerated filer o Consumers Energy Company: Large accelerated filer o Accelerated filer o Non-Accelerated filer þ
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). CMS Energy Corporation: Yes o No þ Consumers Energy Company: Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock at October 30, 2007:
CMS Energy Corporation:
CMS Energy Common Stock, $.01 par value
225,091,031
Consumers Energy Company, $10 par value, privately held by CMS Energy Corporation
CMS Energy Corporation
and
Consumers Energy Company
Quarterly reports on Form 10-Q to the
United States Securities and Exchange Commission
for the Quarter Ended September 30, 2007
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.
A 1,356 MW coal-fueled power plant in Morocco, in which CMS Generation formerly owned a 50 percent interest
Jubail
A 240 MW natural gas cogeneration power plant in Saudi Arabia, in which CMS Generation
formerly owned a 25 percent interest
kWh
Kilowatt-hour (a unit of energy equal to one thousand watt hours)
LS Power Group
LS Power Group, a non-affiliated company
Lucid Energy
Lucid Energy LLC, a non-affiliated company
Ludington
Ludington pumped storage plant, jointly owned by Consumers and Detroit Edison
mcf
One thousand cubic feet of gas
MCV Facility
A natural gas-fueled, combined-cycle cogeneration facility operated by the MCV Partnership
MCV Partnership
Midland Cogeneration Venture Limited Partnership
MCV PPA
The Power Purchase Agreement between Consumers and the MCV Partnership with a 35-year term
commencing in March 1990, as amended, and as interpreted by the Settlement Agreement dated
as of January 1, 1999 between the MCV Partnership and Consumers
MD&A
Management’s Discussion and Analysis
MDEQ
Michigan Department of Environmental Quality
MDL
Multidistrict Litigation
METC
Michigan Electric Transmission Company, LLC, a non-affiliated company
MISO
Midwest Independent Transmission System Operator, Inc.
MMBtu
Million British Thermal Units
Moody’s
Moody’s Investors Service, Inc.
MPSC
Michigan Public Service Commission
MSBT
Michigan Single Business Tax
MW
Megawatt (a unit of power equal to one million watts)
MWh
Megawatt hour (a unit of energy equal to one million watt hours)
Neyveli
CMS Generation Neyveli Ltd, a 250 MW lignite-fired power station located in India, in which
CMS International Ventures formerly owned a 50 percent interest
NMC
Nuclear Management Company LLC, formed in 1999 by Northern States Power Company (now Xcel
Energy Inc.), Alliant Energy, Wisconsin Electric Power Company, and Wisconsin Public Service
Company to operate and manage nuclear generating facilities owned by the utilities
NRC
Nuclear Regulatory Commission
NYMEX
New York Mercantile Exchange
OPEB
Postretirement benefit plans other than pensions for retired employees
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. 157
SFAS No. 157, “Fair Value Measurement”
SFAS No. 158
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)”
SFAS No. 159
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,
Including an amendment to FASB Statement No. 115”
Shuweihat
A power and desalination plant located in the United Arab Emirates, in which CMS Generation
formerly owned a 20 percent interest
Stranded Costs
Costs incurred by utilities in order to serve their customers in a regulated monopoly
environment, which may not be recoverable in a competitive environment because of customers
leaving their systems and ceasing to pay for their costs. These costs could include owned
and purchased generation and regulatory assets.
Superfund
Comprehensive Environmental Response, Compensation and Liability Act
Takoradi
A 200 MW open-cycle combustion turbine crude oil power plant located in Ghana, in which CMS
Generation formerly owned a 90 percent interest
TAQA
Abu Dhabi National Energy Company, a subsidiary of Abu Dhabi Water and Electricity Authority
Taweelah
Al Taweelah A2, a power and desalination plant of Emirates CMS Power Company located in the
United Arab Emirates, in which CMS Generation formerly held a 40 percent interest
TGM
A natural gas transportation and pipeline business located in Argentina, in which CMS
International Ventures formerly owned a 20 percent interest
TGN
A natural gas transportation and pipeline business located in Argentina, in which CMS Gas
Transmission owns a 23.54 percent interest
Trunkline
CMS Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC
Zeeland
A 946 MW gas-fired power plant located in Zeeland, Michigan
This MD&A is a consolidated report of CMS Energy and Consumers. The terms “we” and “our” as used
in this report refer to CMS Energy and its subsidiaries as a consolidated entity, except where it
is clear that such term means only CMS Energy. This MD&A has been prepared in accordance with the
instructions to Form 10-Q and Item 303 of Regulation S-K. This MD&A should be read in conjunction
with the MD&A contained in CMS Energy’s Form 10-K for the year ended December 31, 2006 and the Form
8-K filed June 4, 2007 amending CMS Energy’s 2006 financial statements to reflect certain
discontinued operations resulting from recent asset sales.
Forward-looking statements and information
This Form 10-Q and other written and oral statements that we make contain forward-looking
statements as defined in Rule 3b-6 under the Securities Exchange Act of 1934, as amended, Rule 175
under the Securities Act of 1933, as amended, and relevant legal decisions. Our intention with the
use of such words as “may,”“could,”“anticipates,”“believes,”“estimates,”“expects,”“intends,”“plans,” and other similar words is to identify forward-looking statements that involve risk and
uncertainty. We designed this discussion of potential risks and uncertainties to highlight
important factors that may impact our business and financial outlook. We have no obligation to
update or revise forward-looking statements regardless of whether new information, future events,
or any other factors affect the information contained in the statements. These forward-looking
statements are subject to various factors that could cause our actual results to differ materially
from the results anticipated in these statements. Such factors include our inability to predict
and (or) control:
•
the price of CMS Energy Common Stock, capital and financial market conditions, and
the effect of such market conditions on the Pension Plan, interest rates, and access to
the capital markets, including availability of financing to CMS Energy, Consumers, or any
of their affiliates, and the energy industry,
•
market perception of the energy industry, CMS Energy, Consumers, or any of their
affiliates,
•
the ability of CMS Energy affiliates with interests in the DIG power plant to
effectively restructure power supply agreements on a timely basis,
•
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,
•
the impact of possible regulations or laws regarding carbon dioxide and other greenhouse
gas emissions,
•
national, regional, and local economic, competitive, and regulatory policies,
conditions and developments,
•
adverse regulatory or legal decisions, including those related to environmental laws
and regulations, and potential environmental remediation costs associated with such
decisions, including but not limited to those that may affect Bay Harbor,
potentially adverse regulatory treatment and
(or) regulatory delay or failure to receive timely regulatory orders concerning a
number of significant questions presently or potentially before the
MPSC, including:
•
recovery of Clean Air Act capital and operating costs and other environmental
and safety-related expenditures,
•
recovery of power supply and natural gas supply costs when fuel prices are
increasing and (or) fluctuating,
•
timely recognition in rates of additional equity investments in Consumers,
•
adequate and timely recovery of additional electric and gas rate-based
investments,
•
adequate and timely recovery of higher MISO energy and transmission costs,
•
recovery of Stranded Costs incurred due to customers choosing alternative
energy suppliers,
•
recovery of Palisades plant sale-related costs,
•
authorization of Zeeland power plant purchase costs, and
•
authorization of a new clean coal plant,
•
the effects on our ability to purchase capacity to serve our customers and fully
recover the cost of these purchases, if the owners of the MCV Facility exercise their
right to terminate the MCV PPA,
•
the ability of Consumers to utilize its regulatory
out rights as it pertains to the MCV PPA,
•
the ability of Consumers to recover Big Rock decommissioning funding shortfalls and
nuclear fuel storage costs due to the DOE’s failure to accept spent nuclear fuel on
schedule, including the outcome of pending litigation with the DOE,
•
federal regulation of electric sales and transmission of electricity, including
periodic re-examination by federal regulators of market-based sales authorizations in
wholesale power markets without price restrictions,
•
energy markets, including availability of capacity and the timing and extent of
changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity
and certain related products due to lower or higher demand, shortages, transportation
problems, or other developments,
•
our ability to collect accounts receivable from our customers,
•
earnings volatility as a result of the GAAP requirement that we utilize
mark-to-market accounting on certain energy commodity contracts and interest rate swaps,
which may have, in any given period, a significant positive or negative effect on
earnings, which could change dramatically or be eliminated in subsequent periods,
•
the effect on our utility and utility revenues of the direct and indirect impacts of the continued
economic downturn experienced by the Michigan economy,
•
potential disruption or interruption of facilities or operations due to accidents,
war, terrorism, or changing political environment, and the ability to obtain or maintain
insurance coverage for such events,
•
technological developments in energy production, delivery, and usage,
achievement of capital expenditure and operating expense goals,
•
changes in financial or regulatory accounting principles or policies,
•
changes in domestic or foreign tax laws, or new IRS or foreign governmental
interpretations of existing or past tax laws,
•
changes in federal or state regulations or laws that could have an impact on our business,
•
outcome, cost, and other effects of legal or administrative proceedings,
settlements, investigations or claims, including claims, damages, and fines resulting
from round-trip trading and alleged inaccurate commodity price reporting, including the outcome of
investigations by the DOJ regarding round-trip trading and price reporting,
•
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,
•
potential assertion of indemnity or warranty claims with respect to previously owned assets and businesses,
•
credit ratings of CMS Energy, Consumers, or any of their affiliates,
•
other business or investment considerations that may be disclosed from time to time
in CMS Energy’s or Consumers’ SEC filings, or in other publicly issued written documents,
and
•
other uncertainties that are difficult to predict, many of which are beyond our
control.
For additional information regarding these and other uncertainties, see the “Outlook” section
included in this MD&A, Note 3, Contingencies, and Part II, Item 1A. Risk Factors.
CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company
of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving
in Michigan’s Lower Peninsula. Enterprises, through various subsidiaries and equity investments,
is engaged primarily in domestic independent power production. We manage our businesses by the
nature of services each provides and operate principally in three business segments: electric
utility, gas utility, and enterprises.
We earn our revenue and generate cash from operations by providing electric and natural gas utility
services, electric power generation, and gas distribution, transmission, and storage. Our
businesses are affected primarily by:
•
weather, especially during the normal heating and cooling seasons,
•
economic conditions, primarily in Michigan,
•
regulation and regulatory issues that affect our electric and gas utility operations,
•
energy commodity prices,
•
interest rates, and
•
our debt credit rating.
During the past several years, our business strategy has involved improving our consolidated
balance sheet and maintaining focus on our core strength: utility operations and service. As an
indication of our commitment to our utility business, we have invested $650 million in Consumers
during 2007.
We have completed the sale of all of our international Enterprises assets, using the proceeds to retire debt and to invest in our utility business. Asset sales
completed in 2007 include:
•
a portfolio of our businesses in Argentina and our northern Michigan non-utility natural
gas assets to Lucid Energy for $130 million in March 2007,
•
our ownership interest in El Chocon, an Argentine hydroelectric generating business, to
Endesa, S.A. for $50 million in March 2007,
•
our ownership interest in SENECA and certain associated generating equipment to PDVSA
for $106 million in April 2007,
•
our ownership interest in businesses in the Middle East, Africa, and India to TAQA for
$900 million in May 2007,
•
CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility, for $211 million in
June 2007,
•
our investment in GasAtacama to Endesa S.A. for $80 million in August 2007, and
•
our investment in Jamaica to AEI for $14 million in October 2007.
We also made important progress at Consumers to reduce business risk and to meet the future needs
of our customers. We sold Palisades to Entergy in April 2007 for $380 million. The final purchase
price, subject to various closing adjustments, resulted in us receiving $363 million as of
September 30, 2007. The sale also resulted in an immediate improvement in our cash flow, a
reduction in our nuclear operating and decommissioning risk, and an improvement in our financial
flexibility to support other utility investments.
In September 2007, we claimed relief under the regulatory-out provision in the MCV PPA, thereby
limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we
collect from our customers. As a result of our exercise of the regulatory-out provision, the MCV
Partnership may,
under certain circumstances, have the right to terminate or reduce the amount of
capacity sold under the MCV PPA, which could affect our need to build or purchase additional
generating capacity. The MCV Partnership has
notified us that it disputes our right to exercise the regulatory-out provision.
We introduced our Balanced Energy Initiative, a comprehensive plan to meet customer energy needs
over the next 20 years, in May 2007. The plan, as filed with the MPSC, is designed to meet the
growing customer demand for electricity with energy efficiency,
demand management, expansion of the use of renewable energy, and development of new power plants to
complement existing generating sources.
In September 2007, we filed the second phase of our Balanced Energy Initiative with the MPSC,
which contains our plan for construction of a new 800 MW clean coal plant at an existing site
located near Bay City, Michigan. Our plan calls for 500 MW of the plant’s output to be used for
our customers in Michigan and to commit the remaining 300 MW to others. We expect the plant
to enter operation
in 2015 with our share of the cost estimated at $1.3 billion excluding financing costs and $1.6
billion with financing costs.
In May 2007, we entered an agreement to buy a 946 MW natural gas-fired power plant located in
Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $517 million.
We expect to close by early 2008, subject to approval from the MPSC.
We took an important step in our business plan in January 2007 by reinstating a quarterly dividend
of $0.05 per share on our common stock, after a four-year suspension. For the nine months ended
September 30, 2007, we paid $34 million in common stock dividends. We also resolved a
long-outstanding litigation issue. In September 2007, we settled two class action lawsuits related
to round-trip trading by CMS MST. We believe that eliminating this business uncertainty was in the
best interests of our shareholders.
We also are in the process of restructuring our investment in DIG. This restructuring may involve
renegotiation or possible buyout of the DIG power sales contracts as well as other measures. These
options may require material cash payments. We believe that resolving the issues associated with
the unfavorable supply contracts will allow us to maximize future benefits from our DIG investment.
In the future, we will focus our strategy on:
•
reducing parent debt,
•
continued investment in our utility business,
•
growing earnings while controlling operating costs, and
•
principles of safe, efficient operations, customer value, fair and timely regulation,
and consistent financial performance.
As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been
hampered by negative developments in Michigan’s automotive industry and limited growth in the
non-automotive sectors of the state’s economy.
Net Income (Loss) Available to Common Stockholders
$
82
$
(103
)
$
185
Basic Earnings (Loss) Per Share
$
0.37
$
(0.47
)
$
0.84
Diluted Earnings (Loss) Per Share
$
0.34
$
(0.47
)
$
0.81
Electric Utility
$
67
$
93
$
(26
)
Gas Utility
(8
)
(20
)
12
Enterprises (Includes the MCV Partnership and
FMLP interests)
58
(133
)
191
Corporate Interest and Other
(35
)
(54
)
19
Discontinued Operations
—
11
(11
)
Net Income (Loss) Available to Common Stockholders
$
82
$
(103
)
$
185
For the three months ended September 30, 2007, our net income was $82 million, a $185 million
increase compared to our 2006 third quarter net loss. Compared with the third quarter of 2006, net
loss from our gas utility decreased, reflecting the positive effect of an MPSC gas rate order. At
our Enterprises and Corporate segments, the positive impacts from the recognition of an insurance
award, the recognition of a gain related to our sale of assets to Lucid, and the absence of a 2006
asset impairment charge more than offset the absence of a 2006 property tax refund at the MCV
Partnership. Net income was negatively impacted by decreased Palisades-related earnings at our
electric utility and the absence of earnings from discontinued operations.
Specific changes to net income available to common stockholders for the three months ended
September 30, 2007 versus 2006 are:
In Millions
•
absence of a 2006 asset impairment of our investment in GasAtacama,
169
•
recognition of an insurance reimbursement related to the non-payment by the Argentine
government of our ICSID award,
48
•
increase in earnings from our gas utility primarily due to the positive effect of an
MPSC gas rate order,
12
•
recognition of a gain associated with the sale of our Argentine and Michigan assets
to Lucid Energy,
11
•
increase in earnings from Enterprises primarily due to decreased operating and
maintenance expenses, and mark-to-market gains at CMS ERM compared to losses in 2006,
partially offset by the absence of earnings from equity method investments that were
sold in
2007,
8
•
absence of a 2006 property tax refund at the MCV Partnership,
(26
)
•
decreased Palisades-related earnings at our electric utility partially offset by
lower operating and maintenance expenses, and
(26
)
•
reduction in earnings from discontinued operations.
Enterprises (Includes the MCV
Partnership and FMLP interests)
(173
)
(215
)
42
Corporate Interest and Other
(51
)
(48
)
(3
)
Discontinued Operations
(87
)
32
(119
)
Net Loss Available to Common Stockholders
$
(100
)
$
(58
)
$
(42
)
For the nine months ended September 30, 2007, our net loss was $100 million, a $42 million increase
in net loss compared to 2006. Compared with the nine months ended September30, 2006, net income from our gas and electric utilities increased, reflecting the positive effect
of an MPSC gas rate order, an increase in gas deliveries due to weather, and lower operating and
maintenance expenses. These impacts were partially offset by decreased Palisades-related earnings
at our electric utility. At our Enterprises and Corporate segments, the positive impacts from a
reduction in net asset impairment charges, and gains from mark-to-market activity compared to
losses in 2006, more than offset the net negative impact of taxes and the absence of earnings from
equity investments sold in 2007. Net income was negatively impacted by activities associated with
discontinued operations as the net loss on the disposal of international businesses in 2007
replaced earnings recorded for these businesses in 2006.
Specific changes to net loss available to common stockholders for the nine months ended September30, 2007 versus 2006 are:
In Millions
•
impairments of our investments in TGN, GasAtacama, Jamaica, and PowerSmith,
$
(181
)
•
impact of activities associated with discontinued operations as the net loss on the
disposal of international businesses in 2007 replaced earnings recorded for
these businesses in 2006,
(119
)
•
absence of tax benefits recorded at Corporate and Enterprises in 2006 from
the resolution of an IRS income tax audit,
(54
)
•
the establishment of a tax provision on the cumulative undistributed earnings of foreign
subsidiaries sold in 2007, compared to tax benefits recorded in 2006,
(67
)
•
absence of earnings from our equity method investments that were sold in 2007,
(17
)
•
absence of an insurance reimbursement received for previously incurred legal expenses,
(15
)
•
premiums paid on the early retirement of corporate debt,
(6
)
•
absence of a 2006 GasAtacma impairment,
169
•
reduction to our corporate deferred tax valuation allowances associated with capital loss
carryforwards and foreign basis differences primarily due to the sale of international
businesses in 2007 compared to an increase in the valuation allowance in 2006,
94
•
recognition of an insurance reimbursement related to the non-payment by the Argentine
government of our ICSID award,
48
•
increase in earnings at our gas and electric utility segments,
38
•
absence of mark-to-market losses net of operating earnings from our investment in
the MCV Partnership, and
35
•
additional increase in earnings at Enterprises primarily due to mark-to-market gains
at CMS ERM compared to losses in 2006 and gains associated with asset sales.
Other operating expenses, other income, and
non-commodity revenue
33
97
General taxes
(7
)
(14
)
Interest charges
(7
)
(13
)
Income taxes
14
1
Total change
$
(26
)
$
(1
)
Electric deliveries: For the three months ended September 30, 2007, electric delivery revenues
decreased $6 million versus 2006, as deliveries to end-use customers were 10.5 billion kWh, a
decrease of less than 0.1 billion kWh or less than 1 percent versus 2006. The decrease in electric
deliveries for the three months ended September 30, 2007 is primarily due to unfavorable weather.
For the nine months ended September 30, 2007, electric delivery revenues increased $26 million
versus 2006, as deliveries to end-use customers were 29.5 billion kWh, an increase of 0.5 billion
kWh or 2 percent versus 2006. The increase in electric deliveries for the nine months ended
September 30, 2007 is primarily due to favorable weather.
Surcharge revenue: In the first quarter of 2006,
we started collecting a surcharge that the MPSC
authorized under Section 10d(4) of the Customer Choice Act. The surcharge factors increased in January 2007
pursuant to a MPSC order. The increase in the surcharge factors increased electric
delivery revenue by $3 million for the three months ended September 30, 2007 and $11 million for
the nine months ended September 30, 2007 versus 2006.
Palisades revenue to PSCR: As
a result of the sale of Palisades, electric revenue of $50 million
for the three months ended September 30, 2007 and $91 million for the nine months ended September30, 2007, related to Palisades rate base is now designated toward recovery of PSCR costs.
Power supply costs and related revenue: PSCR revenue decreased by $6 million for the three months
ended September 30, 2007 and $18 million for the nine months ended September 30, 2007 versus 2006.
These decreases primarily reflect amounts excluded from recovery in the 2006 PSCR Reconciliation
case. A portion of these excluded costs are instead being recovered through Electric Delivery
Revenue. The decrease also reflects the absence, in 2007, of an increase in Power Supply Revenue
associated with the 2005 PSCR Reconciliation case.
Other operating expenses, other income and non-commodity revenue: For the three months ended
September 30, 2007, other operating expenses decreased $30 million, other income increased $10
million, and non-commodity revenue decreased $7 million versus 2006. For the nine months ended
September 30, 2007, other operating expenses decreased $79 million, other income increased $26
million, and non-commodity revenue decreased $8 million versus 2006.
The decrease in other operating expenses was primarily due to lower operating and maintenance
expense, including reductions to certain workers’ compensation and injuries and damages expense.
These decreases were offset partially by higher depreciation and amortization expense. Operating
and maintenance expense decreased primarily due to the absence, in 2007, of costs incurred in 2006
related to a planned refueling outage at Palisades, and lower overhead line maintenance, and storm
restoration costs. Also contributing to the decrease was the sale of Palisades in April 2007.
Depreciation and amortization expense increased due to higher non-nuclear plant in service and
greater amortization of certain regulatory assets.
For the three months ended September 30, 2007, the increase in other income was primarily due to
higher interest income mainly due to the proceeds from the sale of Palisades and equity infusions
from the parent. For the nine months ended September 30, 2007, the increase in other income was
primarily due to higher interest income and higher income associated with our Section 10d(4)
Regulatory Asset. The increase on our Section 10d(4) Regulatory Asset reflects the absence, in
2007, of the impact of the MPSC’s final order in this case.
General taxes: For the three months ended September 30, 2007, general tax expense increased
primarily due to higher property tax and MSBT tax expense. For the nine months ended September 30,2007, general tax expense increased primarily due to higher property tax, sales and use tax
expense, and MSBT tax expense.
Interest charges: For the three months ended September 30, 2007, interest charges increased $7
million versus 2006. For the nine months ended September 30, 2007, interest charges increased $13
million versus 2006. The increase was primarily due to interest associated with amounts to be
refunded to customers as a result of the sale of Palisades. The MPSC order approving the Palisades
power purchase agreement with Entergy directed us to record interest on the unrefunded balance.
Income taxes: For the three months and nine months ended September 30, 2007, income taxes
decreased versus 2006 primarily due to lower earnings.
Gas wholesale and retail
services, other gas
revenues and other income
3
13
Operation and maintenance
(2
)
(22
)
General taxes and depreciation
(4
)
(10
)
Interest charges
3
2
Income taxes
(4
)
(22
)
Total change
$
12
$
39
Gas deliveries: For the three months ended September 30, 2007, gas deliveries decreased less than
1 bcf or 1 percent versus 2006. Despite lower gas deliveries, gas delivery revenue increased by $5
million due to higher estimated system efficiency.
For the
nine months ended September 30, 2007, gas delivery revenues
increased by $22 million versus 2006 as gas deliveries, including miscellaneous transportation to end-use customers, were 207 bcf,
an increase of 18 bcf or 9 percent. The increase in gas deliveries was primarily due to favorable
weather.
Gas rate increases: In November 2006, the MPSC issued an order authorizing an annual rate increase
of $81 million. In August 2007, the MPSC issued an order authorizing an annual rate increase of
$50 million. As a result of these orders, gas revenues increased $11 million for the three months
ended September 30, 2007 and $56 million for the nine months ended September 30, 2007.
Gas wholesale and retail services, other gas revenues and other income: For the three and nine
months ended September 30, 2007, the increase was primarily due to higher pipeline capacity
optimization revenue.
Operation and maintenance: For the three months and nine months ended September 30, 2007,
operation and maintenance expenses increased versus 2006 primarily due to higher uncollectible
accounts expense and contributions, beginning in November 2006 pursuant to a November 2006 MPSC
order, to a fund that provides energy assistance to low-income customers.
General taxes and depreciation: For the three months ended September 30, 2007, depreciation
expense increased versus 2006 primarily due to higher plant in service. The increase in general
taxes primarily reflects higher property tax expense and MSBT tax expense. For the nine months
ended September 30, 2007, depreciation expense increased versus 2006 primarily due to higher plant
in service. The increase in general taxes primarily reflects higher property tax expense.
Interest charges: For the three months and nine months ended September 30, 2007, interest charges
reflect lower average debt levels versus 2006.
Income taxes: For the three and nine months ended September 30, 2007, income taxes increased
versus 2006 primarily due to higher earnings by the gas utility.
General taxes, depreciation, and
other income, net
6
6
Asset impairment, net of insurance
reimbursement
288
25
Fixed charges
4
9
Minority interest
(6
)
(6
)
Income taxes
(103
)
(68
)
The MCV Partnership
(28
)
35
Total change
$
191
$
42
Operating revenues: For the three months ended September 30, 2007, operating revenues increased
$17 million versus 2006 primarily due to $22 million of mark-to-market gain in power and gas
contracts compared to losses on such items in 2006 at CMS ERM. Partially offsetting these increases
were decreases of $5 million in third party power and gas sales.
For the nine months ended September 30, 2007, operating revenues increased $24 million versus 2006
primarily due to higher revenues at CMS ERM resulting from
mark-to-market gains of $89 million on power and gas contracts compared to losses on such items in 2006 and increased power sales of $25
million. These were offset partially by the write off of $40 million derivative assets associated
with the Quicksilver contract that was voided by the trial judge in May 2007, absence of 2006 third
party financial settlements of $22 million, and decreased third party gas sales of $28 million.
Cost of gas and purchased power: For the nine months ended September 30, 2007, cost of gas and
purchased power decreased $20 million versus 2006. The decrease was primarily due to a decrease of
$32 million in power purchases from the MISO market, offset partially by higher cost of gas of $12
million resulting from increased usage and higher prices.
Earnings from equity method investees: For the three months ended September 30, 2007, earnings
from equity method investees decreased by $19 million versus 2006. The decrease was due to the
absence of
$17 million of earnings associated with our investments in Africa, the Middle East and India that
were sold in May 2007 and a $2 million reduction in earnings associated with our investment in
GasAtacama.
For the nine months ended September 30, 2007 earnings from equity method investees decreased by $26
million versus 2006. The decrease was due to the absence of $41 million of earnings associated
with sale of our investments in Africa, the Middle East and India in
May 2007, and a $5 million
reduction in earnings associated with our investment in GasAtacama due to the shortage of gas from
Argentina, offset by the absence in 2007 of a $20 million provision for higher foreign taxes in
Argentina recorded in 2006.
Gain on sale of assets: For the three months ended September 30, 2007, the net gain on asset sales
was $18 million. $17 million of the net gain resulted from the settlement of certain legal
proceedings associated with the sale of our Argentine and Michigan assets to Lucid Energy. We also
recorded $1 million in gains from the sale of various assets at CMS ERM. There were no gains or
losses on asset sales for the three months ended September 30, 2006. For additional details, see
Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
For the nine months ended September 30, 2007, the net gain on asset sales was $16 million. The net
gain consisted of $34 million from the sale of our equity investment in El Chocon to Endesa S.A.
and $1 million in gains from the sale of various assets at CMS Energy. These gains were partially
offset by a $14 million net loss on the sale of our equity investments in Africa, the Middle East
and India to TAQA and a $5 million net loss on the sale of our Argentine and Michigan assets to
Lucid Energy. There were no gains or losses on asset sales for the nine months ended September 30,2006. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment
Charges.
Operation and maintenance: For the three months ended September 30, 2007, operation and
maintenance expenses decreased $13 million versus 2006 due to the absence, in 2007, of a $6 million
loss recorded on the termination of the remaining prepaid gas contracts at CMS ERM, reimbursement
of $3 million in arbitration costs at CMS Gas Transmission, and a $4 million net reduction in other
expenses primarily due to the absence of expenses associated with
assets sold during the first six months of 2007.
For the nine months ended September 30, 2007, operation and maintenance expenses decreased $7
million versus 2006 due to the absence, in 2007, of a $6 million loss recorded on the termination
of the remaining prepaid gas contracts at CMS ERM, reimbursement of $3 million in arbitration costs
at CMS Gas Transmission, partially offset by a $2 million net increase in other expenses primarily
due to expenses associated with assets sold during the first six months of 2007.
General taxes, depreciation, and other income, net: For the three months ended September 30, 2007,
the net of general taxes, depreciation, and other income increased
operating income by $6 million versus 2006 due to lower accretion expense related to the termination of the prepaid gas contracts
at CMS ERM.
For the nine months ended September 30, 2007, the net of general taxes, depreciation, and other
income increased operating income by $6 million versus 2006 due to lower accretion expense of $4
million related to the termination of the prepaid gas contracts at CMS ERM, and lower expense due
to asset sales of $2 million.
Asset impairment charges, net of insurance reimbursement: For the three months ended September 30,2007, asset impairment charges, net of insurance reimbursement, decreased $288 million versus 2006.
The decrease in impairment charges relates to a $75 million credit recorded in September 2007 to
recognize a prior insurance award associated with our ownership interest in TGN, and the absence,
in 2007, of a $213 million impairment of our equity investment in GasAtacama and related notes
receivable recorded in 2006. For additional details, see Note 2, Asset Sales, Discontinued
Operations and Impairment Charges.
For the nine months ended September 30, 2007, asset impairment charges, net of insurance
reimbursement, decreased $25 million versus 2006. For the nine months ended September 30, 2007, we
recorded net impairment charges of $204 million that included $277 million of charges for the
reduction in fair value of our investments in TGN, Jamaica, GasAtacama and PowerSmith, and a $75
million credit to recognize a
prior insurance award associated with our ownership interest in TGN.
For the nine months ended September 30,2006, we recorded a $212 million charge for the reduction in the fair value of our equity
investment in GasAtacama and related notes receivable. For additional details, see Note 2, Asset
Sales, Discontinued Operations and Impairment Charges.
Fixed charges: For the three and nine months ended September 30, 2007, fixed charges decreased due
to lower interest expenses from subsidiary debt due to asset sales in 2007.
Minority Interest: The allocation of profits to minority owners decreases our net income, and the
allocation of losses to minority owners increases our net income. For the three months ended
September 30, 2007, minority owners shared in a portion of the profits at our subsidiaries. For the
three months ended September 30, 2006, minority owners shared in a portion of losses at our
subsidiaries.
For the nine months ended September 30, 2007, minority owners shared in a portion of greater
profits at our subsidiaries versus profits shared in 2006.
Income taxes: For the three months ended September 30, 2007, income tax expense increased $103
million versus 2006. The increase reflects $113 million of tax expense on higher earnings and the
absence of $4 million in tax benefits recorded in 2006 related to foreign subsidiaries subsequently
sold in 2007, offset by $14 million of tax benefit primarily related to lower tax reserves in 2007.
For the nine months ended September 30, 2007, income tax expense increased $68 million versus 2006.
The increase reflects the $68 million net increase in tax expense on earnings associated with the
recognition of previously unremitted foreign earnings of subsidiaries sold in 2007. Also
increasing tax expense was $26 million of tax expense on higher earnings. These expenses were
offset by $26 million of tax benefits primarily related to lower tax reserves in 2007.
The MCV Partnership: Due to the November 2006 sale of our ownership interests in the MCV
Partnership, we have condensed their consolidated results of operations for the three and nine
months ended September 30, 2007 for discussion purposes. The decrease in losses from our ownership
interest in the MCV Partnership is primarily due to the absence, in 2007, of mark-to-market losses
on certain long-term contracts and financial hedges.
CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
In Millions
September 30
2007
2006
Change
Three months ended
$
(35
)
$
(54
)
$
19
Nine months ended
$
(51
)
$
(48
)
$
(3
)
For the three months ended September 30, 2007, corporate interest and other net expenses were $35
million, a decrease of $19 million versus 2006. The $19 million decrease
primarily reflects the absence, in 2007, of a portion of the reduction in fair value of our
investment in GasAtacama recognized in 2006 and reduced interest expense due to lower debt levels
in 2007. Partially offsetting the decrease were premiums on the early retirement of CMS Energy debt
paid in 2007.
For the nine months ended September 30, 2007, corporate interest and other net expense were $51
million, an increase of $3 million versus 2006. The $3 million increase
primarily reflects the absence, in 2007, of a tax benefit due to the resolution of an IRS income
tax audit, higher income tax expense in 2007, and the absence of an insurance reimbursement
received in June 2006 for previously incurred legal expenses. Also contributing to the increase
was the recognition of a portion of the reduction in fair value of our investment in GasAtacama and
premiums paid on the early retirement of CMS Energy
debt in June 2007.
Partially offsetting the increase was the reduction of certain deferred tax valuation allowances in
March 2007 that were no longer required due to the sale of our international operations.
Discontinued Operations: For the three months ended September 30, 2007, there was no net income
from discontinued operations compared to net income of $11 million in 2006.
For the nine months ended September 30, 2007, the net loss from discontinued operations was $87
million compared to $32 million in net income in 2006. The $119 million change is primarily due to
the net loss on the disposal of international businesses in 2007, which replaced earnings recorded
for these businesses in 2006.
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. For additional
accounting policies, see Note 1, Corporate Structure and Accounting Policies.
Use of Estimates and Assumptions
We use estimates and assumptions in preparing our consolidated financial statements that may affect
reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation,
amortization, financial and derivative instruments, employee benefits, and contingencies. For
example, we estimate the rate of return on plan assets and the cost of future health-care benefits
to determine our annual pension and other postretirement benefit costs. Actual results may differ
from estimated results due to factors such as changes in the regulatory environment, competition,
foreign exchange, regulatory decisions, and lawsuits.
Contingencies: We are involved in various regulatory and legal proceedings that arise in the
ordinary course of our business. We record a liability for contingencies based upon our assessment
that a loss is probable and the amount of loss can be reasonably estimated. We use the principles
in SFAS No. 5 when recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter.
The amount of income taxes we pay is subject to ongoing audits by federal, state, and foreign tax
authorities, which can result in proposed assessments. Our estimate for the potential outcome for
any uncertain tax issue is highly judgmental. We believe we have provided adequately for any
likely outcome related to these matters. However, our future results may include favorable or
unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or
resolved or when statutes of limitation on potential assessments expire. As a result, our
effective tax rate may fluctuate significantly on a quarterly basis. The FASB issued a new
interpretation on the recognition and measurement of uncertain tax positions that we adopted on
January 1, 2007. For additional details, see the “Implementation of New Accounting Standards”
section included in this MD&A.
Discontinued Operations: We have determined that certain consolidated subsidiaries meet the
criteria of assets held for sale under SFAS No. 144. At December 31, 2006, these subsidiaries
included our Argentine businesses sold in March 2007, a majority of our Michigan non-utility
businesses sold in March 2007, CMS Energy Brasil S.A., Takoradi, SENECA, and certain associated
holding companies. There were no assets classified as held for sale at September 30, 2007. For
additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
Accounting for Financial and Derivative Instruments, Trading Activities, and Market Risk
Information
Financial Instruments: Debt and equity securities classified as available-for-sale are reported at
fair value determined from quoted market prices. Unrealized gains or losses resulting from changes
in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in
equity as part of AOCL. Unrealized gains or losses are excluded from earnings unless the related
changes in fair value are determined to be other than temporary.
Derivative Instruments: We account for derivative instruments in accordance with SFAS No. 133.
Except as noted within this section, since the year ended December 31, 2006, there have been no
significant changes in the amount or types of derivatives that we hold or to how we account for
derivatives. For additional details on our derivatives, see Note 6, Financial and Derivative
Instruments.
To determine the fair value of our derivatives, we use information from external sources (i.e.,
quoted market prices and third party valuations), if available. For certain contracts, this
information is not available and we use mathematical valuation models to value our derivatives.
These models require various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. The following table
summarizes the interest rate and volatility rate assumptions we used to value these contracts at
September 30, 2007:
Interest Rates (%)
Volatility Rates (%)
Electricity-related option contracts
3.6
68 — 113
Changes in forward prices or volatilities could significantly change the calculated fair value of
our derivative contracts. The cash returns we actually realize on these contracts may vary, either
positively or negatively, from the results that we estimate using these models. As part of valuing
our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the
financial condition of our counterparties.
Derivative Contracts Associated with Equity Investments: In May 2007, we sold our ownership
interest in businesses in the Middle East, Africa, and India. Certain of these businesses held
interest rate contracts and foreign exchange contracts that were derivatives. Before the sale, we
recorded our proportionate share of the change in fair value of these contracts in AOCL if the
contracts qualified for cash flow hedge accounting; otherwise, we recorded our share in Earnings
from Equity Method Investees.
At the date of the sale, we had accumulated a net loss of $13 million, net of tax, in AOCL
representing our proportionate share of mark-to-market gains and losses from cash flow hedges held
by the equity method investees. After the sale, we reclassified this amount and recognized it in
earnings as a reduction of the gain on the sale. For additional details on the sale of our
interest in these equity method investees, see Note 2, Asset Sales, Discontinued Operations and
Impairment Charges.
CMS ERM Contracts: CMS ERM enters into and owns energy contracts that support CMS Energy’s ongoing
operations. We include the fair value of the derivative contracts held by CMS ERM in either Price
risk management assets or Price risk management liabilities on our Consolidated Balance Sheets.
The following tables provide a summary of these contracts at September 30, 2007:
(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) The fair value of CMS ERM’s trading contracts has increased significantly from December 31,2006 due to the termination of certain gas contracts. CMS ERM had recorded derivative liabilities,
representing cumulative unrealized mark-to-market losses, associated with these contracts.
(c) Reflects changes in the fair value of contracts over the period, as well as increases or
decreases to credit reserves. For CMS ERM’s non-trading contracts, this amount also reflects the
rescission of a natural gas contract with Quicksilver. CMS ERM had recorded a derivative asset,
representing cumulative unrealized mark-to-market gains, associated with this contract. See Note
3, Contingencies, “Other Contingencies — Quicksilver Resources, Inc.” for additional details.
Prices obtained from external
sources or based on models and
other valuation methods
(11
)
(9
)
(2
)
—
—
Total
$
(14
)
$
(12
)
$
(2
)
$
—
$
—
Market Risk Information: The following is an update of our risk sensitivities since December 31,2006. These sensitivities indicate the potential loss in fair value, cash flows, or future
earnings from our financial instruments, including our derivative contracts, assuming a
hypothetical adverse change in market rates or prices of 10 percent. Changes in excess of the
amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed
the 10 percent shift used for the analyses.
Factors affecting our liquidity and capital requirements are:
•
results of operations,
•
capital expenditures,
•
energy commodity and transportation costs,
•
contractual obligations,
•
regulatory decisions,
•
debt maturities,
•
credit ratings,
•
working capital needs, and
•
collateral requirements.
During the summer months, we purchase natural gas and store it for resale primarily during the
winter heating season. Although our prudent natural gas costs are recoverable from our customers,
the amount paid for natural gas stored as inventory requires additional liquidity due to the lag in
cost recovery.
Our current financial plan includes controlling operating expenses and capital expenditures and
evaluating market conditions for financing opportunities, if needed.
We believe the following items will be sufficient to meet our liquidity needs:
•
our current level of cash and revolving credit facilities,
•
our anticipated cash flows from operating and investing activities, and
•
our ability to access secured and unsecured borrowing capacity in the capital markets,
if necessary.
In the second quarter of 2007, Moody’s and S&P upgraded long-term credit ratings of CMS Energy and
Consumers and revised the rating outlook to stable from positive.
Cash Position, Investing, and Financing
Our operating, investing, and financing activities meet consolidated cash needs. At September 30,2007, we had $1.293 billion consolidated cash, which includes $48 million of restricted cash and $4
million from entities consolidated pursuant to FIN 46(R).
Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For
the nine months ended September 30, 2007, Consumers paid $176 million in common stock dividends to
CMS Energy.
Summary of Consolidated Statements of Cash Flows:
In Millions
Nine months ended September 30
2007
2006
Net cash provided by (used in):
Operating activities
$
(116
)
$
447
Investing activities
1,394
(436
)
Net cash provided by operating and investing activities
1,278
11
Financing activities
(386
)
(400
)
Effect of exchange rates on cash
2
1
Net Increase (Decrease) in Cash and Cash Equivalents
$
894
$
(388
)
Operating Activities: For the nine months ended September 30, 2007, net cash used in operating
activities was $116 million, an increase of $563 million versus 2006. The increase in cash used in
operations was a result of the absence, in 2007, of the sale of accounts receivable combined with
payments made to fund our pension plan and to settle a shareholder class action lawsuit. The
absence of the return of funds formerly held as collateral under certain gas hedging arrangements
and other timing differences also contributed to the increased use of cash from operations. These
increases were offset partially by the absence of the MCV Partnership gas supplier funds on deposit
and a decrease in expenditures for gas inventory, as the milder winter in 2006 allowed us to
accumulate more gas in our storage facilities.
Investing Activities: For the nine months ended September 30, 2007, net cash provided by investing
activities was $1.394 billion, an increase of $1.83 billion versus 2006. This increase was
primarily due to proceeds from asset sales and proceeds from nuclear decommissioning trust funds.
For additional details on asset sales, see Note 2, Asset Sales, Discontinued Operations and
Impairment Charges.
Financing Activities: For the nine months ended September 30, 2007, cash used in financing
activities was $386 million, a decrease of $14 million versus 2006. This was primarily due to a
decrease in debt payments offset by the payment of common stock dividends. For additional details
on long-term debt activity, see Note 4, Financings and Capitalization.
Our cash flow statements include amounts related to discontinued operations through the date of
disposal. For additional details on discontinued operations, see Note 2, Asset Sales, Discontinued
Operations and Impairment Charges.
Obligations and Commitments
Revolving Credit Facilities: For details on our revolving credit facilities, see Note 4,
Financings and Capitalization.
Dividend Restrictions: For details on dividend restrictions, see Note 4, Financings and
Capitalization.
Off-Balance Sheet Arrangements: CMS Energy and certain of its subsidiaries enter into various
arrangements in the normal course of business to facilitate commercial transactions with third
parties. These arrangements include indemnifications, letters of credit, surety bonds, and
financial and performance guarantees.
We enter into agreements containing indemnifications standard in the industry and indemnifications
specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually
agreements to reimburse other companies if those companies incur losses due to third party claims
or breach of contract terms. 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 these obligations and believe it is unlikely that we would
be required to perform or otherwise incur any material losses associated with these guarantees.
For additional details on these and other guarantee arrangements, see Note 3, Contingencies, “Other
Contingencies — FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others.”
In May 2007, we sold our ownership interests in businesses in the Middle East, Africa, and India to
TAQA. TAQA has assumed all contingent obligations related to our project-financing security
agreements. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset
Sales, Discontinued Operations and Impairment Charges.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may
sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for
securitized
financial assets provides a lower cost source of funding compared to unsecured debt. For additional details,
see Note 4, Financings and Capitalization.
Outlook
CORPORATE OUTLOOK
Our business strategy will focus on continued investment in our utility business, reducing parent
debt, and growing earnings while controlling operating costs.
Our primary focus with respect to our non-utility businesses is to optimize cash flow and maximize
the value of our remaining assets. Our primary focus with respect to our utility business is to continue to invest in our utility
system to enable us to meet our customer commitments, comply with increasing environmental
performance standards, and maintain adequate supply and capacity.
In January 2007, we reinstated a quarterly dividend on our common stock after a four-year
suspension at $0.05 per share. For the nine months ended September 30, 2007, we paid $34 million
in common stock dividends. On October 26, 2007, we declared a dividend of $0.05 per share on our
common stock payable November 30, 2007 to shareholders of record on November 9, 2007.
ELECTRIC UTILITY BUSINESS OUTLOOK
Growth: In 2007, we expect electric deliveries to grow about one percent compared to 2006 levels.
The outlook for 2007 assumes a small decline in industrial economic activity and normal weather
conditions throughout the remainder of the year.
Over the next five years, we expect electric deliveries to grow less than 1.5 percent per year.
This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after
2007. 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 the following:
•
energy conservation measures,
•
fluctuations in weather conditions, and
•
changes in economic conditions, including utilization and expansion or contraction of
manufacturing facilities.
Electric Customer Revenue Outlook: Michigan’s economy has been hampered by automotive
manufacturing facility and related supplier closures and restructurings. The Michigan economy has
also had limited growth in the non-automotive sector. Although our electric utility results are
not dependent upon a single customer, or even a few customers, customers in the automotive sector
represented five percent of our total 2006 electric revenue. We cannot predict the impact of the
Michigan economy on our electric utility customers.
Electric Reserve Margin: We have purchased capacity and energy contracts covering partially the
estimated reserve margin requirements for 2008 through 2010. As of September 30, 2007, we expect
total 2007 capacity costs for these primarily seasonal electric capacity and energy contracts to be
$17 million.
We are
currently planning for a reserve margin of approximately 11 percent
for summer 2008, or supply resources equal to 111 percent of
projected firm summer peak load. Of the 2008 supply resources target,
we expect 85 percent to come from our electric generating plants and
long-term power purchase contracts with other contractual
arrangements making up the remainder of our supply resource needs for
2008. If the MPSC approves the Zeeland power plant purchase, we
expect 95 percent of our 2008 supply resource target will be satisfied
with our electric generating plants and long-term power purchase
contracts, with other contractual arrangements making up the
remainder of our supply resource needs for 2008. Our 15-year power
purchase agreement with Entergy for 100 percent of the Palisades
facility’s current electric output will offset the reduction in
the owned capacity represented by the sale of Palisades in April 2007.
In September 2007, we exercised the regulatory-out provision in the MCV PPA, resulting in a
reduction in the amount we pay to the MCV Partnership to equal the amount we are allowed to recover
in the rates charged to customers. The MCV Partnership may, under certain circumstances, have the
right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA
represents 13 percent of our 2008 expected supply resources.
Electric Transmission Expenses: METC, which provides electric transmission service to us,
increased substantially the transmission rates it charged us in 2006. The revenue collected by
METC under those rates in 2006 was subject to refund. The parties filed a settlement agreement
with the FERC, which was approved in August 2007. This settlement resulted in a refund of 2006
transmission charges of $18 million and a corresponding reduction of our power supply costs.
Electric transmission expenses are anticipated to increase in 2008 by $42 million due primarily to
a 33 percent increase in rates charged to us by our major
transmission provider. This increase is
included in our 2008 PSCR Plan filed with the MPSC in September 2007.
In September 2007, the FERC approved a proposal from transmission owners and operators to include
100 percent of generator interconnection costs in our transmission rates. Previously, generator
interconnection costs were split 50-50 between transmission owners and operators and generators.
Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing regarding the
FERC’s order.
For additional details on power supply costs, see Note 3, Contingencies, “Consumers’ Electric
Utility Rate Matters — Power Supply Costs.”
21st Century Electric Energy Plan: In January 2007, the then chairman of the MPSC proposed three
major policy initiatives to the governor of Michigan. The initiatives involve the use of more
renewable energy resources by all load-serving entities such as Consumers, the creation of an
energy efficiency program, and a procedure for reviewing proposals to construct new generation
facilities. The January proposal indicated that Michigan needs new base-load capacity by 2015 and
recommended measures to make it easier to predict customer demand and revenues. The proposed
initiatives will require changes to current legislation. We will continue to participate as the
MPSC, legislature, and other stakeholders address future electric resource needs.
Balanced Energy Initiative: In May 2007, we filed a “Balanced Energy Initiative” with the MPSC
providing a comprehensive energy resource plan to meet our projected short-term and long-term
electric power requirements. The plan is responsive to the 21st Century Electric Energy Plan and
assumes that Michigan will implement a state-wide energy efficiency program and a renewable energy
portfolio standard. The filing requests the MPSC to rule that the Balanced Energy Initiative
represents a reasonable and prudent plan for the acquisition of necessary electric utility
resources. As acknowledged in the 21st Century Electric Energy Plan, implementation of the
Balanced Energy Initiative will require legislative repeal or significant reform of the Customer
Choice Act. In addition, we endorse the 21st Century Electric
Energy Plan recommendation to adopt
a new, up-front certification policy for major power plant investments.
In September 2007, as part of our Balanced Energy Initiative, we announced plans to build an 800 MW
advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. We
expect to use 500 MW of the plant’s output to serve
Consumers’ customers and to commit the remaining 300 MW to others. We expect the plant to enter operation in 2015 with our share of the cost estimated at
$1.3 billion excluding financing costs and $1.6 billion with financing costs.
There are
several obstacles that must be cleared before construction of the
proposed new clean coal plant, including:
•
repeal or significant reform of the Customer Choice Act,
•
obtaining environmental permits,
•
successful MPSC regulatory review and approval, and
•
obtaining property tax abatements.
In
September 2007, we filed with the MPSC an updated Balanced Energy Initiative including our plan for
construction of the new clean coal plant in order to start the regulatory review
process for the new plant. In October 2007, we filed an application with the MDEQ for the
environmental air quality permits required for the new plant. The
Michigan Attorney General has filed a motion with the MPSC to dismiss the Balanced Energy Initiative case claiming that the MPSC lacks
jurisdiction over the matter.
Proposed Power Plant Purchase: In May 2007, we reached an agreement with Broadway Gen Funding LLC,
an affiliate of LS Power Group, to buy a 946 MW gas-fired power plant located in Zeeland, Michigan
for $517 million. The power plant will help meet the growing energy needs of our customers. We
expect to close on the purchase by early 2008, subject to the MPSC’s approval.
Proposed Renewable Energy Legislation: There are various bills introduced into the U.S. Congress
and the Michigan legislature relating to mandatory renewable energy standards. If enacted, these
bills generally would require electric utilities to acquire a certain percentage of their power
from renewable sources or otherwise pay fees or purchase allowances in lieu of having the
resources. We cannot predict whether any such bill will be enacted or in what form.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial condition and future
results of operations. These trends or uncertainties have, or had, or are reasonably expected to have, a
material impact on revenues or income from continuing electric operations.
Electric Environmental Estimates: Our operations are subject to various state and federal
environmental laws and regulations. Costs to operate our facilities in compliance with these laws
and regulations generally have been recovered in customer rates.
Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be
a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant
reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital
expenditures totaling $880 million. From 1998 to present, we have incurred $784 million in capital
expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that
the remaining $96 million of capital expenditures will be made through 2011. These expenditures
include installing selective catalytic reduction
control technology on four of our coal-fired electric generating units. The key assumptions in the
capital expenditure estimate include:
•
construction commodity prices, especially construction material and labor,
•
project completion schedules,
•
cost escalation factor used to estimate future years’ costs of 2.6 percent, and
•
an AFUDC capitalization rate of 7.8 percent.
In addition to modifying coal-fired electric generating plants, our compliance plan includes the
use of nitrogen oxide emission allowances until all of the control equipment is operational in
2011. The nitrogen oxide emission allowance annual expense is projected to be $2 million per year
through 2011, which we expect to recover from our customers through the PSCR process. The
projected annual expense is based on market price forecasts and forecasts of regulatory provisions,
known as progressive flow control, that restrict the usage in any given year of allowances banked
from previous years. The allowances and their cost are accounted for as inventory. The allowance
inventory is expensed at the rolling average cost as the electric generating plants emit nitrogen
oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that
requires additional coal-fired electric generating plant emission controls for nitrogen oxides and
sulfur dioxide. We plan to meet the nitrogen oxide requirements of this rule by year-round
operation of our selective catalytic reduction control technology units, installation of low
nitrogen oxide burners, and purchasing emission allowances. We plan to meet the sulfur dioxide
requirements of this rule using sorbent injection, installation of flue gas desulfurization
scrubbers and purchasing emission allowances. Our total cost for equipment installation is
expected to reach approximately $740 million by 2015. Additional purchases of sulfur dioxide
emission allowances in 2012 and 2013 will be needed at an estimated cost of $10 million per year,
which we expect to recover from our customers through the PSCR process.
The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of
Columbia by a number of utilities and other companies. Final briefs were submitted by September 5,2007, with a decision expected in 2008. We cannot predict the outcome of these appeals.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury Rule, which
requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010
and further reductions by 2018. The Clean Air Mercury Rule was appealed to the U.S. Court of
Appeals by a number of states and other entities. Final briefs were submitted by July 13, 2007,
with a decision expected in 2008. We cannot predict the outcome of these appeals.
In April 2006, Michigan’s governor announced a plan that would result in mercury emissions
reductions of 90 percent by 2015. We are working with the MDEQ on the details of this rule;
however, we have developed preliminary cost estimates and a mercury emissions reduction scenario
based on our best knowledge of control technology options and initially proposed requirements. We
estimate costs associated with Phase I of the state’s mercury rule will be approximately $190
million by 2010 and an additional $320 million by 2015.
The following table compares the federal Clean Air Mercury Rule to the proposed state mercury rule:
State and Federal
State and Federal
Phase I
Phase II
Federal Clean Air
Mercury Rule
30% reduction by 2010
with interstate
trading of allowances
70% reduction by 2018
with interstate
trading of allowances
Proposed State
Mercury Rule
30% reduction by 2010
without interstate
trading of allowances
90% reduction by 2015
without interstate
trading of allowances
Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly
classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to
modify the plant. We have received and responded to information requests from the EPA on this
subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of
“routine maintenance.” If our interpretation is found to be incorrect, we may be required to
install additional pollution controls at some or all of our coal-fired electric generating plants
and potentially pay fines. Additionally, the viability of certain plants remaining in operation
would be re-examined. We cannot predict the financial impact or outcome of this issue.
Greenhouse Gases: Several legislative proposals have been introduced in the United States Congress
that would require reductions in emissions of greenhouse gases, including carbon dioxide.
These laws, if enacted, could require us to replace equipment, install additional equipment for pollution controls,
purchase allowances, curtail operations, or take other steps. Although associated
capital or operating costs relating to greenhouse gas regulation or legislation
could be material, and cost recovery cannot be assured, we expect to have an opportunity
to recover these costs and capital expenditures in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.
On April2, 2007, the U.S. Supreme Court ruled that the Clean Air Act gives the EPA the authority to
regulate emissions of carbon dioxide and other greenhouse gases from automobiles. In its decision,
the court ordered the EPA to revisit its finding that it has the discretion not to regulate
greenhouse gas emissions from automobiles.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory
emissions reduction requirements could have far-reaching and significant implications for the
energy sector. We cannot estimate the effect of federal or state greenhouse gas policy on our
future consolidated results of operations, cash flows, or financial position due to the uncertain
nature of the policies at this time. However, we will continue to monitor greenhouse gas policy
developments and assess and respond to their potential implications on our business operations.
Water: In March 2004, the
EPA issued rules that govern electric generating plant cooling water
intake systems. The rules require significant reduction in fish harmed by
operating equipment. EPA compliance options in the rule were challenged in court. In January
2007, the court rejected many of the compliance options favored by industry and remanded the bulk
of the rule back to the EPA for reconsideration. The court’s ruling is expected to increase
significantly the cost of complying with this rule. However, the cost to comply will not be known
until the EPA’s reconsideration is complete. At this time, the EPA has not established a schedule
to address the court decision.
For additional details on electric environmental matters, see Note 3, Contingencies, “Consumers’
Electric Utility Contingencies — Electric Environmental Matters.”
Competition and Regulatory Restructuring: The Customer Choice Act allows all of our electric
customers to buy electric generation service from us or from an alternative electric supplier. At
September 30, 2007, alternative electric suppliers were providing 311 MW of generation service to
ROA customers.
This is 4 percent of our total distribution load and represents an increase of 1
percent of ROA load compared to September 30, 2006.
In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred from 2002
through 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have
experienced a downward trend in ROA customers. If this trend continues, it will extend the time it
takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends,
which affect our ability to recover timely these Stranded Costs.
Electric Rate Case: In March 2007, we filed an application with the MPSC seeking an 11.25 percent
authorized return on equity and an annual increase in revenues of $157 million. The increase seeks
recovery of the costs associated with increased plant investment, increased equity investment, and
greater operation and maintenance expenses. In May 2007, we filed supplemental testimony with the
MPSC to include transaction costs from the sale of Palisades. In July 2007, we filed an amended
application with the MPSC to include the proposed purchase of the Zeeland power plant, the approval
of an energy efficiency program, and to make other revisions. The revised application seeks an
annual increase in revenues of $282 million.
In July 2007, we also filed an amended application for rate relief that seeks the removal of costs
associated with Palisades, the approval of partial and immediate rate relief for certain items,
including the proposed purchase of the Zeeland power plant, and the approval of a plan to
distribute excess proceeds from the sale of Palisades to customers. The case schedule will allow
for an MPSC order on our Zeeland request and on our request for partial and immediate rate relief
by the end of 2007 and a final rate order in mid-2008. We cannot predict the amount or timing of
any MPSC decision on our requests.
For additional details and material changes relating to the restructuring of the electric utility
industry and electric rate matters, see Note 3, Contingencies, “Consumers’ Electric Utility Rate
Matters.”
OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES
The MCV PPA:The MCV Partnership, which leases and operates the MCV Facility, contracted to sell
electricity to Consumers for a 35-year period beginning in 1990. The cost that we incur under the
MCV PPA exceeded the recovery amount allowed by the MPSC until we exercised the regulatory-out
provision in the MCV PPA in September 2007. This action limited our capacity and fixed energy
payments to the MCV Partnership to the amounts that we collect from our customers. We incurred $39
million in underrecoveries in 2007. The MCV Partnership has notified us that it disputes our right to
exercise the regulatory-out provision. We believe that the provision is valid and fully
effective, but cannot assure that we will prevail in the event of a proceeding on this issue.
As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA.
If the MCV Partnership terminates the MCV PPA or reduces the amount of capacity sold under the MCV
PPA, we would seek to replace the lost capacity to maintain an adequate electric reserve margin.
This could involve entering into a new PPA and (or) entering into electric capacity contracts on
the open market. We cannot predict our ability to enter into such contracts at a reasonable price.
We are also unable to predict regulatory approval of the terms and conditions of such contracts,
or that the MPSC would allow full recovery of our incurred costs.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a
determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we
recover from customers. Also, in May 2007, the MCV Partnership filed an application with the MPSC
seeking approval to increase our recovery of costs incurred under the MCV PPA. We are unable to
predict
the outcome of these requests. For additional details on the MCV PPA, see Note 3,
Contingencies, “Other Consumers’ Electric Utility Contingencies — The MCV PPA.”
Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. The final
purchase price, subject to various closing adjustments, resulted in us receiving $363 million as of
September 30, 2007. We also paid Entergy $30 million to assume ownership and responsibility for
the Big Rock ISFSI. Because of the sale of Palisades, we also paid the NMC, the former operator of
Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC.
The MPSC order approving the Palisades transaction allowed us to recover the book value of
Palisades. This results in us crediting estimated proceeds in excess of book value of $66 million
to our customers from June 2007 through December 2008. After closing adjustments, which are
subject to MPSC review, proceeds in excess of the book value were
$77 million as of September 30,2007. The MPSC order deferred ruling on the recovery of transaction costs, including the NMC exit
fees, and the $30 million payment to Entergy related to the Big Rock ISFSI until the next general
rate case.
Entergy assumed responsibility for the future decommissioning of Palisades and for storage and
disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. We transferred
$252 million in trust fund assets to Entergy. We are crediting estimated excess decommissioning
funds of $189 million to our retail customers from June 2007 through December 2008. Access to
additional decommissioning fund balances above the estimates in the MPSC order resulted in excess
decommissioning funds of $123 million as of September 30,2007. We have proposed a plan to credit these balances to our retail customers and this plan is under review by the MPSC in our current
electric rate case filing.
As part of the transaction, Entergy will sell us 100 percent of the plant’s output up to its
current annual average capacity of 798 MW under a 15-year power purchase agreement. Because of the
Palisades power purchase agreement and our continuing involvement with the Palisades assets, we
account for the disposal of Palisades as a financing for accounting purposes and not a sale. This
resulted in the recognition of a finance obligation of $197 million.
For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales,
Discontinued Operations and Impairment Charges.
GAS UTILITY BUSINESS OUTLOOK
Growth: In 2007, we project gas deliveries will decline slightly, on a weather-adjusted basis,
from 2006 levels due to continuing conservation and overall economic conditions in the state of
Michigan. Over the next five years, we expect gas deliveries to decline by less than one-half of
one percent annually. Actual gas deliveries in future periods may be affected by:
Several gas business trends or uncertainties may affect our future financial results and financial
condition. These trends or uncertainties could have a material impact on future revenues or income
from gas operations.
Gas Environmental Estimates: We expect to incur investigation and remedial action costs at a
number of sites, including 23 former manufactured gas plant sites. For additional details, see
Note 3, Contingencies, “Consumers’ Gas Utility Contingencies — Gas Environmental Matters.”
Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural
gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these
costs, policies, and practices for prudency in annual plan and reconciliation proceedings. For
additional details on gas cost recovery, see Note 3, Contingencies, “Consumers’ Gas Utility Rate
Matters — Gas Cost Recovery.”
Gas Depreciation: In June 2007, the MPSC issued its final order in the generic ARO accounting case
and modified the filing requirement for our next gas depreciation case. The original filing
requirement date was changed from 90 days after the issuance of this order to no later than August1, 2008. Additionally, we have been ordered to use 2007 data and prepare a cost of removal
depreciation study with five alternatives using the MPSC’s prescribed methods.
If a final order in our next gas depreciation case is not issued concurrently with a final order in
a general gas rate case, the MPSC may incorporate the results of the depreciation case into general
gas rates through use of a surcharge mechanism (which may be either positive or negative).
2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25
percent authorized return on equity along with an $88 million annual increase in our gas delivery
and transportation rates. We proposed the use of a Revenue Decoupling and Conservation Incentive
Mechanism for residential and general service rate classes, which would partially separate the
collection of fixed costs from gas sales and enhance the utility’s ability to recover its fixed
costs.
In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate
increase of $50 million, including an authorized return on equity of 10.75 percent. The proposed
Revenue Decoupling and Conservation Incentive Mechanism was not approved. On September 25, 2007,
the MPSC reopened the record in the case to allow all interested parties to be heard concerning the
approval of an energy efficiency program, which we included in our original filing. If approved in
total, this would result in an additional rate increase of $9 million to be used to implement the
energy efficiency program.
ENTERPRISES OUTLOOK
In 2007, we completed the sale of our international assets. Our primary focus with respect to our non-utility businesses is to optimize cash flow and maximize
the value of our remaining assets.
We completed the sale of a portfolio of our businesses in Argentina and our northern Michigan
non-utility natural gas assets to Lucid Energy for $130 million in March 2007.
In connection with the sale of our Argentine and Michigan assets, we entered into agreements that
grant Lucid Energy:
•
an option to buy CMS Gas Transmission’s ownership interest in TGN, subject to the rights
of other third parties,
•
the right to certain proceeds that may be awarded and received by CMS Gas
Transmission in connection with certain legal proceedings, and
•
the right to proceeds that Enterprises will receive if it sells its stock
interest in CMS Generation San Nicolas Company.
Under these agreements, we have essentially sold our rights to certain awards or proceeds that we
may receive in the future. Of the total consideration received in the sale, we allocated $32
million to these agreements and recorded this amount as a deferred credit on our Consolidated
Balance Sheets. Due to the settlement of certain legal proceedings in September 2007, a portion of
CMS Gas Transmission’s obligations under these agreements has been satisfied. As such, we
recognized $17 million of the deferred credit as a gain in September 2007.
We entered into an agreement to sell our investment in Jamaica to AEI for gross cash proceeds of
$14 million in June 2007. We closed on the sale in October 2007.
Uncertainties: Trends or uncertainties that could have a material impact on our consolidated
income, cash flows, or balance sheet and credit improvement include:
•
the outcome of ongoing negotiations to restructure the power supply agreements
associated with our DIG power plant,
•
the impact of indemnity and environmental remediation obligations at Bay Harbor,
•
the outcome of certain legal proceedings,
•
the impact of representations, warranties, and related indemnities in connection with
the sales of our international assets,
•
the outcome of the planned sale of other assets, and
•
changes in commodity prices and interest rates on certain derivative contracts that do
not qualify for hedge accounting and must be marked to market through earnings.
Prairie State: In October 2006, we signed agreements with Peabody Energy to co-develop the Prairie
State Energy Campus (Prairie State), a 1,600 MW power plant and coal mine in southern Illinois. In
April 2007, we withdrew from Prairie State because it did not meet our investment criteria,
including the level of power purchase agreements for our share of output from Prairie State.
DIG Supply Contracts: DIG and CMS ERM are parties to long-term requirements contracts to provide
steam and (or) electricity based on a fixed price schedule. The price of natural gas, the primary
fuel used by DIG, is volatile and has increased substantially in recent years. Because the prices
charged under DIG’s contracts do not reflect current natural gas prices, DIG’s and CMS ERM’s
financial performance has been impacted negatively. However, since not all of its capacity is
committed under these contracts, DIG has been able to sell a portion of its electric capacity and
(or) energy into the market at a profit, or, through CMS ERM, engage in a hedging strategy to
minimize its losses. DIG and CMS ERM may take various actions such as seeking restructuring or
buyout of the contracts, which may require material cash payments. If a restructuring or buyout is
not possible, then continuing losses under the contracts could have a material adverse impact on
our financial position and results of operations. CMS Energy may also take other measures to
address the unfavorable returns, including the sale of DIG.
Software Implementation: We are in the process of implementing new business software to replace
existing business processes and information technology. The core business processes include
finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset
construction and maintenance work management. We intend the new business software, scheduled to be
in production in the first half of 2008, to improve customer service, reduce risk,
and increase flexibility.
Michigan Public Service Commission: During the third quarter of 2007, the Michigan governor
appointed a new MPSC chairperson and a new MPSC Commissioner. We are unable to predict the impact
of these appointments.
Litigation and Regulatory Investigation: We are the subject of an investigation by the DOJ
regarding round-trip trading transactions by CMS MST. Also, we are named as a party in various
litigation matters including, but not limited to, securities class
action lawsuits and several lawsuits regarding alleged false natural
gas price reporting and price manipulation. Additionally, the SEC is investigating the actions of
former CMS Energy subsidiaries in relation to Equatorial Guinea. For additional details regarding
these and other matters, see Note 3, Contingencies and Part II, Item 1. Legal Proceedings.
Michigan Tax Legislation: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan
Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts
tax of 0.8 percent. The bill provides for a number of tax credits and incentives geared toward
those companies investing and employing in Michigan. The Michigan Business Tax, which is effective
January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31,2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional
deductions in future years against the business income portion of the tax. These future deductions
are phased in over a 15-year period, beginning in 2015. As a result of the enactment of this tax,
we recorded, on a consolidated basis, a net deferred tax liability of
$113 million and a corresponding net
deferred tax asset of $113 million.
In September 2007, Michigan’s governor also signed legislation expanding the state’s sales tax to
certain services. The list of covered services includes certain services that we purchase from
outside vendors and potentially services that we sell. This list includes, but is not limited to,
certain consulting services, landscaping (which encompasses tree trimming), janitorial services,
security guards and security systems.
The Michigan Business Tax and the expanded sales tax were enacted to replace the expiring Michigan
Single Business Tax. We are currently evaluating the impact of the replacement of the Michigan
Single Business Tax with these new taxes. We expect to recover the taxes that we pay from our
customers, but we cannot predict the timeliness of such recovery.
Implementation of New Accounting Standards
SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an
amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS
No. 158. Phase one of this standard required us to recognize the funded status of our defined
benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase one
was implemented in December 2006. Phase two of this standard requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008. We do not believe
that implementation of phase two of this standard will have a material effect on our consolidated
financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.
FIN 48, Accounting for Uncertainty in Income Taxes: We adopted the provisions of FIN 48 on January1, 2007. This interpretation provides a two-step approach for the recognition and measurement of
uncertain tax positions taken, or expected to be taken, by a company on its income tax returns.
The first step is to evaluate the tax position to determine if, based on management’s best
judgment, it is greater than 50 percent likely that we will sustain the tax position. The second
step is to measure the appropriate amount of the benefit to recognize. This is done by estimating
the potential outcomes and recognizing the greatest amount that has a cumulative probability of at
least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on
differences between tax positions recognized in our consolidated financial statements and the
amount claimed, or expected to be claimed, on the tax return.
As a result of the implementation of FIN 48, we have identified additional uncertain tax benefits
of $11 million as of January 1, 2007. Included in this amount is an increase in our valuation
allowance of $100 million, decreases to tax reserves of $61 million and a decrease to deferred tax
liabilities of $28 million.
CMS Energy and its subsidiaries file a consolidated U.S. federal income tax return as well as
unitary and combined income tax returns in several states. CMS Energy and its subsidiaries also
file separate company income tax returns in several states. The only significant state tax paid by
CMS Energy is in Michigan. However, since the Michigan Single Business Tax is not an income tax,
it is not part of the FIN 48 analysis. For the U.S. federal income tax return, CMS Energy
completed examinations by federal taxing authorities for its taxable years prior to 2002. The
federal income tax returns for the years 2002 through 2005 are open under the statute of
limitations.
We have reflected a net interest liability of $3 million related to our uncertain income tax
positions on our Consolidated Balance Sheets as of January 1, 2007. We have not accrued any
penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties,
where applicable, related to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against certain U.S. and foreign
deferred tax assets totaling $216 million and other uncertain tax positions of $31 million,
resulting in total unrecognized benefits of $247 million. Of this amount, $217 million would
result in a decrease in our effective tax rate, if recognized. We released $81 million of our
valuation allowance in the first quarter of 2007, reducing our effective tax rate, due to the
anticipated sales of our foreign investments. During the second quarter of 2007, we eliminated $63
million of valuation allowance attributable to additional foreign asset sales. This had no income
impact, as an identical amount of deferred tax asset also expired. As we continue to market our
foreign investments, it is reasonably possible that additional valuation allowance adjustments
could be made.
New Accounting Standards Not Yet Effective
SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective
for us January 1, 2008. The standard provides a revised definition of “fair value” and gives
guidance on how to measure the fair value of assets and liabilities. Under the standard, fair
value is defined as the price that would be received to sell an asset or paid to transfer a
liability in an orderly exchange between market participants. The standard does not expand the use
of fair value in any new circumstances. However, additional disclosures will be required on the
impact and reliability of fair value measurements reflected in our consolidated financial
statements. The standard will also eliminate the existing prohibition of recognizing “day one”
gains or losses on derivative instruments, and will generally require such gains and losses to be
recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS
No. 157. We currently do not hold any derivatives that would involve day one gains or losses.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an
amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for
us January 1, 2008. This standard will give us the option to select certain financial instruments
and other items, which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we would recognize
unrealized gains and
losses associated with changes in the fair value of the item over time. The
statement will also require disclosures for items for which the fair value option has been elected.
We are presently evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.
FSP FIN 39-1, Amendment of FASB Interpretation No. 39: In April 2007, the FASB issued FSP FIN
39-1, effective for us January 1, 2008. This standard will permit us to offset the fair value of
derivative instruments with cash collateral received or paid for those derivative instruments
executed with the same counterparty under a master netting arrangement. As a result, we will be
permitted to record one net asset or liability that represents the total net exposure of all
derivative positions under a master netting arrangement. The decision to offset derivative
positions under master netting arrangements remains an accounting policy choice. We presently
record the net fair value of derivative assets and liabilities for those contracts held by CMS ERM
that are subject to master netting arrangements, and separately record amounts for cash collateral
received or paid for these instruments. Under this standard, as a result of offsetting the
collateral amounts against the fair value of derivative assets and liabilities, both our total
assets and total liabilities could be reduced. The standard is to be applied retrospectively by
adjusting the financial statements for all periods presented. There will be no impact to earnings
from adopting this standard.
EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:
In June 2007, the FASB ratified EITF Issue 06-11, effective for us on a prospective basis beginning
January 1, 2008. EITF 06-11 requires companies to recognize the income tax benefit realized from
dividends or dividend equivalents that are charged to retained earnings and paid to employees for
non-vested equity-classified employee share-based payment awards as an increase to additional
paid-in capital. We do not believe that implementation of this standard will have a material
effect on our financial statements.
These interim Consolidated Financial Statements have been prepared by CMS Energy in accordance with
accounting principles generally accepted in the United States for interim financial information and
with the instructions to Form 10-Q and Article 10 of Regulation S-X. As such, certain information
and footnote disclosures normally included in consolidated financial statements prepared in
accordance with accounting principles generally accepted in the United States have been condensed
or omitted. Certain prior year amounts have been reclassified to conform to the presentation in
the current year, including certain reclassifications to our Consolidated Financial Statements for
discontinued operations. Therefore, the consolidated financial statements for the year ended
December 31, 2006 and for the three and nine months ended September 30, 2006 have been updated for
amounts previously reported. 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 Notes to Consolidated Financial Statements and the related Consolidated Financial Statements
should be read in conjunction with the Consolidated Financial Statements and related Notes
contained in CMS Energy’s Form 10-K for the year ended December 31, 2006 and the Form 8-K filed
June 4, 2007 amending CMS Energy’s 2006 financial statements to reflect certain discontinued
operations resulting from certain asset sales. Due to the seasonal nature of CMS Energy’s
operations, the results as presented for this interim period are not necessarily indicative of
results to be achieved for the fiscal year.
1: Corporate Structure and Accounting Policies
Corporate Structure: CMS Energy is an energy company operating primarily in Michigan. We are the
parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas
utility company serving in Michigan’s Lower Peninsula. Enterprises, through various subsidiaries and
equity investments, is engaged in primarily domestic independent power production. We manage our
businesses by the nature of services each provides and operate principally in three business
segments: electric utility, gas utility, and enterprises.
Principles of Consolidation: The consolidated financial statements include CMS Energy, Consumers,
Enterprises, and all other entities in which we have a controlling financial interest or are the
primary beneficiary, in accordance with FIN 46(R). We use the equity method of accounting for
investments in companies and partnerships that are not consolidated, where we have significant
influence over operations and financial policies, but are not the primary beneficiary. We
eliminate intercompany transactions and balances.
Use of Estimates: We prepare our consolidated financial statements in conformity with U.S. GAAP.
We are required to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.
We record estimated liabilities for contingencies in our consolidated financial statements when it
is probable that a loss will be incurred in the future as a result of a current event, and when an
amount can be reasonably estimated. For additional details, see Note 3, Contingencies.
Revenue Recognition Policy: We recognize revenues from deliveries of electricity and natural gas,
and the transportation, processing, and storage of natural gas when services are provided. We
record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of
marketed electricity, natural gas, and other energy products at delivery. We recognize
mark-to-market changes in
the fair values of energy trading contracts that qualify as derivatives as revenues in the periods
in which the changes occur.
Accounting for Legal Fees: We expense legal fees as incurred; fees incurred but not yet billed are
accrued based on estimates of work performed. This policy also applies to fees incurred on behalf
of employees and officers related to indemnification agreements; such fees are billed directly to
us.
Accounting for MISO Transactions: MISO requires that we submit hourly day-ahead and real-time bids
and offers for energy at locations across the MISO region. Consumers and CMS ERM account for MISO
transactions on a net hourly basis in each of the real-time and day-ahead markets, and net
transactions across all MISO energy market nodes at which they enter into transactions. To the
degree we have made net purchases in a single hour, we report the net amount in the “Purchased and
interchange power” line item of the Consolidated Statements of Income (Loss). To the degree we
have made net sales in a single hour, we report the net amount in the “Operating Revenue” line item
of the Consolidated Statements of Income (Loss). CMS ERM records billing adjustments when it
receives invoices. Consumers records expense accruals for future adjustments based on historical
experience, and reconciles accruals to actual expenses when invoices are received.
International Operations and Foreign Currency: Our previously owned 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. We show these foreign currency translation adjustments in
the stockholders’ equity section on our Consolidated Balance Sheets. We include exchange rate
fluctuations on transactions denominated in a currency other than the functional currency, except
those that are hedged, in determining net income.
At September 30, 2007, the cumulative Foreign Currency Translation component of stockholders’
equity was $129 million, net of tax, which primarily represents currency losses in Argentina. The
cumulative foreign currency loss due to the unfavorable exchange rate of the Argentine peso using
an exchange rate of 3.149 pesos per U.S. dollar was $129 million, net of tax.
Impairment of Long-Lived Assets and Equity Method Investments: We evaluate potential impairments
of our 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.
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.
We also assess our ability to recover the carrying amounts of our equity method investments
whenever events or changes in circumstances indicate that the carrying amount of the investments
may not be recoverable. This assessment requires us to determine the fair values of our equity
method investments. We determine fair value using 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 record a write down if the fair value is less than the
carrying value and the decline in value is considered to be other than temporary.
For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
Other Income and Other Expense: The following tables show the components of Other income and Other
expense:
In Millions
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Other income
Interest and dividends — related parties
$
—
$
2
$
—
$
8
Electric restructuring return
—
1
1
3
Return on stranded and security costs
1
1
4
4
Nitrogen oxide allowance sales
—
1
—
7
Refund of surety bond premium
—
—
—
1
Gain on investment
3
—
7
—
All other
—
2
3
5
Total other income
$
4
$
7
$
15
$
28
In Millions
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Other expense
Accretion expense
$
—
$
—
$
—
$
(4
)
Derivative loss on debt tender offer
—
—
(3
)
—
Loss on reacquired and extinguished debt
(11
)
—
(22
)
(5
)
Civic and political expenditures
(1
)
(1
)
(2
)
(2
)
Donations
—
—
—
(1
)
All other
—
(1
)
(2
)
(3
)
Total other expense
$
(12
)
$
(2
)
$
(29
)
$
(15
)
Reclassifications:
We have reclassified certain prior period amounts on our Consolidated Financial
Statements to conform to the presentation for the current period. These reclassifications did not
affect consolidated net income (loss) or cash flow for the periods presented. The most significant
of these reclassifications is related to certain subsidiaries reclassified as “held for sale” on
our Consolidated Balance Sheets and activities of those subsidiaries as Income (Loss) From
Discontinued Operations in our Consolidated Statements of Income (Loss). For additional details,
see Note 2, Asset Sales, Discontinued Operations and Impairment Charges, “Discontinued Operations.”
New Accounting Standards Not Yet Effective: SFAS No. 157, Fair Value Measurements: In September
2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a
revised definition of “fair value” and gives guidance on how to measure the fair value of assets
and liabilities. Under the standard, fair value is defined as the price that would be received to
sell an asset or paid to transfer a liability in an orderly exchange between market participants.
The standard does not expand the use of fair value in any new circumstances. However, additional
disclosures will be required on the impact and reliability of fair value measurements reflected in
our consolidated financial statements. The standard will also eliminate the existing prohibition
of recognizing “day one” gains or losses on derivative instruments, and will generally require such
gains and losses to be recognized through earnings. We are presently evaluating the impacts, if
any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day
one gains or losses.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an
amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for
us January 1, 2008. This standard will give us the option to select certain financial instruments
and other items, which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we would recognize
unrealized gains and losses associated with changes in the fair value of the item over time. The
statement will also require disclosures for items for which the fair value option has been elected.
We are presently evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.
FSP FIN 39-1, Amendment of FASB Interpretation No. 39: In April 2007, the FASB issued FSP FIN
39-1, effective for us January 1, 2008. This standard will permit us to offset the fair value of
derivative instruments with cash collateral received or paid for those derivative instruments
executed with the same counterparty under a master netting arrangement. As a result, we will be
permitted to record one net asset or liability that represents the total net exposure of all
derivative positions under a master netting arrangement. The decision to offset derivative
positions under master netting arrangements remains an accounting policy choice. We presently
record the net fair value of derivative assets and liabilities for those contracts held by CMS ERM
that are subject to master netting arrangements, and separately record amounts for cash collateral
received or paid for these instruments. Under this standard, as a result of offsetting the
collateral amounts against the fair value of derivative assets and liabilities, both our total
assets and total liabilities could be reduced. The standard is to be applied retrospectively by
adjusting the financial statements for all periods presented. There will be no impact to earnings
from adopting this standard.
EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:
In June 2007, the FASB ratified EITF Issue 06-11, effective for us on a prospective basis beginning
January 1, 2008. EITF 06-11 requires companies to recognize the income tax benefit realized from
dividends or dividend equivalents that are charged to retained earnings and paid to employees for
non-vested equity-classified employee share-based payment awards as an increase to additional
paid-in capital. We do not believe that implementation of this standard will have a material
effect on our financial statements.
2: Asset Sales, Discontinued Operations and Impairment Charges
Asset Sales
The impacts of our asset sales are included in Gain on asset sales, net and Income (Loss) from
Discontinued Operations in our Consolidated Statements of Income (Loss). There were no asset sales
for the nine months ended September 30, 2006.
We completed the sale of a portfolio of our businesses in Argentina and our northern Michigan
non-utility natural gas assets to Lucid Energy for gross cash proceeds of $130 million in March
2007. The $301 million pretax loss on sale includes a $279 million loss in discontinued operations
and a $22 million loss in continuing operations.
In connection with the sale of our Argentine and Michigan assets, we entered into agreements that
grant Lucid Energy:
•
an option to buy CMS Gas Transmission’s ownership interest in TGN, subject to the rights
of other third parties,
the right to certain proceeds that may be awarded and received by CMS Gas
Transmission in connection with certain legal proceedings, and
•
the right to proceeds that Enterprises will receive if it sells its stock
interest in CMS Generation San Nicolas Company.
Under these agreements, we have essentially sold our rights to certain awards or proceeds that we
may receive in the future. Of the total consideration received in the sale, we allocated $32
million to these agreements and recorded this amount as a deferred credit on our Consolidated
Balance Sheets. Due to the settlement of certain legal proceedings in September 2007, a portion of
CMS Gas Transmission’s obligations under these agreements has been satisfied. As such, we
recognized $17 million of the deferred credit as a gain in September 2007.
We also sold our interest in El Chocon, an Argentine hydroelectric generating business, to Endesa,
S.A. for gross cash proceeds of $50 million in March 2007. We recorded a $34 million pretax gain
in continuing operations.
We sold our ownership interest in SENECA and certain associated generating equipment to PDVSA,
which is owned by the Bolivarian Republic of Venezuela, for gross cash proceeds of $106 million in
April 2007. We recorded a $46 million pretax gain in discontinued operations.
We sold our ownership interest in businesses in the Middle East, Africa, and India to TAQA for $900
million in May 2007. Gross proceeds from the sale included $792 million in cash proceeds and
TAQA’s assumption of $108 million in debt. Businesses included in the sale were Takoradi,
Taweelah, Shuweihat, Jorf Lasfar, Jubail, and Neyveli. The $80 million pretax gain on sale
includes a $96 million gain recorded in discontinued operations and a $16 million loss recorded in
continuing operations.
In June 2007, we sold CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility, for $211
million, which included $201 million in cash proceeds and CPFL Energia S.A.’s assumption of a $10
million tax liability. We recorded a $3 million pretax gain in discontinued operations.
We sold our investment in GasAtacama to Endesa S.A. for gross cash proceeds of $80 million in
August 2007. There was no gain or loss on the sale.
For the nine months ended September 30, 2007, the following table summarizes asset sales 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)
March
El Chocon
$
34
$
22
March
TGM and Bay Area Pipeline (a)
(22
)
(14
)
May
Middle East, Africa and India businesses (b)
(16
)
(12
)
August
GasAtacama
—
—
September
Sale of award rights (a)
17
11
Various
Other
3
2
Total gain on asset sales
$
16
$
9
(a)
Included in the $130 million sale to Lucid Energy.
Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. Due to
various closing adjustments such as working capital and capital expenditure adjustments and nuclear
fuel usage and inventory adjustments, we have received $363 million in proceeds as of September 30,2007. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock
ISFSI. Because of the sale of Palisades, we paid the NMC, the former operator of Palisades, $7
million in exit fees and forfeited our $5 million investment in the NMC.
Entergy assumed responsibility for the future decommissioning of Palisades and for storage and
disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. At closing, we
transferred $252 million in decommissioning trust fund balances
to Entergy. We are crediting excess decommissioning funds of $189 million to our retail customers from June 2007 through
December 2008 and have recorded this obligation, plus interest, as a regulatory liability on our
Consolidated Balance Sheets. Modification to the terms of the transaction allowed us immediate
access to additional excess decommissioning trust funds of $123 million as of September 30, 2007.
We have proposed a plan to credit these excess decommissioning fund balances to our retail
customers. This plan is under review by the MPSC in our current electric rate case filing. We
recorded this balance, plus interest, as a regulatory liability on our Consolidated Balance Sheets.
The MPSC order approving the Palisades transaction allows us to recover the book value of
Palisades, which we estimated at $314 million. As a result, we
are crediting proceeds in excess of
book value of $66 million to our retail customers from June 2007 through December 2008. After
closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were
$77 million as of September 30, 2007. We deferred the gain as a regulatory liability. The MPSC
order put off ruling on the recovery of transaction costs, including the NMC exit fees, and the $30
million payment to Entergy related to the Big Rock ISFSI until our next general rate case. We
deferred these costs as a regulatory asset on our Consolidated Balance Sheets as recovery is
probable.
In April 2007, the NRC issued an order approving the transfer of the Palisades operating license.
Intervenors have filed petitions for reconsideration of the NRC orders approving the transfer of
the Palisades and Big Rock licenses. The NRC did not alter or stay the prior order approving the
license transfer. We believe that it is unlikely that the NRC will conduct further proceedings or
alter its prior orders, but we cannot predict the outcome of the matter.
Palisades Power Purchase Agreement: Entergy contracted to sell us 100 percent of the plant’s
output up to its current annual average capacity of 798 MW under a 15-year power purchase agreement
beginning in April 2007. We provided $30 million in security to Entergy for our power purchase
agreement obligation in the form of a letter of credit. We estimate that capacity and energy
payments under the Palisades power purchase agreement will be $180 million in 2007 and average $300
million per year thereafter.
Due to the Palisades power purchase agreement, the transaction is a sale and leaseback for
accounting purposes. SFAS No. 98 specifies the accounting required for a seller’s sale and
simultaneous leaseback involving real estate. We have continuing involvement with Palisades
through security provided to Entergy for our power purchase agreement obligation and our DOE
liability and other forms of involvement. As a result, we accounted for the Palisades plant, which
is the real estate asset subject to the leaseback, as a financing for accounting purposes and not a
sale. As a financing, no gain on the sale of Palisades was recognized on the Consolidated
Statements of Income (Loss). We accounted for the remaining non-real estate assets and liabilities
associated with the transaction as a sale.
As a financing, the Palisades plant remains on our Consolidated Balance Sheets and we continue to
depreciate it. We recorded the related proceeds as a finance obligation with payments recorded to
interest expense and the finance obligation based on the amortization of the obligation over the
life of the Palisades power purchase agreement. The value of the finance obligation was based on
an allocation of the transaction proceeds to the fair values of the net assets sold and fair value
of the Palisades plant asset under the financing. As of September 30, 2007, the financing
obligation was $190 million. We estimate future payments of $13 million per year over the next
five years.
Subsequent Asset Sale: We entered into an agreement to sell our investment in Jamaica to AEI for
gross cash proceeds of $14 million in June 2007. We closed on the sale in October
2007.
In accordance with SFAS No. 144, our consolidated financial statements have been reclassified for
all periods presented to reflect the operations, assets and liabilities of our consolidated
subsidiaries that meet the criteria of discontinued operations. The assets and liabilities of
these subsidiaries have been classified as “Assets held for sale” and “Liabilities held for sale”
on our December 31, 2006 consolidated balance sheets. Subsidiaries classified as “held for sale”
at December 31, 2006 include our Argentine businesses, a majority of our Michigan non-utility gas
businesses, CMS Energy Brasil S.A., SENECA, Takoradi, and certain associated holding companies. At
September 30, 2007, there were no subsidiaries classified as “held for sale” due to the completion
of these sales in the first and second quarters of 2007.
The major classes of assets and liabilities “held for sale” on our December 31, 2006 Consolidated
Balance Sheet are as follows:
Our discontinued operations contain the activities of the subsidiaries classified as “held for
sale” as well as those disposed of for the nine months ended September 30, 2007 and are a component
of our Enterprises business segment. We reflect the following amounts in the Income (Loss) From
Discontinued Operations line in our Consolidated Statements of Income (Loss):
In Millions
Three months ended September 30
2007
2006
Revenues
$
—
$
174
Pretax income from discontinued operations
$
—
$
22
Income tax expense
—
11
Income From Discontinued Operations
$
—
$
11
In Millions
Nine months ended September 30
2007
2006
Revenues
$
235
$
486
Pretax income (loss) from discontinued
operations
$
(88
)
$
56
Income tax expense (benefit)
(1
)(a)
24
Income (Loss) From Discontinued Operations
$
(87
)(b)
$
32
(a)
Includes a $5 million additional charge related to foreign earnings repatriated in March 2007.
(b)
Includes a loss on disposal of our Argentine and northern Michigan non-utility assets of $279
million ($171 million after-tax and after minority interest), a gain on disposal of SENECA of $46
million ($33 million after-tax and after minority interest), a gain on disposal of our ownership
interest in businesses in the Middle East, Africa, and India of $96 million ($62 million
after-tax), and a gain on disposal of CMS Energy Brasil S.A. of $3 million ($2 million after-tax).
Income (Loss) From Discontinued Operations includes a provision for anticipated closing costs and a
portion of CMS Energy’s parent company interest expense. Interest expense of $7 million for the
nine months ended September 30, 2007 and $12 million for the nine months ended September 30, 2006
has been allocated based on the net book value of the asset to be sold divided by CMS Energy’s
total capitalization of each discontinued operation multiplied by CMS Energy’s interest expense.
Impairment Charges
The table below summarizes our asset impairments:
In Millions
Pretax
After-tax
Pretax
After-tax
Nine months ended September 30
2007
2007
2006
2006
Asset impairments:
Enterprises:
TGN (a)
$
140
$
91
$
—
$
—
GasAtacama (b)
35
23
239
169
Jamaica (c)
22
14
—
—
PowerSmith (d)
5
3
—
—
Prairie State (e)
2
1
—
—
Total asset impairments
$
204
$
132
$
239
$
169
(a)
In the first quarter of 2007, we recorded a $215 million impairment charge to recognize the
reduction in fair value of our investment in TGN, a natural gas business in Argentina. The
impairment included a cumulative net foreign currency translation loss of approximately $197
million.
In December 2005, certain insurance underwriters paid $75 million to CMS Gas
Transmission in respect of their insurance obligations resulting from the non-payment of the
ICSID arbitration award. We recorded this payment as a deferred credit on our Consolidated Balance
Sheets because of a contingent obligation to refund the proceeds if the arbitration decision was
annulled. In September 2007, the contingent repayment obligation was eliminated by agreement. Later that month,
a separate arbitration panel ruling on the annulment issue upheld the
prior ICSID award. As a result, we recognized the $75 million deferred credit in
Asset impairment charges, net of insurance recoveries on our Consolidated Statements of Income
(Loss). For additional details on this settlement, see Note 3, Contingencies, “Other
Contingencies — Argentina.”
We will maintain our interest in TGN, which remains subject to a potential sale to the
government of Argentina or some other disposition.
(b)
In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas
to GasAtacma due to the Argentine government’s decision to increase the cost of its gas exports
using a special tax. We performed an impairment analysis to determine the fair value of our
investment in GasAtacama and concluded that the fair value was lower than the carrying amount
and that this decline was other than temporary. We recorded an impairment charge in the third
quarter of 2006. As a result, our consolidated net income was reduced by $169 million after
considering tax effects and minority interest.
In the second quarter of 2007, we recorded an impairment charge to reflect the fair value of our
investment in GasAtacama as determined in sale negotiations.
(c)
In the first quarter of 2007, we recorded an impairment charge to reflect the fair value of
our investment in an electric generating plant in Jamaica.
(d)
In the first quarter of 2007, we recorded an impairment charge to reflect the fair value of
our investment in PowerSmith.
(e)
In the second quarter of 2007, we recorded an impairment charge to reflect our withdrawal
from the co-development of Prairie State with Peabody Energy because it did not meet our
investment criteria.
3: CONTINGENCIES
SEC and DOJ Investigations: During the period of May 2000 through January 2002, CMS MST engaged in
simultaneous, prearranged commodity trading transactions in which energy commodities were sold and
repurchased at the same price. These so-called round-trip trades had no impact on previously
reported consolidated net income, earnings per share or cash flows, but had the effect of
increasing operating revenues and operating expenses by equal amounts.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the
DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what
effect, if any, this investigation will have on its business. In March 2004, the SEC approved a
cease-and-desist order settling an administrative action against CMS Energy related to round-trip
trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s
findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in
March 2004, the SEC filed an action against three former employees related to round-trip trading at
CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal
defense costs for the remaining two individuals in accordance with existing indemnification
policies. Those two individuals filed a motion to dismiss the SEC action, which was denied.
Securities Class Action Lawsuits: Beginning in May 2002, a number of complaints were filed against
CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the
United States District Court for the Eastern District of Michigan. The cases were consolidated
into a single lawsuit (the “Shareholder Action”), which generally seeks unspecified damages based
on allegations that the defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy’s business and financial condition,
particularly with respect to revenues and expenses recorded in connection with round-trip trading
by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the
individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual
defendants. In March 2006, the court conditionally certified a class consisting of “all persons
who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17,2002 and who were damaged thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent
Adjustable Convertible Trust Securities (“ACTS”) from the class and, in response, a new class
action lawsuit was filed on behalf of ACTS purchasers (the “ACTS Action”) against the same
defendants named in the Shareholder Action. The settlement described in the following paragraph
has resolved both the Shareholder and ACTS Actions.
On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the
“MOU”), subject to court approval, regarding settlement of the two class action lawsuits. The
settlement was approved by a special committee of independent directors and by the full board of
directors of CMS Energy. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. Under the terms of the MOU, the litigation was settled for a
total of $200 million, including the cost of administering the settlement and any attorney fees the
court awards. CMS Energy made a payment of approximately $123 million plus interest on the
settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of
the settlement amount. In entering into the MOU, CMS Energy made no admission of liability under
the Shareholder Action and the ACTS Action. The parties executed a Stipulation and Agreement of
Settlement dated May 22, 2007 (“Stipulation”) incorporating the terms of the MOU. In accordance
with the Stipulation, CMS Energy paid approximately $1 million of the settlement amount to fund
administrative expenses. On September 6, 2007, the court issued a final order approving the
settlement. The remaining settlement amount was paid following the September 6, 2007 hearing.
On October 5, 2007, two
former officers of Consumers filed an appeal of the order approving
the settlement of the shareholder litigation. Based on the objections
they filed in the District Court and comments made on the record at
the fairness hearing on September 6, 2007, they are not challenging
the amount of the settlement. Their principal complaint was with the
exclusion of all present and former officers and their immediate
families from participation in the settlement. It is not anticipated
that the appeal will result in changes to any material terms of the
settlement approved by the District Court.
Gas Index Price Reporting Investigation: CMS Energy 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 cooperated with an investigation
by the DOJ regarding this matter. Although CMS Energy has not received any formal notification
that the DOJ has completed its investigation, the DOJ’s last request for information occurred in
November 2003, and CMS Energy completed its response to this request in May 2004. CMS Energy is
unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation
will have on its business.
The CFTC filed a civil injunctive action against two former CMS Field Services employees in
Oklahoma federal district court on February 1, 2005. The action alleges the two engaged in
reporting false natural gas trade information, and seeks to prohibit these acts, compel compliance
with the Commodities Exchange Act, and impose monetary penalties. The court entered separate
consent orders with respect to each of the two individuals, one dated April 18, 2007 and one dated
June 25, 2007, resolving this litigation. The consent orders prohibit each of the individuals from
engaging in certain activities and further provide civil monetary penalties in the amount of
$100,000 for one individual and $25,000 for the other individual. Pursuant to agreements with each
of the individuals, CMS has paid $95,000 of the $100,000 amount and $22,000 of the $25,000 amount,
with the remaining amounts paid
by the individuals themselves. These settlements put an end to CFTC enforcement actions relating
to gas price reporting by individuals once employed at present or former CMS subsidiaries.
Gas Index Price Reporting Litigation: CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas,
Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as
defendants in various lawsuits arising as a result of claimed inaccurate natural gas price
reporting. Allegations include manipulation of NYMEX natural gas futures and options prices,
price-fixing conspiracies, and artificial inflation of natural gas retail prices in California,
Colorado, Kansas, Missouri, Tennessee, and Wisconsin. CMS MST has settled a master class action
suit in California state court for $7 million. The CMS Energy defendants
have also settled four class action suits originally filed in California federal
court. The other cases in several federal and state jurisdictions remain pending.
We cannot predict the outcome of these matters.
Katz Technology Litigation: In June 2007, Ronald A. Katz Technology Licensing, L.P. (“RAKTL”),
filed a lawsuit in the United States District Court for the Eastern District of Michigan against
CMS Energy and Consumers alleging patent infringement. RAKTL is claiming that automated customer
service, bill payment services and gas leak reporting offered to our customers and accessed through
toll free numbers infringe on patents held by RAKTL. This case has been transferred to the U.S.
District Court for the Central District of California where other similar cases against public
utilities, banks and other entities involving these patents are pending. We obtained an opinion
from patent counsel that our automated telephone systems do not infringe on RAKTL patents and that
those patents may be invalid. We will defend ourselves vigorously against these claims but cannot
predict their outcome.
Bay Harbor: As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, which
went forward under an agreement with the MDEQ, third parties constructed a golf course and a park
over several abandoned CKD piles, left over from the former cement plant operation on the Bay
Harbor site. Pursuant to the agreement with the MDEQ, a water collection system was constructed to
recover seep water from one of the CKD piles and CMS Energy built a treatment plant to treat the
seep water. In 2002, CMS Energy sold its interest in Bay Harbor, but retained its obligations
under previous environmental indemnifications entered into at the inception of the project.
In September 2004, the MDEQ issued a notice of noncompliance after finding high-pH seep water in
Lake Michigan adjacent to the property. The MDEQ also found higher than acceptable levels of heavy
metals, including mercury, in the seep water.
In February 2005, the EPA executed an AOC to address problems at Bay Harbor, upon the consent of
CMS Land Company (CMS Land) and CMS Capital, LLC, both subsidiaries of CMS Energy. Pursuant to the
AOC, the EPA approved a Removal Action Work Plan in July 2005. Among other things, this plan calls
for the installation of collection trenches to intercept high-pH CKD leachate flow to the lake.
All collection systems contemplated in this work plan have been installed. Shoreline effectiveness
monitoring is ongoing, and CMS Land is obligated to address any observed exceedances in pH. This
may potentially include the augmentation of the collection system. In May 2006, the EPA approved a
pilot carbon dioxide augmentation plan to augment the leachate recovery system by improving pH
results in the Pine Court area of the collection system. The augmentation system was installed in
June 2006. Depending upon measurement results, further augmentation may be necessary.
In February 2006, CMS Land submitted to the EPA a proposed Remedial Investigation and Feasibility
Study for the East Park CKD pile. The EPA approved a schedule for near-term activities, which
includes consolidating certain CKD materials and installing collection trenches in the East Park
leachate release area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan
and Final Engineering Design for Consolidation. CMS Energy and the MDEQ have initiated
negotiations of an AOC and to define a long-term remedy at East Park. These negotiations
have included, among other things, issues relating to the disposal of leachate, the
location and design of collection lines and upstream diversion of water, potential
flow of leachate below the collection system, and other issues.
As a result of the installation of collection systems at the East Park and Bay Harbor sites, CMS
Land is collecting and treating approximately 135,000 gallons of leachate per day and shipping it
by truck for disposal at a Class 1 well located in Johannesburg, Michigan, and at a Municipal
Wastewater Treatment Plant located in Traverse City, Michigan. To address the longer term disposal
of leachate, CMS Land has filed two permit applications with the MDEQ and the EPA, the first to
treat the collected leachate at the East Park and Bay Harbor sites before releasing the water to
Lake Michigan and a second to dispose of leachate in a deep injection well in Alba, Michigan, that
we would own and operate.
CMS Land has entered into various access, purchase and settlement agreements with several of the
affected landowners at Bay Harbor, and entered into a confidential settlement with one landowner to
resolve a lawsuit filed by that landowner. We have received demands for indemnification relating
to claims and (or) lawsuits filed by a property owner and a former business owner at Bay Harbor.
CMS Land has purchased five unimproved lots and two lots with houses. At this time, CMS Land
believes it has all necessary access arrangements to complete the remediation work required under
the AOC.
CMS Energy recorded charges related to this matter in 2004, 2005, and 2006 totaling $93 million.
At September 30, 2007, CMS Energy has a liability of $40 million for its remaining obligations. We
based the liability on 2006 discounted costs, using a discount rate of 4.7 percent and an inflation
rate of 1 percent on annual operating and maintenance costs. We used the interest rate for 30-year
U.S. Treasury securities for the discount rate. The undiscounted amount of the remaining
obligation is $53 million. We expect to pay $18 million in 2007, $17 million in 2008, $3 million
in 2009, and the remaining expenditures as part of long-term operating and maintenance costs. Any
significant change in assumptions, such as an increase in the number of sites, different
remediation techniques, nature and extent of contamination, inability to reach agreement with the
MDEQ or EPA over remedial actions, failure to obtain requested permits from the EPA and the DEQ
related to the Alba injection well or the release of treated leachate to Lake Michigan, and legal
and regulatory requirements, could impact our estimate of remedial action costs and the timing of
the expenditures. An adverse outcome of this matter could, depending on the size of any
indemnification obligation or liability under environmental laws, have a potentially significant
adverse effect on CMS Energy’s financial condition and liquidity and could negatively impact CMS
Energy’s financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter.
Consumers’ Electric Utility Contingencies
Electric Environmental Matters: Our operations are subject to environmental laws and regulations.
Costs to operate our facilities in compliance with these laws and regulations generally have been
recovered in customer rates.
Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly
classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to
modify the plant. We have received and responded to information requests from the EPA on this
subject. We believe that we have properly interpreted the requirements of “routine maintenance.”
If our interpretation is found to be incorrect, we may be required to install additional pollution
controls at some or all of our coal-fired electric generating plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be called into question.
We cannot predict the financial impact or outcome of this issue.
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 the
Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties
with substantial assets are potentially responsible with respect to the individual sites. Based on
our experience, we estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $10 million. At September 30, 2007, we have recorded a liability
for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.
The timing of payments related to the remediation of our Superfund sites is uncertain. Any
significant change in assumptions, such as different remediation techniques, nature and extent of
contamination, and legal and regulatory requirements, could affect our estimate of remedial action
costs and the timing of our remediation payments.
Ludington PCB: In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at Ludington. We removed and replaced
part of the PCB material. Since proposing a plan to deal with the remaining materials, we have had
several conversations with the EPA. The EPA has proposed a rule that would authorize continued use
of such material in place, subject to certain restrictions. We are not able to predict when a
final rule will be issued.
Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of
Violation(NOV)/Finding of Violation (FOV) from the EPA alleging that fourteen of our utility
boilers exceeded visible emission limits in their associated air permits. The utility boilers are
located at the D.E. Karn/J.C. Weadock Generating Complex, the J.H. Campbell Plant, the BC Cobb
Electric Generating Station and the JR Whiting Plant, which are all located in Michigan. We have
formally responded to the NOV/FOV denying the allegations and are awaiting the EPA’s response to
our submission. We cannot predict the financial impact or outcome of this issue.
Litigation: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell
power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we
incorrectly calculated the energy charge payments made pursuant to power purchase agreements with
qualifying facilities. The judge deferred to the primary jurisdiction of the MPSC, dismissing the
circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR
plan case concluding that we have been correctly administering the energy charge calculation
methodology. The plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The
plaintiffs also filed suit in the United States Court for the Western District of Michigan, which
the judge subsequently dismissed on the basis that the pending state court litigation would fully
resolve any federal issue before the courts. The plaintiffs then appealed the dismissal to the
United States Court of Appeals, which held that the district court matter should be stayed rather
than dismissed, pending the outcome of the state appeal. We cannot predict the outcome of these
appeals.
Consumers’ Electric Utility Rate Matters
Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded
Costs. In November 2004, the MPSC approved recovery of Stranded Costs incurred from 2002 through
2003 plus the cost of money through the period of collection. At September 30, 2007, we had a
regulatory asset for Stranded Costs of $67 million on our Consolidated Balance Sheets. We collect
these Stranded Costs through a surcharge on ROA customers. At September 30, 2007, alternative
electric suppliers were providing 311 MW of generation service to ROA customers, which represents
an increase of 1 percent of ROA load compared to September 30, 2006. Since the MPSC order, we have
experienced downward trends in ROA customers. This trend has affected negatively our ability to
recover these
Stranded Costs in a timely manner. If this trend continues, it may require legislative or
regulatory assistance to recover fully our Stranded Costs. It is difficult to predict future ROA
customer trends and their effect on the timely recovery of Stranded Costs.
Power Supply Costs: To reduce the risk of high power supply costs during peak demand periods and
to achieve our reserve margin target, we purchase electric capacity and energy contracts for the
physical delivery of electricity primarily in the summer months and to a lesser degree in the
winter months. We have purchased capacity and energy contracts covering partially the estimated
reserve margin requirements for 2008 through 2010.
PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC
reviews these costs for reasonableness and prudency in annual plan proceedings and in plan
reconciliation proceedings. The following table summarizes our PSCR reconciliation filings with
the MPSC:
Power Supply Cost Recovery Reconciliation
Net Under-
PSCR Cost of Power
Description of Net
PSCR Year
Date Filed
Order Date
recovery
Sold
Underrecovery
2005 Reconciliation
March 2006
July 2007
$36 million
$1.081 billion
MPSC approved the
recovery of our $36
million
underrecovery,
including the cost
of money, related
to our commercial
and industrial
customers.
2006 Reconciliation
March 2007
Pending
$105 million
$1.490 billion
Underrecovery
relates to our
increased METC
costs and coal
supply costs,
increased bundled
sales, and other
cost increases
beyond those
included in the
2006 PSCR plan
filings.
2007 PSCR Plan: In September 2006, we filed our 2007 PSCR plan with the MPSC. The plan sought
authorization to incorporate our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR monthly
factor. In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR
monthly factor on January 1, 2007, as filed. The order also allowed us to continue to roll in
prior year underrecoveries and overrecoveries in future PSCR plans. In September 2007, the ALJ
recommended in his Proposal for Decision that we reduce our 2006 underrecovery rolled into 2007 by
$62 million to reflect the refund of 100 percent of the proceeds from the sale of sulfur dioxide
allowances. Our PSCR plan proposed to refund 50 percent of the proceeds to customers. In
accordance with FERC regulations, we reserved this amount, excluding interest, as a regulatory
liability on our Consolidated Balance Sheets until a final order is received from the MPSC.
Underrecoveries in power supply costs are included in Accrued power supply and gas revenue on our
Consolidated Balance Sheets. We expect to recover fully all of our PSCR costs. When we are unable
to collect these costs as they are incurred, there is a negative impact on our cash flows from
electric utility operations. We cannot predict the outcome of these proceedings.
2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. Included
in our request is proposed recovery of estimated 2007 PSCR underrecoveries of $84 million. We
expect to self-implement the proposed 2008 PSCR charge in January 2008, absent action by the MPSC
by the end of 2007. We cannot predict the outcome of this proceeding.
Electric Rate Case: In March 2007, we filed an application with the MPSC seeking an 11.25 percent
authorized return on equity and an annual increase in revenues of $157 million. In May 2007, we
filed supplemental testimony with the MPSC to include transaction costs from the sale of Palisades.
In July 2007, we filed an amended application with the MPSC to include the proposed purchase of
the Zeeland power plant, the approval of an energy efficiency program, and to make other revisions.
In July 2007, we also filed an amended application for rate relief, which seeks the following:
•
approval to remove the costs associated with Palisades,
•
recovery of the proposed purchase of the Zeeland power plant,
•
partial and immediate rate relief associated with 2007 capital investments, a $400
million equity infusion into Consumers, and general inflation on operation and maintenance
expenses to 2007 levels, and
•
approval of a plan for the distribution of additional excess proceeds from the sale of
Palisades to customers, effectively offsetting the partial and immediate relief for up to
nine months.
The following table summarizes the components of the final and interim requested increase in
revenue:
In Millions
Zeeland
and
Partial
and
Components of the increase in revenue
Immediate
Final
Increase in base rates (a)
$
77
$
146
Removal of Palisades from base rates
(169
)
(169
)
Elimination of Palisades base rate recovery credit from the
PSCR (b)
167
167
Surcharge for return on nuclear investments (c)
—
13
Total requested increase in revenues at March 2007 filing
75
157
Palisades transaction costs
—
28
Zeeland power plant non-fuel revenue requirements
84
92
Energy Efficiency Program surcharge
—
5
Palisades excess proceeds
(127
)
—
Total requested increase in revenues
$
32
$
282
(a)
The increase in base rates relates to Clean Air Act-related and other utility expenditures,
changes in the capital structure, and increased distribution system operation and maintenance costs
including employee pension and health care costs.
(b)
Palisades power purchase agreement costs in the PSCR are presently offset through a base rate
recovery credit. The Palisades base rate recovery credit will be discontinued once Palisades’
costs are removed from base rates.
(c)
The nuclear surcharge is a proposal to earn a return on funds spent on Big Rock spent nuclear
fuel storage, decommissioning, and site restoration expenditures until pending DOE litigation and
future MPSC proceedings regarding this issue are concluded.
When we are unable to include increased costs and investments in rates in a timely manner, there is
a negative impact on our cash flows from electric utility operations. We cannot predict the amount
or timing of any MPSC decision on the requests.
The MCV PPA:The MCV Partnership, which leases and operates the MCV Facility, contracted to sell
1,240 MW of electricity to Consumers under a 35-year power purchase agreement beginning in 1990.
We estimate that capacity and energy payments under the MCV PPA, excluding RCP savings, will range
from $650 million to $750 million per year, which assumes successful exercise of the regulatory-out
provision in the MCV PPA.
Regulatory-out Provision in the MCV PPA: The cost that we incur under the MCV PPA exceeded the
recovery amount allowed by the MPSC until we exercised the regulatory-out provision in the MCV PPA
in September 2007. This action limited our capacity and fixed energy payments to the MCV
Partnership to the amounts that we collect from our customers. Cash underrecoveries of our
capacity and fixed energy payments were $39 million in 2007. However, we used savings from the
RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy
underrecoveries expense.
As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA
from 1,240 MW to 806 MW, which could affect our electric reserve margin. The MCV Partnership has
until January 26, 2008 to notify us of their intention to terminate the MCV PPA at which time the
MCV Partnership must specify the termination date. We have not yet received any notification of
termination. However, the MCV Partnership has notified us that it
disputes our right to exercise the
regulatory-out provision. We believe that the provision is valid and fully effective, but cannot
assure that we will prevail in the event of a proceeding on this issue.
We anticipate that the MPSC will review our exercise of the regulatory-out provision and the likely
consequences of such action in 2007. It is possible that in the event that the MCV Partnership
terminates performance under the MCV PPA, prior orders could limit recovery of replacement power
costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the
cost of replacement power, this could result in our costs exceeding the recovery amount allowed by
the MPSC. We cannot predict the outcome of these matters.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a
determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we
recover from customers. Furthermore, the MCV Partnership filed an application with the MPSC
requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed
energy charges that we are allowed to recover from our customers. We cannot predict the outcome of
these matters.
RCP: In January 2005, we implemented the MPSC-approved RCP with modifications. The RCP allows us
to recover the same amount of capacity and fixed energy charges from customers as approved in prior
MPSC orders. However, we are able to dispatch the MCV Facility based on natural gas market prices.
This results in fuel cost savings for the MCV Facility, which the MCV Partnership shares with us.
The RCP also requires contributions of $5 million annually to a renewable resources program. As of
September 30, 2007, contributions of $13 million were made to the renewable resources program. The
underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the
MCV PPA. However, either party may terminate that agreement under certain conditions. In January
2007, the Michigan Attorney General filed an appeal with the Michigan Supreme Court regarding the
MPSC’s order approving the RCP. The Supreme Court denied the Attorney General’s request to further
consider the matter.
Nuclear Matters: Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs
to decommission Big Rock. In December 2000, funding of the Big Rock trust fund stopped because the
MPSC-
authorized decommissioning surcharge collection period expired. The level of funds provided by the
trust fell short of the amount needed to complete decommissioning. As a result, we provided $45
million of corporate contributions for costs associated with NRC radiological and non-NRC
greenfield decommissioning work as of September 30, 2007. This amount excludes the $30 million
payment to Entergy to assume ownership and responsibility for the Big Rock ISFSI and additional
corporate contributions for nuclear fuel storage costs of $54 million as of September 30, 2007, due
to the DOE’s failure to accept spent nuclear fuel on schedule. We plan to seek recovery from the MPSC of
expenditures that we have funded and have a $129 million regulatory asset recorded on
our Consolidated Balance Sheets as of September 30, 2007.
Actual expenditures for Big Rock decommissioning totaled $388 million as of September 30, 2007.
This total excludes the additional costs for spent nuclear fuel storage due to the DOE’s failure to
accept this spent nuclear fuel on schedule as well as certain increased security costs that we are
recovering through the security cost provisions of Public Act 609 of 2002.
Nuclear Fuel Cost: We deferred payment for disposal of spent nuclear fuel burned before April 7,
1983. Our DOE liability is $158 million at September 30, 2007. This amount includes interest,
which is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered, through
electric rates, the amount of this liability, excluding a portion of interest. In conjunction with
the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155
million letter of credit to Entergy as security for this obligation.
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 a number of 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. If our litigation against the DOE is successful, we plan to use any recoveries as
reimbursement for the incurred costs of spent nuclear fuel storage during our ownership of
Palisades and Big Rock. We can make no assurance that the litigation against the DOE will be
successful. The sale of Palisades and the Big Rock ISFSI did not transfer the right to any
recoveries from the DOE related to costs of spent nuclear fuel storage incurred during our
ownership of Palisades and Big Rock.
In 2002, the site at Yucca Mountain, Nevada was designated for the development of a repository for
the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE,
ultimately, will submit a final license application to the NRC for the repository. The application
and review process is estimated to take several years.
Consumers’ Gas Utility Contingencies
Gas Environmental Matters: We expect to incur investigation and remediation costs at a number of
sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute
that covers environmental activities including remediation. These sites include 23 former
manufactured gas plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or may own only a
portion of the original site. In 2005, we estimated our remaining costs to be between $29 million
and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The
discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in
the consumer price index. We expect to fund most of
these costs through proceeds derived from a settlement with insurers and MPSC-approved rates. At
September 30, 2007, we have a liability of $19 million, net of $63 million of expenditures incurred
to date, and a regulatory asset of $52 million. The timing of payments related to the remediation
of our manufactured gas plant sites is uncertain. 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 and the timing of our remediation payments.
Gas Title Transfer Tracking Fees and Services (TTT): On September 19, 2007, the FERC issued an
order denying Consumers’ request for Summary Disposition and established hearing procedures in this
proceeding. In addition to issues related to the appropriate level of the TTT fee and refunds
related to TTT transactions, this order sets for hearing the issue of whether Consumers has
violated annual reporting requirements of the FERC’s regulations. A prehearing conference was held
on October 4, 2007. Testimony is due November 9, 2007, with hearings to begin February 5, 2008.
We cannot predict the outcome of this proceeding.
Consumers’ Gas Utility Rate Matters
Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural
gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these
costs, policies, and practices for prudency in annual plan and reconciliation proceedings.
The following table summarizes our GCR reconciliation filings with the MPSC:
Gas Cost Recovery Reconciliation
Net Over-
GCR Cost
GCR Year
Date Filed
Order Date
recovery
of Gas Sold
Description of Net Overrecovery
2005-2006
June 2006
April 2007
$3 million
$1.8 billion
The net overrecovery includes
$1 million interest income
through March 2006, which
resulted from a net
underrecovery position during
the majority of the GCR
period.
2006-2007
June 2007
Pending
$5 million
$1.7 billion
The total overrecovery amount
reflects an overrecovery of $1
million plus $4 million in
accrued interest owed to
customers.
Overrecoveries in cost of gas sold are included in Accrued rate refunds on our Consolidated Balance
Sheets.
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan
year, which resulted in approval of a settlement agreement and established a fixed price cap of
$10.10 per mcf for the December 2005 through March 2006 billing period. We were able to maintain
our GCR billing factor below the authorized level for that period. The order was appealed to the
Michigan Court of Appeals by one intervenor. We are unable to predict the outcome of this
proceeding.
GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our 2006-2007 GCR Plan
year, which resulted in approval of a settlement agreement that allowed a base GCR ceiling factor
of $9.48 per mcf for the 12-month period of April 2006 through March 2007. We were able to
maintain our GCR billing factor below the authorized level for that period.
GCR plan for year 2007-2008: In July 2007, the MPSC issued an order for our 2007-2008 GCR plan
year, which resulted in approval of a settlement agreement that allowed a base GCR ceiling factor
of $8.47 per mcf for the 12-month period of April 2007 through March 2008, subject to a quarterly
ceiling price adjustment mechanism.
Due to an increase in NYMEX gas prices compared to the plan, the base GCR ceiling factor increased
to $8.67 per mcf pursuant to the quarterly ceiling price adjustment mechanism for the 3-month
period of July 2007 through September 2007. Beginning October 2007, the base GCR ceiling factor
was adjusted to $8.47 due to a decrease in NYMEX gas prices.
The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts
in our annual GCR reconciliation. Our GCR billing factor for the month of November 2007 is $7.78
per mcf.
2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25
percent authorized return on equity along with an $88 million annual increase in our gas delivery
and transportation rates. We proposed the use of a Revenue Decoupling and Conservation Incentive
Mechanism for residential and general service rate classes, which would partially separate the
collection of fixed costs from gas sales and enhance the utility’s ability to recover its fixed
costs.
In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate
increase of $50 million, including an authorized return on equity of 10.75 percent. The proposed
Revenue Decoupling and Conservation Incentive Mechanism was not approved. On September 25, 2007,
the MPSC reopened the record in the case to allow all interested parties to be heard concerning the
approval of an energy efficiency program, which we included in our original filing. If approved in
total, this would result in an additional rate increase of $9 million to be used to implement the
energy efficiency program.
Other Contingencies
Argentina: As part of its energy privatization incentives, Argentina directed CMS Gas Transmission
to calculate tariffs in U.S. dollars, then convert them to pesos at the prevailing exchange rate,
and to adjust tariffs every six months to reflect changes in inflation. Starting in early 2000,
Argentina suspended the inflation adjustments.
In January 2002, the Republic of Argentina enacted the Public Emergency and Foreign Exchange System
Reform Act. This law repealed the fixed exchange rate of one U.S. dollar to one Argentine peso,
converted all dollar-denominated utility tariffs and energy contract obligations into pesos at the
same one-to-one exchange rate, and directed the Government of Argentina to renegotiate such
tariffs.
CMS Gas Transmission began arbitration proceedings against the Republic of Argentina (Argentina)
under the auspices of the International Centre for the Settlement of Investment Disputes (ICSID) in
mid-2001, citing breaches by Argentina of the Argentine-U.S. Bilateral Investment Treaty (BIT). In
May 2005, an ICSID tribunal concluded, among other things, that Argentina’s economic emergency did
not excuse Argentina from liability for violations of the BIT. The ICSID tribunal found in favor
of CMS Gas Transmission, and awarded damages of U.S. $133 million, plus interest.
The ICSID Convention provides that either party may seek annulment of the award based upon five
possible grounds specified in the ICSID Convention. ICSID formally registered Argentina’s
Application for Annulment in September 2005. In December 2005, certain insurance underwriters paid
$75 million to CMS Gas Transmission in respect of their insurance obligations resulting
from non-payment of the ICSID arbitration award. We recorded this payment as a deferred credit on our Consolidated Balance
Sheets because of a contingent obligation to refund the proceeds
if the arbitration decision was annulled. In September 2007, the contingent repayment obligation was eliminated by agreement.
Later that month, a separate arbitration panel ruling on the
annulment issue upheld the prior ICSID award. As a result, we
recognized the $75 million deferred credit in Asset impairment
charges, net of insurance recoveries on our Consolidated Statements
of Income (Loss).
For
more details on the sale of our Argentine and Michigan assets to Lucid Energy, see Note 2, Asset
Sales, Discontinued Operations and Impairment Charges, “Asset Sales.”
Quicksilver Resources, Inc.: Quicksilver sued CMS MST for breach of contract in connection with a
Contract for Sale and Purchase of natural gas, pursuant to which Quicksilver agreed to sell, and
CMS MST agreed to buy, natural gas. Quicksilver believes that it is entitled to more payments for
natural gas than it has received. CMS MST disagrees with Quicksilver’s analysis and believes that
it has paid all amounts owed for delivery of gas pursuant to the contract. Quicksilver is seeking
damages of up to approximately $126 million, plus prejudgment interest and attorney fees.
The trial commenced on March 19, 2007. The jury verdict awarded Quicksilver zero compensatory
damages but $10 million in punitive damages. The jury found that CMS MST breached the contract and
committed fraud but found no actual damage on account of either such claim.
On May 15, 2007, the trial court, ruling on motions to counter the entry of the judgment, vacated
the jury award of punitive damages but held that the contract should be rescinded prospectively.
The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter
of 2007 of approximately $24 million, net of tax. To preserve its appellate rights, CMS MST filed
a motion to modify, correct or reform the judgment and a motion for a judgment contrary to the jury
verdict with the trial court. The trial court dismissed these motions. CMS MST has filed a notice
of appeal with the Texas Court of Appeals.
Star Energy: In 2000, a Michigan trial judge granted Star Energy, Inc. and White Pine Enterprises,
LLC a 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 an $8 million award. The Michigan Court of
Appeals reversed the damages award and granted Terra Energy Ltd. a new trial on damages only. The
trial was set for August 2007, but the parties reached a settlement before trial. As a result, CMS
Energy recorded a charge in the second quarter of 2007 of approximately $3 million, net of tax.
T.E.S. Filer City Air Permit Issue: In January 2007, we received a Notice of Violation from the
EPA alleging that T.E.S. Filer City, a generating facility in which we have a 50 percent
partnership interest, exceeded certain air permit limits. We are in discussions with the EPA with
regard to these allegations, but cannot predict the financial impact or outcome of this issue.
Equatorial
Guinea Tax Claim: In 2004, CMS Energy received a request for indemnification from the purchaser of
CMS Oil and Gas. The indemnification claim relates to the sale by CMS Energy of its oil, gas and
methanol projects in Equatorial Guinea and the claim of the government of Equatorial Guinea that we
owe it $142 million in taxes in connection with that sale. CMS Energy and its tax advisors concluded that
the government’s tax claim is without merit and the purchaser of CMS Oil and Gas submitted a response to the government rejecting the claim.
CMS Energy was informed recently that the Equatorial Guinea
government still intends to pursue its claim. An adverse outcome of this claim could
have a material adverse effect on CMS Energy’s financial condition, liquidity and results of
operations. We cannot predict the ultimate cost or outcome of this matter.
Other: In addition to the matters disclosed within this Note, Consumers and certain other
subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before
various courts and governmental agencies arising from the ordinary course of business. These
lawsuits and proceedings may involve personal injury, property damage, contractual matters,
environmental issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this Note. Resolution
of these contingencies is not expected to have a material adverse impact on our financial position,
liquidity, or future results of operations.
FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others: The Interpretation requires the
guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the
obligation it undertakes in issuing the guarantee.
Indemnifications from asset sales and
other agreements (a)
Various
Indefinite
$
1,327
$
88
(b)
Surety bonds and other indemnifications
Various
Indefinite
24
—
Guarantees and put options (c)
Various
Various through
September 2027
99
1
(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 claims related to tax disputes,
claims related to power purchase agreements and the failure of title to the assets or stock sold by
us to the purchaser.
(b)
In the second quarter of 2007, we recorded $87 million of liabilities related to tax and other
indemnifications for completed asset sales.
(c)
Maximum obligation includes $85 million related to the MCV Partnership’s non-performance under
a steam and electric power agreement with Dow. We sold our interests in the MCV Partnership and
the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments, to pay $85 million, subject to certain reimbursement rights,
if Dow terminates an agreement under which the MCV Partnership provides it steam and electric
power. This agreement expires in March 2016, subject to certain terms and conditions. The
purchaser secured its reimbursement obligation with an irrevocable letter of credit of up to $85
million.
The following table provides additional information regarding our guarantees:
Events That Would Require
Guarantee Description
How Guarantee Arose
Performance
Indemnifications from
asset sales
and other agreements
Stock and asset sales agreements
Findings of
misrepresentation,
breach of
warranties, tax
claims and other
specific events or
circumstances
Surety bonds and other
indemnifications
Normal operating activity,
permits and licenses
Nonperformance
Guarantees and put options
Normal operating activity
Nonperformance or
non-payment by a
subsidiary under a
related contract
Agreement to provide power and
steam to Dow
MCV Partnership’s
nonperformance or
non-payment under a
related contract
Bay Harbor remediation efforts
Owners exercising
put options
requiring us to
purchase property
At September 30, 2007, certain contracts contained provisions allowing us to recover, from third
parties, amounts paid under the guarantees. For example, if we are required to purchase a property
under a put option agreement, we may sell the property to recover the amount paid under the option.
We enter into various agreements containing tax and other indemnification provisions in connection
with a variety of transactions, including the sale of our interests in the MCV Partnership and the
FMLP and the sale of our interest in Palisades and the Big Rock ISFSI. While we are unable to
estimate the maximum potential obligation related to these indemnities, we consider the likelihood
that we would be required to perform or incur significant losses related to these indemnities and
the guarantees listed in the preceding tables to be remote.
Financings: The following is a summary of significant long-term debt transactions during the nine
months ended September 30, 2007:
Principal
Issue/Retirement
(in millions)
Interest Rate (%)
Date
Maturity Date
Debt Issuances
CMS Energy
Senior notes
$
250
6.55
%
July 2007
July 2017
Senior notes (a)
150
Variable
July 2007
January 2013
Total
$
400
Debt Retirements:
CMS Energy
Senior notes
$
260
8.90
%
June 2007
July 2008
Senior notes
409
7.50
%
July and August 2007
January 2009
Enterprises
CMS Generation
Investment Co.
IV Bank
Loan
108
Variable
May 2007
December 2008
Total
$
777
(a)
The variable rate senior notes bear interest at three-month LIBOR plus 95 basis points (6.31
percent at September 30, 2007).
Costs and discounts associated with CMS Energy’s senior notes issuances totaled $7 million and are
being amortized over the lives of the related debt. Premiums associated with CMS Energy’s debt
retirements totaled $21 million and were charged to other expense.
In October 2007, $289 million of CMS Energy’s 9.875 percent senior notes matured and were redeemed.
Revolving Credit Facilities: The following secured revolving credit facilities with banks are
available at September 30, 2007:
We replaced our $300 million facility with a new $300 million credit facility in April 2007.
Consumers replaced its $500 million facility with a new $500 million credit facility in March 2007.
The new facilities contain less restrictive covenants, and provide for lower fees and lower
interest margins than the previous credit facilities.
Dividend Restrictions: Under provisions of our senior notes indenture, at September 30, 2007,
payment of common stock dividends was limited to $499 million. The dividend restrictions in our
secured revolving credit facility were removed in April 2007.
Under the provisions of its articles of incorporation, at September 30, 2007, Consumers had $250
million of unrestricted retained earnings available to pay common stock dividends. The dividend
restrictions in its secured revolving credit facility were removed in March 2007. Provisions of
the Federal Power Act and the Natural Gas Act effectively restrict dividends to the amount of
Consumers’ retained earnings. For the nine months ended September 30, 2007, we received $176
million of common stock dividends from Consumers.
Preferred Stock: In February 2007, our non-voting preferred subsidiary interest of $11 million was
repurchased and redeemed for a cash payment of $32 million. The original $19 million addition to
paid-in-capital was reversed and a $1 million redemption premium was charged to retained deficit.
Contingently Convertible Securities: In September 2007, the $11.87 per share conversion trigger
price contingency was met for our $250 million 4.50 percent contingently convertible preferred
stock and the $12.81 per share conversion trigger price contingency was met for our $150 million
3.375 percent contingently convertible senior notes. As a result, these securities are convertible
at the option of the security holders for the three months ending December 31, 2007, with the par
value or principal payable in cash. As of October 2007, none of the security holders have notified
us of their intention to convert these securities.
Because the 3.375 percent senior notes are convertible on demand, they are classified as current
liabilities.
Capital Lease Obligations: Our capital leases are comprised mainly of leased service vehicles,
office furniture, and gas pipeline capacity. At September 30, 2007, capital lease obligations
totaled $62 million. We estimate future minimum lease payments to range between $10 million and
$19 million per year over the next five years.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers sells
certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose
entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million
of the receivables. The special purpose entity sold no receivables at September 30, 2007 and $325
million of receivables at December 31, 2006. Consumers continues to service the receivables sold
to the special purpose entity. The purchaser of the receivables has no recourse against Consumers’
other assets for failure of a debtor to pay when due and no right to any receivables not sold.
Consumers has neither recorded a gain or loss on the receivables sold nor retained an interest in
the receivables sold.
Certain cash flows under Consumers’ accounts receivable sales program are shown in the following
table:
In Millions
Nine months ended September 30
2007
2006
Net cash flow as a result of accounts receivable financing
The following table presents the basic and diluted earnings per share computations based on
Income (Loss) from Continuing Operations:
In Millions, Except Per Share Amounts
Three Months Ended September 30
2007
2006
Income (Loss) Available to Common Stockholders
Income (Loss) from Continuing Operations
$
84
$
(112
)
Less Preferred Dividends
(2
)
(2
)
Income (Loss) from Continuing Operations
Available to
Common Stockholders — Basic and Diluted
$
82
$
(114
)
Average Common Shares Outstanding
Weighted Average Shares — Basic
223.0
220.1
Add dilutive impact of Contingently
Convertible Securities
17.0
—
Add dilutive Stock Options and Warrants
1.3
—
Weighted Average Shares — Diluted
241.3
220.1
Income (Loss) Per Average Common Share
Available to Common Stockholders
Basic
$
0.37
$
(0.52
)
Diluted
$
0.34
$
(0.52
)
In Millions, Except Per Share Amounts
Nine Months Ended September 30
2007
2006
Loss Available to Common Stockholders
Loss from Continuing Operations
$
(4
)
$
(82
)
Less Preferred Dividends and Redemption Premium
(9
)
(8
)
Loss from Continuing Operations Available to
Common Stockholders — Basic and Diluted
$
(13
)
$
(90
)
Average Common Shares Outstanding
Weighted Average Shares — Basic
222.4
219.6
Add dilutive impact of Contingently
Convertible Securities
—
—
Add dilutive Stock Options and Warrants
—
—
Weighted Average Shares — Diluted
222.4
219.6
Loss Per Average Common Share
Available to Common Stockholders
Basic
$
(0.06
)
$
(0.41
)
Diluted
$
(0.06
)
$
(0.41
)
Contingently Convertible Securities: Our contingently convertible securities dilute EPS to the
extent that the conversion value, which is based on the average market price of our common stock,
exceeds the principal or par value. For the nine months ended September 30, 2007, we recorded a
loss from continuing operations. Due to antidilution, there was no impact to diluted EPS from our
contingently convertible securities. Had there been positive income from continuing operations,
our contingently convertible securities would have contributed an additional 19.0 million shares
for the nine months ended September 30, 2007.
Stock Options, Warrants and Restricted Stock: For the nine months ended September 30,2007, due to
antidilution, there was no impact to diluted EPS for 1.1 million shares of unvested restricted
stock awards or for options and warrants to purchase 0.3 million shares of common stock. Since the
exercise price was greater than the average market price of our common stock, there was no impact
to diluted EPS for additional options and warrants to purchase 0.7 million shares of common stock
for the three and nine months ended September 30, 2007. These stock options have the potential to
dilute EPS in the future.
Convertible Debentures: For the three months and nine months ended September 30, 2007, due to
antidilution, there was no impact to diluted EPS from our 7.75 percent convertible subordinated
debentures. Using the if-converted method, the debentures would have:
•
increased the numerator of diluted EPS by $2 million for the three months ended
September 30, 2007, and $7 million for the nine months ended September 30, 2007, from an
assumed reduction of interest expense, net of tax, and
•
increased the denominator of diluted EPS by 4.2 million shares.
We can revoke the conversion rights if certain conditions are met.
6: Financial and derivative instruments
Financial Instruments: The carrying amounts of cash, short-term investments, and current
liabilities approximate their fair values because of their short-term nature. We estimate the fair
values of long-term financial instruments based on quoted market prices or, in the absence of
specific market prices, on quoted market prices of similar instruments or other valuation
techniques.
The cost and fair value of our long-term debt instruments including current maturities are as
follows:
Derivative Instruments: In order to limit our exposure to certain market risks, we may enter into
various risk management contracts, such as swaps, options, futures, and forward contracts. These
contracts, used primarily to manage our exposure to changes in interest rates, commodity prices,
and currency exchange rates, are classified as either non-trading or trading. We enter into these
contracts using established policies and procedures, under the direction of both:
•
an executive oversight committee consisting of senior management representatives, and
•
a risk committee consisting of business unit managers.
The contracts we use to manage market risks may qualify as derivative instruments that are subject
to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative and does not
qualify for the normal purchases and sales exception under SFAS No. 133, it is recorded on our
consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each
quarter to reflect any change in the market value of the contract, a practice known as marking the
contract to market. From time to time, we enter into cash flow hedges. If a derivative qualifies
for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported
in AOCL; otherwise, the changes are reported in earnings.
For a derivative instrument to qualify for cash flow hedge accounting:
•
the relationship between the derivative instrument and the forecasted transaction being
hedged must be formally documented at inception,
•
the derivative instrument must be highly effective in offsetting the hedged
transaction’s cash flows, and
•
the forecasted transaction being hedged must be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded
in AOCL, those gains or losses will be reclassified into earnings in the same period or periods the
hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because
it is determined that the forecasted transaction will not occur, any gain or loss recorded in AOCL
at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for
other economic reasons, any gain or loss as of the termination date is deferred and then
reclassified to earnings when the forecasted transaction affects earnings. The ineffective
portion, if any, of all hedges is recognized in earnings.
To determine the fair value of our derivatives, we use information from external sources (i.e.,
quoted market prices and third party valuations), if available. For certain contracts, this
information is not available and we use mathematical valuation models to value our derivatives.
These models require various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. The cash returns we actually
realize on these contracts may vary, either positively or negatively, from the results that we
estimate using these models. As part of valuing our derivatives at market, we maintain reserves,
if necessary, for credit risks arising from the financial condition of our counterparties.
The majority of our commodity purchase and sale contracts are not subject to derivative accounting
under SFAS No. 133 because:
•
they do not have a notional amount (that is, a number of units specified in a derivative
instrument, such as MWh of electricity or bcf of natural gas),
•
they qualify for the normal purchases and sales exception, or
Our coal purchase contracts are not derivatives because there is not an active market for the coal
we purchase. If an active market for coal develops in the future, some of these contracts may
qualify as derivatives and the resulting mark-to-market impact on earnings could be material.
Derivative accounting is required for certain contracts used to limit our exposure to interest rate
risk, commodity price risk, and foreign exchange risk. The following table summarizes our
derivative instruments:
Derivative contracts associated with
equity investments in:
Shuweihat (c)
—
—
—
—
(14
)
(14
)
Taweelah (c)
—
—
—
(35
)
(11
)
24
Jorf Lasfar (c)
—
—
—
—
(5
)
(5
)
Other
—
—
—
—
1
1
(a)
The fair value of CMS ERM’s non-trading electric and gas contracts has decreased significantly
from December 31, 2006 due to the termination of certain gas contracts. CMS ERM had recorded
derivative assets, representing cumulative unrealized mark-to-market gains, associated with these
contracts.
(b)
The fair value of CMS ERM’s trading electric and gas contracts has increased significantly from
December 31, 2006 due to the termination of certain gas contracts. CMS ERM had recorded derivative
liabilities, representing cumulative unrealized mark-to-market losses, associated with these
contracts.
(c)
We sold our equity investments in Shuweihat, Taweelah, and Jorf Lasfar in May 2007. As such,
we no longer reflect our proportionate share of the fair value of the derivatives contracts held by
these investments in our consolidated financial statements.
We record the fair value of the derivative contracts held by CMS ERM in either Price risk
management assets or Price risk management liabilities on our Consolidated Balance Sheets. At
December 31, 2006, the fair value of derivative contracts associated with our equity investments
was included in Investments — Enterprises on our Consolidated Balance Sheets.
CMS ERM Contracts: CMS ERM enters into and owns energy contracts that support CMS Energy’s ongoing
operations. CMS ERM holds certain contracts for the future purchase and sale of natural gas and
electricity that will result in physical delivery of the commodity at contractual prices. These
forward contracts are generally long-term in nature and are classified as non-trading. CMS ERM
also uses various financial instruments, including swaps, options, and futures, to manage commodity
price risks associated with its forward purchase and sale contracts and with generation assets
owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading
activities.
In accordance with SFAS No. 133, non-trading and trading contracts that qualify as derivatives are
recorded at fair value on our Consolidated Balance Sheets. The resulting assets and liabilities
are marked to market each quarter, and changes in fair value are recorded in earnings as a
component of Operating Revenue. For trading contracts, these gains and losses are recorded net in
accordance with
EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for
as executory contracts (that is, on an accrual basis).
Derivative Contracts Associated with Equity Investments: In May 2007, we sold our ownership
interest in businesses in the Middle East, Africa, and India. Certain of these businesses held:
•
interest rate contracts that hedged the risk associated with variable-rate debt, and
•
foreign exchange contracts that hedged the foreign currency risk associated with
payments to be made under operating and maintenance service agreements.
Before the sale, we recorded our proportionate share of the change in fair value of these contracts
in AOCL if the contracts qualified for cash flow hedge accounting; otherwise, we recorded our share
in Earnings from Equity Method Investees.
At the date of the sale, we had accumulated a net loss of $13 million, net of tax, in AOCL
representing our proportionate share of mark-to-market gains and losses from cash flow hedges held
by the equity method investees. After the sale, we reclassified this amount and recognized it in
earnings as a reduction of the gain on the sale. For additional details on the sale of our
interest in these equity method investees, see Note 2, Asset Sales, Discontinued Operations and
Impairment Charges.
Credit Risk: Our swaps, options, and forward contracts contain credit risk, which is the risk that
counterparties will fail to perform their contractual obligations. We reduce this risk through
established credit policies. For each counterparty, we assess credit quality by using credit
ratings, financial condition, and other available information. We then establish a credit limit
for each counterparty based upon our evaluation of credit quality. We monitor the degree to which
we are exposed to potential loss under each contract and take remedial action, if necessary.
CMS ERM enters into contracts primarily with companies in the electric and gas industry. This
industry concentration may have an impact on our exposure to credit risk, either positively or
negatively, based on how these counterparties are affected by similar changes in economic
conditions, the weather, or other conditions. CMS ERM typically uses industry-standard agreements
that allow for netting positive and negative exposures associated with the same counterparty,
thereby reducing exposure. These contracts also typically provide for the parties to demand
adequate assurance of future performance when there are reasonable grounds for doing so.
The following table illustrates our exposure to potential losses at September 30, 2007, if each
counterparty within this industry concentration failed to perform its contractual obligations.
This table includes contracts accounted for as financial instruments. It does not include trade
accounts receivable, derivative contracts that qualify for the normal purchases and sales exception
under SFAS No. 133, or other contracts that are not accounted for as derivatives.
In Millions
Net Exposure from
Net Exposure from
Exposure Before
Collateral
Investment Grade
Investment Grade
Collateral (a)
Held
Net Exposure
Companies
Companies (%)
CMS ERM
$
5
$
—
$
5
$
4
80
%
(a)
Exposure is reflected net of payables or derivative liabilities if netting arrangements exist.
Based on our credit policies, our current exposures, and our credit reserves, we do not expect a
material adverse effect on our financial position or future earnings as a result of counterparty
nonperformance.
7: Retirement Benefits
We provide retirement benefits to our employees under a number of different plans, including:
benefits to certain management employees under SERP,
•
a defined contribution 401(k) Savings Plan,
•
benefits to a select group of management under the EISP, and
•
health care and life insurance benefits under OPEB.
Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of
our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan’s assets are not
distinguishable by company.
In April 2007, we sold Palisades to Entergy. Employees transferred to Entergy as a result of the
sale no longer participate in our retirement benefit plans. We recorded a net reduction of $22
million in pension SFAS No. 158 regulatory assets with a corresponding decrease of $22 million in
pension liabilities on our Consolidated Balance Sheets. We also recorded a net reduction of $15
million in OPEB regulatory SFAS No. 158 assets with a corresponding decrease of $15 million in OPEB
liabilities. The following table shows the net adjustment:
Pension
OPEB
Plan liability transferred to Entergy
$
44
$
20
Trust assets transferred to Entergy
22
5
Net adjustment
$
22
$
15
Beginning May 1, 2007, the CMS Energy Common Stock Fund is no longer an investment option available
for new investments in the 401(k) Savings Plan and the employer’s match is no longer in CMS Energy
Stock. Participants have an opportunity to reallocate investments in the CMS Energy Stock Fund to
other plan investment alternatives. Beginning November 1, 2007, any remaining shares in the CMS
Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment
options. At September 30, 2007, there were 7 million shares of CMS Energy Common Stock in the CMS
Energy Stock Fund.
SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an
amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS
No. 158. Phase one of this standard required us to recognize the funded status of our defined
benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase one
was implemented in December 2006. Phase two of this standard requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008. We do not believe
that implementation of phase two of this standard will have a material effect on our consolidated
financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.
Costs: The following table recaps the costs, other changes in plan assets, and benefit obligations
incurred in our retirement benefits plans:
In Millions
Pension
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Service cost
$
12
$
13
$
37
$
37
Interest expense
22
20
65
62
Expected return on plan assets
(19
)
(20
)
(59
)
(63
)
Amortization of:
Net loss
12
10
35
32
Prior service cost
1
1
5
5
Net periodic cost
28
24
83
73
Regulatory adjustment
(6
)
(3
)
(14
)
(8
)
Net periodic cost after regulatory adjustment
$
22
$
21
$
69
$
65
In Millions
OPEB
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Service cost
$
7
$
6
$
19
$
18
Interest expense
17
15
52
47
Expected return on plan assets
(16
)
(14
)
(47
)
(43
)
Amortization of:
Net loss
6
5
17
15
Prior service credit
(3
)
(3
)
(8
)
(8
)
Net periodic cost
11
9
33
29
Regulatory adjustment
(2
)
—
(5
)
(1
)
Net periodic cost after regulatory adjustment
$
9
$
9
$
28
$
28
8: Income taxes
The principal components of deferred tax assets (liabilities) recognized on our Consolidated
Balance Sheets both before and after the adoption of FIN 48 are as follows:
As a result of the implementation of FIN 48, we have identified additional uncertain tax benefits
of $11 million as of January 1, 2007. Included in this amount is an increase in our valuation
allowance of
$100 million, decreases to tax reserves of $61 million and a decrease to deferred tax liabilities
of $28 million.
CMS Energy and its subsidiaries file a consolidated U.S. federal income tax return as well as
unitary and combined income tax returns in several states. CMS Energy and its subsidiaries also
file separate company income tax returns in several states. The only significant state tax paid by
CMS Energy is in Michigan. However, since the Michigan Single Business Tax is not an income tax,
it is not part of the FIN 48 analysis. For the U.S. federal income tax return, CMS Energy
completed examinations by federal taxing authorities for its taxable years prior to 2002. The
federal income tax returns for the years 2002 through 2005 are open under the statute of
limitations.
We reflected a net interest liability of $3 million related to our uncertain income tax positions
on our Consolidated Balance Sheets as of January 1, 2007. We have not accrued any penalties with
respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable,
related to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against certain U.S. and foreign
deferred tax assets totaling $216 million and other uncertain tax positions of $31 million,
resulting in total unrecognized benefits of $247 million. Of this amount, $217 million would
result in a decrease in our effective tax rate, if recognized. We released $81 million of our
valuation allowance in the first quarter of 2007, reducing our effective tax rate, due to the
anticipated sales of our foreign investments. During the second quarter we reduced deferred tax
assets and related valuation allowances attributable to sold foreign assets by $63 million each.
This reduction had no income impact. As we continue to market our foreign investments, it is
reasonably possible that additional valuation allowance adjustments could be made over the next 12
months.
The actual income tax benefit on continuing operations differs from the amount computed by applying
the statutory federal tax rate of 35 percent to loss before income taxes as follows:
In Millions
Nine Months Ended September 30
2007
2006
Loss before income taxes
$
(62
)
$
(230
)
Statutory federal income tax rate
x 35
%
x 35
%
Expected income tax benefit
(22
)
(81
)
Increase (decrease) in taxes from:
Property differences
10
15
Income tax effect of foreign investments
47
(20
)
Income tax credit amortization
(3
)
(3
)
Medicare Part D exempt income
(7
)
(5
)
Tax exempt income
(1
)
(2
)
Valuation allowance
(82
)
12
Tax contingency reserves
—
(15
)
IRS settlement/credit restoration
—
(49
)
Recorded income benefit
$
(58
)
$
(148
)
Effective tax rate
94
%
64
%
U.S. income taxes were not recorded on the undistributed earnings of foreign subsidiaries that had
been or were intended to be reinvested indefinitely. Upon distribution, those earnings would
likely be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and
withholding taxes payable to various foreign countries. During the first quarter of 2007, we
announced we had signed
agreements or plans to sell substantially all of our foreign assets or subsidiaries. These
anticipated sales resulted in the recognition in 2007 of $71 million of U.S. income tax expense
associated with the change in our determination of our permanent reinvestment of these
undistributed earnings, with $46 million of this amount reflected in income from continuing
operations and $25 million in discontinued operations.
Michigan Business Tax Act: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan
Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts
tax of 0.8 percent. The bill provides for a number of tax credits and incentives geared toward
those companies investing and employing in Michigan. The Michigan Business Tax, which is effective
January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31,2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional
deductions in future years against the business income portion of the tax. These future deductions
are phased in over a 15-year period, beginning in 2015. As a result of the enactment of this tax,
we recorded, on a consolidated basis, a net deferred tax liability of $113 million completely
offset by a net deferred tax asset of $113 million.
9: Asset Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement Obligations: This standard requires companies to
record the fair value of the cost to remove assets at the end of their useful life, if there is a
legal obligation to remove them. 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 $5 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred,
such as for assets with indeterminate lives, the liability is to be recognized when a reasonable
estimate of fair value can be made. Generally, electric and gas transmission and distribution
assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low
probability of a retirement date. Therefore, no liability has been recorded for these assets or
associated obligations related to potential future abandonment. Also, no liability has been
recorded for assets that have insignificant cumulative disposal costs, such as substation
batteries.
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: This
Interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No.
143. The term refers to a legal obligation to perform an asset retirement activity in which the
timing and (or) method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a conditional ARO, as defined
by FIN 47.
(a) $2 million in ARO liabilities moved to Noncurrent liabilities held for sale on our Consolidated
Balance Sheets at December 31, 2006. These AROs were subsequently settled as a result of the sale
of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid
Energy. Cash payments of $4 million are included in the Other current and non-current liabilities
line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In
April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership and responsibility
for the Big Rock ISFSI. Our AROs related to Palisades and the Big Rock ISFSI ended with the sale
and the related ARO liabilities were removed from our Consolidated Balance Sheets. We also removed
the Big Rock ARO related to the plant in the second quarter of 2007 due to the completion of
decommissioning.
In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No.
631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement
Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas
utilities. In June 2007, the MPSC issued an order that requires:
•
the MPSC Staff to advise the MPSC whether there are any FERC accounts, rules or
procedures that should be adopted by reference or changed, and
•
the use of a revised calculation for cost of removal estimates derived from applying
SFAS No. 143, which includes the use of standard retirement units.
We will also be required to file a new gas depreciation study by August 1, 2008, using 2007 removal
costs as the basis for the calculation, and a new electric depreciation study by August 3, 2009,
using 2008 removal costs as the basis for the calculation.
10: Equity Method Investments
Where ownership is more than 20 percent but less than a majority, we account for certain
investments in other companies, partnerships, and joint ventures by the equity method of
accounting. Earnings from equity method investments were less than $1 million for the three months
ended September 30, 2007 and $19 million for the three months ended September 30, 2006. Earnings
from equity method investments were $36 million for the nine months ended September 30, 2007 and
$63 million for the nine months ended September 30, 2006. The amount of consolidated retained
earnings that represent undistributed earnings from these equity method investments were $21
million as of September 30, 2007. As of September 30, 2006, there were no undistributed earnings
from our equity method investments. The most significant of these investments was our 50 percent
interest in Jorf Lasfar, which was sold in May 2007.
Summarized Income Statement Data for Jorf Lasfar is as follows:
In Millions
Three Months Ended
Nine Months Ended
September 30
2007 (a)
2006
2007 (a)
2006
Operating revenue
$
—
$
121
$
164
$
355
Operating expenses
—
77
113
235
Operating income
—
44
51
120
Other expense, net
—
16
19
42
Net income
$
—
$
28
$
32
$
78
(a)
Jorf Lasfar was sold May 2, 2007. The summarized income statement data in the table is
comprised of Jorf Lasfar’s financial information through April 30, 2007.
Our reportable segments consist of business units organized and managed by the nature of products
and services each provides. We evaluate performance based upon the net income of each segment. We
operate principally in three reportable segments: electric utility, gas utility, and enterprises.
“Other” includes corporate interest and other expenses and benefits.
The following tables show our financial information by reportable segment:
In Millions
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Operating Revenue
Electric utility
$
963
$
976
$
2,663
$
2,496
Gas utility
209
201
1,811
1,576
Enterprises
105
108
303
323
Other
5
3
13
9
Total Operating Revenue
$
1,282
$
1,288
$
4,790
$
4,404
Net Income (Loss) Available
to Common Stockholders
Electric utility
$
67
$
93
$
158
$
159
Gas utility
(8
)
(20
)
53
14
Enterprises
58
(133
)
(173
)
(215
)
Discontinued operations
—
11
(87
)
32
Other
(35
)
(54
)
(51
)
(48
)
Total Net Income (Loss)
Available to Common
Stockholders
Consumers Energy Company Management’s Discussion and Analysis
In this MD&A, Consumers Energy, which includes Consumers Energy Company and all of its
subsidiaries, is at times referred to in the first person as “we,”“our” or “us.” This MD&A has
been prepared in accordance with the instructions to Form 10-Q and Item 303 of Regulation S-K.
This MD&A should be read in conjunction with the MD&A contained in Consumers Energy’s Form 10-K for
the year ended December 31, 2006.
Forward-looking statements and information
This Form 10-Q and other written and oral statements that we make contain forward-looking
statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with
the use of words such as “may,”“could,”“anticipates,”“believes,”“estimates,”“expects,”“intends,”“plans,” and other similar words is to identify forward-looking statements that involve
risk and uncertainty. We designed this discussion of potential risks and uncertainties to
highlight important factors that may impact our business and financial outlook. We have no
obligation to update or revise forward-looking statements regardless of whether new information,
future events, or any other factors affect the information contained in the statements. These
forward-looking statements are subject to various factors that could cause our actual results to
differ materially from the results anticipated in these statements. Such factors include our
inability to predict and (or) control:
•
the price of CMS Energy Common Stock, capital and financial market conditions, and the
effect of such market conditions on the Pension Plan, interest rates, and access to the
capital markets, including availability of financing to Consumers, CMS Energy, or any of
their affiliates, and the energy industry,
•
market perception of the energy industry, Consumers, CMS Energy, or any of their
affiliates,
•
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,
•
the impact of possible regulations or laws regarding carbon dioxide and other greenhouse
gas emissions,
•
national, regional, and local economic, competitive, and regulatory policies,
conditions and developments,
•
adverse regulatory or legal decisions, including those related to environmental laws
and regulations, and potential environmental remediation costs associated with such
decisions,
•
potentially adverse regulatory treatment and
(or) regulatory delay or failure to receive timely
regulatory orders concerning a number of significant questions presently or potentially
before the MPSC, including:
•
recovery of Clean Air Act capital and operating costs and other environmental
and safety-related expenditures,
•
recovery of power supply and natural gas supply costs,
timely recognition in rates of additional equity investments in Consumers,
•
adequate and timely recovery of additional electric and gas rate-based
investments,
•
adequate and timely recovery of higher MISO energy and transmission costs,
•
recovery of Stranded Costs incurred due to customers choosing alternative
energy suppliers,
•
recovery of Palisades sale-related costs,
•
approval of Zeeland power plant purchase costs, and
•
approval of a new clean coal plant,
•
the effects on our ability to purchase capacity to serve our customers and fully
recover the cost of these purchases, if the owners of the MCV Facility exercise their right
to terminate the MCV PPA,
•
our ability to utilize our regulatory out rights as it
pertains to the MCV PPA,
•
our ability to recover Big Rock decommissioning funding shortfalls and nuclear fuel
storage costs due to the DOE’s failure to accept spent nuclear fuel on schedule, including the outcome of pending litigation with the DOE,
•
federal regulation of electric sales and transmission of electricity, including
periodic re-examination by federal regulators of our market-based sales authorizations in
wholesale power markets without price restrictions,
•
energy markets, including availability of capacity and the timing and extent of changes
in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and
certain related products due to lower or higher demand, shortages, transportation problems,
or other developments,
•
our ability to collect accounts receivable from our customers,
•
earnings volatility as a result of the GAAP requirement that we utilize mark-to-market
accounting on certain energy commodity contracts and interest rate swaps, which may have,
in any given period, a significant positive or negative effect on earnings, which could
change dramatically or be eliminated in subsequent periods,
•
the effect on our utility and utility revenues of the direct and indirect impacts of the continued economic
downturn experienced by the Michigan economy,
•
potential disruption or interruption of facilities or operations due to accidents, war,
terrorism, or changing political environment, and the ability to obtain or maintain
insurance coverage for such events,
•
technological developments in energy production, delivery, and usage,
•
achievement of capital expenditure and operating expense goals,
•
changes in financial or regulatory accounting principles or policies,
changes in domestic or foreign tax laws or new IRS or foreign governmental
interpretations of
existing or past tax laws,
•
changes in federal or state regulations or laws that could have an impact on our business,
•
outcome, cost, and other effects of legal or administrative proceedings, settlements,
investigations or claims,
•
disruptions in the normal commercial insurance and surety bond markets that may
increase costs or reduce traditional insurance coverage, particularly terrorism and
sabotage insurance and performance bonds,
•
credit ratings of Consumers, CMS Energy, or any of their affiliates,
•
other business or investment considerations that may be disclosed from time to time in
Consumers’ or CMS Energy’s SEC filings, or in other publicly issued written documents, and
•
other uncertainties that are difficult to predict, many of which are beyond our
control.
For additional information regarding these and other uncertainties, see the “Outlook” section
included in this MD&A, Note 3, Contingencies, and Part II, Item 1A. Risk Factors.
Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility
company serving in Michigan’s Lower Peninsula. Our customer base includes a mix of residential,
commercial, and diversified industrial customers.
We manage our business by the nature of services each provides and operate principally in two
business segments: electric utility and gas utility. Our electric utility operations include the
generation, purchase, distribution, and sale of electricity. Our gas utility operations include
the purchase, transportation, storage, distribution, and sale of natural gas.
We earn our revenue and generate cash from operations by providing electric and natural gas utility
services, electric power generation, gas distribution, transmission, and storage, and other energy
related services. Our businesses are affected primarily by:
•
weather, especially during the normal heating and cooling seasons,
•
economic conditions,
•
regulation and regulatory issues,
•
energy commodity prices,
•
interest rates, and
•
our debt credit rating.
During the past several years, our business strategy has involved improving our consolidated
balance sheet and maintaining focus on our core strength: utility operations and service.
In April 2007, we sold Palisades to Entergy for $380 million. The final purchase price, subject to
various closing adjustments, resulted in us receiving $363 million as of September 30, 2007. We
also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. We
entered into a 15-year power purchase agreement with Entergy for 100 percent of the plant’s current
electric output. The sale resulted in an immediate improvement in our cash flow, a reduction in
our nuclear operating and decommissioning risk, and an improvement in our financial flexibility to
support other utility investments. The MPSC order approving the
transaction requires that we credit $255 million to our retail customers from June 2007 through December 2008. As of September 30,2007, there are additional excess sales proceeds and decommissioning fund balances of $134 million
above the amount in the MPSC order. The distribution of these additional amounts has not yet been
addressed by the MPSC.
In September 2007, we claimed relief under the regulatory-out provision in the MCV PPA, thereby
limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we
collect from our customers. As a result of our exercise of the regulatory-out provision, the MCV
Partnership may, under certain circumstances, have the right to terminate or reduce the amount of
capacity sold under the MCV PPA, which could affect our need to build or purchase additional
generating capacity. The MCV Partnership has notified us that it
disputes our right to exercise the regulatory-out provision.
We introduced our Balanced Energy Initiative, a comprehensive plan to meet customer energy needs
over the next 20 years, in May 2007. The plan, as filed with the MPSC, is designed to meet the
growing customer demand for electricity with energy efficiency,
demand management, expansion of the use of renewable energy, and development of new power plants to complement existing generating sources.
In September 2007, we filed the second phase of our Balanced Energy Initiative with the MPSC,
which contains our plan for construction of a new 800 MW clean coal plant at an existing site
located near Bay
City, Michigan. Our plan calls for 500 MW of the plant’s output to be used for our customers in
Michigan and to commit the remaining 300 MW to others. We expect the plant to enter operation in 2015 with our
share of the cost estimated at $1.3 billion excluding financing costs and $1.6 billion with
financing costs.
In May 2007, we entered an agreement to buy a 946 MW natural gas-fired power plant located in
Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $517 million.
We expect to close by early 2008, subject to approval from the MPSC.
In the future, we will continue to focus on:
•
investing in our utility system to enable us to meet our customer commitments, comply
with increasing environmental performance standards, improve system performance, and
maintain adequate supply and capacity,
•
growing earnings while controlling operating and fuel costs,
•
managing cash flow issues, and
•
principles of safe, efficient operations, customer value, fair and timely regulation,
and consistent financial performance.
As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been
hampered by negative developments in Michigan’s automotive industry and limited growth in the
non-automotive sectors of the state’s economy.
Other (Includes the MCV Partnership and FMLP interests)
1
26
(25
)
Net income available to common stockholder
$
60
$
99
$
(39
)
For the three months ended September 30, 2007, net income available to our common stockholder was
$60 million, compared to $99 million for the three months ended September 30, 2006. The decrease
primarily reflects a decrease in electric net income due to the sale of Palisades in April 2007.
As a result of the sale of Palisades, electric revenue related to the recovery of Palisades and Big
Rock costs has been used to offset costs incurred under our power purchase agreement with Entergy.
Also contributing to the decrease was the absence, in 2007, of the recognition of a property tax
refund. Partially offsetting these decreases was lower nuclear operating and maintenance costs due
to the sale of Palisades.
Specific changes to net income available to our common stockholder for 2007 versus 2006 are:
In Millions
•
decrease in general taxes primarily due to absence, in 2007, of a property tax
refund at the MCV Partnership,
$
(32
)
•
decrease due to electric revenue being used to offset costs incurred under our power
purchase agreement with Entergy,
(32
)
•
other net decreases,
(7
)
•
lower nuclear operating and maintenance costs,
21
•
increase in gas delivery revenue primarily due to the MPSC’s November 2006 and August
2007 gas rate orders, and
8
•
increase in gas delivery revenue primarily due to higher estimated system efficiency.
Other (Includes the MCV Partnership and FMLP interests)
5
(29
)
34
Net income available to common stockholder
$
216
$
144
$
72
For the nine months ended September 30, 2007, net income available to our common stockholder was
$216 million, compared to $144 million for the nine months ended September 30, 2006. The increase
primarily reflects the sale of our ownership interest in the MCV Partnership in late 2006.
Accordingly, in 2007, we are no longer experiencing mark-to-market losses on certain long-term gas
contracts and associated financial hedges at the MCV Partnership. The increase also reflects
higher net income from our electric and gas utilities due to higher, weather-driven sales caused by
favorable weather compared to 2006, and gas rate increases authorized in November 2006 and August
2007. Partially offsetting these gains was a decrease in electric net income due to the sale of
Palisades in April 2007. As a result of the sale of Palisades, electric revenue related to the
recovery of Palisades and Big Rock costs has been used to offset costs incurred under our power
purchase agreement with Entergy.
Specific changes to net income available to our common stockholder for 2007 versus 2006 are:
In Millions
•
lower nuclear operating and maintenance costs,
$
46
•
increase in gas delivery revenue primarily due to the MPSC’s November 2006 and August
2007 gas rate orders,
37
•
decrease in losses from our ownership interest in the MCV Partnership primarily due to
the absence, in 2007, of mark-to-market losses on certain long-term gas contracts and
financial hedges, and a property tax refund,
34
•
increase in electric revenue primarily due to favorable weather and higher surcharge
revenue,
24
•
increase in gas delivery revenue primarily due to favorable
weather,
14
•
decrease due to electric revenue
being used to offset costs incurred under our power purchase agreement with Entergy,
(59
)
•
increase in general taxes,
(13
)
•
increase in income taxes, primarily due to the absence of IRS income tax benefits, and
Other operating expenses, other income, and
non-commodity revenue
33
97
General taxes
(7
)
(14
)
Interest charges
(7
)
(13
)
Income taxes
14
1
Total change
$
(26
)
$
(1
)
Electric deliveries: For the three months ended September 30, 2007, electric delivery revenues
decreased $6 million versus 2006, as deliveries to end-use customers were 10.5 billion kWh, a
decrease of less than 0.1 billion kWh or less than
1 percent versus 2006. The decrease in electric
deliveries for the three months ended September 30, 2007 is primarily due to unfavorable weather.
For the nine months ended September 30, 2007, electric delivery revenues increased $26 million
versus 2006, as deliveries to end-use customers were 29.5 billion kWh, an increase of 0.5 billion
kWh or 2 percent versus 2006. The increase in electric deliveries for the nine months ended
September 30, 2007 is primarily due to favorable weather.
Surcharge revenue: In the first quarter of 2006, we started collecting a surcharge that the MPSC
authorized under Section 10d(4) of the Customer Choice Act. The
surcharge factors increased in January 2007 pursuant to a MPSC order.
The increase in the surcharge factors increased electric
delivery revenue by $3 million for the three months ended September 30, 2007 and $11 million for
the nine months ended September 30, 2007 versus 2006.
Palisades revenue to PSCR: As a result of the sale of Palisades, electric revenue of $50 million
for the three months ended September 30, 2007 and $91 million for the nine months ended September30, 2007, related to Palisades rate base is now designated toward recovery of PSCR costs.
Power supply costs and related revenue: PSCR revenue decreased by $6 million for the three months
ended September 30, 2007 and $18 million for the nine months ended September 30, 2007 versus 2006.
These decreases primarily reflect amounts excluded from recovery in the 2006 PSCR Reconciliation
case. A portion of these excluded costs are instead being recovered through Electric Delivery
Revenue. The decrease also reflects the absence, in 2007, of an increase in Power Supply Revenue
associated with the 2005 PSCR Reconciliation case.
Other operating expenses, other income and non-commodity revenue: For the three months ended
September 30, 2007, other operating expenses decreased $30 million, other income increased $10
million,
and non-commodity revenue decreased $7 million versus 2006. For the nine months ended September30, 2007, other operating expenses decreased $79 million, other income increased $26 million, and
non-commodity revenue decreased $8 million versus 2006.
The decrease in other operating expenses was primarily due to lower operating and maintenance
expense, including reductions to certain workers’ compensation and injuries and damages expense.
These decreases were offset partially by higher depreciation and amortization expense. Operating
and maintenance expense decreased primarily due to the absence, in 2007, of costs incurred in 2006
related to a planned refueling outage at Palisades, and lower overhead line maintenance, and storm
restoration costs. Also contributing to the decrease was the sale of Palisades in April 2007.
Depreciation and amortization expense increased due to higher non-nuclear plant in service and
greater amortization of certain regulatory assets.
For the three months ended September 30, 2007, the increase in other income was primarily due to
higher interest income mainly due to the proceeds from the sale of Palisades and equity infusions
from the parent. For the nine months ended September 30, 2007, the increase in other income was
primarily due to higher interest income and higher income associated with our Section 10d(4)
Regulatory Asset. The increase on our Section 10d(4) Regulatory Asset reflects the absence, in
2007, of the impact of the MPSC’s final order in this case.
General taxes: For the three months ended September 30, 2007, general tax expense increased
primarily due to higher property tax and MSBT tax expense. For the nine months ended September 30,2007, general tax expense increased primarily due to higher property tax, sales and use tax
expense, and MSBT tax expense.
Interest charges: For the three months ended September 30, 2007, interest charges increased $7
million versus 2006. For the nine months ended September 30, 2007, interest charges increased $13
million versus 2006. The increase was primarily due to interest associated with amounts to be
refunded to customers as a result of the sale of Palisades. The MPSC order approving the Palisades
power purchase agreement with Entergy directed us to record interest on the unrefunded balance.
Income taxes: For the three months and nine months ended September 30, 2007, income taxes decreased
versus 2006 primarily due to lower earnings.
Gas wholesale and retail
services, other gas
revenues and other income
3
13
Operation and maintenance
(2
)
(22
)
General taxes and depreciation
(4
)
(10
)
Interest charges
3
2
Income taxes
(4
)
(22
)
Total change
$
12
$
39
Gas deliveries: For the three months ended September 30, 2007, gas deliveries decreased less than
1 bcf or 1 percent versus 2006. Despite lower gas deliveries, gas delivery revenue increased by $5
million due to higher estimated system efficiency.
For the nine months ended September 30, 2007, gas delivery revenues increased by $22 million
versus 2006 as gas deliveries, including miscellaneous transportation to end-use customers, were 207 bcf,
an increase of 18 bcf or 9 percent. The increase in gas deliveries was primarily due to favorable
weather.
Gas rate increases: In November 2006, the MPSC issued an order authorizing an annual rate increase
of $81 million. In August 2007, the MPSC issued an order authorizing an annual rate increase of
$50 million. As a result of these orders, gas revenues increased $11 million for the three months
ended September 30, 2007 and $56 million for the nine months ended September 30, 2007.
Gas wholesale and retail services, other gas revenues and other income: For the three and nine
months ended September 30, 2007, the increase was primarily due to higher pipeline capacity
optimization revenue.
Operation and maintenance: For the three months and nine months ended September 30, 2007,
operation and maintenance expenses increased versus 2006 primarily due to higher uncollectible
accounts expense and contributions, beginning in November 2006 pursuant to a November 2006 MPSC
order, to a fund that provides energy assistance to low-income customers.
General taxes and depreciation: For the three months ended September 30, 2007, depreciation
expense increased versus 2006 primarily due to higher plant in service. The increase in general
taxes primarily reflects higher property tax expense and MSBT tax expense. For the nine months
ended September 30, 2007, depreciation expense increased versus 2006 primarily due to higher plant
in service. The increase in general taxes primarily reflects higher property tax expense.
Interest charges: For the three months and nine months ended September 30, 2007, interest charges
reflect lower average debt levels versus 2006.
Income taxes: For the three and nine months ended September 30, 2007, income taxes increased
versus 2006 primarily due to higher earnings by the gas utility.
OTHER RESULTS OF OPERATIONS
In Millions
September 30
2007
2006
Change
Three months ended
$
1
$
26
$
(25
)
Nine months ended
$
5
$
(29
)
$
34
For the three months ended September 30, 2007, net income from other nonutility operations
decreased $25 million versus 2006. In late 2006, we sold our ownership interest in the MCV
Partnership. The change in earnings reflects the absence, in 2007, of the recognition of a property
tax refund received in 2006.
For the nine months ended September 30, 2007, net income from other nonutility operations was $5
million, an increase of $34 million versus 2006. In late 2006, we sold our ownership interest in
the MCV Partnership. The change in earnings reflects the absence, in 2007, of a $35 million loss
related to our ownership interest in the MCV Partnership. The loss in 2006 primarily reflects
mark-to-market losses on certain long-term gas contracts and associated financial hedges.
Partially offsetting this increase is the absence, in 2007, of the recognition of a property tax
refund and the absence, in 2007, of tax benefits associated with the resolution of an IRS income
tax audit.
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. For additional
accounting policies, see Note 1, Corporate Structure and Accounting Policies.
Use of Estimates and Assumptions
We use estimates and assumptions in preparing our consolidated financial statements that may affect
reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation,
amortization, financial and derivative instruments, employee benefits, and contingencies. For
example, we estimate the rate of return on plan assets and the cost of future health-care benefits
to determine our annual pension and other postretirement benefit costs. Actual results may differ
from estimated results due to factors such as changes in the regulatory environment, competition,
regulatory decisions, and lawsuits.
Contingencies: We are involved in various regulatory and legal proceedings that arise in the
ordinary course of our business. We record a liability for contingencies based upon our assessment
that a loss is probable and the amount of loss can be reasonably estimated. We use the principles
in SFAS No. 5 when recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter. We discuss
significant contingencies in the “Outlook” section included in this MD&A.
Accounting for Financial and Derivative Instruments and Market Risk Information
Financial Instruments: Debt and equity securities classified as available-for-sale are reported at
fair value determined from quoted market prices. Unrealized gains or losses resulting from changes
in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in
equity as part of AOCI. Unrealized gains or losses are excluded from earnings unless the related
changes in fair value are determined to be other than temporary.
Derivative Instruments: We account for derivative instruments in accordance with SFAS No. 133.
Since the year ended December 31, 2006, there have been no significant changes in the amount or
types of derivatives that we hold or to how we account for derivatives. For additional details on
our derivatives, see Note 5, Financial and Derivative Instruments.
To determine the fair value of our derivatives, we use information from external sources (i.e.,
quoted market prices and third party valuations), if available. For certain contracts, this
information is not available and we use mathematical valuation models to value our derivatives.
These models require various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. Changes in forward prices or
volatilities could significantly change the calculated fair value of our derivative contracts. The
cash returns we actually realize on these contracts may vary, either positively or negatively, from
the results that we estimate using these models. As part of valuing our derivatives at market, we
maintain reserves, if necessary, for credit risks arising from the financial condition of our
counterparties.
Market Risk Information: The following is an update of our risk sensitivities since December 31,2006. These sensitivities indicate the potential loss in fair value, cash flows, or future earnings
from our financial instruments, including our derivative contracts, assuming a hypothetical adverse
change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the
sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift
used for the analyses.
Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest rates of 10
percent):
Other accounting policies important to an understanding of our results of operations and financial
condition include:
•
accounting for long-lived assets,
•
accounting for the effects of industry regulation,
•
accounting for pension and OPEB,
•
accounting for asset retirement obligations,
•
accounting for nuclear decommissioning costs, and
•
accounting for related party transactions.
These accounting policies were disclosed in our 2006 Form 10-K and there have been no subsequent
material changes.
Capital Resources and Liquidity
Factors affecting our liquidity and capital requirements are:
•
results of operations,
•
capital expenditures,
•
energy commodity and transportation costs,
•
contractual obligations,
•
regulatory decisions,
•
debt maturities,
•
credit ratings,
•
working capital needs, and
•
collateral requirements.
During the summer months, we purchase natural gas and store it for resale primarily during the
winter heating season. Although our prudent natural gas costs are recoverable from our customers,
the amount paid for natural gas stored as inventory requires additional liquidity due to the lag in
cost recovery.
Our current financial plan includes controlling operating expenses and capital expenditures and
evaluating market conditions for financing opportunities, if needed.
We believe the following items will be sufficient to meet our liquidity needs:
•
our current level of cash and revolving credit facilities,
•
our anticipated cash flows from operating and investing activities, and
•
our ability to access secured and unsecured borrowing capacity in the capital markets,
if necessary.
In the second quarter of 2007, Moody’s and S&P upgraded our long-term credit ratings and revised
our rating outlook to stable from positive.
Cash Position, Investing, and Financing
Our operating, investing, and financing activities meet consolidated cash needs. At September 30,2007, we had $810 million of consolidated cash, which includes $41 million of restricted cash.
Net cash provided by (used in) operating and investing activities
340
(282
)
Financing activities
392
(6
)
Net Increase (Decrease) in Cash and Cash Equivalents
$
732
$
(288
)
Operating Activities: For the nine months ended September 30, 2007, net cash provided by operating
activities was $189 million, an increase of $100 million versus 2006. In addition to increased
earnings, operating cash flow increased due to the absence, in 2007, of tax payments made to the
parent related to the 2006 IRS income tax audit, and the absence of the MCV Partnership gas
supplier funds on deposit. Also increasing our operating cash flow was our decrease in
expenditures for gas inventory as the milder winter in 2006 allowed us to accumulate more gas in
our storage facilities. These increases were reduced partially by our payment to fund our pension
plan and the absence, in 2007, of the sale of accounts receivable.
Investing Activities: For the nine months ended September 30, 2007, net cash provided by investing
activities was $151 million, an increase of $522 million versus 2006. This increase was due to
proceeds from the sale of Palisades and proceeds from our nuclear decommissioning trust funds.
This increase was partially offset by the absence, in 2007, of $128 million of restricted cash
released in February 2006.
Financing Activities: For the nine months ended September 30, 2007, net cash provided by financing
activities was $392 million, an increase of $398 million versus 2006. This increase was primarily
due to an increase in cash infusions from the parent and a reduction in debt retirements. These
changes were partially offset by an increase in dividends paid to the parent.
Obligations and Commitments
Revolving Credit Facility: For details on our revolving credit facility, see Note 4, Financings
and Capitalization.
Dividend Restrictions: For details on dividend restrictions, see Note 4, Financings and
Capitalization.
Off-Balance Sheet Arrangements: We enter into various arrangements in the normal course of
business to facilitate commercial transactions with third parties. These arrangements include
indemnifications, letters of credit and surety bonds.
We enter into agreements containing indemnifications standard in the industry and indemnifications
specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually
agreements to reimburse other companies if those companies incur losses due to third party claims
or breach of contract terms. 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 these obligations and believe it is unlikely that we would
be required to perform or otherwise incur any material losses associated with these guarantees.
For additional details on these arrangements, see Note 3, Contingencies, “Other Contingencies -
FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others.”
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we may sell up
to $325 million of certain accounts receivable. The highly liquid and efficient market for
securitized
financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see
Note 4, Financings and Capitalization.
Outlook
CORPORATE OUTLOOK
Our business strategy will focus on investing in our utility system to enable us to meet our
customer commitments, comply with increasing environmental performance standards, and maintain
adequate supply and capacity.
ELECTRIC BUSINESS OUTLOOK
Growth: In 2007, we expect electric deliveries to grow about one percent compared to 2006 levels.
The outlook for 2007 assumes a small decline in industrial economic activity and normal weather
conditions throughout the remainder of the year.
Over the next five years, we expect electric deliveries to grow less than 1.5 percent per year.
This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after
2007. 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 the following:
•
energy conservation measures,
•
fluctuations in weather conditions, and
•
changes in economic conditions, including utilization and expansion or contraction of
manufacturing facilities.
Electric Customer Revenue Outlook: Michigan’s economy has been hampered by automotive
manufacturing facility and related supplier closures and restructurings. The Michigan economy has
also had limited growth in the non-automotive sector. Although our electric utility results are
not dependent upon a single customer, or even a few customers, customers in the automotive sector
represented five percent of our total 2006 electric revenue. We cannot predict the impact of the
Michigan economy on our electric utility customers.
Electric Reserve Margin: We have purchased capacity and energy contracts covering partially the
estimated reserve margin requirements for 2008 through 2010. As of September 30, 2007, we expect
total 2007 capacity costs for these primarily seasonal electric capacity and energy contracts to be
$17 million.
We are
currently planning for a reserve margin of approximately 11 percent
for summer 2008, or supply resources equal to 111 percent of
projected firm summer peak load. Of the 2008 supply resources target,
we expect 85 percent to come from our electric generating plants and
long-term power purchase contracts with other contractual
arrangements making up the remainder of our supply resource needs for
2008. If the MPSC approves the Zeeland power plant purchase, we
expect 95 percent of our 2008 supply resource target will be
satisfied with our electric generating plants and long-term power
purchase contracts, with other contractual arrangements making up the
remainder of our supply resource needs for 2008. Our 15-year power
purchase agreement with Entergy for 100 percent of the Palisades
facility’s current electric output will offset the reduction in
the owned capacity represented by the sale of Palisades in April 2007.
In September 2007, we exercised the regulatory-out provision in the MCV PPA, resulting in a
reduction in the amount we pay to the MCV Partnership to equal the amount we are allowed to recover
in the rates charged to customers. The MCV Partnership may, under certain circumstances, have the
right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA
represents 13 percent of our 2008 expected supply resources.
Electric Transmission Expenses: METC, which provides electric transmission service to us,
increased substantially the transmission rates it charged us in 2006. The revenue collected by
METC under those rates in 2006 was subject to refund. The parties filed a settlement agreement
with the FERC, which was approved in August 2007. This settlement resulted in a refund of 2006
transmission charges of $18 million and a corresponding reduction of our power supply costs.
Electric transmission expenses are anticipated to increase in 2008 by $42 million due primarily to
a 33 percent increase in rates charged to us by our major
transmission provider. This increase is
included in our 2008 PSCR Plan filed with the MPSC in September 2007.
In September 2007, the FERC approved a proposal from transmission owners and operators to include
100 percent of generator interconnection costs in our transmission rates. Previously, generator
interconnection costs were split 50-50 between transmission owners and operators and generators.
Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing regarding the
FERC’s order.
For additional details on power supply costs, see Note 3, Contingencies, “Electric Rate Matters —
Power Supply Costs.”
21st Century Electric Energy Plan: In January 2007, the then chairman of the MPSC proposed three
major policy initiatives to the governor of Michigan. The initiatives involve the use of more
renewable energy resources by all load-serving entities such as Consumers, the creation of an
energy efficiency program, and a procedure for reviewing proposals to construct new generation
facilities. The January proposal indicated that Michigan needs new base-load capacity by 2015 and
recommended measures to make it easier to predict customer demand and revenues. The proposed
initiatives will require changes to current legislation. We will continue to participate as the
MPSC, legislature, and other stakeholders address future electric resource needs.
Balanced Energy Initiative: In May 2007, we filed a “Balanced Energy Initiative” with the MPSC
providing a comprehensive energy resource plan to meet our projected short-term and long-term
electric power requirements. The plan is responsive to the 21st Century Electric Energy Plan and
assumes that Michigan will implement a state-wide energy efficiency program and a renewable energy
portfolio standard. The filing requests the MPSC to rule that the Balanced Energy Initiative
represents a reasonable and prudent plan for the acquisition of necessary electric utility
resources. As acknowledged in the 21st Century Electric Energy Plan, implementation of the
Balanced Energy Initiative will require legislative repeal or significant reform of the Customer
Choice Act. In addition, we endorse the 21st Century Electric Energy Plan recommendation to adopt
a new, up-front certification policy for major power plant investments.
In September 2007, as part of our Balanced Energy Initiative, we announced plans to build an 800 MW
advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. We
expect to use 500 MW of the plant’s output to serve
Consumers’ customers and to commit the remaining 300 MW to others. We expect the plant to enter operation in 2015 with our share of the cost estimated at
$1.3 billion excluding financing costs and $1.6 billion with financing costs.
There are
several obstacles that must be cleared before construction of the
proposed new clean coal plant, including:
•
repeal or significant reform of the Customer Choice Act,
•
obtaining environmental permits,
•
successful MPSC regulatory review and approval, and
•
obtaining property tax abatements.
In
September 2007, we filed with the MPSC an updated Balanced Energy Initiative including our plan for
construction of the new clean coal plant in order to start the regulatory review
process for the new plant. In October 2007, we filed an application with the MDEQ for the
environmental air quality permits required for the new plant. The
Michigan Attorney General has filed a motion with the MPSC to dismiss the Balanced Energy Initiative case claiming that the MPSC lacks
jurisdiction over the matter.
Proposed Power Plant Purchase: In May 2007, we reached an agreement with Broadway Gen Funding LLC,
an affiliate of LS Power Group, to buy a 946 MW gas-fired power plant located in Zeeland, Michigan
for $517 million. The power plant will help meet the growing energy needs of our customers. We
expect to close on the purchase by early 2008, subject to the MPSC’s approval.
Proposed Renewable Energy Legislation: There are various bills introduced into the U.S. Congress
and the Michigan legislature relating to mandatory renewable energy standards. If enacted, these
bills generally would require electric utilities to acquire a certain percentage of their power
from renewable sources or otherwise pay fees or purchase allowances in lieu of having the
resources. We cannot predict whether any such bill will be enacted or in what form.
ELECTRIC BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial condition and future
results of operations. These trends or uncertainties have, or had, or are reasonably expected to have, a
material impact on revenues or income from continuing electric operations.
Electric Environmental Estimates: Our operations are subject to various state and federal
environmental laws and regulations. Costs to operate our facilities in compliance with these laws
and regulations generally have been recovered in customer rates.
Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be
a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant
reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital
expenditures totaling $880 million. From 1998 to present, we have incurred $784 million in capital
expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that
the remaining $96 million of capital expenditures will be made through 2011. These expenditures
include installing selective catalytic reduction control technology on four of our coal-fired
electric generating units. The key assumptions in the capital expenditure estimate include:
•
construction commodity prices, especially construction material and labor,
•
project completion schedules,
•
cost escalation factor used to estimate future years’ costs of 2.6 percent, and
•
an AFUDC capitalization rate of 7.8 percent.
In addition to modifying coal-fired electric generating plants, our compliance plan includes the
use of nitrogen oxide emission allowances until all of the control equipment is operational in
2011. The nitrogen oxide emission allowance annual expense is projected to be $2 million per year
through 2011, which we expect to recover from our customers through the PSCR process. The
projected annual expense
is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that
restrict the usage in any given year of allowances banked from previous years. The allowances and
their cost are accounted for as inventory. The allowance inventory is expensed at the rolling
average cost as the electric generating plants emit nitrogen oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that
requires additional coal-fired electric generating plant emission controls for nitrogen oxides and
sulfur dioxide. We plan to meet the nitrogen oxide requirements of this rule by year-round
operation of our selective catalytic reduction control technology units, installation of low
nitrogen oxide burners, and purchasing emission allowances. We plan to meet the sulfur dioxide
requirements of this rule using sorbent injection, installation of flue gas desulfurization
scrubbers and purchasing emission allowances. Our total cost for equipment installation is
expected to reach approximately $740 million by 2015. Additional purchases of sulfur dioxide
emission allowances in 2012 and 2013 will be needed at an estimated cost of $10 million per year,
which we expect to recover from our customers through the PSCR process.
The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of
Columbia by a number of utilities and other companies. Final briefs were submitted by September 5,2007, with a decision expected in 2008. We cannot predict the outcome of these appeals.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury Rule, which
requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010
and further reductions by 2018. The Clean Air Mercury Rule was appealed to the U.S. Court of
Appeals by a number of states and other entities. Final briefs were submitted by July 13, 2007,
with a decision expected in 2008. We cannot predict the outcome of these appeals.
In April 2006, Michigan’s governor announced a plan that would result in mercury emissions
reductions of 90 percent by 2015. We are working with the MDEQ on the details of this rule;
however, we have developed preliminary cost estimates and a mercury emissions reduction scenario
based on our best knowledge of control technology options and initially proposed requirements. We
estimate costs associated with Phase I of the state’s mercury rule will be approximately $190
million by 2010 and an additional $320 million by 2015.
The following table compares the federal Clean Air Mercury Rule to the proposed state mercury rule:
State and Federal
State and Federal
Phase I
Phase II
Federal Clean Air
Mercury Rule
30% reduction by 2010
with interstate
trading of allowances
70% reduction by 2018
with interstate
trading of allowances
Proposed State
Mercury Rule
30% reduction by 2010
without interstate
trading of allowances
90% reduction by 2015
without interstate
trading of allowances
Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly
classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to
modify the plant. We have received and responded to information requests from the EPA on this
subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of
“routine maintenance.”
If our interpretation is found to be incorrect, we may be required to install additional pollution
controls at some or all of our coal-fired electric generating plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation would be re-examined. We
cannot predict the financial impact or outcome of this issue.
Greenhouse Gases: Several legislative proposals have been introduced in the United States Congress
that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, if enacted, could
require us to replace equipment, install additional equipment for pollution controls,
purchase allowances, curtail operations, or take other steps. Although associated
capital or operating costs relating to greenhouse gas regulation or legislation
could be material, and cost recovery cannot be assured, we expect to have an opportunity
to recover these costs and capital expenditures in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.
On April 2, 2007, the U.S. Supreme Court ruled that the Clean Air Act gives the EPA the authority to
regulate emissions of carbon dioxide and other greenhouse gases from automobiles. In its decision,
the court ordered the EPA to revisit its finding that it has the discretion not to regulate
greenhouse gas emissions from automobiles.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory
emissions reduction requirements could have far-reaching and significant implications for the
energy sector. We cannot estimate the effect of federal or state greenhouse gas policy on our
future consolidated results of operations, cash flows, or financial position due to the uncertain
nature of the policies at this time. However, we will continue to monitor greenhouse gas policy
developments and assess and respond to their potential implications on our business operations.
Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water
intake systems. The rules require significant reduction in fish harmed by
operating equipment. EPA compliance options in the rule were challenged in court. In January
2007, the court rejected many of the compliance options favored by industry and remanded the bulk
of the rule back to the EPA for reconsideration. The court’s ruling is expected to increase
significantly the cost of complying with this rule. However, the cost to comply will not be known
until the EPA’s reconsideration is complete. At this time, the EPA has not established a schedule
to address the court decision.
For additional details on electric environmental matters, see Note 3, Contingencies, “Electric
Contingencies — Electric Environmental Matters.”
Competition and Regulatory Restructuring: The Customer Choice Act allows all of our electric
customers to buy electric generation service from us or from an alternative electric supplier. At
September 30, 2007, alternative electric suppliers were providing 311 MW of generation service to
ROA customers. This is 4 percent of our total distribution load and represents an increase of 1
percent of ROA load compared to September 30, 2006.
In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred from 2002
through 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have
experienced a downward trend in ROA customers. If this trend continues, it will extend the time it
takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends,
which affect our ability to recover timely these Stranded Costs.
Electric Rate Case: In March 2007, we filed an application with the MPSC seeking an 11.25 percent
authorized return on equity and an annual increase in revenues of $157 million. The increase seeks
recovery of the costs associated with increased plant investment, increased equity investment, and
greater operation and maintenance expenses. In May 2007, we filed supplemental testimony with the
MPSC to include transaction costs from the sale of Palisades. In July 2007, we filed an amended
application with the MPSC to include the proposed purchase of the Zeeland power plant, the approval
of an energy efficiency program, and to make other revisions. The revised application seeks an
annual increase in revenues of $282 million.
In July 2007, we also filed an amended application for rate relief that seeks the removal of costs
associated with Palisades, the approval of partial and immediate rate relief for certain items,
including the
proposed purchase of the Zeeland power plant, and the approval of a plan to
distribute excess proceeds from the sale of
Palisades to customers. The case schedule will allow for an MPSC order on our Zeeland request and
on our request for partial and immediate rate relief by the end of 2007 and a final rate order in
mid-2008. We cannot predict the amount or timing of any MPSC decision on our requests.
For additional details and material changes relating to the restructuring of the electric utility
industry and electric rate matters, see Note 3, Contingencies, “Electric Rate Matters.”
OTHER ELECTRIC BUSINESS UNCERTAINTIES
The MCV PPA:The MCV Partnership, which leases and operates the MCV Facility, contracted to sell
electricity to Consumers for a 35-year period beginning in 1990. The cost that we incur under the
MCV PPA exceeded the recovery amount allowed by the MPSC until we exercised the regulatory-out
provision in the MCV PPA in September 2007. This action limited our capacity and fixed energy
payments to the MCV Partnership to the amounts that we collect from our customers. We incurred $39
million in underrecoveries in 2007. The MCV Partnership has notified us that it disputes our right to
exercise the regulatory-out provision. We believe that the provision is valid and fully
effective, but cannot assure that we will prevail in the event of a proceeding on this issue.
As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA.
If the MCV Partnership terminates the MCV PPA or reduces the amount of capacity sold under the MCV
PPA, we would seek to replace the lost capacity to maintain an adequate electric reserve margin.
This could involve entering into a new PPA and (or) entering into electric capacity contracts on
the open market. We cannot predict our ability to enter into such contracts at a reasonable price.
We are also unable to predict regulatory approval of the terms and conditions of such contracts,
or that the MPSC would allow full recovery of our incurred costs.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a
determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we
recover from customers. Also, in May 2007, the MCV Partnership filed an application with the MPSC
seeking approval to increase our recovery of costs incurred under the MCV PPA. We are unable to
predict the outcome of these requests. For additional details on the MCV PPA, see Note 3,
Contingencies, “Other Electric Contingencies — The MCV PPA.”
Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. The final
purchase price, subject to various closing adjustments, resulted in us receiving $363 million as of
September 30, 2007. We also paid Entergy $30 million to assume ownership and responsibility for
the Big Rock ISFSI. Because of the sale of Palisades, we also paid the NMC, the former operator of
Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC.
The MPSC order approving the Palisades transaction allowed us to recover the book value of
Palisades. This results in us crediting estimated proceeds in excess of book value of $66 million
to our customers from June 2007 through December 2008. After closing adjustments, which are
subject to MPSC review, proceeds in excess of the book value were
$77 million as of September 30,2007. The MPSC order deferred ruling on the recovery of transaction costs, including the NMC exit
fees, and the $30 million payment to Entergy related to the Big Rock ISFSI until the next general
rate case.
Entergy assumed responsibility for the future decommissioning of Palisades and for storage and
disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. We transferred
$252 million in trust fund assets to Entergy. We are crediting estimated excess decommissioning
funds of $189 million to our retail customers from June 2007 through December 2008. Access to
additional decommissioning fund balances above the estimates in the MPSC order resulted in excess
decommissioning funds of $123
million as
of September 30, 2007. We have proposed a plan to credit these balances to our retail customers
and this plan is under review by the MPSC in our current electric rate case filing.
As part of the transaction, Entergy will sell us 100 percent of the plant’s output up to its
current annual average capacity of 798 MW under a 15-year power purchase agreement. Because of the
Palisades power purchase agreement and our continuing involvement with the Palisades assets, we
account for the disposal of Palisades as a financing for accounting purposes and not a sale. This
resulted in the recognition of a finance obligation of $197 million.
For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales.
GAS BUSINESS OUTLOOK
Growth: In 2007, we project gas deliveries will decline slightly, on a weather-adjusted basis,
from 2006 levels due to continuing conservation and overall economic conditions in the state of
Michigan. Over the next five years, we expect gas deliveries to decline by less than one-half of
one percent annually. Actual gas deliveries in future periods may be affected by:
•
fluctuations in weather conditions,
•
use by independent power producers,
•
changes in gas commodity prices,
•
Michigan economic conditions,
•
the price of competing energy sources or fuels,
•
gas consumption per customer, and
•
improvements in gas appliance efficiency.
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our future financial results and financial
condition. These trends or uncertainties could have a material impact on future revenues or income
from gas operations.
Gas Environmental Estimates: We expect to incur investigation and remedial action costs at a
number of sites, including 23 former manufactured gas plant sites. For additional details, see
Note 3, Contingencies, “Gas Contingencies — Gas Environmental Matters.”
Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural
gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these
costs, policies, and practices for prudency in annual plan and reconciliation proceedings. For
additional details on gas cost recovery, see Note 3, Contingencies, “Gas Rate Matters — Gas Cost
Recovery.”
Gas Depreciation: In June 2007, the MPSC issued its final order in the generic ARO accounting case
and modified the filing requirement for our next gas depreciation case. The original filing
requirement date was changed from 90 days after the issuance of this order to no later than August1, 2008. Additionally, we have been ordered to use 2007 data and prepare a cost of removal
depreciation study with five alternatives using the MPSC’s prescribed methods.
If a final order in our next gas depreciation case is not issued concurrently with a final order in
a general gas rate case, the MPSC may incorporate the results of the depreciation case into general
gas rates through use of a surcharge mechanism (which may be either positive or negative).
2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25
percent authorized return on equity along with an $88 million annual increase in our gas delivery
and transportation rates. We proposed the use of a Revenue Decoupling and Conservation Incentive
Mechanism for residential and general service rate classes, which would partially separate the
collection of fixed costs from gas sales and enhance the utility’s ability to recover its fixed
costs.
In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate
increase of $50 million, including an authorized return on equity of 10.75 percent. The proposed
Revenue Decoupling and Conservation Incentive Mechanism was not approved. On September 25, 2007,
the MPSC reopened the record in the case to allow all interested parties to be heard concerning the
approval of an energy efficiency program, which we included in our original filing. If approved in
total, this would result in an additional rate increase of $9 million to be used to implement the
energy efficiency program.
OTHER OUTLOOK
Software Implementation: We are in the process of implementing new business software to replace
existing business processes and information technology. The core business processes include
finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset
construction and maintenance work management. We intend the new business software, scheduled to be
in production in the first half of 2008, to improve customer service, reduce risk,
and increase flexibility.
Michigan Public Service Commission: During the third quarter of 2007, the Michigan governor
appointed a new MPSC chairperson and a new MPSC Commissioner. We are unable to predict the impact
of these appointments.
Litigation and Regulatory Investigation: CMS Energy is the subject of various investigations as a
result of round-trip trading transactions by CMS MST, including an investigation by the DOJ. For
additional details regarding this investigation and litigation, see Note 3, Contingencies.
Michigan Tax Legislation: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan
Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts
tax of 0.8 percent. The bill provides for a number of tax credits and incentives geared toward
those companies investing and employing in Michigan. The Michigan Business Tax, which is effective
January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31,2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional
deductions in future years against the business income portion of the tax. These future deductions
are phased in over a 15-year period, beginning in 2015. As a result of the enactment of this tax,
we recorded, on a consolidated basis, a net deferred tax liability of $125 million completely
offset by a net deferred tax asset of $125 million.
In September 2007, Michigan’s governor also signed legislation expanding the state’s sales tax to
certain services. The list of covered services includes certain services that we purchase from
outside vendors and potentially services that we sell. This list includes, but is not limited to,
certain consulting services, landscaping (which encompasses tree trimming), janitorial services,
security guards and security systems.
The Michigan Business Tax and the expanded sales tax were enacted to replace the expiring Michigan
Single Business Tax. We are currently evaluating the impact of the replacement of the Michigan
Single Business Tax with these new taxes. We expect Consumers to recover the taxes paid from
customers, but we cannot predict the timeliness of such recovery.
SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an
amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS
No. 158. Phase one of this standard required us to recognize the funded status of our defined
benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase one
was implemented in December 2006. Phase two of this standard requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008. We do not believe
that implementation of phase two of this standard will have a material effect on our consolidated
financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.
FIN 48, Accounting for Uncertainty in Income Taxes: We adopted the provisions of FIN 48 on January1, 2007. This interpretation provides a two-step approach for the recognition and measurement of
uncertain tax positions taken, or expected to be taken, by a company on its income tax returns.
The first step is to evaluate the tax position to determine if, based on management’s best
judgment, it is greater than 50 percent likely that we will sustain the tax position. The second
step is to measure the appropriate amount of the benefit to recognize. This is done by estimating
the potential outcomes and recognizing the greatest amount that has a cumulative probability of at
least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on
differences between tax positions recognized in our consolidated financial statements and the
amount claimed, or expected to be claimed, on the tax return.
As a result of the implementation of FIN 48, we have identified additional uncertain tax benefits
of $5 million as of January 1, 2007. Included in this amount is an increase in our valuation
allowance of $7 million, increases to tax reserves of $55 million and a decrease to deferred tax
liabilities of $57 million.
Consumers joins in the filing of a consolidated U.S. federal income tax return as well as unitary
and combined income tax returns in several states. Consumers and its subsidiaries also file
separate company income tax returns in several states. The only significant state tax paid by
Consumers or any of its subsidiaries is in Michigan. However, since the Michigan Single Business
Tax is not an income tax, it is not part of the FIN 48 analysis. The IRS has completed its audits
for all the consolidated federal returns, of which Consumers is a member, for years through 2001.
The federal income tax returns for the years 2002 through 2005 are open under the statute of
limitations.
We have reflected a net interest liability of $1 million related to our uncertain income tax
positions on our Consolidated Balance Sheets as of January 1, 2007. We have not accrued any
penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties,
where applicable, related to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against certain deferred tax
assets totaling $22 million and other net uncertain tax positions of $55 million, resulting in
total uncertain benefits of $77 million. Of this amount, $24 million would result in a decrease in
our effective tax rate, if recognized. We are not expecting any material changes to our uncertain
tax positions over the next 12 months.
SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective
for us January 1, 2008. The standard provides a revised definition of “fair value” and gives
guidance on how to measure the fair value of assets and liabilities. Under the standard, fair
value is defined as the price that would be received to sell an asset or paid to transfer a
liability in an orderly exchange between market participants. The standard does not expand the use
of fair value in any new circumstances. However, additional disclosures will be required on the
impact and reliability of fair value measurements reflected in our consolidated financial
statements. The standard will also eliminate the existing prohibition of recognizing “day one”
gains or losses on derivative instruments, and will generally require such gains and losses to be
recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS
No. 157. We currently do not hold any derivatives that would involve day one gains or losses.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an
amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for
us January 1, 2008. This standard will give us the option to select certain financial instruments
and other items, which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we would recognize
unrealized gains and losses associated with changes in the fair value of the item over time. The
statement will also require disclosures for items for which the fair value option has been elected.
We are presently evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.
EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:
In June 2007, the FASB ratified EITF Issue 06-11, effective for us on a prospective basis beginning
January 1, 2008. EITF 06-11 requires companies to recognize the income tax benefit realized from
dividends or dividend equivalents that are charged to retained earnings and paid to employees
for non-vested equity-classified employee share-based payment awards as an increase to additional
paid-in capital. We do not believe that implementation of this standard will have a material
effect on our financial statements.
These interim Consolidated Financial Statements have been prepared by Consumers in accordance with
accounting principles generally accepted in the United States for interim financial information and
with the instructions to Form 10-Q and Article 10 of Regulation S-X. As such, certain information
and footnote disclosures normally included in consolidated financial statements prepared in
accordance with accounting principles generally accepted in the United States have been condensed
or omitted. Certain prior year amounts have been reclassified to conform to the presentation in
the current year. In management’s opinion, the unaudited information contained in this report
reflects all adjustments of a normal recurring nature necessary to assure the fair presentation of
financial position, results of operations and cash flows for the periods presented. The Notes to
Consolidated Financial Statements and the related Consolidated Financial Statements should be read
in conjunction with the Consolidated Financial Statements and related Notes contained in the
Consumers’ Form 10-K for the year ended December 31, 2006. Due to the seasonal nature of
Consumers’ operations, the results as presented for this interim period are not necessarily
indicative of results to be achieved for the fiscal year.
1: Corporate Structure and Accounting Policies
Corporate Structure: Consumers, a subsidiary of CMS Energy, a holding company, is a combination
electric and gas utility company serving Michigan’s Lower Peninsula. Our customer base includes a
mix of residential, commercial, and diversified industrial customers. We manage our business by
the nature of services each provides and operate principally in two business segments: electric
utility and gas utility.
Principles of Consolidation: The consolidated financial statements include Consumers, and all
other entities in which we have a controlling financial interest or are the primary beneficiary, in
accordance with FIN 46(R). We use the equity method of accounting for investments in companies and
partnerships that are not consolidated, where we have significant influence over operations and
financial policies, but are not the primary beneficiary. We eliminate intercompany transactions
and balances.
Use of Estimates: We prepare our consolidated financial statements in conformity with U.S. GAAP.
We are required to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.
We record estimated liabilities for contingencies in our consolidated financial statements when it
is probable that a loss will be incurred in the future as a result of a current event, and when the
amount can be reasonably estimated. For additional details, see Note 3, Contingencies.
Revenue Recognition Policy: We recognize revenues from deliveries of electricity and natural gas,
and the storage of natural gas when services are provided. We record sales tax on a net basis and
exclude it from revenues.
Accounting for Legal Fees: We expense legal fees as incurred; fees incurred but not yet billed are
accrued based on estimates of work performed. This policy also applies to fees incurred on behalf
of
employees and officers related to indemnification agreements; such fees are billed directly to
us.
Accounting for MISO Transactions: MISO requires that we submit hourly day-ahead and real-time bids
and offers for energy at locations across the MISO region. We account for MISO transactions on a
net hourly basis in each of the real-time and day-ahead markets, and net transactions across all
MISO energy market nodes at which we enter into transactions. To the degree we have made net
purchases in a single hour, we report the net amount in the
“Purchased and interchange power” line
item of the Consolidated Statements of Income. To the degree we have made net sales in a single
hour, we report the net amount in the “Operating Revenue” line item of the Consolidated Statements
of Income. We record expense accruals for future adjustments based on historical experience, and
reconcile accruals to actual expenses when invoices are received.
Reclassifications:
We have reclassified certain prior period amounts on our Consolidated Financial
Statements to conform to the presentation for the current period. These reclassifications did not
affect consolidated net income or cash flow for the periods presented.
Other Income and Other Expense: The following tables show the components of Other income and Other
expense:
In Millions
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Other income
Electric restructuring return
$
—
$
1
$
1
$
3
Return on stranded and security costs
1
1
4
4
Nitrogen oxide allowance sales
—
1
—
7
Gain on stock
—
—
4
1
Gain on investment
3
—
7
—
Gain on asset sales, net
—
—
2
—
All other
1
—
3
2
Total other income
$
5
$
3
$
21
$
17
In Millions
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Other expense
Civic and political expenditures
$
(1
)
$
(1
)
$
(2
)
$
(2
)
Donations
—
—
—
(1
)
All other
—
—
(2
)
(2
)
Total other expense
$
(1
)
$
(1
)
$
(4
)
$
(5
)
New Accounting Standards Not Yet Effective: SFAS No. 157, Fair Value Measurements: In September
2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a
revised definition of “fair value” and gives guidance on how to measure the fair value of assets
and liabilities. Under the standard, fair value is defined as the price that would be received to
sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not
expand the use of fair value in any new circumstances. However, additional disclosures will be
required on the impact and reliability of fair value measurements reflected in our consolidated
financial statements. The standard will also eliminate the existing prohibition of recognizing
“day one” gains or losses on derivative instruments, and will generally require such gains and
losses to be recognized through earnings. We are presently evaluating the impacts, if any, of
implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one
gains or losses.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an
amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for
us January 1, 2008. This standard will give us the option to select certain financial instruments
and other items, which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we would recognize
unrealized gains and losses associated with changes in the fair value of the item over time. The
statement will also require disclosures for items for which the fair value option has been elected.
We are presently evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.
EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:
In June 2007, the FASB ratified EITF Issue 06-11, effective for us on a prospective basis beginning
January 1, 2008. EITF 06-11 requires companies to recognize the income tax benefit realized from
dividends or dividend equivalents that are charged to retained earnings and paid to employees for
non-vested equity-classified employee share-based payment awards as an increase to additional
paid-in capital. We do not believe that implementation of this standard will have a material
effect on our financial statements.
2: Asset Sales
Gross cash proceeds from the sale of assets totaled $337 million through September 30, 2007. The
sale of assets resulted in a $2 million gain on our Consolidated Statements of Income.
Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. Due to
various closing adjustments such as working capital and capital expenditure adjustments and nuclear
fuel usage and inventory adjustments, we have received $363 million in proceeds as of September 30,2007. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock
ISFSI. Because of the sale of Palisades, we paid the NMC, the former operator of Palisades, $7
million in exit fees and forfeited our $5 million investment in the NMC.
Entergy assumed responsibility for the future decommissioning of Palisades and for storage and
disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. At closing, we
transferred $252 million in decommissioning trust fund balances
to Entergy. We are crediting excess decommissioning funds of $189 million to our retail customers from June 2007 through
December 2008 and have recorded this obligation, plus interest, as a regulatory liability on our
Consolidated Balance Sheets. Modification to the terms of the transaction allowed us immediate
access to additional excess decommissioning trust funds of $123 million as of September 30, 2007.
We have proposed a plan to credit these excess decommissioning fund balances to our retail
customers. This plan is under review by the MPSC in our current electric rate case filing. We
recorded this balance, plus interest, as a regulatory liability on our Consolidated Balance Sheets.
The MPSC order approving the Palisades transaction allows us to recover the book value of
Palisades, which we estimated at $314 million. As a result, we
are crediting proceeds in excess of book value of
$66 million to our retail customers from June 2007 through December 2008. After
closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were
$77 million as of September 30, 2007. We deferred the gain as a regulatory liability. The MPSC
order put off ruling on the recovery of transaction costs, including the NMC exit fees, and the $30
million payment to Entergy related to the Big Rock ISFSI until our next general rate case. We
deferred these costs as a regulatory asset on our Consolidated Balance Sheets as recovery is
probable.
In April 2007, the NRC issued an order approving the transfer of the Palisades operating license.
Intervenors have filed petitions for reconsideration of the NRC orders approving the transfer of
the Palisades and Big Rock licenses. The NRC did not alter or stay the prior order approving the
license transfer. We believe that it is unlikely that the NRC will conduct further proceedings or
alter its prior orders, but we cannot predict the outcome of the matter.
The following table summarizes the impacts of the Palisades and the Big Rock ISFSI transaction:
In Millions
MPSC Order
Estimated
Customer
Closing
Total
Customer Benefits
Benefits Estimate
Adjustments
Benefits
Purchase price
$
380
$
(7
)
$
373
Less: Book value of Palisades
314
(18
)
296
Excess proceeds
66
11
77
Excess decommissioning trust funds
189
123
312
Total customer benefits
$
255
$
134
$
389
Total
Deferred Costs
Costs
NMC exit fee
$
7
Forfeiture of the NMC investment
5
Selling expenses
14
Total transaction costs
26
Big Rock ISFSI operation and
maintenance fee to Entergy
Palisades Power Purchase Agreement: Entergy contracted to sell us 100 percent of the plant’s
output up to its current annual average capacity of 798 MW under a 15-year power purchase agreement
beginning in April 2007. We provided $30 million in security to Entergy for our power purchase
agreement obligation in the form of a letter of credit. We estimate that capacity and energy
payments under the Palisades power purchase agreement will be $180 million in 2007 and average $300
million per year thereafter.
Due to the Palisades power purchase agreement, the transaction is a sale and leaseback for
accounting purposes. SFAS No. 98 specifies the accounting required for a seller’s sale and
simultaneous leaseback involving real estate. We have continuing involvement with Palisades
through security provided to Entergy for our power purchase agreement obligation and our DOE
liability and other forms of involvement. As a
result, we accounted for the Palisades plant, which is the real estate asset subject to the
leaseback, as a financing for accounting purposes and not a sale. As a financing, no gain on the
sale
of Palisades was recognized on the Consolidated Statements of Income. We accounted for the
remaining non-real estate assets and liabilities associated with the transaction as a sale.
As a financing, the Palisades plant remains on our Consolidated Balance Sheets and we continue to
depreciate it. We recorded the related proceeds as a finance obligation with payments recorded to
interest expense and the finance obligation based on the amortization of the obligation over the
life of the Palisades power purchase agreement. The value of the finance obligation was based on
an allocation of the transaction proceeds to the fair values of the net assets sold and fair value
of the Palisades plant asset under the financing. As of September 30, 2007, the financing
obligation was $190 million. We estimate future payments of $13 million per year over the next
five years.
3: Contingencies
SEC and DOJ Investigations: During the period of May 2000 through January 2002, CMS MST engaged in
simultaneous, prearranged commodity trading transactions in which energy commodities were sold and
repurchased at the same price. These so called round-trip trades had no impact on previously
reported consolidated net income, earnings per share or cash flows, but had the effect of
increasing operating revenues and operating expenses by equal amounts.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the
DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what
effect, if any, this investigation will have on its business. In March 2004, the SEC approved a
cease-and-desist order settling an administrative action against CMS Energy related to round-trip
trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s
findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in
March 2004, the SEC filed an action against three former employees related to round-trip trading at
CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal
defense costs for the remaining two individuals in accordance with existing indemnification
policies. Those two individuals filed a motion to dismiss the SEC action, which was denied.
Securities Class Action Lawsuits: Beginning in May 2002, a number of complaints were filed against
CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the
United States District Court for the Eastern District of Michigan. The cases were consolidated
into a single lawsuit (the “Shareholder Action”), which generally seeks unspecified damages based
on allegations that the defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy’s business and financial condition,
particularly with respect to revenues and expenses recorded in connection with round-trip trading
by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the
individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual
defendants. In March 2006, the court conditionally certified a class consisting of “all persons
who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17,2002 and who were damaged thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent
Adjustable Convertible Trust Securities (“ACTS”) from the class and, in response, a new class
action lawsuit was filed on behalf of ACTS purchasers (the “ACTS Action”) against the same
defendants named in the Shareholder Action. The settlement described in the following paragraph
has resolved both the Shareholder and ACTS actions.
On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the
“MOU”), subject to court approval, regarding settlement of the two class action lawsuits. The
settlement was approved by a special committee of independent directors and by the full board of
directors of CMS Energy. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. Under the terms of the MOU, the litigation was settled for a
total of $200 million, including the cost of administering the settlement and any attorney fees the
court awards. CMS Energy made a payment of approximately $123 million plus interest on the
settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of
the settlement amount. In entering into the MOU, CMS Energy made no admission of liability under
the Shareholder Action and the ACTS Action. The parties executed a Stipulation and Agreement of
Settlement dated May 22, 2007 (“Stipulation”) incorporating the terms of the MOU. In accordance
with the Stipulation, CMS has paid approximately $1 million of the settlement amount to fund
administrative expenses. On September 6, 2007, the court issued a final order approving the
settlement. The remaining settlement amount was paid following the September 6, 2007 hearing.
On
October 5, 2007, two former officers of Consumers filed an
appeal of the order approving the settlement of the shareholder
litigation. Based on the objections they filed in the District Court
and comments made on the record at the fairness hearing on
September 6, 2007, they are not challenging the amount of the
settlement. Their principal complaint was with the exclusion of all
present and former officers and their immediate families from
participation in the settlement. It is not anticipated that the
appeal will result in changes to any material terms of the settlement
approved by the District Court.
Katz Technology Litigation: In June 2007, Ronald A. Katz Technology Licensing, L.P. (“RAKTL”),
filed a lawsuit in the United States District Court for the Eastern District of Michigan against
CMS Energy and Consumers alleging patent infringement. RAKTL is claiming that automated customer
service, bill payment services and gas leak reporting offered to our customers and accessed through
toll free numbers infringe on patents held by RAKTL. This case has been transferred to the U.S.
District Court for the Central District of California where other similar cases against public
utilities, banks and other entities involving these patents are pending. We obtained an opinion
from patent counsel that our automated telephone systems do not infringe on RAKTL patents and that
those patents may be invalid. We will defend ourselves vigorously against these claims but cannot
predict their outcome.
ELECTRIC CONTINGENCIES
Electric Environmental Matters: Our operations are subject to environmental laws and regulations.
Costs to operate our facilities in compliance with these laws and regulations generally have been
recovered in customer rates.
Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly
classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to
modify the plant. We have received and responded to information requests from the EPA on this
subject. We believe that we have properly interpreted the requirements of “routine maintenance.”
If our interpretation is found to be incorrect, we may be required to install additional pollution
controls at some or all of our coal-fired electric generating plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be called into question.
We cannot predict the financial impact or outcome of this issue.
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 the
Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties
with substantial assets are potentially responsible with respect to the individual sites. Based on
our experience, we estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $10 million. At September 30, 2007, we have recorded a liability
for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.
The timing of payments related to
the remediation of our Superfund sites is uncertain. Any significant change in assumptions, such as different
remediation techniques, nature and extent of contamination, and legal and regulatory requirements,
could affect our estimate of remedial action costs and the timing of our remediation payments.
Ludington PCB: In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at Ludington. We removed and replaced
part of the PCB material. Since proposing a plan to deal with the remaining materials, we have had
several conversations with the EPA. The EPA has proposed a rule that would authorize continued use
of such material in place, subject to certain restrictions. We are not able to predict when a
final rule will be issued.
Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of
Violation(NOV)/Finding of Violation (FOV) from the EPA alleging that fourteen of our utility
boilers exceeded visible emission limits in their associated air permits. The utility boilers are
located at the D.E. Karn/J.C. Weadock Generating Complex, the J.H. Campbell Plant, the BC Cobb
Electric Generating Station and the JR Whiting Plant, which are all located in Michigan. We have
formally responded to the NOV/FOV denying the allegations and are awaiting the EPA’s response to
our submission. We cannot predict the financial impact or outcome of this issue.
Litigation: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell
power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we
incorrectly calculated the energy charge payments made pursuant to power purchase agreements with
qualifying facilities. The judge deferred to the primary jurisdiction of the MPSC, dismissing the
circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR
plan case concluding that we have been correctly administering the energy charge calculation
methodology. The plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The
plaintiffs also filed suit in the United States Court for the Western District of Michigan, which
the judge subsequently dismissed on the basis that the pending state court litigation would fully
resolve any federal issue before the courts. The plaintiffs then appealed the dismissal to the
United States Court of Appeals, which held that the district court matter should be stayed rather
than dismissed, pending the outcome of the state appeal. We cannot predict the outcome of these
appeals.
ELECTRIC RATE MATTERS
Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded
Costs. In November 2004, the MPSC approved recovery of Stranded Costs incurred from 2002 through
2003 plus the cost of money through the period of collection. At September 30, 2007, we had a
regulatory asset for Stranded Costs of $67 million on our Consolidated Balance Sheets. We collect
these Stranded Costs through a surcharge on ROA customers. At September 30, 2007, alternative
electric suppliers were providing 311 MW of generation service to ROA customers, which represents
an increase of 1 percent of ROA load compared to September 30, 2006. Since the MPSC order, we have
experienced downward trends in ROA customers. This trend has affected negatively our ability to
recover these Stranded Costs in a timely manner. If this trend continues, it may require
legislative or regulatory assistance to recover fully our Stranded Costs. It is difficult to
predict future ROA customer trends and their effect on the timely recovery of Stranded Costs.
Power Supply Costs: To reduce the risk of high power supply costs during peak demand periods and
to achieve our reserve margin target, we purchase electric capacity and energy contracts for the
physical delivery of electricity primarily in the summer months and to a lesser degree in the
winter months. We
have purchased capacity and energy contracts covering partially the estimated reserve margin
requirements for 2008 through 2010.
PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC
reviews these costs for reasonableness and prudency in annual plan proceedings and in plan
reconciliation proceedings. The following table summarizes our PSCR reconciliation filings with
the MPSC:
Power Supply Cost Recovery Reconciliation
Net Under-
PSCR Cost of Power
Description of Net
PSCR Year
Date Filed
Order Date
recovery
Sold
Underrecovery
2005 Reconciliation
March 2006
July 2007
$36 million
$1.081 billion
MPSC approved the
recovery of our $36
million
underrecovery,
including the cost
of money, related
to our commercial
and industrial
customers.
2006 Reconciliation
March 2007
Pending
$105 million
$1.490 billion
Underrecovery
relates to our
increased METC
costs and coal
supply costs,
increased bundled
sales, and other
cost increases
beyond those
included in the
2006 PSCR plan
filings.
2007 PSCR Plan: In September 2006, we filed our 2007 PSCR plan with the MPSC. The plan sought
authorization to incorporate our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR monthly
factor. In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR
monthly factor on January 1, 2007, as filed. The order also allowed us to continue to roll in
prior year underrecoveries and overrecoveries in future PSCR plans. In September 2007, the ALJ
recommended in his Proposal for Decision that we reduce our 2006 underrecovery rolled into 2007 by
$62 million to reflect the refund of 100 percent of the proceeds from the sale of sulfur dioxide
allowances. Our PSCR plan proposed to refund 50 percent of the proceeds to customers. In
accordance with FERC regulations, we reserved this amount, excluding interest, as a regulatory
liability on our Consolidated Balance Sheets until a final order is received from the MPSC.
Underrecoveries in power supply costs are included in Accrued power supply and gas revenue on our
Consolidated Balance Sheets. We expect to recover fully all of our PSCR costs. When we are unable
to collect these costs as they are incurred, there is a negative impact on our cash flows from
electric utility operations. We cannot predict the outcome of these proceedings.
2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. Included
in our request is proposed recovery of estimated 2007 PSCR underrecoveries of $84 million. We
expect to self-implement the proposed 2008 PSCR charge in January 2008, absent action by the MPSC
by the end of 2007. We cannot predict the outcome of this proceeding.
Electric Rate Case: In March 2007, we filed an application with the MPSC seeking an 11.25 percent
authorized return on equity and an annual increase in revenues of $157 million. In May
2007, we filed
supplemental testimony with the MPSC to include transaction costs from the sale of Palisades. In
July 2007, we filed an amended application with the MPSC to include the proposed purchase of the
Zeeland power plant, the approval of an energy efficiency program, and to make other revisions.
In July 2007, we also filed an amended application for rate relief, which seeks the following:
•
approval to remove the costs associated with Palisades,
•
recovery of the proposed purchase of the Zeeland power plant,
•
partial and immediate rate relief associated with 2007 capital investments, a $400
million equity infusion into Consumers, and general inflation on operation and maintenance
expenses to 2007 levels, and
•
approval of a plan for the distribution of additional excess proceeds from the sale of
Palisades to customers, effectively offsetting the partial and immediate relief for up to
nine months.
The following table summarizes the components of the final and interim requested increase in
revenue:
In Millions
Zeeland
and Partial
and
Components of the increase in revenue
Immediate
Final
Increase in base rates (a)
$
77
$
146
Removal of Palisades from base rates
(169
)
(169
)
Elimination of Palisades base rate recovery credit from the
PSCR (b)
167
167
Surcharge for return on nuclear investments (c)
—
13
Total requested increase in revenues at March 2007 filing
75
157
Palisades transaction costs
—
28
Zeeland power plant non-fuel revenue requirements
84
92
Energy Efficiency Program surcharge
—
5
Palisades excess proceeds
(127
)
—
Total requested increase in revenues
$
32
$
282
(a)
The increase in base rates relates to Clean Air Act-related and other utility expenditures,
changes in the capital structure, and increased distribution system operation and maintenance costs
including employee pension and health care costs.
(b)
Palisades power purchase agreement costs in the PSCR are presently offset through a base rate
recovery credit. The Palisades base rate recovery credit will be discontinued once Palisades’
costs are removed from base rates.
(c)
The nuclear surcharge is a proposal to earn a return on funds spent on Big Rock spent nuclear
fuel storage, decommissioning, and site restoration expenditures until pending DOE litigation and
future MPSC proceedings regarding this issue are concluded.
When we are unable to include increased costs and investments in rates in a timely manner, there is
a negative impact on our cash flows from electric utility operations. We cannot predict the amount
or timing of any MPSC decision on the requests.
The MCV PPA:The MCV Partnership, which leases and operates the MCV Facility, contracted to sell
1,240 MW of electricity to Consumers under a 35-year power purchase agreement beginning in 1990.
We estimate that capacity and energy payments under the MCV PPA, excluding RCP savings, will range
from $650 million to $750 million per year, which assumes successful exercise of the regulatory-out
provision in the MCV PPA.
Regulatory-out Provision in the MCV PPA: The cost that we incur under the MCV PPA exceeded the
recovery amount allowed by the MPSC until we exercised the regulatory-out provision in the MCV PPA
in September 2007. This action limited our capacity and fixed energy payments to the MCV
Partnership to the amounts that we collect from our customers. Cash underrecoveries of our
capacity and fixed energy payments were $39 million in 2007. However, we used savings from the
RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy
underrecoveries expense.
As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA
from 1,240 MW to 806 MW, which could affect our electric reserve margin. The MCV Partnership has
until January 26, 2008 to notify us of their intention to terminate the MCV PPA at which time the
MCV Partnership must specify the termination date. We have not yet received any notification of
termination. However, the MCV Partnership has notified us that it
disputes our right to exercise the regulatory-out provision. We believe that the provision is valid and fully effective, but cannot
assure that we will prevail in the event of a proceeding on this issue.
We anticipate that the MPSC will review our exercise of the regulatory-out provision and the likely
consequences of such action in 2007. It is possible that in the event that the MCV Partnership
terminates performance under the MCV PPA, prior orders could limit recovery of replacement power
costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the
cost of replacement power, this could result in our costs exceeding the recovery amount allowed by
the MPSC. We cannot predict the outcome of these matters.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a
determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we
recover from customers. Furthermore, the MCV Partnership filed an application with the MPSC
requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed
energy charges that we are allowed to recover from our customers. We cannot predict the outcome of
these matters.
RCP: In January 2005, we implemented the MPSC-approved RCP with modifications. The RCP allows us
to recover the same amount of capacity and fixed energy charges from customers as approved in prior
MPSC orders. However, we are able to dispatch the MCV Facility based on natural gas market prices.
This results in fuel cost savings for the MCV Facility, which the MCV Partnership shares with us.
The RCP also requires contributions of $5 million annually to a renewable resources program. As of
September 30, 2007, contributions of $13 million were made to the renewable resources program. The
underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the
MCV PPA. However, either party may terminate that agreement under certain conditions. In
January 2007, the Michigan Attorney General filed an appeal with the Michigan Supreme Court
regarding the MPSC’s order approving the RCP. The Supreme Court denied the Attorney General’s
request to further consider the matter.
Nuclear Matters: Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs
to decommission Big Rock. In December 2000, funding of the Big Rock trust fund stopped because the
MPSC-authorized decommissioning surcharge collection period expired. The level of funds provided
by the trust fell short of the amount needed to complete decommissioning. As a result, we provided
$45 million of corporate contributions for costs associated with NRC radiological and non-NRC
greenfield decommissioning work as of September 30, 2007. This amount excludes the $30 million
payment to Entergy to assume ownership and responsibility for the Big Rock ISFSI and additional
corporate contributions for nuclear fuel storage costs of $54 million as of September 30, 2007, due
to the DOE’s failure to accept spent nuclear fuel on schedule. We plan to seek recovery from
the MPSC of expenditures that we have funded and have a $129 million regulatory asset recorded on
our Consolidated Balance Sheets as of September 30, 2007.
Actual expenditures for Big Rock decommissioning totaled $388 million as of September 30, 2007.
This total excludes the additional costs for spent nuclear fuel storage due to the DOE’s failure to
accept this spent nuclear fuel on schedule as well as certain increased security costs that we are
recovering through the security cost provisions of Public Act 609 of 2002.
Nuclear Fuel Cost: We deferred payment for disposal of spent nuclear fuel burned before April 7,
1983. Our DOE liability is $158 million at September 30, 2007. This amount includes interest,
which is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered, through
electric rates, the amount of this liability, excluding a portion of interest. In conjunction with
the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155
million letter of credit to Entergy as security for this obligation.
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 a number of 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. If our litigation against the DOE is successful, we plan to use any recoveries as
reimbursement for the incurred costs of spent nuclear fuel storage during our ownership of
Palisades and Big Rock. We can make no assurance that the litigation against the DOE will be
successful. The sale of Palisades and the Big Rock ISFSI did not transfer the right to any
recoveries from the DOE related to costs of spent nuclear fuel storage incurred during our
ownership of Palisades and Big Rock.
In 2002, the site at Yucca Mountain, Nevada was designated for the development of a repository for
the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE,
ultimately, will submit a final license application to the NRC for the repository. The application
and review process is estimated to take several years.
Gas Environmental Matters: We expect to incur investigation and remediation costs at a number of
sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute
that covers environmental activities including remediation. These sites include 23 former
manufactured gas plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or may own only a
portion of the original site. In 2005, we estimated our remaining costs to be between $29 million
and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The
discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in
the consumer price index. We expect to fund most of these costs through proceeds derived from a
settlement with insurers and MPSC-approved rates. At September 30, 2007, we have a liability of
$19 million, net of $63 million of expenditures incurred to date, and a regulatory asset of $52
million. The timing of payments related to the remediation of our manufactured gas plant sites is
uncertain. 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 and the timing of our remediation
payments.
Gas Title Transfer Tracking Fees and Services (TTT): On September 19, 2007, the FERC issued an
order denying Consumers’ request for Summary Disposition and established hearing procedures in this
proceeding. In addition to issues related to the appropriate level of the TTT fee and refunds
related to TTT transactions, this order sets for hearing the issue of whether Consumers has
violated annual reporting requirements of the FERC’s regulations. A prehearing conference was held
on October 4, 2007. Testimony is due November 9, 2007, with hearings to begin February 5, 2008.
We cannot predict the outcome of this proceeding.
GAS RATE MATTERS
Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural
gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these
costs, policies, and practices for prudency in annual plan and reconciliation proceedings.
The following table summarizes our GCR reconciliation filings with the MPSC:
Gas Cost Recovery Reconciliation
Net Over-
GCR Cost
GCR Year
Date Filed
Order Date
recovery
of Gas Sold
Description of Net Overrecovery
2005-2006
June 2006
April 2007
$3 million
$1.8 billion
The net overrecovery includes
$1 million interest income
through March 2006, which
resulted from a net
underrecovery position during
the majority of the GCR
period.
2006-2007
June 2007
Pending
$5 million
$1.7 billion
The total overrecovery amount
reflects an overrecovery of $1
million plus $4 million in
accrued interest owed to
customers.
Overrecoveries in cost of gas sold are included in Accrued rate refunds on our Consolidated Balance
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan
year, which resulted in approval of a settlement agreement and established a fixed price cap of
$10.10 per mcf for the December 2005 through March 2006 billing period. We were able to maintain
our GCR billing factor below the authorized level for that period. The order was appealed to the
Michigan Court of Appeals by one intervenor. We are unable to predict the outcome of this
proceeding.
GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our 2006-2007 GCR Plan
year, which resulted in approval of a settlement agreement that allowed a base GCR ceiling factor
of $9.48 per mcf for the 12-month period of April 2006 through March 2007. We were able to
maintain our GCR billing factor below the authorized level for that period.
GCR plan for year 2007-2008: In July 2007, the MPSC issued an order for our 2007-2008 GCR plan
year, which resulted in approval of a settlement agreement that allowed a base GCR ceiling factor
of $8.47 per mcf for the 12-month period of April 2007 through March 2008, subject to a quarterly
ceiling price adjustment mechanism.
Due to an increase in NYMEX gas prices compared to the plan, the base GCR ceiling factor increased
to $8.67 per mcf pursuant to the quarterly ceiling price adjustment mechanism for the 3-month
period of July 2007 through September 2007. Beginning October 2007, the base GCR ceiling factor
was adjusted to $8.47 due to a decrease in NYMEX gas prices.
The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts
in our annual GCR reconciliation. Our GCR billing factor for the month of November 2007 is $7.78
per mcf.
2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25
percent authorized return on equity along with an $88 million annual increase in our gas delivery
and transportation rates. We proposed the use of a Revenue Decoupling and Conservation Incentive
Mechanism for residential and general service rate classes, which would partially separate the
collection of fixed costs from gas sales and enhance the utility’s ability to recover its fixed
costs.
In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate
increase of $50 million, including an authorized return on equity of 10.75 percent. The proposed
Revenue Decoupling and Conservation Incentive Mechanism was not approved. On September 25, 2007,
the MPSC reopened the record in the case to allow all interested parties to be heard concerning the
approval of an energy efficiency program, which we included in our original filing. If approved in
total, this would result in an additional rate increase of $9 million to be used to implement the
energy efficiency program.
OTHER CONTINGENCIES
Other: In addition to the matters disclosed within this Note, we are party to certain lawsuits and
administrative proceedings before various courts and governmental agencies arising from the
ordinary course of business. These lawsuits and proceedings may involve personal injury, property
damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and
other matters.
We have accrued estimated losses for certain contingencies discussed within this Note. Resolution
of these contingencies is not expected to have a material adverse impact on our financial position,
liquidity, or future results of operations.
FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others: The Interpretation requires the
guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the
obligation it undertakes in issuing the guarantee.
The following table provides additional information regarding our guarantees:
Events That Would Require
Guarantee Description
How Guarantee Arose
Performance
Surety bonds and other
indemnifications
Normal operating
activity, permits and
licenses
Nonperformance
Guarantee
Agreement to provide
power and steam to
Dow
MCV Partnership’s
nonperformance or
non-payment under a
related contract
At September 30, 2007, only our guarantee to provide power and steam to Dow contained provisions
allowing us to recover, from third parties, amounts paid under the guarantees.
We sold our interests in the MCV Partnership and the FMLP. The sales agreement calls for the
purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay
Consumers $85 million, subject to certain reimbursement rights, if Dow terminates an agreement
under which the MCV Partnership provides it steam and electric power. This agreement expires in
March 2016 and is subject to certain terms and conditions. The purchaser secured their
reimbursement obligation with an irrevocable letter of credit of up to $85 million.
We enter into various agreements containing tax and other indemnification provisions in connection
with a variety of transactions, including the sale of our interests in the MCV Partnership and the
FMLP and the sale of our interest in Palisades and the Big Rock ISFSI. While we are unable to
estimate the maximum potential obligation related to these indemnities, we consider the likelihood
that we would be required to perform or incur significant losses related to these indemnities and
the guarantees listed in the preceding tables to be remote.
We replaced our $500 million facility with a new $500 million credit facility in March 2007. The
new facility contains less restrictive covenants, and provides for lower fees and lower interest
margins than the previous credit facilities.
Dividend Restrictions: Under the provisions of our articles of incorporation, at September 30,2007, we had $250 million of unrestricted retained earnings available to pay common stock
dividends. The dividend restrictions in our secured revolving credit facility were removed in
March 2007. Provisions of the Federal Power Act and the Natural Gas Act effectively restrict
dividends to the amount of our retained earnings. For the nine months ended September 30, 2007, we
paid $176 million in common stock dividends to CMS Energy.
Capital Lease Obligations: Our capital leases are comprised mainly of leased service vehicles,
office furniture, and gas pipeline capacity. At September 30, 2007, capital lease obligations
totaled $62 million. We estimate future minimum lease payments to range between $10 million and
$19 million per year over the next five years.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we sell certain
accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In
turn, the special purpose entity may sell an undivided interest in up to $325 million of the
receivables. The special purpose entity sold no receivables at September 30, 2007 and $325 million
of receivables at December 31, 2006. We continue to service the receivables sold to the special
purpose entity. The purchaser of the receivables has no recourse against our other assets for
failure of a debtor to pay when due and no right to any receivables not sold. We have neither
recorded a gain or loss on the receivables sold nor retained an interest in the receivables sold.
Certain cash flows under our accounts receivable sales program are shown in the following table:
In Millions
Nine months ended September 30
2007
2006
Net cash flow as a result of accounts receivable financing
$
(325
)
$
(9
)
Collections from customers
$
4,631
$
4,402
5: Financial and Derivative Instruments
Financial Instruments: The carrying amounts of cash, short-term investments, and current
liabilities approximate their fair values because of their short-term nature. We estimate the fair
values of long-term financial instruments based on quoted market prices or, in the absence of
specific market prices, on quoted market prices of similar instruments or other valuation
techniques.
The cost and fair value of our long-term debt instruments including current maturities are as
follows:
Derivative Instruments: In order to limit our exposure to certain market risks, we may enter into
various risk management contracts, such as swaps, options, futures, and forward contracts. These
contracts, used primarily to manage our exposure to changes in interest rates and commodity prices,
are entered into for purposes other than trading. We enter into these contracts using established
policies and procedures, under the direction of both:
•
an executive oversight committee consisting of senior management representatives, and
•
a risk committee consisting of business unit managers.
The contracts we use to manage market risks may qualify as derivative instruments that are subject
to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative and does not
qualify for the normal purchases and sales exception under SFAS No. 133, it is recorded on our
consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each
quarter to reflect any change in the market value of the contract, a practice known as marking the
contract to market. From time to time, we enter into cash flow hedges. If a derivative qualifies
for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported
in AOCI; otherwise, the changes are reported in earnings.
The majority of our commodity purchase and sale contracts are not subject to derivative accounting
under SFAS No. 133 because:
•
they do not have a notional amount (that is, a number of units specified in a
derivative instrument, such as MWh of electricity or bcf of natural gas),
•
they qualify for the normal purchases and sales exception, or
•
there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active market for the coal
we purchase. If an active market for coal develops in the future, some of these contracts may
qualify as derivatives and the resulting mark-to-market impact on earnings could be material.
Derivative accounting is required for certain contracts used to limit our exposure to commodity
price risk. At September 30, 2007, the fair value of these derivative contracts was immaterial.
6: Retirement Benefits
We provide retirement benefits to our employees under a number of different plans, including:
benefits to certain management employees under SERP,
•
a defined contribution 401(k) Savings Plan,
•
benefits to a select group of management under the EISP, and
•
health care and life insurance benefits under OPEB.
Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of
our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan’s assets are not
distinguishable by company.
In April 2007, we sold Palisades to Entergy. Employees transferred to Entergy as a result of the
sale no longer participate in our retirement benefit plans. We recorded a net reduction of $22
million in pension SFAS No. 158 regulatory assets with a corresponding decrease of $22 million in
pension liabilities on our Consolidated Balance Sheets. We also recorded a net reduction of $15
million in OPEB regulatory SFAS No. 158 assets with a corresponding decrease of $15 million in OPEB
liabilities. The following table shows the net adjustment:
Beginning May 1, 2007, the CMS Energy Common Stock Fund is no longer an investment option available
for new investments in the 401(k) Savings Plan and the employer’s match is no longer in CMS Energy
Stock. Participants have an opportunity to reallocate investments in the CMS Energy Stock Fund to
other plan investment alternatives. Beginning November 1, 2007, any remaining shares in the CMS
Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment
options. At September 30, 2007, there were 7 million shares of CMS Energy Common Stock in the CMS
Energy Stock Fund.
SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an
amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS
No. 158. Phase one of this standard required us to recognize the funded status of our defined
benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase one
was implemented in December 2006. Phase two of this standard requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008. We do not believe
that implementation of phase two of this standard will have a material effect on our consolidated
financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.
Costs: The following table recaps the costs, other changes in plan assets, and benefit obligations
incurred in our retirement benefits plans:
In Millions
Pension
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Service cost
$
12
$
12
$
35
$
35
Interest expense
20
20
61
59
Expected return on plan assets
(18
)
(20
)
(56
)
(60
)
Amortization of:
Net loss
11
10
33
30
Prior service cost
1
1
5
5
Net periodic cost
26
23
78
69
Regulatory adjustment
(6
)
(3
)
(14
)
(8
)
Net periodic cost after regulatory adjustment
$
20
$
20
$
64
$
61
In Millions
OPEB
Three Months Ended
Nine Months Ended
September 30
2007
2006
2007
2006
Service cost
$
7
$
6
$
20
$
18
Interest expense
17
15
52
47
Expected return on plan assets
(16
)
(14
)
(47
)
(43
)
Amortization of:
Net loss
6
5
17
15
Prior service credit
(3
)
(3
)
(8
)
(8
)
Net periodic cost
11
9
34
29
Regulatory adjustment
(2
)
—
(5
)
(1
)
Net periodic cost after regulatory adjustment
$
9
$
9
$
29
$
28
7: Asset Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement Obligations: This standard requires companies to
record the fair value of the cost to remove assets at the end of their useful life, if there is a
legal obligation to remove them. 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 $5 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred,
such as for assets with indeterminate lives, the liability is to be recognized when a reasonable
estimate of fair value can be made. Generally, gas transmission and electric and gas distribution
assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low
probability of a retirement date. Therefore, no liability has been recorded for these assets or
associated obligations related to potential future abandonment. Also, no liability has been
recorded for assets that have insignificant cumulative disposal costs, such as substation batteries.
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: This
Interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No.
143. The term refers to a legal obligation to perform an asset retirement activity in which the
timing and (or) method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a conditional ARO, as defined
by FIN 47.
The following tables describe our assets that have legal obligations to be removed at the end of
their useful life:
Cash payments of $4 million are included in the Other current and non-current liabilities line
in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In
April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership and responsibility
for the Big Rock ISFSI. Our AROs related to Palisades and the Big Rock ISFSI ended with the sale
and the related ARO liabilities were removed from our Consolidated Balance Sheets. We also removed
the Big Rock ARO related to the plant in the second quarter of 2007 due to the completion of
decommissioning.
In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No.
631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement
Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas
utilities. In June 2007, the MPSC issued an order that requires:
•
the MPSC Staff to advise the MPSC whether there are any FERC accounts, rules or
procedures that should be adopted by reference or changed, and
•
the use of a revised calculation for cost of removal estimates derived from applying
SFAS No. 143, which includes the use of standard retirement units.
We will also be required to file a new gas depreciation study by August 1, 2008, using 2007 removal
costs as the basis for the calculation, and a new electric depreciation study by August 3, 2009,
using 2008 removal costs as the basis for the calculation.
8: income taxes
The principal components of deferred tax assets (liabilities) recognized on our Consolidated
Balance Sheets both before and after the adoption of FIN 48 are as follows:
As a result of the implementation of FIN 48, we identified additional uncertain tax benefits of $5
million as of January 1, 2007. Included in this amount is an increase in our valuation allowance
of $7 million, increases to tax reserves of $55 million and a decrease to deferred tax liabilities
of $57 million.
Consumers joins in the filing of a consolidated U.S. federal income tax return as well as unitary
and combined income tax returns in several states. Consumers and its subsidiaries also file
separate company income tax returns in several states. The only significant state tax paid by
Consumers or any of its subsidiaries is in Michigan. However, since the Michigan Single Business
Tax is not an income tax, it is not part of the FIN 48 analysis. The IRS has completed its audits
for all the consolidated federal returns, of which Consumers is a member, for years through 2001.
The federal income tax returns for the years 2002
through 2005 are open under the statute of limitations.
We reflected a net interest liability of $1 million related to our uncertain income tax positions
on our Consolidated Balance Sheets as of January 1, 2007. We have not accrued any penalties with
respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable,
related to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against certain deferred tax
assets totaling $22 million and other net uncertain tax positions of $55 million, resulting in
total uncertain benefits of $77 million. Of this amount, $24 million would result in a decrease in
our effective tax rate, if recognized. We are not expecting any material changes to our uncertain
tax positions over the next 12 months.
The actual income tax expense differs from the amount computed by applying the statutory federal
tax rate of 35 percent to income before income taxes as follows:
In Millions
Nine Months Ended September 30
2007
2006
Income before income taxes
$
332
$
211
Statutory federal income tax rate
x 35
%
x 35
%
Expected income tax expense
116
74
Increase (decrease) in taxes from:
Property differences
10
15
IRS Settlement/Credit Restoration
—
(18
)
Fair market value charitable donation
(2
)
—
Tax exempt income
(1
)
(2
)
Medicare Part D exempt income
(7
)
(4
)
Income tax credit amortization
(3
)
(3
)
Valuation Allowance
—
5
Other, net
2
(1
)
Recorded income tax expense
$
115
$
66
Effective tax rate
35
%
31
%
Michigan Business Tax Act: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan
Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts
tax of 0.8 percent. The bill provides for a number of tax credits and incentives geared toward
those companies investing and employing in Michigan. The Michigan Business Tax, which is effective
January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31,2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional
deductions in future years against the business income portion of the tax. These future deductions
are phased in over a 15-year period, beginning in 2015. As a result of the enactment of this tax,
we recorded, on a consolidated basis, a net deferred tax liability of $125 million completely
offset by a net deferred tax asset of $125 million.
Our reportable segments consists of business units organized and managed by the nature of the
products and services each provides. We evaluate performance based upon the net income of each
segment. We operate principally in two segments: electric utility and gas utility.
The following tables show our financial information by reportable segment:
Item 3. Quantitative and Qualitative Disclosures About Market Risk
CMS ENERGY
Quantitative and Qualitative Disclosures about Market Risk is contained in PART I: CMS Energy
Corporation’s Management’s Discussion and Analysis, which is incorporated by reference herein.
CONSUMERS
Quantitative and Qualitative Disclosures about Market Risk is contained in PART I: Consumers Energy
Company’s Management’s Discussion and Analysis, which is incorporated by reference herein.
Item 4. Controls and Procedures
CMS ENERGY
Disclosure Controls and Procedures: CMS Energy’s management, with the participation of its CEO and
CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period
covered by this report. Based on such evaluation, CMS Energy’s CEO and CFO have concluded that, as
of the end of such period, its disclosure controls and procedures are effective.
Internal Control Over Financial Reporting: There have not been any changes in CMS Energy’s
internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f)
under the Exchange Act) during the last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, its internal control over financial reporting.
CONSUMERS
Disclosure Controls and Procedures: Consumers’ management, with the participation of its CEO and
CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period
covered by this report. Based on such evaluation, Consumers’ CEO and CFO have concluded that, as
of the end of such period, its disclosure controls and procedures are effective.
Internal Control Over Financial Reporting: There have not been any changes in Consumers’ internal
control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under
the Exchange Act) during the last fiscal quarter that have materially affected, or are reasonably
likely to materially affect, its internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The discussion below is limited to an update of developments that have occurred in various judicial
and administrative proceedings, many of which are more fully described in CMS Energy’s and
Consumers’ Forms 10-K for the year ended December 31, 2006 and Forms 10-Q for the quarters ended
March 31, 2007 and June 30, 2007. Reference is also made to the NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS, in particular, Note 3, Contingencies, for CMS Energy and Note 3, Contingencies, for
Consumers, included herein for additional information regarding various pending administrative and
judicial proceedings involving rate, operating, regulatory and environmental matters.
Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United States District Court
for the Eastern District of California in November 2003 against a number of energy companies
engaged in the sale of natural gas in the United States (including CMS Energy). The complaint
alleged defendants entered into a price-fixing scheme by engaging in activities to manipulate the
price of natural gas in California. The complaint alleged violations of the federal Sherman Act,
the California Cartwright Act, and the California Business and Professions Code relating to
unlawful, unfair and deceptive business practices. In April 2004, a Nevada Multidistrict
Litigation (MDL) Panel ordered the transfer of the Texas-Ohio case to a pending MDL matter in the
Nevada federal district court that at the time involved seven complaints originally filed in
various state courts in California. These complaints make allegations similar to those in the
Texas-Ohio case regarding price reporting, although none contain a federal Sherman Act claim. In
November 2004, those seven complaints, as well as a number of others that were originally filed in
various state courts in California and subsequently transferred to the MDL proceeding, were
remanded back to California state court. The Texas-Ohio case remained in Nevada federal district
court, and defendants, with CMS Energy joining, filed a motion to dismiss. The court issued an
order granting the motion to dismiss on April 8, 2005 and entered a judgment in favor of the
defendants on April 11, 2005. Texas-Ohio has appealed the dismissal to the Ninth Circuit Court of
Appeals.
While that
appeal was pending, CMS Energy agreed to settle the Texas-Ohio case
and four other cases originally filed in California federal courts
for a total payment of $700,000. That settlement money was paid and
on September 10, 2007, the court entered an order granting final
approval of the settlement and dismissing the CMS Energy defendants
from these cases. On September 26, 2007, the Ninth Circuit Court of
Appeals reversed the ruling of the trial judge in the Texas-Ohio case
and held that the “filed rate doctrine” is not applicable
to the claims. The Ninth Circuit then remanded the case to the
federal district court. While CMS Energy is no longer a party to the
Texas-Ohio case, the ninth circuit ruling may affect the position of
CMS entities in other pending cases.
Three federal putative class actions, Fairhaven Power Company v. Encana Corp. et al., Utility
Savings & Refund Services LLP v. Reliant Energy Resources Inc. et al., and Abelman Art Glass v.
Encana Corp. et al., all of which make allegations similar to those in the Texas-Ohio case
regarding price manipulation and seek similar relief, were originally filed in the United States
District Court for the Eastern District of California in September 2004, November 2004 and December
2004, respectively. The Fairhaven and Abelman Art Glass cases also include claims for unjust
enrichment and a constructive trust. The three complaints were filed against CMS Energy and many
of the other defendants named in the Texas-Ohio case. In addition, the Utility Savings case names
CMS MST and Cantera Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural Gas,
LLC and CMS Energy is required to indemnify Cantera Natural Gas, LLC and Cantera Resources Inc.
with respect to these actions.)
The Fairhaven, Utility Savings and Abelman Art Glass cases have been transferred to the MDL
proceeding, where the Texas-Ohio case was pending. Pursuant to stipulation by the parties and
court order, defendants were not required to respond to the Fairhaven, Utility Savings and Abelman
Art Glass complaints until the court ruled on defendants’ motion to dismiss in the Texas-Ohio case.
Plaintiffs subsequently filed a consolidated class action complaint alleging violations of federal
and California antitrust laws. Defendants filed a motion to dismiss, arguing that the consolidated
complaint should be dismissed for the same reasons as the Texas-Ohio case. The court issued an
order granting the motion to dismiss on December 19, 2005 and entered judgment in favor of
defendants on December 23, 2005. Plaintiffs have appealed the dismissal to the Ninth Circuit Court
of Appeals. California-based plaintiffs in the pending Ninth Circuit Court of Appeals cases
(Texas-Ohio, Fairhaven, Abelman Art Glass and Utility Savings) have entered into a settlement
agreement dated January 10, 2007 to collectively settle their claims against all CMS Energy
defendants for the payment of $700,000. Plaintiffs filed a motion for preliminary approval of this
and other settlements with various defendants on April 3, 2007. An order was entered on May 3,2007 granting preliminary approval of the settlement, and CMS has wire transferred its $700,000
settlement payment. On September 10, 2007, the court entered an
order granting final approval of the settlement and dismissing the
CMS Energy defendants and other settling defendants from these cases.
Commencing in or about February 2004, 15 state law complaints containing allegations similar to
those made in the Texas-Ohio case, but generally limited to the California Cartwright Act and
unjust enrichment, were filed in various California state courts against many of the same
defendants named in the federal price manipulation cases discussed above. In addition to CMS
Energy, CMS MST is named in all of the 15 state law complaints. Cantera Gas Company and Cantera
Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in all but one
complaint.
In February 2005, these 15 separate actions, as well as nine other similar actions that were filed
in California state court but do not name CMS Energy or any of its former or current subsidiaries,
were ordered coordinated with pending coordinated proceedings in the San Diego Superior Court. The
24 state court complaints involving price reporting were coordinated as Natural Gas Antitrust Cases
V. Plaintiffs in Natural Gas Antitrust Cases V were ordered to file a consolidated complaint, but
a consolidated complaint was filed only for the two putative class action lawsuits. Pursuant to a
ruling dated August 23, 2006, CMS Energy, Cantera Gas Company and Cantera Natural Gas, LLC were
dismissed as defendants in the master class action and the thirteen non-class actions, due to lack
of personal jurisdiction. CMS MST remains a defendant in all of these actions. CMS MST has
settled a master class action suit in California state court for $7 million. In March 2007, CMS
Energy paid $7 million into a trust fund account following preliminary approval of the settlement
by the judge. The court entered a judgment, final order and decree dated June 12, 2007 granting
final approval to the class action settlement with CMS MST. Certain of the individual cases filed
in the California State Court remain pending.
Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action complaint brought on
behalf of retail and business purchasers of natural gas in Tennessee, was filed in the Chancery
Court of Fayette County, Tennessee in January 2005. The complaint contains claims for violations
of the Tennessee Trade Practices Act based upon allegations of false reporting of price information
by defendants to publications that compile and publish indices of natural gas prices for various
natural gas hubs. The complaint seeks statutory full consideration damages and attorneys fees and
injunctive relief regulating defendants’ future conduct. The defendants include CMS Energy, CMS
MST and CMS Field Services. On August 10, 2005, certain defendants, including CMS MST, filed a
motion to dismiss and CMS Energy and CMS Field Services filed a motion to dismiss for lack of
personal jurisdiction. Defendants attempted to remove the case to federal court, but it was
remanded to state court by a federal judge. On February 2, 2007, the state court granted
defendants’ motion to dismiss the complaint. Plaintiffs filed a notice of appeal on April 4, 2007.
Oral arguments on the appeal is set for November 8, 2007.
J.P. Morgan Trust Company, in its capacity as Trustee of the FLI Liquidating Trust, filed an action
in Kansas state court in August 2005 against a number of energy companies, including CMS Energy,
CMS MST and CMS Field Services. The complaint alleges various claims under the Kansas Restraint of
Trade Act relating to reporting false natural gas trade information to publications that report
trade information. Plaintiff is seeking statutory full consideration damages for its purchases of
natural gas between January 1, 2000 and December 31, 2001. The case was removed to the United
States District Court for the District of Kansas on September 8, 2005 and transferred to the MDL
proceeding on October 13, 2005. A motion to remand the case back to Kansas state court was denied
on April 21, 2006. The court initially issued an order granting the motion to dismiss on December18, 2006, but later reversed the ruling on reconsideration and has now denied the defendants’
motion to dismiss. On September 7, 2007, the CMS Energy defendants
filed an answer to the complaint.
On November 20, 2005, CMS MST was served with a summons and complaint which named CMS Energy, CMS
MST and CMS Field Services as defendants in a putative class action filed in Kansas state court,
Learjet, Inc., et al. v. Oneok, Inc., et al. Similar to the other actions that have been filed,
the complaint alleges that during the putative class period, January 1, 2000 through October 31,2002, defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by knowingly
reporting false or inaccurate information to the publications, thereby affecting the market price
of natural gas. Plaintiffs,
who allege they purchased natural gas from defendants and others for their facilities, are seeking
statutory full consideration damages consisting of the full consideration paid by plaintiffs for
natural gas. On December 7, 2005, the case was removed to the United States District Court for the
District of Kansas and later that month a motion was filed to transfer the case to the MDL
proceeding. On January 6, 2006, plaintiffs filed a motion to remand the case to Kansas state
court. On January 23, 2006, a conditional transfer order transferring the case to the MDL
proceeding was issued. On February 7, 2006, plaintiffs filed an opposition to the conditional
transfer order and on June 20, 2006 the MDL Panel issued an order transferring the case to the MDL
proceeding. The court issued an order dated August 3, 2006 denying the motion to remand the case
to Kansas state court. Defendants have filed a motion to dismiss,
which was denied on July 27, 2007. On September 7, 2007, the CMS
Energy defendants filed an answer to the complaint.
Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok, Inc., et al., a class
action complaint brought on behalf of retail direct purchasers of natural gas in Colorado, was
filed in Colorado state court in May 2006. Defendants, including CMS Energy, CMS Field Services,
and CMS MST, are alleged to have violated the Colorado Antitrust Act of 1992 in connection with
their natural gas price reporting activities. Plaintiffs are seeking full refund damages. The
case was removed to the United States District Court for the District of Colorado on June 12, 2006,
a conditional transfer order transferring the case to the MDL proceeding was entered on June 27,2006, and an order transferring the case to the MDL proceeding was entered on October 17, 2006.
The court issued an order dated December 4, 2006 denying the motion to remand the case back to
Colorado state court. Defendants have filed a motion to dismiss. On August 21, 2007, the court
granted the motion to dismiss by CMS Energy on the basis of a lack of jurisdiction. The other
defendants remain in the case, and they filed an answer to the
complaint on September 7, 2007. The remaining CMS Energy defendants
also filed a summary judgment motion which remains pending.
On October 30, 2006, CMS Energy and CMS MST were each served with a summons and complaint which
named CMS Energy, CMS MST and CMS Field Services as defendants in an action filed in Missouri state
court, titled Missouri Public Service Commission v. Oneok, Inc. The Missouri Public Service
Commission purportedly is acting as an assignee of six local distribution companies, and it alleges
that from at least January 2000 through at least October 2002, defendants knowingly reported false
natural gas prices to publications that compile and publish indices of natural gas prices, and
engaged in wash sales. The complaint contains claims for violation of the Missouri Anti-Trust Law,
fraud and unjust enrichment. Defendants removed the case to Missouri federal court and then
transferred it to the Nevada MDL proceeding. A second action, Heartland Regional Medical Center,
et al. v. Oneok, Inc., et al., was filed in Missouri state court in March 2007 alleging violations
of Missouri anti-trust laws. The second action is denoted as a class action. Defendants also
removed this case to Missouri federal court, and it has been conditionally transferred to the
Nevada MDL proceeding.
A class action complaint, Arandell Corp., et al v. XCEL Energy Inc., et al, was filed on or about
December 15, 2006 in Wisconsin state court on behalf of Wisconsin commercial entities that
purchased natural gas between January 1, 2000 and October 31, 2002. Defendants, including CMS
Energy, CMS ERM and Cantera Gas Company, LLC, are alleged to have violated Wisconsin’s Anti-Trust
statute by conspiring to manipulate natural gas prices. Plaintiffs are seeking full consideration
damages, plus exemplary damages in an amount equal to three times the actual damages, and
attorneys’ fees. The action was removed to Wisconsin federal district court and CMS entered a
special appearance for purpose of filing a motion to dismiss all the CMS defendants on the ground
of lack of personal jurisdiction and that motion was filed on
September 10, 2007. The court has not yet ruled on the motion. The court denied plaintiffs’ motion to remand the case back to
Wisconsin state court, and the case has been transferred to the Nevada MDL proceeding.
CMS Energy and the other CMS defendants will defend themselves vigorously against these matters but
cannot predict their outcome.
On November 1, 2001, Quicksilver sued CMS MST in the Texas State Court in Fort Worth, Texas for
breach of contract in connection with a Base Contract for Sale and Purchase of natural gas,
pursuant to which Quicksilver agreed to sell, and CMS MST agreed to buy, natural gas. Quicksilver
contended that a special provision in the contract requires CMS MST to pay Quicksilver 50 percent
of the difference between $2.47/MMBtu and the index price each month. CMS MST disagrees with
Quicksilver’s interpretation of the special provision and contends that it has paid all monies owed
for delivery of gas pursuant to the contract. Quicksilver is seeking damages of approximately $126
million, plus prejudgment interest and attorneys’ fees.
Trial commenced on March 19, 2007. The jury verdict awarded Quicksilver zero compensatory damages
but $10 million in punitive damages. The jury found that CMS MST breached the contract and
committed fraud but found no actual damage on account of either such claim.
On May 15, 2007, the trial court, ruling on motions to counter the entry of the judgment, vacated
the jury award of punitive damages but held that the contract should be rescinded prospectively.
The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter
of 2007 of approximately $24 million, net of tax. To preserve its appellate rights, CMS MST filed
a motion to modify, correct or reform the judgment and a motion for a judgment contrary to the jury
verdict with the trial court. The trial court dismissed these motions. CMS MST has filed a notice
of appeal with the Texas Court of Appeals.
CMS ENERGY AND CONSUMERS
SECURITIES CLASS ACTION LAWSUITS
Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain
officers and directors of CMS Energy and its affiliates in the United States District Court for the
Eastern District of Michigan. The cases were consolidated into a single lawsuit (the “Shareholder
Action”), which generally seeks unspecified damages based on allegations that the defendants
violated United States securities laws and regulations by making allegedly false and misleading
statements about CMS Energy’s business and financial condition, particularly with respect to
revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005,
the court granted a motion to dismiss Consumers and three of the individual defendants, but denied
the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the
court conditionally certified a class consisting of “all persons who purchased CMS Common Stock
during the period of October 25, 2000 through and including May 17, 2002 and who were damaged
thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent Adjustable Convertible Trust
Securities (“ACTS”) from the class and, in response, a new class action lawsuit was filed on behalf
of ACTS purchasers (the “ACTS Action”) against the same defendants named in the Shareholder Action.
The settlement described in the following paragraph has resolved both the Shareholder and ACTS
actions.
On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the
“MOU”), subject to court approval, regarding settlement of the two class action lawsuits. The
settlement was approved by a special committee of independent directors and by the full board of
directors of CMS Energy. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. Under the terms of the MOU, the litigation was settled for a
total of $200 million, including the cost of administering the settlement and any attorney fees the
court awards. CMS Energy made a payment of approximately $123 million plus interest on the
settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of
the settlement amount. In entering into the
MOU, CMS Energy made no admission of liability under the Shareholder Action and the ACTS Action.
The parties executed a Stipulation and Agreement of Settlement dated May 22, 2007 (“Stipulation”)
incorporating the terms of the MOU. In accordance with the Stipulation, CMS has paid approximately
$1 million of the settlement amount to fund administrative expenses. On September 6, 2007, the
court issued a final order approving the settlement. The remaining settlement amount was paid
following the September 6, 2007 hearing.
On October 5, 2007, two
former officers of Consumers filed an appeal of the order approving
the settlement of the shareholder litigation. Based on the objections
they filed in the District Court and comments made on the record at
the fairness hearing on September 6, 2007, they are not challenging
the amount of the settlement. Their principal complaint was with the
exclusion of all present and former officers and their immediate
families from participation in the settlement. It is not anticipated
that the appeal will result in changes to any material terms of the
settlement approved by the District Court.
ENVIRONMENTAL MATTERS
CMS Energy and Consumers, as well as their subsidiaries and affiliates are subject to various
federal, state and local laws and regulations relating to the environment. Several of these
companies have been named parties to various actions involving environmental issues. Based on
their present knowledge and subject to future legal and factual developments, they believe it is
unlikely that these actions, individually or in total, will have a material adverse effect on their
financial condition or future results of operations. For additional information, see both CMS
Energy’s and Consumers’ Forms 10-K for the year ended December 31, 2006 — ITEM 7. MANAGEMENT’S
DISCUSSION AND ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS.
Item 1A. Risk Factors
Other than discussed below, there have been no material changes to the Risk Factors as previously
disclosed in CMS Energy’s Form 10-K and Consumers’ Form 10-K for the year ended December 31, 2006
and Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007.
Risks Related to CMS Energy and Consumers
CMS Energy and Consumers may be adversely affected by regulatory investigations regarding
“round-trip” trading by CMS MST as well as civil lawsuits regarding pricing information that CMS
MST and CMS Field Services provided to market publications.
As a result of round-trip trading transactions (simultaneous, prearranged commodity trading
transactions in which energy commodities were sold and repurchased at the same price) at CMS MST,
CMS Energy is under investigation by the DOJ. CMS Energy received subpoenas in 2002 and 2003 from
U.S. Attorneys’ Offices regarding investigations of those trades. CMS Energy responded to those
subpoenas in 2003 and 2004.
In March 2004, the SEC approved a cease-and-desist order settling an administrative action against
CMS Energy relating to round-trip trading. The order did not assess a fine and CMS Energy neither
admitted nor denied the order’s findings.
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
has cooperated with an investigation by the DOJ regarding this matter. Although CMS Energy has not
received any formal notification that the DOJ has completed its investigation, the DOJ’s last
request for information occurred in November 2003, and CMS Energy completed its response to this
request in May 2004. CMS Energy is unable to predict the outcome of the DOJ investigation and what
effect, if any, the investigation will have on CMS Energy. The CFTC filed a civil injunctive
action against two former CMS Field Services employees in Oklahoma federal district court on
February 1, 2005. The action alleges the two engaged in reporting false natural gas trade
information, and seeks to enjoin these acts,
compel compliance with the Commodities Exchange Act, and impose monetary penalties. Trial dates
have been held in abeyance pending settlement discussions. CMS Energy is currently advancing legal
defense costs to the two individuals in accordance with existing indemnification policies. The
court entered separate consent orders with respect to each of the two individuals, one dated April18, 2007 and one dated June 25, 2007, resolving this litigation. The consent orders enjoin each of
the individuals from engaging in certain activities and further provide civil monetary penalties in
the amount of $100,000 for one individual and $25,000 for the other individual. Pursuant to
agreements with each of the individuals, CMS has paid $95,000 of the $100,000 amount and $22,000 of
the $25,000 amount, with the remaining amounts paid by the individuals themselves. These
settlements put an end to CFTC enforcement actions relating to gas price reporting by individuals
once employed at present or former CMS subsidiaries.
CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS
Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a
result of false natural gas price reporting. Allegations include manipulation of NYMEX natural gas
futures and options prices, price-fixing conspiracies, and artificial inflation of natural gas
retail prices in California, Colorado, Kansas, Missouri, Tennessee, and Wisconsin. In September
2006, CMS MST reached an agreement in principle to settle a master class action suit in California
for $7 million, pending approval by the trial Court. The court entered an order granting
preliminary approval of the settlement, and CMS MST has paid the $7 million settlement amount. The
court entered a judgment, final order and decree dated June 12, 2007 granting final approval to the
class action settlement with CMS MST.
CMS Energy and the other CMS Energy defendants will defend themselves vigorously against all of
these matters, but cannot predict the outcome of the DOJ investigations and the lawsuits. It is
possible that the outcome in one or more of the investigations or the lawsuits could adversely
affect CMS Energy’s and Consumers’ financial condition, liquidity or results of operations.
CMS Energy and Consumers could incur significant capital expenditures to comply with environmental
standards and face difficulty in recovering these costs on a current basis.
CMS Energy, Consumers, and their subsidiaries are subject to costly and increasingly stringent
environmental regulations. They expect that the cost of future environmental compliance,
especially compliance with clean air and water laws, will be significant.
In 1998, the EPA issued regulations requiring the State of Michigan to further limit nitrogen oxide
emissions at coal-fired electric generating plants. The EPA and State of Michigan regulations
require Consumers to make significant capital expenditures estimated to be $880 million. From 1998
to present, Consumers has incurred $784 million in capital expenditures to comply with these
regulations and anticipates that the remaining $96 million of capital expenditures will be made in
2007 through 2011. In addition to modifying coal-fired electric plants, Consumers’ compliance plan
includes the use of nitrogen oxide emission allowances until all of the control equipment is
operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $2
million per year through 2011, which Consumers expects to recover from customers through the PSCR
process.
In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired
electric plant emission controls for nitrogen oxides and sulfur dioxide. Consumers plans to meet
the nitrogen oxide requirements of this rule by year-round operation of its selective catalytic
reduction control technology units, installation of low nitrogen oxide burners, and purchasing
emission allowances. Consumers plans to meet the sulfur dioxide requirements of this rule using
sorbent injection, installation of flue gas desulfurization scrubbers and purchasing emission
allowances. Consumers’ total cost for equipment installation is expected to reach approximately
$740 million by 2015. Additional purchases of
sulfur dioxide emission allowances in 2012 and 2013 will be needed for an estimated cost of $10
million per year, which Consumers expects to recover from customers through the PSCR process.
The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of
Columbia by a number of utilities and other companies. Final briefs were due September 5, 2007
with a decision expected in 2008. We cannot predict the outcome of these appeals.
Also in March 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of
mercury emissions from coal-fired electric generating plants by 2010 and further reductions by
2018. The Clean Air Mercury Rule was appealed to the U.S. Court of Appeals by a number of states
and other entities. Final briefs were due July 13, 2007, with a decision expected in 2008. We
cannot predict the outcome of these appeals.
In April 2006, Michigan’s governor announced a plan that would result in mercury emissions
reductions of 90 percent by 2015. Consumers is currently working with the MDEQ on the details of
these rules; however, Consumers has developed preliminary cost estimates and a mercury emissions
reduction scenario based on its best knowledge of control technology options and initially proposed
requirements. The scenario includes expenditures of approximately $510 million for mercury control
equipment and continuous emissions monitoring systems through 2015.
The EPA has alleged that some utilities have incorrectly classified plant modifications as “routine
maintenance” rather than seeking permits from the EPA to modify the plant. We have received and
responded to information requests from the EPA on this subject. We believe that we have properly
interpreted the requirements of “routine maintenance.” If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some or all of our
coal-fired electric generating plants and potentially pay fines. Additionally, the viability of
certain plants remaining in operation could be called into question.
Several legislative proposals have been introduced in the United States Congress that would require
reductions in emissions of greenhouse gases, including carbon dioxide. On April 2, 2007, the U.S.
Supreme Court ruled that the Clean Air Act gives the EPA the authority to regulate emissions of
carbon dioxide and other greenhouse gases from automobiles. In its decision, the court ordered the
EPA to revisit its finding that it has the discretion not to regulate greenhouse gas emissions
from automobiles.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory
emissions reduction requirements could have far-reaching and significant implications for the
energy sector. We cannot estimate the effect of federal or state greenhouse gas policy on our
future consolidated results of operations, cash flows, or financial position due to the uncertain
nature of the policies at this time. However, we will continue to monitor greenhouse gas policy
developments and assess and respond to their potential implications on our business operations.
In March 2004, the EPA issued rules that govern electric generating plant cooling water intake
systems. The rules require significant reduction in fish killed by operating equipment. EPA
compliance options in the rule were challenged in court. In January 2007, the court rejected many
of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for
reconsideration. The court’s ruling is expected to increase significantly the cost of complying
with this rule. However, the cost to comply will not be known until the EPA’s reconsideration is
complete. At this time, the EPA has not established a schedule to address the court decision.
CMS Energy expects to collect fully from its customers, through the ratemaking process, these and
other required environmental expenditures. However, if these expenditures are not recovered from
customers in Consumers’ rates, CMS Energy and/or Consumers may be required to seek significant
additional financing to fund these expenditures, which could strain their cash resources.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
A Shareholder who wishes to submit a proposal for consideration at the CMS Energy 2008 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 13, 2007. In any event, if CMS Energy has not received
written notice of any matter to be proposed at that meeting by February 26, 2008, the holders of
proxies may use their discretionary voting authority on such matter. The proposals should be
addressed to: Corporate Secretary, CMS Energy Corporation, One Energy Plaza, Jackson, MI49201.
Effective November 1, 2007, CMS Energy and Consumers entered into Indemnification Agreements with
each of their respective Directors. These Agreements have an indefinite term and provide for
advancement of costs and expenses incurred to defend certain legal actions relating to their
services as a Director. These Indemnification Agreements provide consistent indemnification
provisions for all Directors and replace Indemnification Agreements that were in place for certain
Directors.
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.
