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 June 30, 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 1-2967.
UNION ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Missouri 43-0559760
(State or other jurisdiction (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) 621-3222
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 .
------------ --------------
Shares outstanding of each of registrant's classes of common stock as of August
14, 2001: Common Stock, $5 par value, held by Ameren Corporation (parent
company of Registrant) - 102,123,834
Union Electric Company
Index
Page No.
Part I Financial Information
Item 1. Financial Statements (Unaudited)
Balance Sheet
- June 30, 2001 and December 31, 2000 10
Statement of Income
- Three months, six months and 12 months ended
June 30, 2001 and 2000 11
Statement of Cash Flows
- Six months ended June 30, 2001 and 2000 12
Statement of Common Stockholder's Equity
- Six months ended June 30, 2001 and
12 months ended December 31, 2000 13
Notes to Financial Statements 14
Item 2. Management's Discussion and Analysis of 2
Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 8
Part II Other Information
Item 4. Submission of Matters to a Vote of Security
Holders 19
Item 5. Other Information 19
Item 6. Exhibits and Reports on Form 8-K 19
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED).
The unaudited financial statements of Union Electric Company (AmerenUE or the
Registrant) appear on pages 10 through 18 of this report.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
OVERVIEW
The Registrant is a subsidiary of Ameren Corporation (Ameren), a holding company
registered under the Public Utility Holding Company Act of 1935 (PUHCA). Both
Ameren and its subsidiaries are subject to the regulatory provisions of the
PUHCA. The Registrant is a public utility operating company engaged principally
in the generation, transmission, distribution and sale of electric energy and
the purchase, distribution, transportation and sale of natural gas in the states
of Missouri and Illinois. The Registrant serves 1.2 million electric and 125,000
gas customers in a 24,500 square-mile area of Missouri and Illinois, including
Metropolitan St. Louis.
The Registrant's financial statements include charges for services that Ameren
Services Company (Ameren Services), a wholly owned subsidiary of Ameren,
provides to the Registrant. Ameren Services provides shared support services for
all Ameren companies. Charges are based upon the actual costs incurred by Ameren
Services, as required by PUHCA.
The following discussion and analysis should be read in conjunction with the
Notes to the Financial Statements beginning on page 14, and the Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A),
the Audited Financial Statements, and the Notes to the Financial Statements
appearing in the Registrant's 2000 Form 10-K.
RESULTS OF OPERATIONS
Earnings
Second quarter 2001 earnings of $80 million decreased $4 million compared to
2000 second quarter earnings. Earnings for the six months ended June 30, 2001,
decreased $5 million from the year ago period to $116 million. Earnings for the
12 months ended June 30, 2001 were $339 million, a $13 million decrease from the
preceding 12-month period. Earnings 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), 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, six-month and 12-month periods ended June 30, 2001 and 2000 are
detailed on the following pages.
Electric Operations
Electric Operating Revenues Variations for periods ended June 30, 2001
from comparable prior-year periods
- ------------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Three Months Six Months Twelve Months
------------ ---------- -------------
- ------------------------------------------------------------------------------------------------------------------------
Credit to electric customers $ 30 $ 25 $ (7)
Effect of abnormal weather 16 38 61
Growth and other 13 12 20
Interchange sales 42 103 140
- ------------------------------------------------------------------------------------------------------------------------
$ 101 $ 178 $ 214
- ------------------------------------------------------------------------------------------------------------------------
The $101 million increase in second quarter electric revenues compared to the
year-ago quarter was primarily driven by an 8 percent increase in total
kilowatthour sales. Residential, commercial and interchange sales increased 8
percent, 10 percent and 23 percent, respectively. These increases were partially
offset by decreases in industrial and
2
wholesale sales. The increase in revenues was also attributed to a reduction in
the estimated credits to Missouri electric customers (see Note 2 under Notes to
Financial Statements for further information).
Electric revenues for the first six months of 2001 increased $178 million
compared to the same 2000 period primarily due to a 10 percent increase in total
kilowatthour sales. Interchange sales increased 24 percent, while residential
and commercial sales each increased 9 percent. These increases were partially
offset by a decrease in wholesale sales. The increase in revenues was also
attributed to a reduction in the estimated credits to Missouri electric
customers (see Note 2 under Notes to Financial Statements for further
information).
Electric revenues for the 12 months ended June 30, 2001 increased $214 million
compared to the prior 12-month period. The increase in revenues was primarily
due to a 36 percent increase in interchange sales, coupled with increases of 10
percent and 6 percent in residential and commercial sales, respectively.
Fuel and Purchased Power Variations for periods ended June 30, 2001
from comparable prior-year periods
- ----------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) Three Months Six Months Twelve Months
------------ ---------- -------------
- ----------------------------------------------------------------------------------------------------------------------
Fuel:
Generation $ (9) $ (4) $ 24
Price 7 11 (3)
Generation efficiencies and other (1) (2) (3)
Purchased power variation 85 124 121
- ----------------------------------------------------------------------------------------------------------------------
$ 82 $ 129 $ 139
- ----------------------------------------------------------------------------------------------------------------------
The increase in fuel and purchased power costs for the three-month, six-month
and 12-month periods ended June 30, 2001 compared to the year ago comparable
periods, was primarily due to increased purchased power resulting from higher
sales volumes and the Callaway Nuclear Plant refueling, which occurred in the
second quarter of 2001.
Gas Operations
Gas revenues for the six months and 12 months ended June 30, 2001 increased $27
million and $62 million, respectively, compared to the prior-year periods
primarily due to increases in retail sales resulting from a return to more
normal weather conditions, as compared to the same year ago periods, and higher
gas costs recovered from customers through the Registrant's purchased gas
adjustment clauses.
Gas costs for the six months and 12 months ended June 30, 2001 increased $25
million and $50 million, respectively, compared to the year-ago periods,
primarily due to higher sales and gas prices.
Other Operating Expenses
Other operating expense variations reflected recurring factors such as growth,
inflation, labor and employee benefit cost increases and plant maintenance
outages.
Other operations expenses for the three, six and 12 months ended June 30, 2001
increased $12 million, $37 million and $91 million, respectively, compared to
the same year-ago periods primarily due to higher employee benefit costs due to
changes in actuarial assumptions and investment performance of employee benefit
plans' assets, increases in professional services and automated meter reading
services.
Maintenance expenses for the three, six and 12 months ended June 30, 2001
increased $20 million, $26 million and $15 million, respectively, compared to
the same year-ago periods primarily due to a refueling outage at the
Registrant's Callaway Nuclear Plant during the second quarter of 2001. The
spring 2001 refueling was completed in 45 days. There was no refueling in 2000.
Depreciation and amortization expense for the six months and 12 months ended
June 30, 2001 increased $4 million and $9 million, respectively, compared to the
prior year periods due to an increase in depreciable property.
Taxes
Income taxes decreased $13 million, $10 million and $23 million, for the three,
six and 12 months ended June 30, 2001, respectively, due to lower pretax income.
3
Other tax expense increased $5 million for the six months ended June 30, 2001
primarily due to increases in gross receipts tax resulting from increases in
electric sales, compared to the year-ago period.
Other tax expense increased $12 million for the 12 months ended June 30, 2001
due to increases in gross receipts tax and increased property tax assessments in
the state of Missouri.
Other Income and Deductions
Miscellaneous, net increased $5 million for the 12 months ended June 30, 2001,
compared to the year-ago period primarily due to prior period write-offs of
certain nonregulated investments.
Interest Expense
Interest expense for the three months and six months ended June 30, 2001
decreased $4 million and $6 million, respectively, due to decreases in the
nuclear fuel lease and commercial paper balances.
Balance Sheet
The $79 million decrease in intercompany notes receivable at June 30, 2001,
compared to December 31, 2000, reflects changes in funds invested in a regulated
money pool (see "Liquidity and Capital Resources" below and Note 3 under Notes
to Financial Statements for further information).
Changes in accounts and wages payable and taxes accrued resulted from the timing
of various payments to taxing authorities and suppliers, including Ameren
Services.
The decrease in other current liabilities of $44 million is primarily due to the
reduction in the estimated credit that the Registrant expects to pay its
Missouri electric customers (see Note 2 under Notes to Financial Statements for
further information).
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $226 million for the six months
ended June 30, 2001, compared to $161 million during the same 2000 period.
Cash flows used in investing activities totaled $179 million and $171 million
for the six months ended June 30, 2001 and 2000, respectively. Construction
expenditures for the six months ended June 30, 2001, for constructing new or
improving existing facilities were $252 million. In addition, the Registrant
expended $13 million for the acquisition of nuclear fuel. The Registrant has
made commitments to purchase four combustion turbine generating units totaling
192 megawatts to be located in Missouri and a 50 megawatt unit to be located at
the Venice, Illinois plant that are expected to be operational by summer 2002.
The cost of those units is approximately $125 million.
Cash flows used in financing activities totaled $61 million for the six months
ended June 30, 2001, compared to $106 million during the same 2000 period. The
Registrant's principal financing activities for the period included the issuance
and redemption of long-term debt and the payment of dividends.
The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant is authorized by the
Securities and Exchange Commission (SEC) under PUHCA to have up to $1 billion of
short-term unsecured debt instruments outstanding at any one time. Short-term
borrowings consist of bank loans (maturities generally on an overnight basis)
and commercial paper (maturities generally within 1 to 45 days). At June 30,
2001, the Registrant had committed bank lines of credit aggregating $151 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. At June 30, 2001, the Registrant
had no outstanding short-term borrowings.
The Registrant also has a bank credit agreement due 2002 which permits the
borrowing of up to $300 million on a long-term basis, all of which was unused,
and $135 million was available at June 30, 2001. In addition, the Registrant has
the ability to borrow up to approximately $488 million from Ameren or from two
of Ameren's other subsidiaries, Central Illinois Public Service Company
(AmerenCIPS) and Ameren Services, through a regulated money pool agreement. The
total amount available to the Registrant at any given time from the regulated
money pool is reduced by the amount of borrowings by AmerenCIPS or Ameren
Services but increased to the extent AmerenCIPS or Ameren Services have surplus
funds and the availability of other external borrowing sources. The
4
regulated money pool was established to coordinate and provide for certain
short-term cash and working capital requirements of the Registrant, AmerenCIPS
and Ameren Services and is administered by Ameren Services. Interest is
calculated at varying rates of interest depending on the composition of internal
and external funds in the regulated money pool. For the three months and six
months ended June 30, 2001, the average interest rate for the regulated money
pool was 4.38 percent and 4.94 percent, respectively. As of June 30, 2001, the
Registrant had loaned $177 million to the regulated money pool and at least $104
million was available through the regulated money pool subject to reduction for
borrowings by AmerenCIPS or Ameren Services.
Additionally, the Registrant has a lease agreement that provides for the
financing of nuclear fuel. At June 30, 2001, the maximum amount that could be
financed under the agreement was $120 million. Cash used in financing activities
for the six months ended June 30, 2001, included redemptions under the lease for
nuclear fuel of $64 million, offset by $3 million of issuances. At June 30,
2001, $53 million was financed under the lease.
During the course of Ameren's resource planning, several alternatives, in
addition to the Missouri and Venice plant capacity additions described above,
are being considered to satisfy anticipated regulatory load requirements for
2001 and beyond for the Registrant, AmerenCIPS and AmerenEnergy Resources
Company (Resources Company), the Ameren subsidiary which holds its nonregulated
generation operations. The Registrant has purchased 500 megawatts of capacity
and energy for the summer of 2001 (450 megawatts from AmerenEnergy Marketing
Company (Marketing Company), a subsidiary of Resources Company). Alternatives
being considered for the summer of 2002 and beyond include the purchase of
capacity and energy, among other things. The Registrant is reviewing three
combustion turbine generating units, which had been planned for commercial
operation in 2004 and 2005 by Resources Company, to determine if they can be
used by the Registrant instead of Resources Company, in order to fulfill the
Registrant's generating capacity needs. 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.
In May 2001, the Missouri Public Service Commission (MoPSC) filed pleadings with
the Federal Energy Regulatory Commission (FERC) and the SEC relating to the
Registrant's agreement to purchase 450 megawatts of capacity and energy from
Marketing Company. The Missouri Office of Public Counsel (OPC) also filed
pleadings with the FERC in this matter. The MoPSC's FERC pleading was filed in a
proceeding initiated by Marketing Company for approval of its power sales
agreement with the Registrant. Such pleading requested the FERC to reject
Marketing Company's proposed market based rates alleging concerns about
affiliate abuse and the overall competitiveness of the market and requested the
FERC to set for hearing the appropriate level of cost-based rates, or in the
alternative, set for hearing whether Marketing Company has demonstrated that its
proposed market-based rates will be just and reasonable. In its pleading, the
OPC submitted similar comments. In June 2001, the FERC issued an order which
accepted the power sales agreement (with minor modifications), without hearing
or suspension, and rejected the pleadings of the MoPSC and the OPC. In July
2001, the MoPSC filed with the FERC a request for clarification of its June 2001
order in the following two respects: (1) that it does not insulate the power
sales agreement from a finding of invalidity by the SEC under PUHCA and (2) that
it does not preempt the MoPSC from inquiring into the reasonableness of the
Registrant's decision to enter into the agreement. To date, the FERC has not
responded to the MoPSC's request for clarification. Under the terms of the
FERC's June 2001 order, the power sales agreement became effective June 1, 2001.
The MoPSC's SEC pleading requests an investigation into the contractual
relationship between the Registrant, Marketing Company and AmerenEnergy
Generating Company (Generating Company), another subsidiary of Resources
Company, in the context of the 450 megawatt power sales agreement and requests
that the SEC find that such relationship violates a provision of PUHCA which
requires state utility commission approval of power sales contracts between an
electric utility company and an affiliated exempt wholesale generator, like
Generating Company. In this case, the MoPSC's approval of the power sales
agreement was not requested under PUHCA because Generating Company is not a
party to the agreement. As a remedy, the MoPSC proposes that the SEC require the
Registrant to contract directly with Generating Company and submit such contract
to the MoPSC for review. The SEC has not responded to this matter to date.
At this time, management is unable to predict the outcome of these proceedings
or the ultimate impact on the Registrant's future financial position, results of
operation 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
5
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, 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. Management is unable to determine the impact of
these actions on the Registrant's future financial position, results of
operations or liquidity.
RATE MATTERS
On June 30, 2001, the Registrant's experimental alternative regulation plan (the
Plan) for its Missouri electric customers expired (see Note 2 under Notes to
Financial Statements for further information about the Plan). With the Plan's
expiration, on July 2, 2001, the MoPSC staff filed with the MoPSC an excess
earnings complaint against the Registrant that proposes to reduce the
Registrant's annual electric revenues ranging from $213 million to $250 million.
Factors contributing to the MoPSC staff's recommendation include return on
equity (ROE), revenues and customer growth, depreciation rates and other cost of
service expenses. The ROE incorporated into the MoPSC staff's recommendation
ranges from 9.04 percent to 10.04 percent. Evidentiary hearings on the MoPSC
staff's recommendation will be conducted before the MoPSC. To date, hearings
have not been scheduled. The MoPSC is not bound by the MoPSC staff's
recommendation. Depending on the outcome of the MoPSC's decision, further
appeals in the courts may be warranted. As a result, a final decision on this
matter may not occur until 2002. The Registrant is preparing to vigorously
contest the MoPSC staff's recommendation in proceedings before the MoPSC. At
this time, the Registrant can not predict the outcome of this complaint
proceeding, or its impact on the Registrant's financial position, results of
operations or liquidity; however, the impact could be material.
In the interim, the Registrant expects to continue negotiations with all
pertinent parties with the intent to continue with a form of incentive
regulation similar to the Plan. The Registrant can not predict the outcome of
these negotiations and their impact on the Registrant's financial position,
results of operations or liquidity.
See Note 2 under Notes to 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 Illinois Law) providing for electric
utility restructuring in Illinois. This legislation introduces competition into
the supply of electric energy in Illinois.
The Illinois Law, among other things, requires 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
6
industrial customers in Illinois represent approximately 7 percent of the
Registrant's total sales. As of June 30, 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
During the legislative session that ended in May 2001, the Registrant was
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 have allowed the State's largest nonresidential
customers to choose their electric supplier, among other things. No electric
industry legislation was passed during the legislative session.
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 $17
million ($10 million after taxes), which related to the Registrant's estimated
obligation under the Midwest ISO agreement for costs incurred by the Midwest
ISO, plus estimated exit costs. During first quarter 2001, the 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. Also in the first quarter 2001, in a proceeding before
the FERC, the Alliance RTO and the Midwest ISO reached an agreement that would
enable the Registrant 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.
Additional regulatory approvals of the SEC, FERC, MoPSC and the Illinois
Commerce Commission may be required in connection with various transactions
involving the Alliance RTO relating to its organization, capitalization and the
possible transfer of transmission assets. Such approvals, if required, will be
sought at the appropriate times. The Alliance RTO is expected to be operational
by the end of 2001. 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.
ACCOUNTING MATTERS
In January 2001, the Registrant implemented Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities". The impact of that adoption resulted in the Registrant recording a
cumulative effect charge of $5 million after taxes to the income statement, and
a cumulative adjustment of $8 million after income taxes to other comprehensive
income (OCI), which reduced stockholder's equity. (See Note 4 under Notes to
Financial Statements for further information.) In June 2001, the Derivatives
Implementation Group (DIG), a committee of the Financial Accounting Standards
Board (FASB) responsible for providing guidance on the implementation of SFAS
133, reached a conclusion regarding the appropriate accounting treatment of
certain types of energy contracts under SFAS 133. Specifically, the DIG
concluded that power purchase or sales agreements (both forward contracts and
option contracts) may meet an exception for normal purchases and sales
accounting treatment if certain criteria are met. At this time, the Registrant
is evaluating the impact of the DIG's decision to determine its effect on the
Registrant's future financial condition, results of operations, or liquidity
upon application.
The DIG is currently reviewing the accounting treatment for fuel contracts that
combine a forward contract and a purchased option contract. The DIG has not
reached a conclusion on whether or not these contracts qualify under the scope
exception in SFAS 133 for normal purchases and sales. The Registrant is unable
to predict when this issue will be ultimately resolved and the impact that the
resolution will have on the Registrant's future financial condition, results of
operations or liquidity; however, it could be material.
In July 2001, the FASB issued SFAS No. 141, "Business Combinations," SFAS 142,
"Goodwill and Other Intangible Assets," and SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 141 requires business combinations to be accounted
for under the purchase method of accounting, which requires one party in the
transaction to be identified as the acquiring enterprise and for that party to
record the assets and liabilities of the acquired enterprise at fair market
value rather than historical cost. It prohibits use of the pooling-of-interests
method of accounting for business combinations. SFAS 141 is effective for all
business combinations initiated after June 30, 2001, or transactions completed
using the purchase method after June 30, 2001. SFAS 142 requires goodwill
recorded in the financial statements to be tested for impairment at least
annually, rather than amortized over a fixed
7
period, with impairment losses recorded in the income statement. SFAS 142 is
effective for all fiscal years beginning after December 15, 2001. SFAS 143
requires an entity to record a liability and corresponding asset representing
the present value of legal obligations associated with the retirement of
tangible, long-lived assets. SFAS 143 is effective for fiscal years beginning
after June 15, 2002. SFAS 141 and SFAS 142 are not expected to have a material
effect on the Registrant's financial position, results of operations or
liquidity upon adoption. At this time, the Registrant is unable to determine the
impact of SFAS 143 on its financial position, results of operations or liquidity
upon adoption.
ITEM 3. 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 Ameren's, including 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. Ameren handles market risks in accordance
with established policies, which may include entering into various derivative
transactions. In the normal course of business, Ameren and the Registrant also
face 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.
Ameren'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, and commercial paper. 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 $5 million,
and net income would decrease by approximately $3 million. This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt and commercial paper, as of June 30, 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
that has its value 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.
Ameren 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 Ameren'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. All of the required coal
for the Registrant's
8
coal plants has been acquired at fixed prices for 2001. In addition, at least 80
percent of the coal requirements through 2005 are covered by long-term
contracts. The Registrant has recently experienced some delays in its coal
deliveries due to certain transportation and operating constraints in the
system. The Registrant is working closely with the transportation companies and
monitoring its operating practices in order to maintain adequate levels of coal
inventory for future operating purposes.
With regard to the Registrant's exposure to commodity price risk for purchased
power and excess electricity sales, Ameren has a subsidiary, AmerenEnergy, Inc.,
(AmerenEnergy), which has as its primary responsibility managing market risks
associated with changing market prices for electricity purchased and sold on
behalf of the Registrant.
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 June 30, 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 electric rates.
SAFE HARBOR STATEMENT
Statements made in this Form 10-Q 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 Annual Report on
Form 10-K for the fiscal year ended December 31, 2000, 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 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;
wholesale pricing for electricity; business and economic conditions; the impact
of the adoption of new accounting standards; interest rates; weather conditions;
fuel 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; cost and
availability of transmission capacity for the energy generated by the
Registrant's generating facilities or required to satisfy energy sales made by
the Registrant; and legal and administrative proceedings.
9
UNION ELECTRIC COMPANY
BALANCE SHEET
UNAUDITED
(Thousands of Dollars, Except Shares)
June 30, December 31,
ASSETS 2001 2000
- ------ --------------- ----------------
Property and plant, at original cost:
Electric $9,616,855 $9,449,275
Gas 245,147 236,139
Other 37,062 37,140
--------------- ----------------
9,899,064 9,722,554
Less accumulated depreciation and amortization 4,684,187 4,571,292
--------------- ----------------
5,214,877 5,151,262
Construction work in progress:
Nuclear fuel in process 84,528 117,789
Other 207,049 111,527
--------------- ----------------
Total property and plant, net 5,506,454 5,380,578
--------------- ----------------
Investments and other assets:
Nuclear decommissioning trust fund 187,210 190,625
Other 73,513 65,811
--------------- ----------------
Total investments and other assets 260,723 256,436
--------------- ----------------
Current assets:
Cash and cash equivalents 5,209 19,960
Accounts receivable - trade (less allowance for doubtful
accounts of $4,159 and $6,251, respectively) 317,141 277,947
Other accounts and notes receivable 36,941 28,216
Intercompany notes receivable 177,010 255,570
Materials and supplies, at average cost -
Fossil fuel 67,869 52,155
Other 83,465 82,161
Other 13,043 16,757
--------------- ----------------
Total current assets 700,678 732,766
--------------- ----------------
Regulatory assets:
Deferred income taxes 601,203 599,973
Other 140,134 146,373
--------------- ----------------
Total regulatory assets 741,337 746,346
--------------- ----------------
Total Assets $7,209,192 $7,116,126
=============== ================
CAPITAL AND LIABILITIES
- -----------------------
Capitalization:
Common stock, $5 par value, 150,000,000 shares authorized -
102,123,834 shares outstanding $510,619 $510,619
Other paid-in capital, principally premium on
common stock 701,896 701,896
Retained earnings 1,333,187 1,358,137
Accumulated other comprehensive income (3,610) -
--------------- ----------------
Total common stockholder's equity 2,542,092 2,570,652
Preferred stock not subject to mandatory redemption 155,197 155,197
Long-term debt 1,844,779 1,760,439
--------------- ----------------
Total capitalization 4,542,068 4,486,288
--------------- ----------------
Current liabilities:
Accounts and wages payable 263,616 293,511
Accumulated deferred income taxes 23,131 30,325
Taxes accrued 166,749 86,125
Other 152,183 196,127
--------------- ----------------
Total current liabilities 605,679 606,088
--------------- ----------------
Accumulated deferred income taxes 1,339,547 1,315,109
Accumulated deferred investment tax credits 132,320 132,922
Regulatory liability 142,091 148,643
Other deferred credits and liabilities 447,487 427,076
-------------- ----------------
Total Capital and Liabilities $7,209,192 $7,116,126
============== ================
See Notes to Financial Statements.
10
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
UNAUDITED
(Thousands of Dollars)
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
----------------------- ---------------------- -----------------------
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
OPERATING REVENUES:
Electric $765,032 $664,416 $1,361,897 $1,183,529 $2,768,364 $2,554,173
Gas 18,046 18,095 87,282 60,172 156,351 94,446
Other 203 - 310 - 310 -
---------- ---------- ----------- ----------- ----------- ------------
Total operating revenues 783,281 682,511 1,449,489 1,243,701 2,925,025 2,648,619
OPERATING EXPENSES:
Operations
Fuel and purchased power 261,338 179,176 480,639 351,614 857,537 718,731
Gas 11,422 9,849 56,998 32,448 106,073 56,560
Other 132,283 120,668 262,734 225,393 537,640 446,697
--------- --------- ----------- ---------- ----------- -----------
405,043 309,693 800,371 609,455 1,501,250 1,221,988
Maintenance 100,475 80,400 158,980 132,660 276,350 261,555
Depreciation and amortization 69,616 67,337 138,438 134,403 274,411 265,342
Income taxes 48,217 60,872 79,229 89,484 216,545 239,273
Other taxes 53,311 50,196 103,175 97,911 214,724 202,584
---------- ---------- ----------- ----------- ------------ -----------
Total operating expenses 676,662 568,498 1,280,193 1,063,913 2,483,280 2,190,742
OPERATING INCOME 106,619 114,013 169,296 179,788 441,745 457,877
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction 2,218 1,600 3,823 2,829 6,292 5,111
Miscellaneous, net 1,991 2,662 9,028 5,541 19,933 14,474
----------- ----------- ------------ ----------- ------------ ----------
Total other income and
(deductions) 4,209 4,262 12,851 8,370 26,225 19,585
INCOME BEFORE
INTEREST CHARGES 110,828 118,275 182,147 188,158 467,970 477,462
INTEREST CHARGES:
Interest 29,910 33,548 60,465 66,014 123,733 124,014
Allowance for borrowed funds used
during construction (1,540) (2,125) (3,825) (3,944) (8,193) (7,480)
---------- ----------- ----------- ----------- ----------- -----------
Net interest charges 28,370 31,423 56,640 62,070 115,540 116,534
INCOME BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 82,458 86,852 125,507 126,088 352,430 360,928
---------- ----------- ---------- ------------ ----------- -----------
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE, NET
OF INCOME TAXES - - (4,848) - (4,848) -
---------- ----------- ------------ ------------ ---------- -----------
NET INCOME 82,458 86,852 120,659 126,088 347,582 360,928
PREFERRED STOCK DIVIDENDS 2,205 2,205 4,409 4,409 8,817 8,817
---------- ----------- ------------ ------------ ---------- -----------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $80,253 $84,647 $116,250 $121,679 $338,765 $352,111
========== =========== ============ ============ ========== ===========
See Notes to Financial Statements.
11
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
UNAUDITED
(Thousands of Dollars)
Six Months Ended
June 30,
--------------------
2001 2000
---- ----
Cash Flows From Operating:
Net income $120,659 $126,088
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 4,848 -
Depreciation and amortization 132,369 128,429
Amortization of nuclear fuel 12,497 18,342
Allowance for funds used during construction (7,648) (6,773)
Deferred income taxes, net 14,508 6,725
Deferred investment tax credits, net (602) (2,925)
Changes in assets and liabilities:
Receivables, net (47,919) (89,935)
Materials and supplies (17,018) 15,462
Accounts and wages payable (29,895) (46,124)
Taxes accrued 80,624 59,656
Other, net (36,850) (47,586)
----------- -----------
Net cash provided by operating activities 225,573 161,359
Cash Flows From Investing:
Construction expenditures (252,478) (166,283)
Allowance for funds used during construction 7,648 6,773
Nuclear fuel expenditures (12,620) (8,449)
Intercompany notes receivable 78,560 (3,420)
----------- -----------
Net cash used in investing activities (178,890) (171,379)
Cash Flows From Financing:
Dividends on common stock (141,200) (138,150)
Dividends on preferred stock (4,409) (4,409)
Redemptions -
Nuclear fuel lease (64,122) (3,933)
Long-term debt - (186,500)
Issuances -
Nuclear fuel lease 2,497 5,656
Long-term debt 145,800 221,650
----------- -----------
Net cash used in financing activities (61,434) (105,686)
Net change in cash and cash equivalents (14,751) (115,706)
Cash and cash equivalents at beginning of year 19,960 117,308
----------- -----------
Cash and cash equivalents at end of period $ 5,209 $ 1,602
=========== ===========
Cash paid during the periods:
Interest (net of amount capitalized) $53,480 $58,958
Income taxes, net $31,272 $69,868
See Notes to Financial Statements.
12
UNION ELECTRIC COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
UNAUDITED
(Thousands of Dollars)
Six Months Ended Year Ended
June 30, 2001 December 31, 2000
--------------------- -------------------
Common stock $ 510,619 $ 510,619
Other paid-in capital 701,896 701,896
Retained earnings
Beginning balance 1,358,137 1,221,167
Net income 120,659 353,011
Common stock dividends (141,200) (207,224)
Preferred stock dividends (4,409) (8,817)
--------------------- -------------------
1,333,187 1,358,137
Accumulated other comprehensive income
Beginning balance - -
Change in current period (3,610) -
--------------------- -------------------
(3,610) -
--------------------- -------------------
Total common stockholder's equity $ 2,542,092 $ 2,570,652
===================== ===================
Comprehensive income, net of tax
Net income $ 120,659 $ 353,011
Cumulative effect of
accounting change, net of taxes (7,881) -
Unrealized net gain on
derivative hedging instruments 4,271 -
--------------------- -------------------
$ 117,049 $ 353,011
===================== ===================
See Notes to Financial Statements.
13
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2001
Note 1 - Summary of Significant Accounting Policies
Basis of Presentation
Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren
Corporation (Ameren), a holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). Ameren is the parent company of the
following operating subsidiaries: the Registrant, Central Illinois Public
Service Company (AmerenCIPS), and AmerenEnergy Generating Company, a wholly
owned subsidiary of AmerenEnergy Resources Company. Both Ameren and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
Registrant is a public utility engaged principally in the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution, transportation and sale of natural gas in the states of Missouri
and Illinois. Contracts among the Registrant and other Ameren
subsidiaries--dealing with jointly-owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) or the Securities and Exchange
Commission (SEC). Administrative support services are provided to the Registrant
by a separate Ameren subsidiary, Ameren Services Company (Ameren Services). The
Registrant serves 1.2 million electric and 125,000 gas customers in a 24,500
square-mile area of Missouri and Illinois, including Metropolitan St. Louis.
The Registrant also has a 40 percent interest in Electric Energy, Inc. (EEI),
which is accounted for under the equity method of accounting. EEI owns and/or
operates electric generating and transmission facilities in Illinois that supply
electric power primarily to a uranium enrichment plant located in Paducah,
Kentucky.
Interim Financial Statements
Financial statement note disclosures, normally included in 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 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 Financial Statements included in the 2000 Form 10-K for information
relevant to the financial statements contained in this Form 10-Q, including
information as to the significant accounting policies of the Registrant.
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.
Reclassifications
Certain reclassifications have been made to prior years' financial statements to
conform with 2001 reporting.
Factors Affecting Business
Due to the effect of weather on sales and other factors which are characteristic
of public utility operations, financial results for the periods ended June 30,
2001 and 2000, are not necessarily indicative of trends for any three-month,
six-month or 12-month period.
Note 2 - Regulatory Matters
Missouri
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 percent regulatory return on equity be shared equally between customers
and stockholders, and earnings above a 14 percent regulatory return
14
on equity be credited to customers. The formula for computing the credit used
twelve-month results ending June 30, rather than calendar year earnings.
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 the Registrant and CIPSCO Incorporated that formed
Ameren. Like the Original Plan, the New Plan requires that earnings over a 12.61
percent regulatory return on equity up to a 14 percent regulatory return on
equity be shared equally between customers and stockholders. The New Plan also
returns to customers 90 percent of all earnings above a 14 percent regulatory
return on equity up to a 16 percent regulatory return on equity. Earnings above
a 16 percent regulatory return on equity are credited entirely to customers. The
New Plan ran from July 1, 1998 through June 30, 2001. During the three months
ended June 30, 2001, the Registrant reduced the estimated total credit for the
plan year ended June 30, 2001 that the Registrant expects to pay its Missouri
electric customers by $25 million. In total, the Registrant has recorded an
estimated credit of $40 million as of June 30, 2001 for the plan year ended June
30, 2001, compared to an estimated $35 million credit recorded as of June 30,
2000, for the plan year ended June 30, 2000. 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.
With the New Plan's expiration on June 30, 2001, on July 2, 2001, the MoPSC
staff filed with the MoPSC an excess earnings complaint against the Registrant
that proposes to reduce the Registrant's annual electric revenues ranging from
$213 million to $250 million. Factors contributing to the MoPSC staff's
recommendation include return on equity (ROE), revenues and customer growth,
depreciation rates and other cost of service expenses. The ROE incorporated into
the MoPSC staff's recommendation ranges from 9.04 percent to 10.04 percent.
Evidentiary hearings on the MoPSC staff's recommendation will be conducted
before the MoPSC. To date, hearings have not been scheduled. The MoPSC is not
bound by the MoPSC staff's recommendation. Depending on the outcome of the
MoPSC's decision, further appeals in the courts may be warranted. As a result, a
final decision on this matter may not occur until 2002. The Registrant is
preparing to vigorously contest the MoPSC staff's recommendation in proceedings
before the MoPSC. At this time, the Registrant can not predict the outcome of
this complaint proceeding, or its impact on the Registrant's financial position,
results of operations or liquidity; however, the impact could be material.
In the interim, the Registrant expects to continue negotiations with all
pertinent parties with the intent to continue with a form of incentive
regulation similar to the New Plan. The Registrant can not predict the outcome
of these negotiations and their impact on the Registrant's financial position,
results of operations or liquidity.
Midwest ISO and Alliance RTO
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 $17 million ($10 million after taxes), which
related to the Registrant's estimated obligation under the Midwest ISO agreement
for costs incurred by the Midwest ISO, plus estimated exit costs. During first
quarter 2001, the 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. Also in first quarter 2001, in a
proceeding before the FERC, the Alliance RTO and the Midwest ISO reached an
agreement that would enable the Registrant 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. Additional regulatory approvals of the SEC, FERC, MoPSC and the
Illinois Commerce Commission may be required in connection with various
transactions involving the Alliance RTO relating to its organization,
capitalization and the possible transfer of transmission assets. Such approvals,
if required, will be sought at the appropriate times. The Alliance RTO is
expected to be operational by the end of 2001. 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.
15
Note 3 - Related Party Transactions
The Registrant has transactions in the normal course of business with other
Ameren subsidiaries. These transactions are primarily comprised of power
purchases and sales and services received or rendered. Intercompany receivables
included in other accounts and notes receivable were approximately $27 million
and $20 million, respectively, as of June 30, 2001 and December 31, 2000.
Intercompany payables included in accounts and wages payable totaled
approximately $94 million and $27 million, respectively, as of June 30, 2001 and
December 31, 2000.
Also, the Registrant has the ability to borrow up to approximately $488 million
from Ameren, AmerenCIPS or Ameren Services through a regulated money pool
agreement. The total amount available to the Registrant at any given time from
the regulated money pool is reduced by the amount of borrowings by AmerenCIPS or
Ameren Services but increased to the extent AmerenCIPS or Ameren Services have
surplus funds and the availability of other external borrowing sources. The
regulated money pool was established to coordinate and provide for certain
short-term cash and working capital requirements of the Registrant, AmerenCIPS
and Ameren Services and is administered by Ameren Services. Interest is
calculated at varying rates of interest depending on the composition of internal
and external funds in the regulated money pool. For the three months and six
months ended June 30, 2001, the average interest rate for the regulated money
pool was 4.38 percent and 4.94 percent, respectively. Intercompany interest
income for the quarters ended June 30, 2001 and 2000 was approximately $2
million and $3 million, respectively. For the six-month periods ended June 30,
2001 and 2000, intercompany interest income was approximately $5 million for
each period. For the 12-month periods ended June 30, 2001 and 2000, intercompany
interest income was approximately $11 million and $8 million, respectively. As
of June 30, 2001, the Registrant had outstanding intercompany receivables of
$177 million and at least $104 million was available through the regulated money
pool subject to reduction for borrowings by AmerenCIPS or Ameren Services.
Note 4 - Derivative Financial Instruments
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 stockholder's equity. In
accordance with the transition provisions of SFAS 133, the Registrant recorded a
cumulative effect charge of $5 million after income taxes to the income
statement, comprised of $1 million for ineffective portion of cash flow hedges
and $4 million for discontinued hedges. The Registrant also recorded a
cumulative effect adjustment of $8 million after income taxes, representing the
effective portion of designated cash flow hedges, to OCI, which reduced
stockholder's equity. The Registrant expects that by the end of 2001 it will
reclassify to earnings all of the transition adjustment that was recorded in
accumulated OCI. 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
"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
16
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
RMSC to assure compliance with Ameren policies. The RMSC 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 the Registrant's risk management strategies and
the effect of these strategies on the Registrant's financial statements.
Cash Flow Hedges
The Registrant routinely enters into forward purchase and sales contracts for
electricity based on forecasted levels of excess economic generation. The amount
of excess economic generation varies throughout the year and is monitored by the
RMSC. The contracts typically cover a period of twelve months or less. The
17
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
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 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 and six months ended June 30, 2001, the net loss, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of 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.
As of June 30, 2001, all $4 million 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
upon 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 SFAS 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 June 30, 2001, the Registrant has recorded the fair value of derivative
financial instrument assets of $16 million in Other Assets and derivative
financial instrument liabilities of $29 million in Other Deferred Credits and
Liabilities.
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.
18
PART II - OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of stockholders of the Registrant held on April
24, 2001, the following matter was presented to the meeting for a vote and the
results of such voting are as follows:
Item (1) Election of Directors.
Non-Voted
Name For Withheld Brokers
---- ---- --------- ---------
Paul A. Agathen 104,019,088 16,738 0
Warner L. Baxter.................. 104,018,488 17,346 0
Donald E. Brandt.................. 104,020,527 17,132 0
Charles W. Mueller................ 104,019,194 15,688 0
Gary L. Rainwater................. 104,019,084 16,742 0
ITEM 5. OTHER INFORMATION.
Any stockholder proposal intended for inclusion in the proxy material
for the Registrant's 2002 annual meeting of stockholders must be received by the
Registrant by November 30, 2001.
In addition, under the Registrant's By-Laws, stockholders who intend to
submit a proposal in person at an annual meeting, or who intend to nominate a
director at a meeting, must provide advance written notice along with other
prescribed information. In general, such notice must be received by the
Secretary of the Registrant not later than 60 nor earlier than 90 days prior to
the first anniversary of the preceding year's annual meeting. For the
Registrant's 2002 annual meeting of stockholders, written notice of any
in-person stockholder proposal or director nomination must be received not later
than February 23, 2002 or earlier than January 24, 2002.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a)(i) Exhibits.
12 - Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividend Requirements, 12 Months Ended
June 30, 2001.
(a)(ii) Exhibits Incorporated by Reference.
10.1 - Alliance Agreement establishing the Alliance
Independent Transmission System Operator, Inc.,
Alliance Transmission Company, Inc. and Alliance
Transmission Company, LLC and Amendment to admit
AmerenCIPS and AmerenUE (June 30, 2001 Ameren
Corporation Form 10-Q, Exhibit 10.1).
(b) Reports on Form 8-K. None.
Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and Form 10-K
are on file with the SEC under File Number 1-14756.
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.
19
UNION ELECTRIC COMPANY
(Registrant)
By /s/ Donald E. Brandt
--------------------------------
Donald E. Brandt
Senior Vice President
Finance and Corporate Services
(Principal Financial Officer)
Date: August 14, 2001
Exhibit 12
UNION ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED STOCK DIVIDEND REQUIREMENTS
12 Months
Ended
Year Ended December 31, June 30,
--------------------------------------------------------------------------
1996 1997 1998 1999 2000 2001
---- ---- ---- ---- ---- ----
Thousands of Dollars Except Ratios
Net Income $304,876 $301,655 $320,070 $349,252 $353,011 $347,582
Add- Extraordinary items net of tax - 26,967 - - - -
---------- --------- --------- --------- --------- ---------
Net income from continuing operations 304,876 328,622 320,070 349,252 353,011 347,582
---------- --------- --------- --------- --------- ---------
Taxes based on income 196,210 199,763 212,554 226,696 224,149 216,541
---------- --------- --------- --------- --------- ---------
Net income before income taxes 501,086 528,385 532,624 575,948 577,160 564,123
---------- --------- --------- --------- --------- ---------
Add- fixed charges:
Interest on long term debt 120,547 125,705 124,766 117,899 121,763 116,115
Other interest 7,828 9,299 1,660 (1,342) 4,219 4,331
Rentals 3,458 3,727 3,416 3,899 3,928 3,610
Amortization of net debt premium,
discount, expenses and losses 4,269 3,672 3,522 3,421 3,300 3,286
---------- --------- --------- --------- --------- ---------
Total fixed charges 136,102 142,403 133,364 123,877 133,210 127,342
---------- --------- --------- --------- --------- ---------
Earnings available for fixed charges 637,188 670,788 665,988 699,825 710,370 691,465
========== ========= ========= ========= ========= =========
Ratio of earnings to fixed charges 4.68 4.71 4.99 5.64 5.33 5.42
========== ========= ========= ========= ========= =========
Earnings required for preferred dividends:
Preferred stock dividends 13,249 8,817 8,817 8,817 8,817 8,817
Adjustment to pre-tax basis 7,363 4,257 4,649 4,544 4,439 4,362
---------- --------- --------- --------- --------- ---------
20,612 13,074 13,466 13,361 13,256 13,179
Fixed charges plus preferred stock
dividend requirements 156,714 155,477 146,830 137,238 146,466 140,521
========== ========= ========= ========= ========= =========
Ratio of earnings to fixed charges plus
preferred stock dividend requirements 4.06 4.31 4.53 5.09 4.85 4.92
========== ========= ========= ========= ========= =========