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 1-2967.
UNION ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Missouri 43-0559760
(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 .
------------ -------------
Shares outstanding of each of registrant's classes of common stock as of April
30, 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 (Unaudited)
Management's Discussion and Analysis 2
Quantitative and Qualitative Disclosures
About Market Risk 6
Balance Sheet
- March 31, 2001 and December 31, 2000 9
Statement of Income
- Three months and 12 months ended
March 31, 2001 and 2000 10
Statement of Cash Flows
- Three months ended March 31, 2001 and 2000 11
Statement of Common Stockholder's Equity
- March 31, 2001 and December 31, 2000 12
Notes to Financial Statements 13
Part II Other Information 18
PART I. FINANCIAL INFORMATION (UNAUDITED)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
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). 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 following discussion and analysis should be read in conjunction with the
Notes to the Financial Statements beginning on page 13, 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
First quarter 2001 earnings of $36 million decreased $1 million compared to 2000
first quarter earnings. 2001 earnings include the impact of a one-time charge of
$5 million associated with the required adoption of a new accounting standard
related to derivative financial instruments (see Note 8 under Notes to Financial
Statements for further information). Earnings for the 12 months ended March 31,
2001, were $343 million, a $7 million increase 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 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 22 39
Growth and other (1) 45
Interchange sales 62 126
- --------------------------------------------- ------------------- ---- -----------------------
$ 78 $ 168
- --------------------------------------------- ------------------- ---- -----------------------
The $78 million increase in the first quarter electric revenues compared to the
year-ago quarter was primarily driven by a 25 percent increase in interchange
sales, due to strong marketing efforts and greater interchange opportunities.
Also, contributing to the revenue increase was a 5 percent increase in native
sales, which were primarily due to increases in weather-sensitive residential
and commercial sales of 9 percent and 7 percent, respectively, partially offset
by a 24 percent decrease in wholesale sales, while industrial sales were flat.
Electric revenues were also impacted by an increase in the estimated credit to
Missouri electric customers (see Note 5 under Notes to Financial Statements for
further information).
Electric revenues for the 12 months ended March 31, 2001 increased $168 million
compared to the prior 12-month period. The increase in revenues was primarily
driven by increased interchange sales due to increased interchange
opportunities. Interchange sales increased 39 percent, partially offset by a 43
percent decline in wholesale sales and
-2-
a 4 percent decline in industrial sales, while weather sensitive residential and
commercial sales increased by 8 percent and 10 percent, respectively, for the 12
months ended March 31, 2001. Partially offsetting this increase is the estimated
increase in the credit to Missouri electric customers (see Note 5 under the
Notes to 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 $ 6 $ 36
Price 4 (15)
Generation efficiencies and other (1) (4)
Purchased power variation 38 50
- ----------------------------------------------------------------------------------------------
$ 47 $ 67
- ----------------------------------------------------------------------------------------------
The increase in fuel and purchased power costs for the three month and 12 month
periods ended March 31, 2001, compared to the year ago comparable periods, was
primarily due to increased generation and purchased power resulting from higher
sales volumes.
Gas Operations
Gas revenues for the three month and 12 month periods ended March 31, 2001
increased $27 million and $67 million, respectively, compared to the prior-year
periods primarily due to increases in retail sales due to a return to more
normal weather conditions, as compared to the same year ago periods, 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 $23 million
and $49 million, respectively compared to the year-ago period, primarily due to
an 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 for the three months ended March 31, 2001 increased
$26 million, compared to the same year-ago period primarily due to increased
employee benefit costs. Other operations expenses increased $85 million for the
12 months ended March 31, 2001, compared to the same year-ago period primarily
due to increased professional services expenses in addition to the Midwest ISO
charge in the fourth quarter of 2000 (see discussion below under "Electric
Industry Restructuring" for further information).
Maintenance expenses for the three and 12 months ended March 31, 2001 increased
$6 million and $8 million, respectively, compared to the year-ago periods
primarily due to increased fossil power plant maintenance.
Depreciation and amortization expense for the 12 months ended March 31, 2001
increased $8 million compared to the prior year due to an increase in
depreciable property.
Taxes
Other tax expense increased $9 million for the 12 months ended March 31, 2001
due to increased property tax assessments in the state of Missouri and a refund
from previous periods recorded in the first quarter of 2000.
Other Income and Deductions
Other income and deductions for the three and 12 month periods ended March 31,
2001 increased $5 million and $7 million, respectively, due primarily to the
mark to market adjustment made in the first quarter of 2001 relating to the
adoption of Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (see Note 8 under Notes to
Financial Statements for further information).
Balance Sheet
The $25 million decrease in accounts receivable-trade at March 31, 2001,
compared to the year-end, was due primarily to lower revenues in February and
March 2001 compared to November and December 2000. The $18 million decrease in
intercompany notes receivable reflects changes in funds invested in a regulated
money pool (see Note 6 under Notes to Financial Statements for further
information).
-3-
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $128 million for the three months
ended March 31, 2001, compared to $141 million during the same 2000 period.
Cash flows used in investing activities totaled $75 million and $80 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 $89 million. In addition, the Registrant
expended $8 million for the acquisition of nuclear fuel.
Cash flows used in financing activities totaled $48 million for the three months
ended March 31, 2001, compared to $171 million during the same 2000 period. The
Registrant's principal financing activities for the period included 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 the 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 March 31, 2001, the Registrant had committed bank lines of credit
aggregating $150 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 March 31,
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 $239 was available at March 31, 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 Company (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 quarter ended
March 31, 2001, the average interest rate for the regulated money pool was
5.50%. As of March 31, 2001, the Registrant had loaned $238 million to the
regulated money pool and at least $239 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 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 Ameren's resource planning, several alternatives are being
considered to satisfy regulatory load requirements for 2001 and beyond for the
Registrant, AmerenCIPS and AmerenEnergy Resources Company (the Ameren subsidiary
which holds its nonregulated generation operations). The Registrant has
purchased 450 megawatts of capacity and energy for the summer of 2001 from
AmerenEnergy Resources Company, and is considering the purchase of an additional
100 megawatts. Alternatives being considered for the summer of 2002 and beyond
include the purchase of capacity and energy, 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 cost in order to remain competitive in the marketplace. Areas where
the Registrant focuses its review include, but are not limited to, labor
-4-
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 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 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 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 Financial Statements for further discussion of the
experimental alternative regulation plan.
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,
-5-
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 7% 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 $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. In January 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.
In February 2001, in a proceeding before the Federal Energy Regulatory
Commission (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.
In addition, the Registrant'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.
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 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
-6-
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.
Ameren has a subsidiary, AmerenEnergy Fuels and Services Company, a wholly owned
subsidiary of AmerenEnergy 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.
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), whose primary responsibility includes 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 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.
-7-
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;
business and economic conditions; interest rates; weather conditions; the impact
of the adoption of new accounting standards; 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-
UNION ELECTRIC COMPANY
BALANCE SHEET
UNAUDITED
(Thousands of Dollars, Except Shares)
March 31, December 31,
ASSETS 2001 2000
- ------ ------------------ -----------------
Property and plant, at original cost:
Electric $ 9,487,985 $ 9,449,275
Gas 238,817 236,139
Other 37,062 37,140
----------------- ----------------
9,763,864 9,722,554
Less accumulated depreciation and amortization 4,630,401 4,571,292
----------------- ----------------
5,133,463 5,151,262
Construction work in progress:
Nuclear fuel in process 125,554 117,789
Other 145,948 111,527
---------------- ----------------
Total property and plant, net 5,404,965 5,380,578
---------------- ----------------
Investments and other assets:
Nuclear decommissioning trust fund 179,690 190,625
Other 84,501 65,811
---------------- ----------------
Total investments and other assets 264,191 256,436
---------------- ----------------
Current assets:
Cash and cash equivalents 25,287 19,960
Accounts receivable - trade (less allowance for doubtful
accounts of $5,830 and $6,251 respectively) 252,689 277,947
Other accounts and notes receivable 44,428 28,216
Intercompany notes receivable 238,020 255,570
Materials and supplies, at average cost -
Fossil fuel 42,680 52,155
Other 82,536 82,161
Other 15,740 16,757
---------------- ----------------
Total current assets 701,380 732,766
---------------- ----------------
Regulatory assets:
Deferred income taxes 600,238 599,973
Other 143,113 146,373
---------------- ----------------
Total regulatory assets 743,351 746,346
---------------- ----------------
Total Assets $ 7,113,887 $ 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 1,340,202 1,358,137
Accumulated other comprehensive income (2,085) -
---------------- ----------------
Total common stockholder's equity 2,550,632 2,570,652
Preferred stock not subject to mandatory redemption 155,197 155,197
Long-term debt 1,769,072 1,760,439
---------------- ----------------
Total capitalization 4,474,901 4,486,288
---------------- ----------------
Current liabilities:
Accounts and wages payable 224,388 293,511
Accumulated deferred income taxes 21,465 30,325
Taxes accrued 142,030 86,125
Other 213,243 196,127
---------------- ----------------
Total current liabilities 601,126 606,088
---------------- ----------------
Accumulated deferred income taxes 1,318,397 1,315,109
Accumulated deferred investment tax credits 131,322 132,922
Regulatory liability 147,478 148,643
Other deferred credits and liabilities 440,663 427,076
---------------- ----------------
Total Capital and Liabilities $ 7,113,887 $ 7,116,126
=============== ================
See Notes to Financial Statements.
-9-
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
UNAUDITED
(Thousands of Dollars)
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------------- -----------------------------
2001 2000 2001 2000
---- ---- ---- ----
OPERATING REVENUES:
Electric $596,865 $519,113 $2,667,748 $2,499,690
Gas 69,236 42,077 156,400 89,138
Other 107 - 107 151
----------- ------------- --------------- -------------
Total operating revenues 666,208 561,190 2,824,255 2,588,979
OPERATING EXPENSES:
Operations
Fuel and purchased power 219,301 172,438 775,375 708,397
Gas 45,576 22,599 104,500 55,268
Other 130,451 104,725 526,025 441,257
--------- --------- --------------- -------------
395,328 299,762 1,405,900 1,204,922
Maintenance 58,505 52,260 256,275 248,772
Depreciation and amortization 68,822 67,066 272,132 264,427
Income taxes 31,012 28,612 229,200 228,048
Other taxes 49,864 47,715 211,609 202,654
---------- ---------- ------------ -------------
Total operating expenses 603,531 495,415 2,375,116 2,148,823
OPERATING INCOME 62,677 65,775 449,139 440,156
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during
construction 1,605 1,229 5,674 5,730
Miscellaneous, net 7,037 2,879 20,604 13,199
----------- ----------- -------------- -------------
Total other income and (deductions) 8,642 4,108 26,278 18,929
INCOME BEFORE INTEREST CHARGES 71,319 69,883 475,417 459,085
INTEREST CHARGES :
Interest 30,555 32,466 127,371 121,521
Allowance for borrowed funds used during
construction (2,285) (1,819) (8,778) (7,181)
------------ --------- ------------- ------------
Net interest charges 28,270 30,647 118,593 114,340
------------ --------- ------------- ------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 43,049 39,236 356,824 344,745
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES (4,848) - (4,848) -
----------- --------- ------------- ------------
NET INCOME 38,201 39,236 351,976 344,745
PREFERRED STOCK DIVIDENDS 2,204 2,204 8,817 8,817
--------- --------- ------------- -----------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $35,997 $37,032 $343,159 $335,928
========== ========= ============= ===========
See Notes to Financial Statements.
-10-
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
UNAUDITED
(Thousands of Dollars)
Three Months Ended
March 31,
--------------------
2001 2000
---- ----
Cash Flows From Operating:
Net income $38,201 $39,236
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 4,848 -
Depreciation and amortization 65,835 64,077
Amortization of nuclear fuel 8,575 9,075
Allowance for funds used during construction (3,889) (3,048)
Deferred income taxes, net (5,802) (3,284)
Deferred investment tax credits, net (1,600) (1,520)
Changes in assets and liabilities:
Receivables, net 9,046 44,697
Materials and supplies 9,100 18,769
Accounts and wages payable 69,123) (104,429)
Taxes accrued 55,905 52,032
Other, net 17,168 25,030
--------- ----------
Net cash provided by operating activities 128,264 140,635
Cash Flows From Investing:
Construction expenditures (89,286) (100,124)
Allowance for funds used during construction 3,889 3,048
Nuclear fuel expenditures (7,505) (6,228)
Intercompany notes receivable 17,550 23,240
--------- ----------
Net cash used in investing activities (75,352) (80,064)
Cash Flows From Financing:
Dividends on common stock (53,932) (69,076)
Dividends on preferred stock (2,204) (2,204)
Environmental bond redemption fund - (186,500)
Redemptions -
Nuclear fuel lease (34,976) (1,818)
Long-term debt - (99,722)
Issuances -
Nuclear fuel lease 1,727 1,356
Long-term debt 41,800 186,500
--------- ----------
Net cash used in financing activities (47,585) (171,464)
--------- ----------
Net change in cash and cash equivalents 5,327 (110,893)
Cash and cash equivalents at beginning of year 19,960 117,308
--------- ----------
Cash and cash equivalents at end of period $25,287 $ 6,415
========= ===========
Cash paid during the periods:
Interest (net of amount capitalized) $21,292 $22,890
Income taxes, net $ 415 $ (179)
See Notes to Financial Statements.
-11-
UNION ELECTRIC COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
UNAUDITED
(Thousands of Dollars)
Three Months Ended Year Ended
March 31, 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 38,201 353,011
Common stock dividends (53,932) (207,224)
Preferred stock dividends (2,204) (8,817)
--------------------- -------------------
1,340,202 1,358,137
Accumulated other comprehensive income
Beginning balance - -
Change in current period (2,085) -
--------------------- -------------------
(2,085) -
--------------------- -------------------
Total common stockholder's equity $ 2,550,632 $ 2,570,652
===================== ===================
Comprehensive income, net of tax
Net income $ 38,201 $ 353,011
Cumulative effect of accounting change, net of taxes (7,881) -
Unrealized net gain on derivative hedging instruments 5,796 -
--------------------- -------------------
$ 36,116 $ 353,011
===================== ===================
See Notes to Financial Statements.
-12-
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2001
Note 1 - 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.
Note 2 - 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.
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 12-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 percent regulatory return on equity (ROE) be shared equally between
customers and stockholders, and earnings above a 14 percent 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 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
-13-
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 the Registrant 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 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 - 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 $87 million
and $20 million, respectively, as of March 31, 2001 and December 31, 2000.
Intercompany payables included in accounts and wages payable totaled
approximately $94 million and $27 million, respectively, as of March 31, 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
-14-
calculated at varying rates of interest depending on the composition of internal
and external funds in the regulated money pool. For the quarter ended March 31,
2001, the average interest rate for the regulated money pool was 5.50%.
Intercompany interest income for the quarters ended March 31, 2001 and 2000 was
approximately $3 million and $2 million, respectively. For the 12-month periods
ended March 31, 2001 and 2000, intercompany interest income was approximately
$11million and $8 million, respectively. As of March 31, 2001, the Registrant
had outstanding intercompany receivables of $238 million and at least $239
million was available through the regulated money pool subject to reduction for
borrowings by AmerenCIPS or Ameren Services.
Note 7 - 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. In
January 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. In February 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.
In addition, the Registrant'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.
Note 8 -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 $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
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
-15-
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. The Registrant primarily uses derivatives to optimize the value of
its physical and contractual positions. The Registrant 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. 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 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 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
-16-
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 $6 million as Miscellaneous, net 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 and
coal options are recorded as Miscellaneous, net in the statement of income.
Other
As of March 31, 2001, the Registrant has recorded the fair value of derivative
financial instrument assets of $10 million in Other Assets and derivative
financial instrument liabilities of $19 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.
-17-
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
--------------------------------
(a) Exhibits.
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements, 12 Months Ended March
31, 2001.
(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.
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.
UNION ELECTRIC COMPANY
(Registrant)
By /s/ Donald E. Brandt
-------------------------------------
Donald E. Brandt
Senior Vice President
Finance and Corporate Services
(Principal Financial Officer)
Date: May 15, 2001
-18-
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, March 31,
--------------------------------------------------------------------------
1996 1997 1998 1999 2000 2001
---- ---- ---- ---- ---- ----
Thousands of Dollars Except Ratios
Net Income $304,876 $301,655 $320,070 $349,252 $353,011 $351,976
Add- Extraordinary items net of tax - 26,967 - - - -
---------- --------- --------- --------- --------- ---------
Net income from continuing operations 304,876 328,622 320,070 349,252 353,011 351,976
---------- --------- --------- --------- --------- ---------
Taxes based on income 196,210 199,763 212,554 226,696 224,149 228,707
---------- --------- --------- --------- --------- ---------
Net income before income taxes 501,086 528,385 532,624 575,948 577,160 580,683
---------- --------- --------- --------- --------- ---------
Add- fixed charges:
Interest on long term debt 120,547 125,705 124,766 117,899 121,763 119,854
Other interest 7,828 9,299 1,660 (1,342) 4,219 4,220
Rentals 3,458 3,727 3,416 3,899 3,928 3,712
Amortization of net debt premium, discount,
expenses and losses 4,269 3,672 3,522 3,421 3,300 3,296
---------- --------- --------- --------- --------- ---------
Total fixed charges 136,102 142,403 133,364 123,877 133,210 131,082
---------- --------- --------- --------- --------- ---------
Earnings available for fixed charges 637,188 670,788 665,988 699,825 710,370 711,765
========== ========= ========= ========= ========= =========
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 4,551
---------- --------- --------- --------- --------- ---------
20,612 13,074 13,466 13,361 13,256 13,368
Fixed charges plus preferred stock dividend
requirements 156,714 155,477 146,830 137,238 146,466 144,450
========== ========= ========= ========= ========= =========
Ratio of earnings to fixed charges plus
preferred stock dividend requirements 4.06 4.31 4.53 5.09 4.85 4.92
========== ========= ========= ========= ========= =========