UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For Quarterly Period Ended March 31, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For The Transition Period From to
Commission file number 1-14756.
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
Missouri 43-1723446
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number,
including area code: (314) 554-2715
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X . No .
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Shares outstanding of each of registrant's classes of common stock as of April
30, 2001: Common Stock, $ .01 par value - 137,215,462
Ameren Corporation
Index
Page No.
Part I Consolidated Financial Information (Unaudited)
Management's Discussion and Analysis 2
Quantitative and Qualitative Disclosure
About Market Risk 7
Consolidated Balance Sheet
- March 31, 2001 and December 31, 2000 9
Consolidated Statement of Income
- Three months and 12 months ended
March 31, 2001 and 2000 10
Consolidated Statement of Cash Flows
- Three months ended
March 31, 2001 and 2000 11
Consolidated Statement of Common
Stockholders' Equity - March 31, 2001 and
December 31, 2000 12
Notes to Consolidated Financial Statements 13
Part II Other Information 18
PART I. CONSOLIDATED FINANCIAL INFORMATION (UNAUDITED)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
Ameren Corporation (Ameren or the Registrant) is a holding company registered
under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren's primary
operating companies are Union Electric Company (AmerenUE), Central Illinois
Public Service Company (AmerenCIPS), both subsidiaries of Ameren, and
AmerenEnergy Generating Company (Generating Company), the nonregulated electric
generating subsidiary of AmerenEnergy Resources Company (Resources Company),
which is a subsidiary of Ameren. Ameren also has a 60% ownership interest in
Electric Energy, Inc. (EEI), which is consolidated for financial reporting
purposes. Ameren's other subsidiaries include AmerenEnergy, Inc. (AmerenEnergy),
Ameren Development Company, Resources Company, Ameren Services Company and
CIPSCO Investment Company. AmerenEnergy, an energy trading and marketing
subsidiary, primarily serves as a power marketing agent for AmerenUE and
Generating Company and provides a range of energy and risk management services
to targeted customers. Ameren Development Company is a nonregulated subsidiary
encompassing Ameren's nonregulated products and services. Resources Company
holds the Registrant's nonregulated generating operations. Ameren Services
Company provides shared support services to Ameren and all of its subsidiaries.
The following discussion and analysis should be read in conjunction with the
Notes to Consolidated Financial Statements beginning on page 13, and the
Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A), the Audited Consolidated Financial Statements and the Notes
to Consolidated Financial Statements appearing in the Registrant's 2000 Annual
Report to Stockholders (which are incorporated by reference in the Registrant's
2000 Form 10-K).
References to the Registrant are to Ameren on a consolidated basis; however, in
certain circumstances, the subsidiaries are separately referred to in order to
distinguish between their different business activities.
RESULTS OF OPERATIONS
Earnings
First quarter 2001 ongoing earnings of $65 million, or 48 cents per share,
increased $4 million, or 3 cents per share, from 2000's first quarter earnings.
2001 ongoing earnings exclude the impact of a one-time charge of 5 cents per
share, associated with the required adoption of a new accounting standard
related to derivative financial instruments (see Note 7 under Notes to
Consolidated Financial Statements for further information). This resulted in
reported earnings of $58 million, or 43 cents per share, for the first quarter
of 2001. Earnings for the 12 months ended March 31, 2001, were $454 million, or
$3.31 per share, compared to $392 million, or $2.86 per share, for the preceding
12 month period.
Earnings and earnings per share fluctuated due to many conditions, primarily:
sales growth, weather variations, credits to electric customers, electric rate
reductions, gas rate increases, competitive market forces, fluctuating operating
costs (including Callaway Nuclear Plant refueling outages), expenses relating to
the withdrawal from the electric transmission related Midwest Independent System
Operator (Midwest ISO) and charges for coal contract terminations, adoption of a
new accounting standard, changes in interest expense, and changes in income and
property taxes.
The significant items affecting revenues, costs and earnings during the
three-month and 12 month periods ended March 31, 2001 and 2000 are detailed on
the following pages.
Electric Operations
Electric Operating Revenues Variations for periods ended March 31, 2001
from comparable prior-year periods
- ----------------------------------------------------------------------------------------------
(Millions of Dollars) Three Months Twelve Months
- ----------------------------------------------------------------------------------------------
Credit to customers $ ( 5) $ (42)
Effect of abnormal weather 28 35
Growth and other 33 228
Interchange sales 73 72
EEI sales (16) (39)
- ----------------------------------------------------------------------------------------------
$ 113 $ 254
- ----------------------------------------------------------------------------------------------
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The $113 million increase in first quarter electric revenues compared to the
year-ago quarter was primarily driven by increased native sales. Residential and
commercial sales rose by 10 percent and 9 percent, respectively, due to a return
to more normal weather. In addition, industrial sales increased 16 percent,
primarily due to a new customer contract that became effective in August 2000.
Wholesale and interchange sales increased 13 percent and 6 percent,
respectively, for the first quarter of 2001 compared to the year-ago quarter,
due to strong marketing efforts. These increases were partially offset by a 45
percent decline in EEI sales, as a result of a decrease in sales under a
contract with its major customer, and an increase in the estimated credits to
Missouri electric customers (see Note 5 under Notes to Consolidated Financial
Statements for further information).
Electric revenues for the 12 months ended March 31, 2001 increased $254 million
compared to the prior 12 month period. The increase in revenues was primarily
driven by increased wholesale sales due to a new customer contract that became
effective in January 2000. Residential and commercial sales increased 8 percent
and 10 percent, respectively, while industrial sales increased 6 percent. This
increase was partially offset by a 41 percent decline in EEI sales, due to a
decrease in sales under a contract with a major customer, coupled with an
increase in the estimated credit to Missouri electric customers (see Note 5
under Notes to Consolidated Financial Statements for further information).
Fuel and Purchased Power Variations for periods ended March 31, 2001
from comparable prior-year periods
- --------------------------------------------- ------------------- ---- -----------------------
(Millions of Dollars) Three Months Twelve Months
- --------------------------------------------- ------------------- ---- -----------------------
Fuel:
Generation $ 4 $ 39
Price (4) (31)
Generation efficiencies and other 1 (10)
Coal contract termination payments - (52)
Purchased power 71 119
EEI (9) (5)
- ----------------------------------------------------------------------------------------------
$ 60 $ 63
- ----------------------------------------------------------------------------------------------
The $63 million increase in first quarter fuel and purchased power costs
compared to the year-ago quarter was primarily driven by increased purchased
power, resulting from higher sales volume, partially offset by decreased costs
at EEI, due to lower sales.
Fuel and purchased power costs for the 12 months ended March 31, 2001 increased
$60 million versus the comparable prior-year period primarily due to increased
generation and purchased power, resulting from higher sales volume partially
offset by lower fuel prices, which resulted from savings related to the
termination of certain coal contracts in late 1999. AmerenCIPS and two of its
coal suppliers executed agreements to terminate their existing coal supply
contracts effective December 31, 1999 resulting in termination payments of $52
million.
Gas Operations
Gas revenues for the three and 12 month periods ended March 31, 2001 increased
$87 million and $182 million, respectively, compared to the same year-ago
periods. The increase is primarily due to increases in retail sales due to a
return to more normal winter weather conditions and higher gas costs reflected
in the purchased gas adjustment clause (PGA).
Gas costs for the three and 12 months ended March 31, 2001, increased $79
million and $154 million, respectively, compared to the year-ago periods
primarily due to the increase in purchases as well as higher gas prices.
Other Operating Expenses
Other operating expense variations reflected recurring factors such as growth,
inflation, labor and employee benefit costs.
Other operations expenses increased $20 million for the three months ended March
31, 2001, compared to the comparable prior-year period, primarily due to higher
employee benefit costs, resulting primarily from a change in actuarial
assumptions. For the twelve months ended March 31, 2001, expenses increased by
$49 million compared to the same prior-year period primarily due to the
withdrawal from the Midwest ISO (see discussion below under "Electric Industry
Restructuring" for further information), in addition to higher employee benefit
costs, resulting from a change in actuarial assumptions.
Maintenance expenses for the three and 12 months ended March 31, 2001 increased
$13 million and $7 million, respectively, compared to the year-ago periods
primarily due to increased fossil power plant maintenance.
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Depreciation and amortization expenses for the three month and 12 month periods
ended March 31, 2001 increased $5 million and $23 million, respectively,
compared to the comparable prior periods due to increased depreciable property,
primarily resulting from the addition of combustion turbine generating
facilities (see discussion below under "Liquidity and Capital Resources" for
further information).
Taxes
Income taxes increased $38 million for the 12 months ended March 31, 2001 due to
an increase in pretax income.
Other tax expense increased $6 million and $24 million for the three month and
12 month periods ended March 31, 2001, respectively, compared to the year-ago
period, primarily due to a change in the property tax assessment in the state of
Illinois in June 2000.
Other Income and Deductions
The $12 million increase in miscellaneous, net for the 12 month period ended
March 31, 2001, compared to the year-ago period, was primarily due to prior
period write-offs of certain nonregulated investments.
Balance Sheet
The $52 million decrease in accounts receivable-trade was due primarily to lower
revenues in February and March 2001 compared to November and December 2000.
Short-term debt increased $71 million primarily for borrowings to finance the
construction of new combustion turbine generating facilities. See "Liquidity and
Capital Resources" below for further discussion.
The $135 million decrease in accounts and wages payable and taxes accrued
resulted from the timing of various payments to taxing authorities and
suppliers, as well as the payment of employee benefits.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $187 million for the quarter ended
March 31, 2001, compared to $208 million during the same 2000 period.
Cash flows used in investing activities totaled $208 million and $255 million
for the three months ended March 31, 2001 and 2000, respectively. Construction
expenditures for the three months ended March 31, 2001, for constructing new or
improving existing facilities were $204 million, which included expenditures
associated with the purchase of combustion turbine generating facilities. In
addition, the Registrant expended $8 million for the acquisition of nuclear
fuel.
Cash flows used in financing activities totaled $13 million for the three months
ended March 31, 2001, compared to $108 million during the same 2000 period. The
Registrant's principal financing activities for the period included the
redemption of debt and the payment of dividends, partially offset by the
issuance of short-term and long-term debt. On February 9, 2001, the Registrant's
Board of Directors declared a quarterly dividend of 63.5 cents per common share
that was paid to shareholders on March 31, 2001. Common stock dividends paid for
the 12 months ended March 31, 2001, resulted in a payout rate of 77 percent of
the Registrant's earnings to common stockholders. Dividends paid to the
Registrant's common shareholders relative to net cash provided by operating
activities for the same period were 42 percent. On April 24, 2001, the
Registrant's Board of Directors declared a quarterly dividend for the second
quarter of 2001 of 63.5 cents per common share that will be paid to shareholders
on June 29, 2001.
In April 2001, AmerenCIPS filed a shelf registration statement with the SEC on
Form S-3 authorizing the offering from time to time of senior notes in one or
more series with an offering price not to exceed $250 million. The SEC declared
the registration statement effective in May 2001. AmerenCIPS plans to issue up
to $150 million of the senior notes in 2001. The senior notes will be secured by
a related series of AmerenCIPS' first mortgage bonds. The proceeds of those
notes will be used to repay short-term debt and first mortgage bonds maturing in
2001.
On November 1, 2000, Generating Company issued Senior Notes in a private
placement, Series A due 2005 (Series A Notes) and Senior Notes, Series B due
2010 (Series B Notes) (collectively, the Senior Notes). The Series A Notes
totaled $225 million. Interest will accrue on the Series A Notes at a rate of
7.75% per year and will be payable semi-annually in arrears on May 1 and
November 1 of each year commencing on May 1, 2001. Principal of the Series A
Notes will be payable on November 1, 2005. Series B Notes totaled $200 million.
Interest will accrue on the Series B Notes at a rate of 8.35% per year and will
be payable semi-annually in arrears on May 1 and November 1 of each year
commencing on May 1, 2001. Principal of the Series B Notes will be payable on
November 1, 2010. The proceeds from the Senior Notes were $423.6 million,
excluding transaction costs. With the proceeds from the Senior Notes, Generating
Company reduced its short-term borrowings incurred in connection with the
construction of completed combustion turbine generating facilities, paid for the
construction of certain combustion turbine generating facilities,
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and funded working capital and other capital expenditure needs. Generating
Company filed a registration statement in the first quarter of 2001 to register
the Senior Notes under the Securities Act of 1933, as amended, to permit an
exchange offer of the Senior Notes. The registration statement was declared
effective in April 2001.
The Registrant anticipates securing additional permanent financing during
2001-2004 to primarily fund capital expenditure requirements for combustion
turbine generating facilities. At this time, the Registrant is unable to
determine the amount of the additional permanent financing, as well as the
additional financing's impact on the Registrant's financial position, results of
operations or liquidity.
The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant and its subsidiaries
are authorized by the Securities and Exchange Commission (SEC) under the PUHCA
to have up to an aggregate $2.8 billion of short-term unsecured debt instruments
outstanding at any one time. Short-term borrowings consist of commercial paper
(maturities generally within 1 to 45 days) and bank loans. At March 31, 2001,
the Registrant had committed bank lines of credit aggregating $176 million, all
of which was unused and available at such date, which make available interim
financing at various rates of interest based on LIBOR, the bank certificate of
deposit rate or other options. The lines of credit are renewable annually at
various dates throughout the year. The Registrant has bank credit agreements,
expiring at various dates between 2001 and 2002, that support commercial paper
programs totaling $763 million, $463 million of which is available for the
Registrant's own use and for the use of its subsidiaries. The remaining $300
million is available for the use of the Registrant's regulated subsidiaries. At
March 31, 2001, $454 million was available under these bank credit agreements.
The Registrant had $274 million of short-term borrowings at March 31, 2001.
AmerenUE also has a lease agreement that provides for the financing of nuclear
fuel. At March 31, 2001, the maximum amount that could be financed under the
agreement was $120 million. Cash used in financing activities for the three
months ended March 31, 2001, included redemptions under the lease for nuclear
fuel of $35 million, offset by $2 million of issuances. At March 31, 2001, $81
million was financed under the lease.
During the course of the Registrant's resource planning, several alternatives
are being considered to satisfy regulatory load requirements for 2001 and beyond
for AmerenUE, AmerenCIPS and Resources Company. Alternatives being considered
include proposals for the purchase of 100 megawatts of capacity and energy for
the summer of 2001, among other things. At this time, management is unable to
predict which course of action it will pursue to satisfy these requirements and
their ultimate impact on the Registrant's financial position, results of
operations or liquidity.
The Registrant, in the ordinary course of business, explores opportunities to
reduce its costs in order to remain competitive in the marketplace. Areas where
the Registrant focuses its review include, but are not limited to, labor costs
and fuel supply costs. In the labor area, over the past two years, the
Registrant has reached agreements with all of the Registrant's major collective
bargaining units which will permit it to manage its labor costs and practices
effectively in the future. The Registrant also explores alternatives to
effectively manage the size of its workforce. These alternatives include
utilizing hiring freezes, outsourcing and offering employee separation packages.
In the fuel supply area, the Registrant explores alternatives to effectively
manage its overall fuel costs. These alternatives include diversifying fuel
sources for use at the Registrant's fossil power plants (e.g. utilizing low
sulfur versus high sulfur coal), as well as restructuring or terminating
existing contracts with suppliers.
Certain of these cost reduction alternatives could result in additional
investments being made at the Registrant's power plants in order to utilize
different types of coal, or could require nonrecurring payments of employee
separation benefits or nonrecurring payments to restructure or terminate an
existing fuel contract with a supplier. Management is unable to predict which
(if any), and to what extent, these alternatives to reduce its overall cost
structure will be executed, nor can it determine the impact of these actions on
its future financial position, results of operations or liquidity.
RATE MATTERS
In July 1995, the Missouri Public Service Commission (MoPSC) approved an
agreement establishing contractual obligations involving the Registrant's
Missouri retail electric rates. Included was a three-year experimental
alternative regulation plan (the Original Plan) that ran from July 1, 1995
through June 30, 1998. A new three-year experimental alternative regulation plan
(the New Plan) was included in the joint agreement authorized by the MoPSC in
February 1997. The New Plan runs from July 1, 1998 through June 30, 2001. On
February 1, 2001, the Registrant, MoPSC staff, and other parties submitted
filings to the MoPSC addressing the merits of extending the current experimental
alternative regulation plan. In its filing, the Registrant supported an
extension of this plan with certain modifications, including retail electric
rate reductions and additional customer credits. The MoPSC staff filing noted
several concerns with the current
-5-
plan and suggested that under traditional cost of service ratemaking, an
annualized electric rate decrease of at least $100 million could be warranted.
On March 8, 2001, the MoPSC issued an Order authorizing the MoPSC staff to file
an earnings complaint to seek a rate reduction on July 1, 2001 if it determines
that one is warranted. In addition, the Order stated that the New Plan will not
be continued beyond June 30, 2001. The Registrant has been engaged in
discussions with the MoPSC staff and other parties in an effort to address
issues associated with the expiration of the New Plan, including the development
of a new alternative regulation plan. At this time, the Registrant cannot
predict the outcome of these discussions or the timing or amount of any future
electric rate reductions.
See Note 5 under Notes to Consolidated Financial Statements for further
discussion of Rate Matters.
ELECTRIC INDUSTRY RESTRUCTURING
Certain states are considering proposals or have adopted legislation that will
promote competition at the retail level. During 2000 and in early 2001,
deregulation laws established in the state of California, coupled with high
energy prices, increasing demands for power by users in that state, transmission
constraints, and limited generation resources, among other things, negatively
impacted several major electric utilities in that state. Federal and state
regulators and legislators have proposed and implemented, in part, different
courses of action to attempt to address these issues. The Registrant does not
maintain utility operations in the state of California, nor does it provide
energy directly to utilities in that state. At this time, the Registrant is
uncertain what impact, if any, changes in deregulation laws will have on future
federal and state deregulation laws (including the state of Missouri), which
could directly impact the Registrant's future financial position, results of
operations or liquidity.
Illinois
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Law) providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois.
One of the major provisions of the Law includes the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric generation
supplier. The phase-in of retail direct access began on October 1, 1999, with
large commercial and industrial customers principally comprising the initial
group. The remaining commercial and industrial customers in Illinois were
offered choice on December 31, 2000. Commercial and industrial customers in
Illinois represent approximately 13 percent of the Registrant's total sales. As
of March 31, 2001, the impact of retail direct access on the Registrant's
financial condition, results of operations, or liquidity was immaterial. Retail
direct access will be offered to residential customers on May 1, 2002.
Missouri
The Registrant is participating in discussions with the Missouri legislature
regarding legislation that would not restructure the electric industry in
Missouri, but would allow utilities to transfer generation assets to an
affiliated generating company. In addition, the legislation would allow the
State's largest nonresidential customers to choose their electric supplier,
among other things. At this time, the Registrant does not believe that any
electric industry legislation will be passed during the legislative session
scheduled to end in May 2001.
Midwest ISO and Alliance RTO
In the fourth quarter of 2000, the Registrant announced its intention to
withdraw from the Midwest ISO and to join the Alliance Regional Transmission
Organization (Alliance RTO), and recorded a pretax charge to earnings of $25
million ($15 million after taxes, or 11 cents per share), which related to the
Registrant's estimated obligation under the Midwest ISO agreement for costs
incurred by the Midwest ISO, plus estimated exit costs. In January 2001, the
Federal Energy Regulatory Commission (FERC) conditionally approved the
formation, including the rate structure, of the Alliance RTO, and the Registrant
announced that it had signed an agreement to join the Alliance RTO. In February
2001, in a proceeding before the FERC, the Alliance RTO and the Midwest ISO
reached an agreement that would enable Ameren to withdraw from the Midwest ISO
and to join the Alliance RTO. In April 2001, this settlement agreement was
certified by the Administrative Law Judge of the FERC and submitted to the FERC
Commissioners for approval. The settlement agreement was approved by the FERC in
May 2001. The Registrant's withdrawal from the Midwest ISO remains subject to
MoPSC approval. In addition, Ameren's transfer of control and operation of its
transmission assets to the Alliance RTO is subject to MoPSC and Illinois
Commerce Commission approval and its membership in the Alliance RTO is subject
to SEC approval under the PUHCA. At this time, the Registrant is unable to
determine the impact that its withdrawal from the Midwest ISO and its
participation in the Alliance RTO will have on its future financial condition,
results of operation or liquidity.
-6-
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a physical asset or a
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, equity prices, commodity prices, etc.).
The following discussion of the Registrant's risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. The Registrant handles market risks in accordance with established
policies, which may include entering into various derivative transactions. In
the normal course of business, the Registrant also faces risks that are either
non-financial or non-quantifiable. Such risks principally include business,
legal, operational and credit risk and are not represented in the following
analysis.
The Registrant's risk management objective is to optimize its physical
generating assets within prudent risk parameters. Risk management policies are
set by a Risk Management Steering Committee, which is comprised of senior-level
Ameren officers.
Interest Rate Risk
The Registrant is exposed to market risk through changes in interest rates
through its issuance of both long-term and short-term variable-rate debt and
fixed-rate debt, commercial paper and auction-rate preferred stock. The
Registrant manages its interest rate exposure by controlling the amount of these
instruments it holds within its total capitalization portfolio and by monitoring
the effects of market changes in interest rates.
If interest rates increase one percentage point in 2002, as compared to 2001,
the Registrant's interest expense would increase by approximately $10 million
and net income would decrease by approximately $6 million. This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt, commercial paper and auction-rate preferred stock, as of March 31, 2001,
continued to be outstanding throughout 2002, and that the average interest rates
for these instruments increased one percentage point over 2001. The estimate
does not consider the effects of the reduced level of potential overall economic
activity that would exist in such an environment. In the event of a significant
change in interest rates, management would likely take actions to further
mitigate its exposure to this market risk. However, due to the uncertainty of
the specific actions that would be taken and their possible effects, the
sensitivity analysis assumes no change in the Registrant's financial structure.
Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas, fuel and
electricity. Several techniques are utilized to mitigate the Registrant's risk,
including utilizing derivative financial instruments. A derivative is a contract
whose value is dependent on, or derived from, the value of some underlying
asset. The derivative financial instruments that the Registrant uses (primarily
forward contracts, futures contracts and option contracts) are dictated by risk
management policies.
With regard to its natural gas utility business, the Registrant's exposure to
changing market prices is in large part mitigated by the fact that the
Registrant has purchased gas adjustment clauses (PGAs) in place in both its
Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to
its customers its prudently incurred costs of natural gas.
The Registrant has a subsidiary, AmerenEnergy Fuels and Services Company, a
wholly owned subsidiary of Resources Company, which is responsible for providing
fuel procurement and gas supply services on behalf of the Registrant's operating
subsidiaries, and for managing fuel and natural gas price risks. Fixed price
forward contracts, as well as futures and options, are all instruments, which
may be used to manage these risks. The majority of the Registrant's fuel supply
contracts are physical forward contracts. Since the Registrant does not have a
provision similar to the PGA for its electric operations, the Registrant has
entered into several long-term contracts with various suppliers to purchase coal
and nuclear fuel to manage its exposure to fuel prices. With regard to the
Registrant's nonregulated electric generation operations, the Registrant is
exposed to changes in market prices for natural gas to the extent it must
purchase natural gas to run its combustion turbine generators. The Registrant's
natural gas procurement strategy is designed to ensure reliable and immediate
delivery of natural gas to its intermediate and peaking units by optimizing
transportation and storage options and minimizing cost and price risk by
structuring various supply agreements to maintain access to multiple gas pools
and supply basins and reducing the impact of price volatility.
With regard to the Registrant's exposure to commodity price risk for purchased
power and excess electricity sales, the Registrant has a subsidiary,
AmerenEnergy, whose primary responsibility includes managing market risks
associated with changing market prices for electricity purchased and sold on
behalf of AmerenUE and Generating Company.
-7-
Although the Registrant cannot completely eliminate the effects of elevated
prices and price volatility, its strategy is designed to minimize the effect of
these market conditions on the results of operations. The Registrant's gas
procurement strategy includes procuring natural gas under a portfolio of
agreements with price structures, including fixed price, indexed price and
embedded price hedges such as caps and collars. The Registrant's strategy also
utilizes physical assets through storage, operator and balancing agreements to
minimize price volatility. The Registrant's electric marketing strategy is to
extract additional value from its generation facilities by selling energy in
excess of needs for term sales and purchasing energy when the market price is
less than the cost of generation. The Registrant's primary use of derivatives
has been limited to transactions that are expected to reduce price risk exposure
for the Registrant.
Equity Price Risk
The Registrant maintains trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. As of March 31, 2001, these funds were invested
primarily in domestic equity securities, fixed-rate, fixed-income securities,
and cash and cash equivalents. By maintaining a portfolio that includes
long-term equity investments, the Registrant is seeking to maximize the returns
to be utilized to fund nuclear decommissioning costs. However, the equity
securities included in the Registrant's portfolio are exposed to price
fluctuations in equity markets, and the fixed-rate, fixed-income securities are
exposed to changes in interest rates. The Registrant actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, established target
allocation percentages of the assets of its trusts to various investment
options. The Registrant's exposure to equity price market risk is, in large
part, mitigated, due to the fact that the Registrant is currently allowed to
recover its decommissioning costs in its rates.
SAFE HARBOR STATEMENT
Statements made in this annual report to stockholders which are not based on
historical facts, are "forward-looking" and, accordingly, involve risks and
uncertainties that could cause actual results to differ materially from those
discussed. Although such "forward-looking" statements have been made in good
faith and are based on reasonable assumptions, there is no assurance that the
expected results will be achieved. These statements include (without limitation)
statements as to future expectations, beliefs, plans, strategies, objectives,
events, conditions, and financial performance. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated. The
following factors, in addition to those discussed elsewhere in this report and
in the 2000 Annual Report to Stockholders (portions of which are incorporated by
reference in the Registrant's 2000 Form 10-K) and in subsequent securities
filings, could cause results to differ materially from management expectations
as suggested by such "forward-looking" statements: the effects of regulatory
actions, including changes in regulatory policy; changes in laws and other
governmental actions; the impact on the Registrant of current regulations
related to the phasing-in of the opportunity for some customers to choose
alternative energy suppliers in Illinois; the effects of increased competition
in the future, due to, among other things, deregulation of certain aspects of
the Registrant's business at both the state and federal levels; the effects of
withdrawal from the Midwest ISO and membership in the Alliance RTO; future
market prices for fuel and purchased power, electricity, and natural gas,
including the use of financial instruments; average rates for electricity in the
Midwest; business and economic conditions; the impact of the adoption of new
accounting standards; interest rates; weather conditions; fuel prices and
availability; generation plant construction, installation and performance; the
impact of current environmental regulations on utilities and generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative financial effect;
monetary and fiscal policies; future wages and employee benefits costs; and
legal and administrative proceedings.
-8-
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
UNAUDITED
(Thousands of Dollars, Except Shares)
March 31, December 31,
ASSETS 2001 2000
- ------ ------------------ ---------------
Property and plant, at original cost:
Electric $12,748,230 $12,684,366
Gas 513,352 509,746
Other 101,060 97,214
--------------- ---------------
13,362,642 13,291,326
Less accumulated depreciation and amortization 6,289,711 6,204,367
--------------- ---------------
7,072,931 7,086,959
Construction work in progress:
Nuclear fuel in process 125,554 117,789
Other 618,334 500,924
--------------- ---------------
Total property and plant, net 7,816,819 7,705,672
--------------- --------------
Investments and other assets:
Investments 40,752 40,235
Nuclear decommissioning trust fund 179,690 190,625
Other 101,386 97,630
--------------- ---------------
Total investments and other assets 321,828 328,490
--------------- ---------------
Current assets:
Cash and cash equivalents 91,469 125,968
Accounts receivable - trade (less allowance for doubtful
accounts of $7,562 and $8,028, respectively) 422,352 474,425
Other accounts and notes receivable 23,016 56,529
Materials and supplies, at average cost -
Fossil fuel 87,152 107,572
Other 117,207 119,478
Other current assets 30,888 37,210
---------------- ---------------
Total current assets 772,084 921,182
---------------- ---------------
Regulatory assets:
Deferred income taxes 600,234 600,100
Other 155,850 158,986
--------------- ---------------
Total regulatory assets 756,084 759,086
--------------- --------------
Total Assets $ 9,666,815 $ 9,714,430
=============== ==============
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $.01 par value, 400,000,000 shares authorized -
137,215,462 shares outstanding $ 1,372 $ 1,372
Other paid-in capital, principally premium on
common stock 1,581,196 1,581,339
Retained earnings 1,585,667 1,613,960
Accumulated other comprehensive income (3,998) -
Other (5,514) -
---------------- --------------
Total common stockholders' equity 3,158,723 3,196,671
Preferred stock not subject to mandatory redemption 235,197 235,197
Long-term debt 2,748,781 2,745,068
---------------- --------------
Total capitalization 6,142,701 6,176,936
---------------- --------------
Minority interest in consolidated subsidiaries 3,534 3,940
Current liabilities:
Current maturity of long-term debt 44,444 44,444
Short-term debt 273,818 203,260
Accounts and wages payable 251,338 462,924
Accumulated deferred income taxes 39,724 49,829
Taxes accrued 201,623 124,706
Other 336,299 300,798
---------------- --------------
Total current liabilities 1,147,246 1,185,961
---------------- --------------
Accumulated deferred income taxes 1,542,815 1,540,536
Accumulated deferred investment tax credits 161,894 164,120
Regulatory liability 182,276 183,541
Other deferred credits and liabilities 486,349 459,396
---------------- --------------
Total Capital and Liabilities $ 9,666,815 $ 9,714,430
================ ==============
See Notes to Consolidated Financial Statements.
-9-
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
UNAUDITED
(Thousands of Dollars, Except Shares and Per Share Amounts)
Three Months Ended Twelve Months Ended
March 31 March 31
-------------------------- -------------------------
2001 2000 2001 2000
---- ---- ---- ----
OPERATING REVENUES:
Electric $835,797 $723,059 $3,639,316 $3,385,195
Gas 185,886 98,600 411,172 229,448
Other 2,845 3,717 5,494 9,338
------------- ----------- -------------- --------------
Total operating revenues 1,024,528 825,376 4,055,982 3,623,981
OPERATING EXPENSES:
Operations
Fuel and purchased power 303,169 239,938 1,088,452 1,028,220
Gas 136,540 57,987 288,020 134,386
Other 165,583 145,386 684,741 635,628
--------- --------- ------------ ------------
605,292 443,311 2,061,213 1,798,234
Maintenance 87,898 74,957 380,862 373,520
Depreciation and amortization 98,734 93,364 388,480 365,305
Income taxes 49,332 44,251 306,273 267,891
Other taxes 67,186 60,915 271,336 247,591
---------- ---------- ------------ ------------
Total operating expenses 908,442 716,798 3,408,164 3,052,541
OPERATING INCOME 116,086 108,578 647,818 571,440
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during
construction 1,605 1,229 5,674 5,728
Miscellaneous, net (1,505) (4,922) (983) (13,470)
------------ ------------ --------------- -------------
Total other income and (deductions) 100 (3,693) 4,691 (7,742)
INCOME BEFORE INTEREST CHARGES
AND PREFERRED DIVIDENDS 116,186 104,885 652,509 563,698
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest 50,022 41,893 187,835 165,753
Allowance for borrowed funds used during construction (2,349) (1,599) (9,042) (6,860)
Preferred dividends of subsidiaries 3,180 3,198 12,682 12,676
------------ ---------- ------------- -------------
Net interest charges and preferred dividends 50,853 43,492 191,475 171,569
----------- ---------- ------------- -------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 65,333 61,393 461,034 392,129
----------- ---------- ------------- -------------
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES (Note 7) (6,841) - (6,841) -
---------- ---------- ------------ -------------
NET INCOME $ 58,492 $ 61,393 $ 454,193 $ 392,129
========== ========== ============ =============
EARNINGS PER COMMON SHARE - BASIC AND DILUTED
(Based on average shares outstanding):
Income before cumulative effect of change in
accounting principle $ 0.48 $ 0.45 $ 3.36 $2.86
Cumulative effect of change in accounting principle,
net of income taxes (0.05) - (0.05) -
----------- ------------ ------------ --------------
Net income $ 0.43 $ 0.45 $ 3.31 $ 2.86
=========== ============ ============= ==============
AVERAGE COMMON SHARES OUTSTANDING 137,215,462 137,215,462 137,215,462 137,215,462
============= ============ ============== ==============
See Notes to Consolidated Financial Statements.
-10-
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
UNAUDITED
(Thousands of Dollars)
Three Months Ended
March 31,
-----------------------------------------
2001 2000
------ ------
Cash Flows From Operating:
Net income $ 58,492 $ 61,393
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 6,841 -
Depreciation and amortization 95,651 90,279
Amortization of nuclear fuel 8,575 9,075
Allowance for funds used during construction (3,954) (2,828)
Deferred income taxes, net (6,794) (7,169)
Deferred investment tax credits, net (2,226) (321)
Changes in assets and liabilities:
Receivables, net 85,586 62,324
Materials and supplies 22,691 29,224
Accounts and wages payable (211,586) (161,384)
Taxes accrued 76,917 77,145
Other, net 56,351 50,276
--------- ----------
Net cash provided by operating activities 186,544 208,014
Cash Flows From Investing:
Construction expenditures (203,952) (223,375)
Allowance for funds used during construction 3,954 2,828
Nuclear fuel expenditures (7,505) (6,228)
Other (517) (28,089)
------------ ----------
Net cash used in investing activities (208,020) (254,864)
Cash Flows From Financing:
Dividends on common stock (87,132) (87,132)
Environmental bond redemption fund - (237,600)
Redemptions:
Nuclear fuel lease (34,976) (1,818)
Long-term debt (5,000) (104,723)
Issuances:
Nuclear fuel lease 1,727 1,356
Short-term debt 70,558 83,976
Long-term debt 41,800 237,600
------------ ----------
Net cash used in financing activities (13,023) (108,341)
------------ ----------
Net change in cash and cash equivalents (34,499) (155,191)
Cash and cash equivalents at beginning of year 125,968 194,882
----------- ----------
Cash and cash equivalents at end of period $ 91,469 $ 39,691
=========== ==========
Cash paid during the periods:
Interest (net of amount capitalized) $ 31,566 $ 34,199
Income taxes, net $ 962 $ (4,527)
See Notes to Consolidated Financial Statements.
-11-
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
UNAUDITED
(Thousands of Dollars)
Three Months Ended Year Ended
March 31, 2001 December 31, 2000
------------------------ ---------------------
Common stock $ 1,372 $ 1,372
Other paid-in capital
Beginning balance 1,581,339 1,582,501
Employee stock awards (143) (1,162)
------------------------ ---------------------
1,581,196 1,581,339
Retained earnings
Beginning balance 1,613,960 1,505,827
Net income 58,492 457,094
Dividends (86,785) (348,961)
------------------------ ---------------------
1,585,667 1,613,960
Accumulated other comprehensive income
Beginning balance - -
Change in current period (3,998) -
------------------------ ---------------------
(3,998) -
Other
Beginning balance - -
Unamortized restricted stock compensation (5,704) -
Compensation amortized 190 -
------------------------ ---------------------
(5,514) -
------------------------ ---------------------
Total common stockholders' equity $ 3,158,723 $3,196,671
======================== =====================
Comprehensive income, net of tax
Net income $ 58,492 $ 457,094
Cumulative effect of accounting change, net of taxes (11,258) -
Unrealized net gain on derivative hedging instruments 7,260 -
------------------------ ---------------------
$ 54,494 $ 457,094
======================== =====================
See Notes to Consolidated Financial Statements.
-12-
AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2001
Note 1 - Ameren Corporation (Ameren or the Registrant) is a holding company
registered under the Public Utility Holding Company Act of 1935 (PUHCA).
Ameren's primary operating companies are Union Electric Company (AmerenUE),
Central Illinois Public Service Company (AmerenCIPS), both subsidiaries of
Ameren, and AmerenEnergy Generating Company (Generating Company), the
nonregulated electric generating subsidiary of AmerenEnergy Resources Company
(Resources Company), which is a subsidiary of Ameren. Ameren also has a 60%
ownership interest in Electric Energy, Inc. (EEI). EEI owns and/or operates
electric generation and transmission facilities in Illinois that supply electric
power primarily to a uranium enrichment plant located in Paducah, Kentucky. That
interest is consolidated for financial reporting purposes. Ameren's other
subsidiaries include AmerenEnergy, Inc. (AmerenEnergy), Ameren Development
Company, AmerenEnergy Resources Company, Ameren Services Company and CIPSCO
Investment Company. AmerenEnergy, an energy marketing subsidiary, primarily
serves as a power marketing agent for AmerenUE and Generating Company and
provides a range of energy and risk management services to targeted customers.
Ameren Development Company is a nonregulated subsidiary encompassing Ameren's
nonregulated products and services. Resources Company holds the Registrant's
nonregulated generating operations. Ameren Services Company provides shared
support services to Ameren and all of its subsidiaries.
The accompanying financial statements include the accounts of Ameren and its
consolidated subsidiaries (collectively the Registrant). All subsidiaries for
which the Registrant owns directly or indirectly more than 50 percent of the
voting stock are included as consolidated subsidiaries. Ameren's primary
operating companies, AmerenUE, AmerenCIPS and Generating Company, are engaged
principally in the generation, transmission, distribution and sale of electric
energy and the purchase, distribution, transportation and sale of natural gas.
The operating companies serve 1.5 million electric and 300,000 natural gas
customers in a 44,500-square-mile area of Missouri and Illinois. All significant
intercompany balances and transactions have been eliminated from the
consolidated financial statements.
Note 2 - Financial statement note disclosures, normally included in consolidated
financial statements prepared in conformity with generally accepted accounting
principles, have been omitted in this Form 10-Q pursuant to the Rules and
Regulations of the Securities and Exchange Commission (SEC). However, in the
opinion of the Registrant, the disclosures contained in this Form 10-Q are
adequate to make the information presented not misleading. See Notes to
Consolidated Financial Statements included in the 2000 Annual Report to
Stockholders (which are incorporated by reference in the Registrant's 2000 Form
10-K) for information relevant to the consolidated financial statements
contained in this Form 10-Q, including information as to the significant
accounting policies of the Registrant.
Note 3 - In the opinion of the Registrant, the interim financial statements
filed as part of this Form 10-Q reflect all adjustments, consisting only of
normal recurring adjustments, necessary for a fair statement of the results for
the periods presented.
Note 4 - Due to the effect of weather on sales and other factors which are
characteristic of public utility operations, financial results for the periods
ended March 31, 2001 and 2000, are not necessarily indicative of trends for any
three-month or twelve-month period.
Note 5 - In July 1995, the Missouri Public Service Commission (MoPSC) approved
an agreement establishing contractual obligations involving the Registrant's
Missouri retail electric rates. Included was a three-year experimental
alternative regulation plan (the Original Plan) that ran from July 1, 1995
through June 30, 1998, which provided that earnings in those years in excess of
a 12.61% regulatory return on equity (ROE) be shared equally between customers
and stockholders, and earnings above a 14% ROE be credited to customers. The
formula for computing the credit used twelve-month results ending June 30,
rather than calendar year earnings.
The MoPSC staff proposed adjustments to the Registrant's estimated customer
credit for the final year of the Original Plan ended June 30, 1998, which were
the subject of regulatory proceedings before the MoPSC in 1999. In December
1999, the MoPSC issued a Report and Order (Order) concerning these proposed
adjustments. Based on the provisions of that Order, the Registrant revised its
estimated final year credit to $31 million. Subsequently, the Registrant filed a
request for rehearing of the Order with the MoPSC, asking that it reconsider its
decision to adopt
-13-
certain of the MoPSC staff's adjustments. The request was denied by the MoPSC
and in February 2000, the Registrant filed a Petition for Writ of Review with
the Circuit Court of Cole County, Missouri, requesting that the Order be
reversed. The appeal is pending and the ultimate outcome can not be predicted;
however, the final decision is not expected to materially impact the financial
condition, results of operations or liquidity of the Registrant. A partial stay
of the Order was granted by the Court pending the appeal.
A new three-year experimental alternative regulation plan (the New Plan) was
included in the joint agreement authorized by the MoPSC in its February 1997
order approving the merger of AmerenUE and CIPSCO Incorporated which formed
Ameren (the Merger). Like the Original Plan, the New Plan requires that earnings
over a 12.61 percent ROE up to a 14 percent ROE be shared equally between
customers and stockholders. The New Plan also returns to customers 90 percent of
all earnings above a 14 percent ROE up to a 16 percent ROE. Earnings above a 16
percent ROE are credited entirely to customers. The New Plan runs from July 1,
1998 through June 30, 2001. During the three months ended March 31, 2001, the
Registrant recorded an estimated $15 million credit (6 cents per share) for the
plan year ending June 30, 2001 that the Registrant expects to pay its Missouri
electric customers. In total, the Registrant has recorded an estimated credit of
$65 million as of March 31, 2001 for the plan year ending June 30, 2001,
compared to an estimated $30 million credit recorded over the same period last
year. These credits were reflected as a reduction in electric revenues. The
final amount of the credit will depend on several factors, including the
Registrant's earnings for 12 months ended June 30, 2001. In March 2001, the
MoPSC approved a stipulation and agreement of the parties regarding the credit
for the plan year ended June 30, 2000. As of March 31, 2001, the Registrant has
reflected an estimated $30 million credit it expects to pay its Missouri
electric customers for the plan year ended June 30, 2000.
The joint agreement approved by the MoPSC in its February 1997 order approving
the Merger also provided for a Missouri electric rate decrease, retroactive to
September 1, 1998, based on the weather-adjusted average annual credits to
customers under the Original Plan. The rate decrease was impacted by the Order
issued by the MoPSC in December 1999 relating to the estimated credit for the
third year of the Original Plan and a settlement reached between the Registrant,
the MoPSC staff and other parties relating to the calculation of the
weather-adjusted credits. Based on those results, the Registrant estimates that
its Missouri electric rate decrease will be $17 million on an annualized basis.
This estimate is subject to the final outcome of the above-referenced court
appeal of the Order.
On February 1, 2001, the Registrant, MoPSC staff, and other parties submitted
filings to the MoPSC addressing the merits of extending the current experimental
alternative regulation plan. In its filing, the Registrant supported an
extension of this plan with certain modifications, including retail electric
rate reductions and additional customer credits. The MoPSC staff filing noted
several concerns with the current plan and suggested that under traditional cost
of service ratemaking, an annualized electric rate decrease of at least $100
million could be warranted. On March 8, 2001, the MoPSC issued an Order
authorizing the MoPSC staff to file an earnings complaint to seek a rate
reduction on July 1, 2001, if it determines one is warranted. In addition, the
Order stated that the New Plan will not be continued beyond June 30, 2001. The
Registrant has been engaged in discussions with the MoPSC staff and other
parties in an effort to address issues associated with the expiration of the New
Plan, including the development of a new alternative regulation plan. At this
time, the Registrant cannot predict the outcome of these discussions or the
timing or amount of any future electric rate reductions.
Note 6 - In the fourth quarter of 2000, the Registrant announced its intention
to withdraw from the Midwest Independent System Operator (Midwest ISO) and to
join the Alliance Regional Transmission Organization (Alliance RTO), and
recorded a pretax charge to earnings of $25 million ($15 million after taxes, or
11 cents per share), which related to the Registrant's estimated obligation
under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus
estimated exit costs. In January 2001, the Federal Energy Regulatory Commission
(FERC) conditionally approved the formation, including the rate structure, of
the Alliance RTO, and the Registrant announced that it had signed an agreement
to join the Alliance RTO. In February 2001, in a proceeding before the FERC, the
Alliance RTO and the Midwest ISO reached an agreement that would enable Ameren
to withdraw from the Midwest ISO and to join the Alliance RTO. In April 2001,
this settlement agreement was certified by the Administrative Law Judge of the
FERC and submitted to the FERC Commissioners for approval. The settlement
agreement was approved by the FERC in May 2001. The Registrant's withdrawal from
the Midwest ISO remains subject to MoPSC approval. In addition, Ameren's
transfer of control and operation of its transmission assets to the Alliance RTO
is subject to MoPSC and Illinois Commerce Commission approval and its membership
in the Alliance RTO is subject to SEC approval under the PUHCA. At this time,
the Registrant is unable to determine the impact that its withdrawal from the
Midwest ISO and its participation in the Alliance RTO will have on its future
financial condition, results of operation or liquidity.
-14-
Note 7 - Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting
for Derivative Instruments and Hedging Activities" became effective on January
1, 2001. SFAS 133 established accounting and reporting standards for derivative
financial instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS 133 requires recognition of
all derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of derivatives and their designation as either a
fair value hedge or a cash flow hedge determines when the gains or losses on the
derivatives are to be reported in earnings and when they are reported as a
component of other comprehensive income (OCI) in stockholders' equity. In
accordance with the transition provisions of SFAS 133, the Registrant recorded a
cumulative effect charge of $7 million after income taxes to the income
statement, comprised of $2 million for ineffective portion of cash flow hedges
and $5 million for discontinued hedges. The Registrant also recorded a
cumulative effect adjustment of $11 million after income taxes, representing the
effective portion of designated cash flow hedges, to OCI, which reduced
stockholders' equity. The Registrant expects that within the next twelve months
it will reclassify to earnings all of the transition adjustment that was
recorded in accumulated other comprehensive income. Gains and losses on
derivatives that arose prior to the initial application of SFAS 133 and that
were previously deferred as adjustments of the carrying amount of hedged items
were not adjusted and were not included in the transition adjustments described
above.
All derivatives are recognized on the balance sheet at their fair value. On the
date that the Registrant enters into a derivative contract, it designates the
derivative as (1) a hedge of the fair value of a recognized asset or liability
or an unrecognized firm commitment (a "fair value" hedge); (2) a hedge of a
forecasted transaction or the variability of cash flows that are to be received
or paid in connection with a recognized asset or liability (a "cash flow"
hedge); or (3) an instrument that is held for trading or non-hedging purposes (a
"trading" or "non-hedging" instrument). The Registrant reevaluates its
classification of individual derivative transactions daily. The Registrant
designates or de-designates derivative transactions as hedges based on many
factors including changes in expectations of economic generation availability
and changes in projected sales commitments. Changes in the fair value of
derivatives are captured and reported based on the anticipated use of the
derivative. If a derivative is designated as a cash flow hedge, the effective
portion will not be reflected in the income statement. If the derivative is
subsequently designated as a non-hedging instrument, any further change in fair
value will be reflected in the income statement, with any previously deferred
change in fair value remaining in accumulated OCI until the indicated delivery
period. If, on the other hand, the derivative had been designated as a
non-hedging transaction and subsequently designated as a cash flow hedge, the
initial change in fair value between the transaction date and the hedge
designation date will be recorded in income, and the effective portion of any
further change will be deferred in OCI. Changes in the fair value of derivatives
designated as fair value hedges and changes in the fair value of the hedged
asset or liability that are attributable to the hedged risk (including changes
that reflect losses or gains on firm commitments) are recorded in current-period
earnings. Any hedge ineffectiveness (which represents the amount by which the
changes in the fair value of the derivative exceed the changes in the fair value
of the hedged item) is recorded in current-period earnings. Changes in the fair
value of derivative trading and non-hedging instruments are reported in
current-period earnings.
The Registrant utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel, electricity and emission credits. The
Registrant's risk management objective is to optimize the return from its
physical generating assets, while managing exposures to volatile energy
commodity prices and emission allowances within prudent risk management
policies, which are established by a Risk Management Steering Committee (RMSC)
comprised of senior-level Ameren officers. Price fluctuations in natural gas,
fuel and electricity cause (1) an unrealized appreciation or depreciation of the
Registrant's firm commitments to purchase when purchase prices under the firm
commitment are compared with current commodity prices; (2) market values of fuel
and natural gas inventories or purchased power to differ from the cost of those
commodities under the firm commitment; and (3) actual cash outlays for the
purchase of these commodities to differ from anticipated cash outlays. The
derivatives that the Registrant uses to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. Ameren primarily uses derivatives to optimize the value of its
physical and contractual positions. Ameren continually assesses its supply and
delivery commitment positions against forward market prices and internally
forecast forward prices and modifies its exposure to market, credit and
operational risk by entering into various offsetting transactions. In general
these transactions serve to reduce price risk for the Registrant. Additionally,
the Registrant is authorized to engage in certain transactions that serve to
increase the organization's exposure to price, credit and operational risk for
expected gains. All transactions are continuously monitored and valued by the
independent risk management group to assure compliance with Ameren policies.
-15-
The risk management group employs a variety of risk measurement techniques and
position limits including value at risk, credit value at risk, stress testing,
effectiveness testing along with qualitative measures to establish transaction
parameters and measure transaction compliance.
By using derivative financial instruments, the Registrant is exposed to credit
risk and market risk. Credit risk is the risk that the counterparty might fail
to fulfill its performance obligations under contractual terms. Credit risk
management is based upon consideration and measurement of four factors: (1)
accounts receivable (2) mark to market (3) probability of default and (4) the
recovery rate of the defaulted position that is likely to be recovered. The
Registrant manages its credit (or repayment) risk in derivative instruments by
(1) using both portfolio limits, i.e. no more than prescribed dollar amounts
exposed to companies within various credit categories as well as limiting
exposures to individual companies, (2) monitoring the financial condition of its
counterparties and, (3) enhancing credit quality through contractual terms such
as netting, required collateral postings, letters of credit and parental
guaranties.
Market risk is the risk that the value of a financial instrument might be
adversely affected by a change in commodity prices. The Registrant manages this
risk by establishing and monitoring parameters that limit the types and degree
of market risk that may be undertaken as mentioned above.
The following is a summary of Ameren's risk management strategies and the effect
of these strategies on Ameren's consolidated financial statements.
Cash Flow Hedges
The Registrant routinely enters into forward sales contracts for electricity
based on forecasted levels of excess economic generation. The amount of excess
economic generation that may be sold forward varies throughout the year and is
monitored by the RMSC. The contracts typically cover a period of twelve months
or less. The purpose of these contracts is to hedge against possible price
fluctuations in the spot market for the period covered under the contracts. The
Registrant formally documents all relationships between hedging instruments and
hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash flow hedges to specific forecasted
transactions. The Registrant also formally assesses (both at hedge's inception
and on an ongoing basis) whether the derivatives that are used in hedging
transactions have historically been highly effective in offsetting changes in
the cash flows of hedged items and whether those derivatives are expected to
remain highly effective in future periods.
For the three months ended March 31, 2001, the net gain, which represented the
total ineffectiveness of all cash flow hedges as well as the reversal of amounts
previously recorded in the transition adjustment due to transactions going to
delivery, was immaterial. All components of each derivative's gain or loss were
included in the assessment of hedge effectiveness. Additionally, the Registrant
recorded a pretax net gain of $9 million as electric revenues in the statement
of income due to the change in value of discontinued cash flow hedges,
non-hedging transactions and the reversal of amounts previously recorded in the
transition adjustment due to transactions going to delivery.
As of March 31, 2001, all of the deferred net losses on derivative instruments
accumulated in other comprehensive income are expected to be reversed during the
next twelve months. The derivative losses will be reversed due to delivery of
the commodity being hedged.
Other Derivatives
The Registrant enters into option transactions to manage the Registrant's
positions in sulfur dioxide (SO2) allowances. In addition, the Registrant enters
into option transactions to manage the Registrant's coal purchasing prices and
to manage the cost of electricity by selling puts at prices below the marginal
cost of generation. These transactions are treated as non-hedge transactions
under FAS 133; therefore, the net change in the market value of SO2 options is
recorded as electric revenues and the net change in the market value of coal
options is recorded as fuel and purchased power in the statement of income.
Other
As of March 31, 2001, the Registrant has recorded the fair value of derivative
financial instrument assets of $15 million in Other Assets and derivative
financial instrument liabilities of $26 million in Other Deferred Credits and
Liabilities.
-16-
The Registrant has entered into fixed-price forward contracts for the purchase
of coal and natural gas. While these contracts meet the definition of a
derivative under SFAS 133, the Registrant records these transactions as normal
purchases and normal sales because the contracts are expected to result in
physical delivery.
Note 8 - Segment information for the three-month and 12 month periods ended
March 31, 2001 and 2000 is as follows:
- ---------------------------------------------------------------------------------------------------------------------
Utility Reconciling
(in millions) Operations All Other Items * Total
- ---------------------------------------------------------------------------------------------------------------------
Three months ended March 31, 2001:
Revenues $ 1,153 $ 74 $(202) $ 1,025
Net Income 54 4 -- 58
- ---------------------------------------------------------------------------------------------------------------------
Three months ended March 31, 2000:
Revenues $ 816 $ 68 $ (59) $ 825
Net Income 60 1 -- 61
- ---------------------------------------------------------------------------------------------------------------------
12 months ended March 31, 2001:
Revenues $ 4,456 $ 300 $ (700) $ 4,056
Net Income 451 3 -- 454
- ---------------------------------------------------------------------------------------------------------------------
12 months ended March 31, 2000:
Revenues $ 3,569 $ 262 $ (207) $ 3,624
Net Income 390 2 -- 392
- ---------------------------------------------------------------------------------------------------------------------
* Elimination of intercompany revenues.
-17-
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
--------------------------------
(a)(i) Exhibits.
10.1 - 2nd Amended Electric Power Supply Agreement between
Generating Company and AmerenEnergy Marketing Company
(Marketing Co.).
10.2 - Amended Electric Power Supply Agreement between
Marketing Co. and AmerenCIPS.
(a)(ii) Exhibits Incorporated by Reference.
4.1 - Supplemental Indenture dated December 1, 1998 relating
to Senior Note Mortgage Bonds Series AA-1 and AA-2 of
AmerenCIPS (File No. 333-59438, Exhibit 4.2).
4.2 - Indenture dated as of December 1, 1998 between
AmerenCIPS and The Bank of New York, as Trustee,
relating to the Senior Notes [including as exhibits the
forms of the Senior Notes] (File No. 333-59438, Exhibit
4.4).
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K
dated January 11, 2001, reporting the recording of a
nonrecurring charge in the fourth quarter of 2000 as a result
of its decision to withdraw from the Midwest ISO.
Note: Reports of Union Electric Company on Forms 8-K, 10-Q and 10-K
are on file with the SEC under File Number 1-2967.
Reports of Central Illinois Public Service Company on Forms
8-K, 10-Q and Form 10-K are on file with the SEC under File
Number 1-3672.
Information regarding AmerenEnergy Generating Company on Form
S-4 is on file with the SEC under File Number 333-56594 and its
initial report on Form 10-Q (for the quarterly period ended
March 31, 2001) will be filed under the same File Number.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
AMEREN CORPORATION
(Registrant)
By /s/ Donald E. Brandt
------------------------
Donald E. Brandt
Senior Vice President, Finance
(Principal Financial Officer)
Date: May 15, 2001
-18-
Exhibit 10.1
AMENDED
ELECTRIC POWER SUPPLY AGREEMENT
Between Ameren Energy Generating Company
And
Ameren Energy Marketing Company
THIS ELECTRIC POWER SUPPLY AGREEMENT (hereinafter "EPSA") made as of the 1st day
of May, 2000 and amended as of this 14th day of August, 2000 and as further
amended this 30th day of March, 2001, by and between AMEREN ENERGY GENERATING
COMPANY (hereinafter "Company" or "Genco") and AMEREN ENERGY MARKETING COMPANY
(hereinafter "Customer" or "Marketing") (Genco and Marketing may be identified
collectively as "Parties" or individually as a "Party") is for the supply by
Genco to Marketing of electric capacity and energy available from Genco's
electric generating units.
WHEREAS, Genco is a newly-formed generation-only company that has acquired all
electric generating units formerly owned and operated by Central Illinois Public
Service Company ("AmerenCIPS") and may acquire additional electric generating
units thereafter; and
WHEREAS, the electric generating units acquired by Genco from AmerenCIPS are and
will continue to be dispatched by an Agent designated for that purpose ("Agent")
pursuant to a Joint Dispatch Agreement ("JDA") between AmerenCIPS and Union
Electric Company ("AmerenUE"), subsequently amended among AmerenCIPS, AmerenUE
and Genco; and
WHEREAS, Marketing is engaged in the business of purchasing and reselling
electric capacity and energy at wholesale and retail; and
WHEREAS, a portion of the capacity and energy supplied by Genco to Marketing
will be resold to AmerenCIPS for resale as bundled retail electric service
within its existing retail electric service area in Illinois at rates specified
by the Illinois Commerce Commission ("ICC") ("Bundled Sales"), or to wholesale
requirements customers of Marketing or retail customers of either Marketing
and/or AmerenCIPS that are allowed choice of an electric supplier under state
law at market-based prices ("Market Price Sales"); and
WHEREAS, a portion of the capacity and energy supplied by Genco to Marketing
shall be provided in the form of certain ancillary services that shall be resold
by Marketing to (i) AmerenCIPS as needed to support AmerenCIPS' Bundled Sales
and for resale to AmerenCIPS' open access transmission customers; and (ii)
third-parties consistent with the authorization granted Marketing by the Federal
Energy Regulatory Commission ("FERC"); and
-1-
WHEREAS, Genco desires to sell and deliver to Marketing and Marketing desires to
purchase and receive from Genco capacity and energy available from the
generating units transferred by AmerenCIPS to Genco and from any additional
generating units that may be acquired by Genco in the future pursuant to the
rates, terms and conditions as amended and set forth herein;
NOW THEREFORE, in consideration for the agreements and undertakings established
herein and the mutual benefits derived therefrom, it is agreed as follows:
1. GENERATION SERVICES
A. Capacity And Energy Services
Genco shall make available or cause to be made available to Marketing all of the
electric capacity and energy which shall be available from the electric
generating units that have been transferred to Genco by AmerenCIPS and any
additional generating units that may be acquired by Genco in the future
(hereinafter "Power"), and Marketing shall purchase and pay for such Power in
accordance with the terms of this Agreement. The parties acknowledge the
existence of the JDA, and Genco's obligations associated therewith. To the
extent that (i) Marketing cannot resell the capacity and/or energy to which it
has the right and the obligation to purchase hereunder, and (ii) the Agent can
economically sell such capacity and/or energy, Marketing shall release its right
and shall be released from its obligation to purchase capacity and/or energy
under this EPSA equal to the amount of capacity and/or energy to be sold by the
Agent. Marketing shall coordinate with the Agent with respect to the scheduling
and dispatch of Power consistent with the JDA.
B. Ancillary Services
Genco shall provide a portion of the capacity and energy made available to
Customer pursuant to Section 1.A in the form of certain ancillary services as
needed by Customer to serve Customer's full requirements for ancillary services.
Ancillary services provided hereunder shall be those generation-based ancillary
services identified in the Open Access Transmission Tariff ("OATT") of the
applicable transmission provider providing the associated transmission and shall
be consistent with such OATT's definition of each identified ancillary service.
Ancillary services shall be delivered in accordance with the same terms and
conditions as required for delivery of such services under the applicable OATT.
2. TERM
Supply and delivery of Power pursuant to the original EPSA began on the Transfer
Date established in the Asset Transfer Agreement dated May 1, 2000 between Genco
and AmerenCIPS. The term of the Amended EPSA shall commence on the effective
date approved by the Federal Energy Regulatory Commission ("FERC") and shall
remain in effect until terminated by either Party upon at least one year's
written notice to the other Party; but in no event shall the EPSA be terminated
prior to 12:00 P.M. CPT on December 31, 2004.
-2-
3. DELIVERY POINTS
All Power supplied under this EPSA that is provided by generation sources
acquired by Genco from AmerenCIPS shall be deemed to be delivered at the bus bar
connecting each such generation source to the AmerenCIPS transmission system
("Delivery Point A"). All Power supplied under this EPSA that is provided by
other generation sources shall be deemed to be delivered at the generation bus
("Delivery Point B;" collectively with Delivery Point A, hereinafter referred to
as "Points of Delivery"). Energy supplied under this EPSA shall be sixty (60)
hertz, three (3) phase alternating current.
4. TRANSMISSION
Genco shall be responsible for making all necessary arrangements for
transmission and delivery of Power to the Points of Delivery identified above,
and for any communication with any transmission provider relating to the
transmission and delivery of Power to such Points of Delivery, including
communications concerning scheduling, tagging, displacements, disputes, or other
operational issues. Marketing shall cooperate with Genco for the purpose of
attaining the necessary transmission service and for implementing the
transmission service required for supplying the Power to the Points of Delivery.
5. METERING
The Parties recognize that certain meters used to measure the amount of energy
supplied by Genco are owned by AmerenCIPS. In order that the accuracy of
registration is maintained in accordance with good utility practice, Marketing
will provide for such metering equipment to be tested by AmerenCIPS at suitable
intervals. At the request of Genco, Marketing shall arrange for special tests to
be performed, but if less than two- percent inaccuracy is found, Genco shall pay
for the test. The expense of all other tests shall be borne by Marketing.
If requested to do so, Marketing shall arrange for representatives of Genco to
be present at all routine or special tests or whenever any readings for the
purposes of settlements are taken from meters not having an automatic record. If
any test of metering equipment discloses an inaccuracy exceeding two percent,
the accounts of the Parties shall be adjusted for the period, not exceeding 90
days, that such inaccuracy is estimated to have existed. Should any metering
equipment fail to register, the amounts of energy delivered and demands
established shall be estimated from the best available data. Meters shall be
adjusted as nearly as practicable to 100.0% at the time of any meter tests, and
Marketing shall furnish a copy of any meter test results when requested by
Genco.
6. SYSTEM PLANNING
In order for Marketing to be able to plan adequately to market and sell all of
the Power available from Genco, Genco shall notify Marketing no later than
November 1 of each year of the amount of Power it expects to have available in
each month of the next calendar year. Marketing shall provide Genco with its
initial annual capacity and energy forecast on or before December 1 for the next
calendar year. Marketing shall notify Genco of its updated capacity and energy
forecast on or before April 1 for the current year.
-3-
7. RECORDS
Marketing shall provide Genco with all records that may reasonably be requested
by Genco for the purpose of administering this EPSA. The Parties shall keep such
records as may be needed to afford a clear history of all transactions under
this Agreement. The originals of all such records shall be retained by each
party for a minimum of three years and copies shall be delivered to the other
Party upon request.
8. PRICES
A. Charges For Capacity and/or Energy Supplied To Customer
-------------------------------------------------------------
(For Sales Other Than Market Price Sales and Other Than For
-------------------------------------------------------------
Sales of Ancillary Services)
-------------------------------------------------------------
1. Capacity Charges
Each calendar year, Company will be compensated at a rate of $69,708/MWyr
("Rate") for the quantity ("Quantity") of capacity supplied, which shall be
equal to the greater of: (1) Customer's highest hourly capacity forecasted for
that year, or (2) Customer's actual annual peak demand ("Peak Demand"); minus
the portion of the forecasted or actual peak demand, as applicable, represented
by Market Price Sales and by sales of ancillary services to third parties
pursuant to Company's ancillary services authorization as may be granted by
FERC. For the purpose of this provision, Customer's forecasted and actual peak
demand shall be adjusted for losses to the extent necessary to be determined at
the Points of Delivery.
Customer shall pay Company monthly for one-twelfth of the applicable annual
capacity charges for each calendar year during the Term hereunder (or a pro rata
share of such annual capacity charges during the year ending December 31, 2000)
based on Customer's forecasted peak demand. Within 10 days after the close of
each calendar year, Company shall calculate the Customer's capacity charges on
the basis of Customer's actual annual peak demand. In the event that Customer's
actual annual peak demand for such year exceeded its forecasted peak demand for
such year, Customer shall pay Company for any additional capacity charges that
are due with respect to such year at the time of payment of its next monthly
bill.
2. Energy Charges
In addition to the capacity charges specified above, Customer shall pay Company
an energy charge of $21.81/MWh for all energy supplied by Company to the Points
of Delivery for sales other than for Market Price Sales and other than for sales
of ancillary services to third parties pursuant to Company's authorizations for
the sale of ancillary services as granted by the FERC.
-4-
B.Charges for Energy and/or Capacity Supplied to Customer for Market Price Sales
------------------------------------------------------------------------------
In addition to the charges for energy and/or capacity supplied to Customer as
set forth above, Customer shall pay Company all amounts received by Customer for
capacity and energy sold as Market Price Sales. Within 15 days following the
close of each calendar month, Customer shall advise Company of the estimated
amount of capacity and energy sold as Market Price Sales for such month and the
average rate per Mwh at which such capacity and/or energy was sold. Payments for
all such capacity and energy supplied to Customer for Market Price Sales shall
be remitted by Customer to Company in the month following the month in which
Customer receives payment for such capacity and energy. Within 45 days following
the close of each calendar month, Customer shall advise Company of the actual
amounts of Market Price Sales for such month, and the subsequent payments from
Customer to Company shall be adjusted accordingly.
C.Charges For Ancillary Services Sold To Third Parties Pursuant to Company's
FERC Authorizations
------------------------------------------------------------------------------
Customer shall pay Company all amounts received by Customer for ancillary
services provided hereunder and resold by Customer pursuant to the
authorizations for the sale of ancillary services granted Company by the FERC.
Within 15 days following the close of each calendar month, Customer shall advise
Company of the estimated amount of such ancillary services resold by Customer
and the amount of total charges Customer received from such resale. Payment of
the total amount received by Customer shall be remitted to Company in the month
following the month in which Customer receives payment for ancillary services
provided hereunder and resold by Customer.
9. REGULATION
The Parties recognize that this EPSA is subject to regulation by the FERC
pursuant to Part II of the Federal Power Act. If the FERC should require the
modification of this EPSA prior to its acceptance, the Parties shall, in good
faith, attempt to reach agreement on modifications that would be acceptable to
the FERC in a manner that retains the economic benefits intended to be derived
by each party under this EPSA.
10. PAYMENT OF BILLS
A. BILLING FOR SERVICE: Bills for Power supplied to Marketing for sales other
than Market Price Sales will be based upon the Quantity of capacity and amount
of energy supplied by Genco at the Points of Delivery as set forth above. Bills
and payment for ancillary services sold by Customer pursuant to Company's FERC
authorization for the sale of ancillary services shall be rendered consistent
with Section 8C of the EPSA. Within 15 days after the close of each calendar
month, the Genco will issue the bill to Marketing electronically (commonly
referred to as "EDI") or other suitable means. If Genco is unable to obtain
meter information or if final Market Price Sales data or final ancillary
services sales data is unavailable, an estimated bill will be issued, computed
on the basis of Marketing's previous use together with such other information as
is available. Once all billing information is considered final, the estimated
bill will be adjusted and any payment due difference will be reflected on the
next scheduled billing.
-5-
B. PAYMENT PERIODS: The last date for payment of the "net amount" shown on the
bill for Power supplied to Marketing for sales other than Market Price Sales and
other than for sales of ancillary services shall be seven days after the date
the bill is issued (hereinafter "Net Payment Period"). Payment of all amounts
for all Power supplied to Marketing for Market Price Sales and for sales of
ancillary services shall be due on the same date. In the event of a disputed
bill Marketing shall pay the undisputed portion within the Net Payment Period.
When the last day of any Net Payment Period falls on a day other than a business
day of Genco, such period will be automatically extended to include the next
following business day. Genco's non-business days shall include Saturdays,
Sundays, and the following holidays: New Year's day, Lincoln's Birthday,
Washington's Birthday, Martin Luther King's Birthday, Good Friday, Memorial Day,
Independence Day, Labor Day, Columbus Day, Veteran's Day, Thanksgiving day,
Friday following Thanksgiving day, Christmas Eve (the last day of regular work
schedule prior to Christmas day), Christmas day and New Year's Eve (the last day
of regular work schedule prior to New Year's day). Whenever a holiday falls on
Sunday the following Monday will not be considered a business day. Whenever a
holiday falls on a Saturday, the prior Friday will not be considered a business
day.
C. PAYMENT AND LATE PAYMENTS: Marketing shall make payment to Genco by wire
transfer, or other acceptable means, within the Net Payment Period in
immediately available U.S. funds. When a bill is paid after the last date for
payment in the "net amount" shown on the bill a late payment charge equivalent
to one and one half (1 1/2) percent will be assessed each month on the unpaid
balance.
11. GOOD UTILITY PRACTICE
Genco shall operate and maintain each of the electric generating units and
appurtenant facilities that are transferred to it by AmerenCIPS or that it
subsequently acquires in good working order in compliance with all requirements
of any governmental agency and in accordance with good utility practice. Insofar
as practicable, Genco shall advise Marketing of any significant change in its
ability to supply Power to Marketing.
12. INDEMNIFICATION
Marketing shall indemnify and save harmless and defend Genco from and against
any and all claims, demands, damages, costs or expenses arising, growing out of
or resulting in any manner from implementation of this EPSA.
-6-
13. FORCE MAJEURE
In the event of Force Majeure, Genco shall notify Marketing immediately by oral
communication, confirmed in writing, of such occurrence, reporting the
commencement time and date, estimated duration, and estimated magnitude of the
reduction in capacity and/or energy deliveries resulting from the Force Majeure
situation. Genco shall not be liable for the failure to deliver the full amount
or any part of the capacity and energy to be supplied pursuant to this EPSA for
the duration of the Force Majeure. For the purpose of this provision, "Force
Majeure" means an event or circumstances which prevents Genco from performing
its obligations under this EPSA, which is not within the reasonable control of
Genco, and which, by exercise of due diligence, Genco is unable to overcome or
avoid or cause to be avoided. Force Majeure includes, but is not restricted to,
fires, strikes, labor stoppages, epidemics, floods, earthquakes, lightening
storms, ice, acts of God, riots, civil disturbances, civil war, invasion,
insurrection, military or usurped power, war, sabotage, explosions, failure of
equipment or of contractors or suppliers of materials or fuel, inability to
obtain or ship material, fuel or equipment because of the effect of similar
causes on suppliers or carriers, or an action or restraint by court order or
public or governmental authority (so long as the Genco has not applied for or
assisted in the application for such court or governmental action). Force
Majeure shall not include Genco's ability to sell capacity and/or energy to
another purchaser at a more advantageous price than that contained in this EPSA.
The settlement of strikes, walkouts, lockouts, and other labor disputes shall be
entirely within the discretion of Genco, and Genco may make settlement at such
time and on such terms and conditions as it may deem to be advisable.
Interruption by a transmission provider shall not be deemed to be an event of
Force Majeure unless (i) Genco shall have made arrangements with such
transmission provider for the firm transmission, as defined under the
transmission provider's Open Access Transmission Tariff, of the energy and (ii)
such interruption is due to "force majeure" or "uncontrollable force" or a
similar term as defined under the transmission provider's Open Access
Transmission Tariff, and (iii) no other path is available and no other remedy is
available.
14. ASSIGNMENT
This EPSA shall inure to the benefit of, and be binding upon, the respective
successors and assigns of Marketing and Genco. No assignment of this EPSA shall
be made by a Party except to a wholly owned subsidiary or successor to
substantially all of that Party's business who assumes possession and operates
substantially the same facilities and business as the assignor. Notwithstanding
the foregoing, either Party shall be free to assign this EPSA to any of its
subsidiaries or affiliates, without the written consent of the other Party. The
assignment by a Party shall not relieve the Party, without the written consent
of the other Party, of any obligation to provide, or to accept and pay for, as
the case may be, the services contracted for hereunder.
15. NOTICES
All notices to be given under this EPSA shall be in writing via First Class U.S.
mail, FAX or e-mail and shall be deemed given when sent. Notices shall be
addressed as set forth below, or to such other address as the party to be
notified may designate from time to time.
-7-
Notice to Genco:
R. Alan Kelley
Senior Vice President
Ameren Energy Generating Company
One Ameren Plaza
1901 Chouteau Avenue
St. Louis, MO 63103
Notice to Marketing:
Andrew M. Serri
Vice President, Marketing and Sales
Ameren Energy Marketing Company
400 S. Fourth Street
St. Louis, MO 63102
16. WRITTEN MODIFICATION
Nothing contained herein shall be construed as affecting in any way the right of
Genco to unilaterally make application to the FERC for a change in rates and
charges under Section 205 of the Federal Power Act and pursuant to the
Commission's Rules and Regulations promulgated thereunder. Except with respect
to rates and charges, this EPSA shall not be modified except in writing by
amendment, executed by both parties, making express reference to the EPSA and
the specific provisions hereof modified or amended.
17. LIMITS OF LIABILITY
IN THE EVENT OF LITIGATION UNDER THIS EPSA, THE PREVAILING PARTY SHALL BE
ENTITLED TO COMPENSATION FOR ANY REASONABLE ATTORNEYS FEES AND OTHER COSTS THAT
MAY BE INCURRED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE
FOR ANY CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST
PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT,
UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT
THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT
REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY
PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR
PASSIVE.
18. DUTY TO MITIGATE
Each Party agrees that it has a duty to mitigate damages and covenants that it
will use commercially reasonable efforts to minimize any damages it may incur as
a result of the other Party's performance or non-performance of this EPSA.
-8-
19. WAIVERS
Any waiver at any time by either Genco or Marketing of its rights with respect
to a default under this EPSA or with respect to any other matter arising in
connection with this EPSA shall not be deemed a waiver with respect to any
subsequent default or matter. Any delay, short of the statutory period of
limitation, in asserting or enforcing any right under this EPSA shall not be
deemed a waiver of such right.
20. ENTIRE AGREEMENT
This EPSA contains the entire agreement between the Parties in respect to the
subject matter contained herein, and there are no other understandings or
agreements between Genco and Marketing in respect thereof.
21. WARRANTIES
The warranties expressly set forth in this EPSA are the sole warranties given by
either Party to the other Party in connection with the sale and purchase of
Power hereunder. EXCEPT AS SET FORTH HEREIN, GENCO EXPRESSLY NEGATES ANY OTHER
REPRESENTATION OR WARRANTY, WRITTEN OR ORAL, EXPRESSED OR IMPLIED, INCLUDING,
WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY WITH RESPECT TO CONFORMITY TO
MODELS OR EXAMPLES, OR MERCHANTABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE.
22. LIMITATION
This EPSA is not intended to and shall not create rights of any character
whatsoever in favor of any person, corporation, association, or entity other
than the parties to this EPSA, and the obligations herein assumed are solely for
the use and benefit of the parties to this EPSA, their successors in interest,
or assigns.
23. SURVIVORSHIP OF OBLIGATIONS
The termination of this EPSA shall not discharge any Party from any obligation
it owed to the other Party under the EPSA by reason of any transaction, loss,
cost, damage, expense or liability which shall occur or arise prior to such
termination. It is the intent of the Parties that any such obligation owed
(whether the same shall be known or unknown as of the termination of this EPSA)
shall survive the termination of this EPSA. The Parties also intend that the
indemnification and limitation of liability provisions contained in this EPSA
shall remain operative and in full force and effect, regardless of any
termination of this EPSA, except with respect to actions or events occurring or
arising after such termination is effective.
-9-
24. GOVERNING LAW
The interpretation and performance of this EPSA shall be in accordance with and
controlled by the laws of the State of Illinois (including any applicable orders
and regulations issued by the ICC), except as to matters governed by federal
statute.
25. SAVINGS CLAUSE
The provisions of this EPSA shall be interpreted where possible in a manner to
sustain their legality and enforcement. If at any time a provision of this EPSA
is found to be unenforceable, such provision shall be removed and the rest of
this EPSA shall remain intact and in effect as if the removed provision was
never contained therein.
26. RESOLUTION OF DISPUTES
If a question or controversy arises between the Parties concerning the
observance or performance of any of the terms, provisions or conditions
contained herein or the rights or obligations of either Party under this EPSA,
such question or controversy shall in the first instance be the subject of a
meeting between the Parties to negotiate a resolution of such dispute. Such
meeting shall be held within fifteen (15) days of a request by either Party. If
within fifteen (15) days after that meeting, the Parties have not negotiated a
resolution or mutually extended the period of negotiation, either Party may seek
resolution of the question or controversy by arbitration, subject, however, to
any prohibition thereto by any governmental law or regulation.
The Party calling for arbitration ("Initiating Party") shall give written notice
to the other Party setting forth (a) a short and plain statement of the issue(s)
to be arbitrated; (b) a short and plain statement of the claim showing that the
Initiating Party is entitled to relief; and (c) a statement of the relief to
which the Initiating Party claims to be entitled. Such written notice including
sections (a), (b) and (c) defined above shall not exceed a document length of 20
pages, double spaced utilizing a font of 12. Within twenty (20) days from the
date of receipt of such notice, the other Party ("Receiving Party") may submit
its written response and give notice in the same manner required above of
additional issues to be arbitrated. The Initiating Party shall have twenty (20)
days to respond to any issues submitted for arbitration by the Receiving Party.
Within thirty (30) days of the date of the Initiating Party's written notice
requesting arbitration, each party shall designate a competent and disinterested
person to act as that party's designated arbitrator, with the two (2) persons
designated selecting a third neutral arbitrator within twenty (20) days of their
designation. In the event the first two (2) arbitrators cannot agree on a
mutually acceptable third arbitrator, they shall apply to the American
Arbitration Association ("AAA") to appoint the third arbitrator. The arbitration
shall be conducted pursuant to the Federal Rules of Civil Procedure, the Federal
Rules of Evidence, and the Commercial Arbitration Rules of the AAA.
Any decision and award of the majority of arbitrators shall be binding upon both
parties. The arbitrators shall not award any indirect, special, incidental or
consequential damages against either party. Judgment upon the award rendered may
be entered in any court of competent jurisdiction.
-10-
27. HEADINGS
The descriptive headings of the sections of this EPSA have been inserted for
convenience of reference only and shall not modify or restrict any of the terms
and provisions thereof.
IN WITNESS WHEREOF, the Parties hereto have caused this Amended EPSA to be
executed in duplicate, by its authorized officers, day and year first above
written.
AMEREN ENERGY AMEREN ENERGY
MARKETING COMPANY GENERATING COMPANY
By _/s/ Andrew M. Serri ______________ By /s/ Gary L. Rainwater
-------------------- ----------------------------------------
(Company Officer Signature) (Customer Officer Signature)
Andrew M. Serri Gary L. Rainwater
- ------------------------------------------ -----------------------------------------
(Printed Name) (Printed Name)
Vice President of Sales and Marketing President
- ------------------------------------------ -----------------------------------------
(Title) (Title)
-11-
Exhibit 10.2
ELECTRIC POWER SUPPLY AGREEMENT
Between Ameren Energy Marketing Company
And
Central Illinois Public Service Company
THIS ELECTRIC POWER SUPPLY AGREEMENT (hereinafter "EPSA") made as of this 1st
day of December, 1999, and as amended this 30th day of March, 2001, by and
between AMEREN ENERGY MARKETING COMPANY, (hereinafter "Company") and CENTRAL
ILLINOIS PUBLIC SERVICE COMPANY, d.b.a. AmerenCIPS (hereinafter "Customer")
(Company and Customer may be identified collectively as "Parties" or
individually as a "Party") is for the supply by Company of all electric power
and energy, including ancillary services, needed to meet the Customer's full
requirements for electric power and energy.
WHEREAS, Company is engaged in the business of purchasing and reselling electric
power and energy; and
WHEREAS, Customer, which is an electric public utility in Illinois, has
restructured its operations in response to and in accordance with the Illinois
Electric Service Customer Choice and Rate Relief Law of 1997 (the "Customer
Choice Law") by transferring all of its existing generating facilities to a
newly-formed generation-company affiliate ("Ameren Energy Generating Company" or
"Genco"); and
WHEREAS, Company has entered into an agreement to purchase from Genco all of the
capacity and energy available from the generating units that were transferred by
Customer to Genco and any additional generating units that may be acquired by
Genco in the future; and
WHEREAS, Customer is required by the Customer Choice Law to continue to offer
bundled retail electric service within its existing retail electric service area
in Illinois at rates specified by the Illinois Commerce Commission ("ICC")
through December 31, 2004; and
WHEREAS, Customer may continue to make bundled sales of electricity to existing
wholesale electric service customers; and
WHEREAS, Customer is also obligated by the Customer Choice Law to offer retail
electric service to customers in Illinois under unbundled, market-priced tariffs
on file with the ICC and may also sell power to others at market-based rates
("Market Price Sales") through December 31, 2004; and
-1-
WHEREAS, a portion of the capacity and energy supplied by Company to Customer
shall be provided in the form of certain ancillary services to fulfill
Customer's generation-based ancillary service requirements in support of its
bundled sales and resales to Customer's transmission customers under the Ameren
Open Access Transmission, or any successor tariff thereof ("Ameren OATT"); and
WHEREAS, Customer desires to acquire from Company all the electric power and
energy that is needed to enable it to provide electric service after the
transfer of its generating units; and
WHEREAS, Company is capable of supplying all such power and energy to Customer
and desires to do so pursuant to the rates, terms and conditions set forth
herein;
NOW THEREFORE, in consideration for the agreements and undertakings established
herein and the mutual benefits derived therefrom, it is agreed as follows:
1. GENERATION SERVICES
A. Firm Electric Power And Energy Services
-----------------------------------------
Company will supply and deliver to Customer all of the firm electric capacity
and energy (hereinafter "Energy") needed by Customer to serve its native load,
to operate its transmission and distribution system and to provide transmission
and distribution services, to fulfill its obligations under all applicable
federal and state tariffs or contracts, to satisfy regional reliability
requirements, and for any other purpose related to the provision of wholesale or
retail electric service and Customer shall purchase and pay for such Energy in
accordance with the terms of this Agreement.
B. Ancillary Services
Consistent with subsection 1.A above, a portion of the capacity and energy made
available to Customer under this EPSA shall be in the form of certain
generation-based ancillary services as needed by Customer to serve its native
load, to operate its transmission and distribution system and to provide
transmission and distribution services, to fulfill its obligations under all
applicable federal and state tariffs or contracts, and to satisfy regional
reliability requirements. Such ancillary services shall include Reactive Supply
and Voltage Control from Generation Sources Service, Regulation and Frequency
Response Service, Energy Imbalance Service and Retail Energy Imbalance Service,
Operating Reserve - Spinning Reserve Service, Operating Reserve - Supplemental
Reserve Service, and Loss Compensation Service, and shall be delivered in
accordance with the same terms and conditions as required for delivery of such
services under the Ameren OATT. Customer shall purchase and pay for such
ancillary services in accordance with the terms of this Agreement.
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2. TERM
Subject to acceptance of this EPSA by the Federal Energy Regulatory Commission
("FERC"), supply and delivery of Energy pursuant to the EPSA shall begin on the
Transfer Date established in the "Asset Transfer Agreement" dated May 1, 2000
between Customer and Genco and terminate at 12:00 P.M. CPT on December 31, 2004.
3. DELIVERY POINTS
All Energy supplied under this EPSA that is provided by generation sources
acquired by Genco from Customer shall be deemed to be delivered at the bus bar
connecting each such generation source to the Customer's transmission system.
All Energy supplied under this EPSA that is provided by other generation sources
shall be deemed to be delivered at the point of interconnection between
Customer's transmission system and the transmission system over which the Energy
is being delivered. Energy supplied under this EPSA shall be sixty (60) hertz,
three (3) phase alternating current.
4. TRANSMISSION
Transmission of Energy to Customer shall be firm transmission as such is defined
in the transmission provider's Open Access Transmission Tariff. Company shall be
responsible for making all necessary transmission arrangements for transmission
of Energy to the Points of Delivery identified above from sources not directly
interconnected to the Ameren transmission system, and for any communication with
any transmission provider relating to the transmission and delivery of Energy to
Customer, including communications concerning scheduling, tagging,
displacements, disputes, or other operational issues. Customer shall cooperate
with Company for the purpose of attaining the necessary firm transmission
service and for implementing the transmission service required for supplying the
Energy to the Points of Delivery.
5. METERING
The Parties recognize that certain meters used to measure the amount of Energy
received by Customer are owned by Customer. In order that the accuracy of
registration is maintained in accordance with good utility practice, metering
equipment shall be tested by Customer at suitable intervals. At the request of
Company, special tests shall be performed, but if less than two percent
inaccuracy is found, Company shall pay for the test. The expense of all other
tests shall be borne by Customer.
Representatives of each Party may be present at all routine or special tests or
whenever any readings for the purposes of settlements are taken from meters not
having an automatic record. If any test of metering equipment discloses an
inaccuracy exceeding two percent, the accounts of the Parties shall be adjusted
for the period, not exceeding 90 days, that such inaccuracy is estimated to have
existed. Should any metering equipment fail to register, the amounts of Energy
delivered and demands established shall be estimated from the best available
data. Meters shall be adjusted as nearly as practicable to 100.0% at the time of
any meter tests, and Customer shall furnish a copy of any meter test results
when requested by Company.
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6. SYSTEM PLANNING
In order for Company to plan adequately for Customer's Energy requirements,
Customer shall notify Company no later than November 1 of each year of its
annual load plan for the next calendar year during the Term. Such annual load
plan shall be consistent with the forecasted peak demand reported to the
Mid-American Interconnected Network ("MAIN") for such year. Customer shall also
provide to Company an update to its annual load plan on or before March 1 of
each year during the Term.
7. RECORDS
Customer shall provide Company with all records that may reasonably be requested
by Company for the purpose of administering this EPSA. The Parties shall keep
such records as may be needed to afford a clear history of all transactions
under this Agreement. The originals of all such records shall be retained by
each party for a minimum of three years and copies shall be delivered to the
other Party upon request.
8. PRICES
A. Charges For Energy Supplied To Customer (For Sales Other Than Market Price Sales And Other
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Than For Sales of Ancillary Services under the Ameren OATT)
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1. Capacity Charges
Each calendar year, Company will be entitled to be compensated at a rate of
$69,708/MW/Yr. for the quantity ("Quantity") of capacity supplied, which shall
be equal to the greater of: (1) Customer's forecasted peak demand reported to
MAIN for that year, or (2) Customer's actual annual peak demand ("Peak Demand");
minus the portion of the forecasted or actual peak demand, as applicable,
represented by Market Price Sales and by sales of ancillary services pursuant to
the Ameren OATT. For the purpose of this provision, Customer's forecasted peak
demand and actual annual peak demand shall be adjusted for losses to the extent
necessary to be determined at the Points of Delivery.
Customer shall pay Company monthly for one-twelfth of the applicable annual
capacity charges for each calendar year during the Term (or a pro rata share of
such annual capacity charges during the year ending December 31, 2000) based on
Customer's forecasted peak demand for such year as reported to MAIN. Within 10
days after the close of each calendar year, Company shall calculate the
Customer's capacity charges on the basis of Customer's actual annual peak
demand. In the event that Customer's actual annual peak demand for such year
exceeded its forecasted peak demand that had been reported to MAIN for such
year, Customer shall pay Company for any additional capacity charges that are
due with respect to such year at the time of payment of its next monthly bill.
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2. Energy Charges
In addition to the capacity charges specified above, Customer shall pay Company
an energy charge of $21.81/Mwh for all energy supplied by Company to the Points
of Delivery for sale other than as Market Price Sales and other than for sales
of ancillary services pursuant to the Ameren OATT.
B. Charges For Energy Supplied To Customer For Market Price Sales
In addition to the charges for Energy supplied to Customer as set forth above,
Customer shall pay Company an amount equal to the amount Customer receives from
retail customers for power and energy sold as Market Price Sales. Within 15 days
following the close of each calendar month, Customer shall advise Company of the
estimated amount of power and energy sold as Market Price Sales for such month
and the average rate per Mwh at which such power and energy was sold. Payments
for all Energy supplied to Customer for Market Price Sales shall be remitted by
Customer to Company in the month following the month in which Customer receives
payment for such Energy. Within 45 days following the close of each calendar
month, Customer shall advise Company of the actual amounts of Market Price Sales
for such month, and the subsequent payments from Customer to Company shall be
adjusted accordingly.
C. Charges For Ancillary Services for Ameren OATT Transactions
Customer shall pay Company all amounts received by Customer for ancillary
services provided hereunder and resold by Customer pursuant to the Ameren OATT.
Within 15 days following the close of each calendar month, Customer shall advise
Company of the estimated amount of such ancillary services resold by Customer
and the amount of total charges Customer received from such resale. Payment of
the total amount received by Customer shall be remitted to Company in the month
following the month in which Customer receives payment for such ancillary
services provided hereunder and resold by Customer.
9. REGULATION
The parties recognize that this EPSA is subject to regulation by the FERC
pursuant to Part II of the Federal Power Act. If the FERC should require the
modification of this EPSA prior to its acceptance, the parties shall, in good
faith, attempt to reach agreement on modifications that would be acceptable to
the FERC in a manner that retains the economic benefits intended to be derived
by each party under this EPSA.
10. ACCESS
Customer shall provide, at no cost to Company, a suitable place (including means
of support) on and access to Customer's property for Company to install,
maintain, operate, repair, replace, and remove all equipment and facilities
necessary for Company to perform its obligations under this EPSA. Customer shall
use reasonable diligence to protect all of Company's equipment located on
Customer's property.
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11. PAYMENT OF BILLS
A. BILLING FOR SERVICE: Bills for Energy supplied to Customer for sales other
than Market Price Sales will be based upon the Quantity of capacity and amount
of energy supplied by Company at the Points of Delivery. Bills and payment for
ancillary services shall be rendered consistent with Section 8C of the EPSA.
Within 15 days after the close of each calendar month, the Company will issue
the bill to Customer electronically (commonly referred to as "EDI"), or other
suitable means. If the Company is unable to obtain meter information, or if
final Market Price Sales data or ancillary services data is unavailable, an
estimated bill will be issued, computed on the basis of Customer's previous use
together with such other information as is available. Once all billing
information is considered final, the estimated bill will be adjusted and any
payment due difference will be reflected on the next scheduled billing.
B. PAYMENT PERIODS: The last date for payment of the "net amount" shown on the
bill for Energy supplied to Customer for sales other than Market Price Sales and
for ancillary services shall be seven days after the date the bill is issued
(hereinafter "Net Payment Period"). Payment of all amounts for all Energy
supplied to Customer for Market Price Sales and sales of ancillary services
shall be due on the same date. In the event of a disputed bill Customer shall
pay the undisputed portion within the Net Payment Period. When the last day of
any Net Payment Period falls on a day other than a business day of Company, such
period will be automatically extended to include the next following business
day. Other than a business day of Company shall include Saturdays, Sundays, and
the following holidays: New Year's day, Lincoln's Birthday, Washington's
Birthday, Martin Luther King's Birthday, Good Friday, Memorial Day, Independence
Day, Labor Day, Columbus Day, Veteran's Day, Thanksgiving day, Friday following
Thanksgiving day, Christmas Eve (the last day of regular work schedule prior to
Christmas day), Christmas day and New Year's Eve (the last day of regular work
schedule prior to New Year's day). Whenever a holiday falls on Sunday the
following Monday will not be considered a business day. Whenever a holiday falls
on a Saturday, the prior Friday will not be considered a business day.
C. PAYMENT AND LATE PAYMENTS: Customer shall make payment to Company by wire
transfer, or other acceptable means, within the Net Payment Period in
immediately available U.S. funds. When a bill is paid after the last date for
payment in the "net amount" shown on the bill a late payment charge equivalent
to one and one half (1 1/2) percent will be assessed each month on the unpaid
balance.
12. INDEMNIFICATION
Customer shall indemnify and save harmless and defend Company from and against
any and all claims, demands, damages, costs or expenses arising, growing out of
or resulting in any manner after delivery of Energy to Customer or from improper
or negligent construction, installation, insulation, maintenance or operation of
Customer's lines and appurtenances.
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13. FORCE MAJEURE
In the event of Force Majeure, Company shall notify Customer immediately by oral
communication, confirmed in writing, of such occurrence, reporting the
commencement time and date, estimated duration, and estimated magnitude of the
reduction in Energy deliveries resulting from the Force Majeure situation.
Company shall not be liable for the failure to deliver the full amount or any
part of the Energy to be supplied pursuant to this EPSA for the duration of the
Force Majeure. For the purpose of this provision, "Force Majeure" means an event
or circumstances which prevents Company from performing its obligations under
this EPSA, which is not within the reasonable control of the Company, and which,
by exercise of due diligence, the Company is unable to overcome or avoid or
cause to be avoided. Force Majeure includes, but is not restricted to, fires,
strikes, labor stoppages, epidemics, floods, earthquakes, lightening storms,
ice, acts of God, riots, civil disturbances, civil war, invasion, insurrection,
military or usurped power, war, sabotage, explosions, failure of equipment or of
contractors or suppliers of materials or fuel, inability to obtain or ship
material, fuel or equipment because of the effect of similar causes on suppliers
or carriers, or an action or restraint by court order or public or governmental
authority (so long as the Company has not applied for or assisted in the
application for such court or governmental action). Force Majeure shall not
include Company's ability to sell Energy to another purchaser at a more
advantageous price than that contained in this EPSA. The settlement of strikes,
walkouts, lockouts, and other labor disputes shall be entirely within the
discretion of the Company, and Company may make settlement at such time and on
such terms and conditions as it may deem to be advisable. Interruption by a
transmission provider shall not be deemed to be an event of Force Majeure unless
(i) Company shall have made arrangements with such transmission provider for the
firm transmission, as defined under the transmission provider's Open Access
Transmission Tariff, of the Energy and (ii) such interruption is due to "force
majeure" or "uncontrollable force" or a similar term as defined under the
transmission provider's Open Access Transmission Tariff, and (iii) no other path
is available and no other remedy is available.
14. ASSIGNMENT
This EPSA shall inure to the benefit of, and be binding upon, the respective
successors and assigns of Customer and Company. No assignment of this EPSA shall
be made by a Party except to a wholly owned subsidiary or successor to
substantially all of that Party's business who assumes possession and operates
substantially the same facilities and business as the assignor. Notwithstanding
the foregoing, either Party shall be free to assign this EPSA to any of its
subsidiaries or affiliates, without the written consent of the other Party. The
assignment by a Party shall not relieve the Party, without the written consent
of the other Party, of any obligation to provide, or to accept and pay for, as
the case may be, the services contracted for hereunder.
15. NOTICES
All notices to be given under this EPSA shall be in writing via First Class U.S.
mail, FAX or e-mail and shall be deemed given when sent. Notices shall be
addressed as set forth below, or to such other address as the party to be
notified may designate from time to time.
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Notice to Company:
Andrew M. Serri
Vice President of Sales and Marketing
Ameren Energy Marketing Company
400 S. Fourth Street
St. Louis, MO 63102
Notice to Customer:
Thomas R. Voss
Senior Vice President, Customer Services
AmerenCIPS
One Ameren Plaza
1901 Chouteau Avenue
St. Louis, MO 63103
16. WRITTEN MODIFICATION
The rates for service specified herein shall remain in effect for all Energy
supplied by Company through December 31, 2004, and shall not be subject to
change through application to the FERC pursuant to the provisions of Section 205
of the Federal Power Act prior to that time absent the agreement of the Parties.
This EPSA shall not be modified except in writing by amendment, executed by both
parties, making express reference to the EPSA and the specific provisions hereof
modified or amended.
17. LIMITS OF LIABILITY
IN THE EVENT OF LITIGATION UNDER THIS EPSA, THE PREVAILING PARTY SHALL BE
ENTITLED TO COMPENSATION FOR ANY REASONABLE ATTORNEYS FEES AND OTHER COSTS THAT
MAY BE INCURRED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE
FOR ANY CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST
PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT,
UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT
THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT
REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY
PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR
PASSIVE.
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18. DUTY TO MITIGATE
Each Party agrees that it has a duty to mitigate damages and covenants that it
will use commercially reasonable efforts to minimize any damages it may incur as
a result of the other Party's performance or non-performance of this EPSA.
19. WAIVERS
Any waiver at any time by either Company or Customer of its rights with respect
to a default under this EPSA or with respect to any other matter arising in
connection with this EPSA shall not be deemed a waiver with respect to any
subsequent default or matter. Any delay, short of the statutory period of
limitation, in asserting or enforcing any right under this EPSA shall not be
deemed a waiver of such right.
20. ENTIRE AGREEMENT
This EPSA contains the entire agreement between the Parties in respect to the
subject matter contained herein, and there are no other understandings or
agreements between Company and Customer in respect thereof.
21. WARRANTIES
The warranties expressly set forth in this EPSA are the sole warranties given by
either Party to the other Party in connection with the sale and purchase of
Energy hereunder. EXCEPT AS SET FORTH HEREIN, COMPANY EXPRESSLY NEGATES ANY
OTHER REPRESENTATION OR WARRANTY, WRITTEN OR ORAL, EXPRESSED OR IMPLIED,
INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY WITH RESPECT TO
CONFORMITY TO MODELS OR EXAMPLES, OR MERCHANTABILITY OR FITNESS FOR ANY
PARTICULAR PURPOSE.
22. LIMITATION
This EPSA is not intended to and shall not create rights of any character
whatsoever in favor of any person, corporation, association, or entity other
than the parties to this EPSA, and the obligations herein assumed are solely for
the use and benefit of the parties to this EPSA, their successors in interest,
or assigns.
23. SURVIVORSHIP OF OBLIGATIONS
The termination of this EPSA shall not discharge any Party from any obligation
it owed to the other Party under the EPSA by reason of any transaction, loss,
cost, damage, expense or liability which shall occur or arise prior to such
termination. It is the intent of the Parties that any such obligation owed
(whether the same shall be known or unknown as of the termination of this EPSA)
shall survive the termination of this EPSA. The Parties also intend that the
indemnification and limitation of liability provisions contained in this EPSA
shall remain operative and in full force and effect, regardless of any
termination of this EPSA, except with respect to actions or events occurring or
arising after such termination is effective.
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24. GOVERNING LAW
The interpretation and performance of this EPSA shall be in accordance with and
controlled by the laws of the State of Illinois (including any applicable orders
and regulations issued by the ICC), except as to matters governed by federal
statute.
25. SAVING CLAUSE
The provisions of this EPSA shall be interpreted where possible in a manner to
sustain their legality and enforcement. If at any time a provision of this EPSA
is found to be unenforceable, such provision shall be removed and the rest of
this EPSA shall remain intact and in effect as if the removed provision was
never contained therein.
26. RESOLUTION OF DISPUTES
If a question or controversy arises between the Parties concerning the
observance or performance of any of the terms, provisions or conditions
contained herein or the rights or obligations of either Party under this EPSA,
such question or controversy shall in the first instance be the subject of a
meeting between the Parties to negotiate a resolution of such dispute. Such
meeting shall be held within fifteen (15) days of a request by either Party. If
within fifteen (15) days after that meeting, the Parties have not negotiated a
resolution or mutually extended the period of negotiation, either Party may seek
resolution of the question or controversy by arbitration, subject, however, to
any prohibition thereto by any governmental law or regulation.
The Party calling for arbitration ("Initiating Party") shall give written notice
to the other Party setting forth (a) a short and plain statement of the issue(s)
to be arbitrated; (b) a short and plain statement of the claim showing that the
Initiating Party is entitled to relief; and (c) a statement of the relief to
which the Initiating Party claims to be entitled. Such written notice including
sections (a), (b) and (c) defined above shall not exceed a document length of 20
pages, double spaced utilizing a font of 12. Within twenty (20) days from the
date of receipt of such notice, the other Party ("Receiving Party") may submit
its written response and give notice in the same manner required above of
additional issues to be arbitrated. The Initiating Party shall have twenty (20)
days to respond to any issues submitted for arbitration by the Receiving Party.
Within thirty (30) days of the date of the Initiating Party's written notice
requesting arbitration, each party shall designate a competent and disinterested
person to act as that party's designated arbitrator, with the two (2) persons
designated selecting a third neutral arbitrator within twenty (20) days of their
designation. In the event the first two- (2) arbitrators cannot agree on a
mutually acceptable third arbitrator, they shall apply to the American
Arbitration Association ("AAA") to appoint the third arbitrator. The arbitration
shall be conducted pursuant to the Federal Rules of Civil Procedure, the Federal
Rules of Evidence, and the Commercial Arbitration Rules of the AAA.
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Any decision and award of the majority of arbitrators shall be binding upon both
parties. The arbitrators shall not award any indirect, special, incidental or
consequential damages against either party. Judgment upon the award rendered may
be entered in any court of competent jurisdiction.
27. HEADINGS
The descriptive headings of the sections of this EPSA have been inserted for
convenience of reference only and shall not modify or restrict any of the terms
and provisions thereof.
IN WITNESS WHEREOF, the Parties hereto have caused this EPSA to be executed in
duplicate, by its authorized officers, day and year first above written.
AMEREN ENERGY MARKETING CENTRAL ILLINOIS PUBLIC
COMPANY SERVICE COMPANY
By _/s/ Andrew M. Serri____________ By /s/ Thomas R. Voss
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(Company Officer Signature) (Customer Officer Signature)
Andrew M. Serri Thomas R. Voss
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(Printed Name) (Printed Name)
Vice President of Sales Senior Vice President,
and Marketing Customer Services
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(Title) (Title)
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