<PAGE>
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, 1999
[ ] 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) 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 July
31, 1999: Common Stock, $5 par value, held by Ameren Corporation (parent company
of Registrant) - 102,123,834
<PAGE>
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
- June 30, 1999 and December 31, 1998 9
Statement of Income
- Three months, six months and 12 months ended
June 30, 1999 and 1998 10
Statement of Cash Flows
- Six months ended June 30, 1999 and 1998 11
Notes to Financial Statements 12
Part II Other Information 15
<PAGE>
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 which is registered under the Public
Utility Holding Company Act of 1935 (PUHCA). In December 1997, AmerenUE and
CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's
subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO
Investment Company (CIC), becoming wholly-owned subsidiaries of Ameren (the
Merger).
The following discussion and analysis should be read in conjunction with the
Notes to Financial Statements beginning on page 12, and the Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A),
the Audited Financial Statements and the Notes to Financial Statements appearing
in the Registrant's 1998 Form 10-K.
RESULTS OF OPERATIONS
Earnings
Second quarter 1999 earnings of $68 million increased $4 million compared to
1998 second quarter earnings. Earnings for the six months ended June 30, 1999,
increased $18 from the year-ago period to $110 million. Earnings for the twelve
months ended June 30, 1999, were $329 million, a $41 million increase from the
preceding 12-month period. Excluding the extraordinary charge recorded in the
fourth quarter of 1997 to write off the generation-related regulatory assets and
liabilities of the Registrant's Illinois retail electric business, earnings for
the 12-month period ended June 30, 1998, were $315 million.
Earnings fluctuated due to many conditions, primarily: weather variations,
credits to electric customers, sales growth, fluctuating operating costs
(including Callaway Nuclear Plant refueling outages), merger-related expenses,
changes in interest expense, changes in income and property taxes, a charge for
a targeted employee separation plan and an extraordinary charge, as noted above.
The significant items affecting revenues, costs and earnings during the
three-month, six-month and 12-month periods ended June 30, 1999 and 1998 are
detailed below.
Electric Operations
Electric Operating Revenues Variations for periods ended June 30, 1999
from comparable prior-year periods
- --------------------------------------------------------------------------------
(Millions of Dollars) Three Months Six Months Twelve Months
- --------------------------------------------------------------------------------
Credit to customers $ 33 $ 23 $ 23
Rate variations (6) (11) (19)
Effect of abnormal weather (24) (20) 6
Growth and other (19) (2) (2)
Interchange sales 49 68 119
- --------------------------------------------------------------------------------
$ 33 $ 58 $ 127
- --------------------------------------------------------------------------------
The $33 million increase in second quarter electric revenues, compared to the
year-ago quarter, was primarily driven by a 147 percent increase in interchange
sales due to strong marketing efforts, as well as a lower credit to Missouri
electric customers (see Note 5 under Notes to Financial Statements for further
information). These benefits were partially offset by a 5 percent decrease in
native sales as a result of milder weather. Electric revenues were also affected
by rate decreases in both Missouri and Illinois (see Note 5 under Notes to
Financial Statements for further information).
Electric revenues for the first six months of 1999 increased $58 million
compared to the same 1998 period. The increase in revenues was primarily due to
a 71 percent increase in interchange sales due to strong marketing efforts and
decreased credits to Missouri electric customers (see Note 5 under Notes to
Financial Statements for further
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information). These benefits were partially offset by a 2 percent decline in
native sales, primarily due to milder weather, and rate decreases in both
Missouri and Illinois (see Note 5 under Notes to Financial Statements for
further information).
Electric revenues for the 12 months ended June 30, 1999, increased $127 million
compared to the prior 12-month period. The increase in revenues was primarily
driven by an 80 percent increase in interchange sales due to strong marketing
efforts and decreased credits to Missouri electric customers (see Note 5 under
Notes to Financial Statements for further information). These benefits were
partially offset by rate decreases in both Missouri and Illinois (see Note 5
under Notes to Financial Statements for further information).
Fuel and Purchased Power Variations for periods ended June 30, 1999
from comparable prior-year periods
- --------------------------------------------------------------------------------
(Millions of Dollars) Three Months Six Months Twelve Months
- --------------------------------------------------------------------------------
Fuel:
Variation in generation $ 7 $ 12 $ 42
Price (6) (11) (27)
Generation efficiencies and other - 2 5
Purchased power variation 32 39 35
- --------------------------------------------------------------------------------
$ 33 $ 42 $ 55
- --------------------------------------------------------------------------------
Fuel and purchased power costs for the three month, six month and twelve month
periods ended June 30, 1999, compared to the year ago comparable periods,
increased $33 million, $42 million and $55 million, respectively, primarily due
to increased generation and purchased power resulting from higher sales volumes,
partially offset by lower fuel prices.
Gas Operations
Gas revenues for the six months ended June 30, 1999, increased $2 million
compared to the prior-year period primarily due to an annual $12 million
Missouri gas rate increase effective February 1998. This increase was partially
offset by a 6 percent decrease in retail sales. Gas revenues for the twelve
months ended June 30, 1999, decreased $2 million compared to the year-ago period
primarily due to a 10 percent decline in retail sales, partially offset by an
annual $12 million Missouri gas rate increase effective February 1998.
Gas costs for the six months ended June 30, 1999, increased $2 million compared
to the year-ago period, primarily due to increased gas prices. Gas costs for the
twelve month period ended June 30, 1999, decreased $4 million compared to the
year-ago period, primarily due to lower sales and a decrease in gas prices.
Other Operating Expenses
Other operating expense variations reflected recurring factors such as growth,
inflation, labor and benefit increases.
Other operations expenses for the three and six months ended June 30, 1999,
decreased $5 million and $7 million, respectively, compared to the same year-ago
periods primarily due to decreased injuries and damages expenses based on claims
experience, partially offset by increased expenses associated with the year 2000
project. Other operations expenses increased $24 million for the 12-month period
ended June 30, 1999, compared to the same year-ago period primarily due to the
charge for the targeted separation plan and increased expenses associated with
the year 2000 project.
Maintenance expenses for the six months ended June 30, 1999, increased $3
million compared to the year-ago period primarily due to increased power plant
maintenance and tree trimming activity, partially offset by the absence of a
Callaway Nuclear Plant refueling in 1999. There was a Callaway refueling outage
during the six months ended June 30, 1998. The $4 million increase in
maintenance expenses for the 12-month period ended June 30, 1999, compared to
the prior 12-month period was primarily due to increased power plant maintenance
and tree trimming activity, partially offset by the absence of a refueling at
Callaway in 1999.
Taxes
Income taxes increased $4 million, $11 million and $35 million for the three,
six and 12 months ended June 30, 1999, respectively, due to higher pretax
income.
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Other Income and Deductions
Miscellaneous, net increased $2 million for the six months and twelve months
ended June 30, 1999, compared to the comparable year-ago periods, primarily due
to increased interest income and gains on the sale of property.
Balance Sheet
Changes in accounts and wages payable, other taxes accrued, and other current
liabilities resulted from the timing of various payments to taxing authorities
and suppliers.
The $25 million increase in other deferred credits and liabilities was primarily
due to the $20 million estimated credit to Missouri electric customers recorded
in the first quarter of 1999 under the three-year experimental alternative
regulation plan (see Note 5 under Notes to Financial Statements for further
information). The $146 million increase in intercompany notes receivable is due
to funds invested in a utility money pool (see Note 6 under Notes to Financial
Statements).
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $266 million for the six months
ended June 30, 1999, compared to $158 million during the same 1998 period.
Cash flows used in investing activities totaled $277 million and $104 million
for the six months ended June 30, 1999 and 1998, respectively. Construction
expenditures for the six months ended June 30, 1999, for constructing new or
improving existing facilities were $121 million. In addition, the Registrant
expended $19 million for the acquisition of nuclear fuel. Capital requirements
for the remainder of 1999 are expected to be principally for construction
expenditures and the acquisition of nuclear fuel. The Registrant also issued
intercompany notes receivable for $146 million through a utility money pool (see
Note 6 under Notes to Financial Statements for further information).
Cash flows used in financing activities were $23 million for the six months
ended June 30, 1999, compared to $44 million during the same 1998 period. The
Registrant's principal financing activity for the period was the payment of
dividends, partially offset by the issuance of long-term debt.
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 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 10 to 45 days). At June 30,
1999, the Registrant had committed bank lines of credit aggregating $136 million
(all of which were 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, 1999, the Registrant
had no outstanding short-term borrowings.
The Registrant also has a bank credit agreement due 2000 which permits the
borrowing of up to $300 million on a long-term basis, all of which was unused
and $226 million of which was available at June 30, 1999. Also, Ameren has a
bank credit agreement due 2002, which permits the borrowing of up to $200
million on a long-term basis. This credit agreement is available to Ameren and
its subsidiaries, including the Registrant. As of June 30, 1999, $158 million
was available for the Registrant's use.
Additionally, the Registrant has a lease agreement that provides for the
financing of nuclear fuel. At June 30, 1999, the maximum amount that could be
financed under the agreement was $120 million. Cash used in financing activities
for the first six months of 1999 included redemptions under the lease for
nuclear fuel of $7 million, offset by $38 million of issuances. At June 30,
1999, $98 million was financed under the lease.
RATE MATTERS
In March 1999, the Registrant filed delivery service tariffs with the Illinois
Commerce Commission (ICC) to comply with the requirements of the Electric
Service Customer Choice and Rate Relief Law of 1997. These tariffs would be used
by electric customers who choose to purchase their power from an alternative
supplier. Hearings were conducted in June 1999, and a hearing examiner's
proposed order was issued in July. The ICC is required to render a decision on
the delivery services tariffs by September 1, 1999.
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See Note 5 under Notes to Financial Statements for further discussion of Rate
Matters.
ELECTRIC INDUSTRY RESTRUCTURING
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Law) providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois.
One of the major provisions of the Law includes the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric supplier.
The phase-in of retail direct access begins on October 1, 1999, with large
commercial and industrial customers principally comprising the initial group.
The customers in this group represent approximately 7 percent of the
Registrant's total sales. Retail direct access will be offered to the remaining
commercial and industrial customers on December 31, 2000, and to residential
customers on May 1, 2002.
YEAR 2000 ISSUE
The Year 2000 Issue relates to how dates are stored and used in computer
systems, applications, and embedded systems. As the century date change occurs,
certain date-sensitive systems need to be able to recognize the year as 2000 and
not as 1900. This inability to recognize or properly treat the year as 2000 may
cause these systems to process critical financial and operational information
incorrectly. The Registrant's primary concern is the potential for any
interruption in providing electric and gas service to customers, as well as the
potential inability to process critical financial and operational information on
a timely basis, including billing its customers, if appropriate steps are not
taken to address this issue. Management has developed a Year 2000 plan (Plan)
covering Ameren, including AmerenUE, and Ameren's Board of Directors has been
briefed about the Year 2000 Issue and how it may affect the Registrant.
Ameren's Plan to resolve the Year 2000 Issue involves three phases: assessment,
planning, and implementation/ testing. Implementation of the Plan is directly
supervised by each area's responsible Vice President. A Year 2000 Project
Director coordinates the implementation of the Plan among functional teams who
are addressing issues specific to a particular area, such as nuclear and
non-nuclear generation facilities, energy management systems, gas distribution,
etc. Ameren has also engaged certain outside consultants, technicians and other
external resources to aid in formulating and implementing the Plan.
Ameren has completed its assessment phase, which included analyzing
date-sensitive electronic hardware, software applications and embedded systems
and has developed a compliance plan to address issues that were identified. Many
of the major corporate computer systems at Ameren are relatively new and
therefore are either Year 2000 compliant or only require minor modifications.
Also, several of the operating hardware and embedded systems (i.e.,
microprocessor chips) use analog rather than digital technology and thus are
unaffected by the two-digit date issue. In addition, Ameren has contacted
hundreds of vendors and suppliers to verify compliance.
Ameren has also completed its planning phase. Items that have been identified
for remediation have been prioritized into groups based on their significance to
Ameren's operations. The implementation/testing phase for all
components/applications is approximately 87 percent complete as of June 30,
1999. Ameren expects to complete remediation of its significant
components/applications by the end of the third quarter 1999.
With respect to third parties, for areas that interface directly with
significant vendors, Ameren has inventoried vendors and major suppliers and is
currently assessing their Year 2000 readiness through surveys, websites and
personal contact. Ameren plans to follow up with major suppliers and vendors and
verify Year 2000 compliance, where appropriate. Ameren has also queried its
health insurance providers. To date, Ameren is not aware of any problems that
would materially impact its financial condition, results of operations or
liquidity; however, neither Ameren nor the Registrant has the means of ensuring
that these parties will be Year 2000 compliant. The inability of those parties
to complete their Year 2000 resolution process could materially impact Ameren
and the Registrant.
Ameren is also addressing the impact of electric power grid problems that may
occur outside of its own electric system. Ameren has started Year 2000 electric
power grid impact planning through the system's various electric interconnection
affiliations and is working with the Mid-American Interchange Network (MAIN) to
begin planning
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Year 2000 operational preparedness and restoration scenarios. As of July 1, 1999
(the latest information available), MAIN had completed its assessment and
planning phases and was 99 percent complete with its implementation/ testing
phase. In addition, Ameren provides monthly status reports to the North American
Electric Reliability Council (NERC) to assist them in assessing Year 2000
readiness of the regional electric grid. As of July 1, 1999 (the latest
information available), NERC had completed its assessment and planning phases
and was 98 percent complete with its implementation/testing phase. Ameren
participated in a Year 2000 drill conducted by NERC in April 1999. The drill
focused on the testing of the backup systems of voice and data communications
needed to operate the electric power grids in the event of a partial
communication loss. The results of the drill at Ameren were successful.
Additional drills are planned. Through the Electric Power Research Institute
(EPRI), an industry-wide effort has been established to deal with Year 2000
problems affecting digital systems and equipment used by the nation's electric
power companies. Under this effort, participating utilities are working together
to assess specific vendors' system problems and test plans. The assessment will
be shared by the industry as a whole to facilitate Year 2000 problem solving.
In addressing the Year 2000 Issue, Ameren will incur internal labor costs as
well as external consulting and other expenses related to infrastructure
enhancements necessary to prepare for the new century. Ameren estimates that its
external costs (consulting fees and related costs) for addressing the Year 2000
Issue will range from $10 million to $15 million. As of June 30, 1999, Ameren
had expended approximately $7 million. Ameren's plans to complete Year 2000
modifications are based on management's best estimates, which are derived
utilizing numerous assumptions of future events including the continued
availability of certain resources, and other factors. However, there can be no
guarantee that these estimates will be achieved and actual results could differ
materially from those plans. Specific factors that might cause such material
differences include, but are not limited to, the availability and cost of
personnel trained in this area, the ability to locate and correct all relevant
computer codes, and similar uncertainties.
Ameren believes that, with appropriate modifications to existing computer
systems/components, updates by vendors and trading partners, and conversion to
new software and hardware in the ordinary course of business, the Year 2000
Issue will not pose significant operational problems for the Registrant.
However, if such conversions are not completed in a proper and timely manner by
all affected parties, the Year 2000 Issue could result in material adverse
operational and financial consequences to the Registrant, and there can be no
assurance that Ameren's efforts, or those of vendors and trading partners,
interconnection affiliates, NERC or EPRI to address the Year 2000 Issue will be
successful. Ameren is in the process of developing contingency plans to address
potential risks, including risks of vendor/trading partners noncompliance, as
well as noncompliance of any of the Registrant's material operating systems. The
first operational contingency plan addressing power grid issues was completed
during the first quarter of 1999. Contingency plans related to the business
areas were completed in July 1999. At this time, the Registrant is unable to
predict the ultimate impact, if any, of the Year 2000 Issue on the Registrant's
financial condition, results of operations or liquidity; however, the impact
could be material.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a financial instrument,
derivative or non-derivative, caused by fluctuations in interest rates and
equity prices. The following discussion of Ameren's, including AmerenUE'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 also faces risks that are
either non-financial or non-quantifiable. Such risks principally include credit
risk and legal risk and are not represented in the following analysis.
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,
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 1 percent in 2000 as compared to 1999, the
Registrant's interest expense would increase by approximately $6 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 as of June 30, 1999, continued to be outstanding throughout 2000, and that
the average interest rates for these instruments increased 1 percent over 1999.
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The model does not consider the effects of the reduced level of 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 and fuel
and purchased power. 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 AmerenUE has a Purchased Gas Adjustment Clause (PGA) 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. With
approval of the Missouri Public Service Commission, the Registrant participated
in an experimental program to control the volatility of gas prices paid by its
Missouri customers in the 1998-1999 winter months through the purchase of
financial instruments. This program concluded in April 1999.
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 risk for
purchased power, Ameren has established a subsidiary, AmerenEnergy, Inc., whose
primary responsibility includes managing market risks associated with the
changing market prices for purchased power for the Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for
purchased power, 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 AmerenEnergy
is allowed to utilize (which include forward contracts and futures contracts)
are dictated by a risk management policy, which has been reviewed with the
Auditing Committee of Ameren's Board of Directors. Compliance with the risk
management policy is the responsibility of a risk management steering committee,
consisting of Ameren officers and an independent risk management officer at
AmerenEnergy.
As of June 30, 1999, the fair value of derivative financial instruments exposed
to commodity price risk was immaterial. The Registrant expects an increase in
the derivative financial instruments used to manage risk in 1999 due to expected
growth at AmerenEnergy.
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, 1999, 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.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards for derivative instruments and for hedging activities and
requires recognition of all derivatives on the balance sheet measured at fair
value. In June 1999, the FASB issued SFAS 137, "Accounting for Derivative
Instruments and Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133," which delayed the effective date of SFAS 133 to all fiscal
quarters of all fiscal years beginning after June 15, 2000. Earlier application
is still encouraged. At this time, the Registrant is unable to determine the
impact of SFAS 133 on its financial position or results of operations upon
adoption; however, SFAS 133 could increase the volatility of the Registrant's
future earnings.
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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,
financial performance and the Year 2000 Issue. 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.
Factors include, but are not limited to, the effects of regulatory actions;
changes in laws and other governmental actions; competition; 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; fuel
prices and availability; generation plant performance; monetary and fiscal
policies; future wages and employee benefits costs; and legal and administrative
proceedings.
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UNION ELECTRIC COMPANY
BALANCE SHEET
UNAUDITED
(Thousands of Dollars, Except Shares)
<TABLE>
<CAPTION>
June 30, December 31,
ASSETS 1999 1998
- ------ ----------- ----------
<S> <C> <C>
Property and plant, at original cost:
Electric $9,086,644 $8,975,542
Gas 216,413 209,556
Other 35,845 35,994
---------- ----------
9,338,902 9,221,092
Less accumulated depreciation and amortization 4,235,038 4,110,250
---------- ----------
5,103,864 5,110,842
Construction work in progress:
Nuclear fuel in process 127,678 108,294
Other 109,698 127,168
---------- ----------
Total property and plant, net 5,341,240 5,346,304
---------- ----------
Investments and other assets:
Nuclear decommissioning trust fund 177,402 161,877
Other 40,588 45,688
---------- ----------
Total investments and other assets 217,990 207,565
---------- ----------
Current assets:
Cash and cash equivalents 13,559 47,337
Accounts receivable - trade (less allowance for doubtful
accounts of $6,906 and $6,678, respectively) 202,401 143,912
Unbilled revenue 90,282 97,361
Other accounts and notes receivable 43,821 55,502
Intercompany notes receivable 145,500 --
Materials and supplies, at average cost -
Fossil fuel 69,197 53,036
Other 94,202 91,831
Other 9,726 13,529
---------- ----------
Total current assets 668,688 502,508
---------- ----------
Regulatory assets:
Deferred income taxes 606,649 608,353
Other 156,310 165,134
---------- ----------
Total regulatory assets 762,959 773,487
---------- ----------
Total Assets $6,990,877 $6,829,864
========== ==========
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $5 par value, authorized 150,000,000 shares -
outstanding 102,123,834 shares $ 510,619 $ 510,619
Other paid-in capital, principally premium on
common stock 701,896 701,896
Retained earnings 1,198,452 1,211,610
---------- ----------
Total common stockholders' equity 2,410,967 2,424,125
Preferred stock not subject to mandatory redemption 155,197 155,197
Long-term debt 1,777,339 1,674,311
---------- ----------
Total capitalization 4,343,503 4,253,633
---------- ----------
Current liabilities:
Current maturity of long-term debt 119,379 117,269
Accounts and wages payable 183,399 242,522
Accumulated deferred income taxes 46,615 45,061
Taxes accrued 172,573 100,714
Other 188,876 151,385
---------- ----------
Total current liabilities 710,842 656,951
---------- ----------
Accumulated deferred income taxes 1,255,765 1,254,372
Accumulated deferred investment tax credits 141,403 144,175
Regulatory liability 152,513 159,317
Other deferred credits and liabilities 386,851 361,416
---------- ----------
Total Capital and Liabilities $6,990,877 $6,829,864
========== ==========
</TABLE>
See Notes to Financial Statements.
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UNION ELECTRIC COMPANY
STATEMENT OF INCOME
UNAUDITED
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
1999 1998 1999 1998 1999 1998
---- ---- ---- ---- ---- ----
OPERATING REVENUES:
<S> <C> <C> <C> <C> <C> <C>
Electric $ 608,429 $ 574,962 $ 1,069,563 $ 1,011,279 $ 2,348,810 $2,221,389
Gas 12,787 13,621 57,704 55,715 93,164 95,505
Other 151 93 171 267 274 488
---------- ---------- ----------- ----------- ----------- ----------
621,367 588,676 1,127,438 1,067,261 2,442,248 2,317,382
OPERATING EXPENSES:
Operations
Fuel and purchased power 168,842 135,847 289,417 247,624 572,242 517,099
Gas 8,557 8,456 30,357 28,435 51,418 54,926
Other 115,228 120,188 213,152 220,297 454,842 430,810
---------- ---------- ----------- ----------- ----------- ----------
292,627 264,491 532,926 496,356 1,078,502 1,002,835
Maintenance 67,617 66,830 118,240 114,875 225,360 221,381
Depreciation and amortization 64,918 64,254 130,323 128,775 261,335 254,072
Income taxes 49,647 45,831 80,902 70,263 228,024 193,401
Other taxes 50,266 54,443 99,868 102,045 210,612 211,590
---------- ---------- ----------- ----------- ----------- ----------
Total operating expenses 525,075 495,849 962,259 912,314 2,003,833 1,883,279
OPERATING INCOME 96,292 92,827 165,179 154,947 438,415 434,103
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used
during construction 2,219 1,201 4,888 2,218 7,655 4,849
Miscellaneous, net 1,387 1,409 2,715 890 12,729 11,065
---------- ---------- ----------- ----------- ----------- ----------
Total other income and deductions 3,606 2,610 7,603 3,108 20,384 15,914
INCOME BEFORE
INTEREST CHARGES 99,898 95,437 172,782 158,055 458,799 450,017
INTEREST CHARGES:
Interest 31,055 30,660 61,978 64,820 127,105 132,863
Allowance for borrowed funds
used during construction (1,826) (1,474) (3,608) (3,318) (6,235) (6,749)
---------- ---------- ----------- ----------- ----------- ----------
Net interest charges 29,229 29,186 58,370 61,502 120,870 126,114
INCOME BEFORE
EXTRAORDINARY CHARGE 70,669 66,251 114,412 96,553 337,929 323,903
---------- ---------- ----------- ----------- ----------- ----------
EXTRAORDINARY CHARGE
(NET OF INCOME TAXES) -- -- -- -- -- (26,967)
---------- ---------- ----------- ----------- ----------- ----------
NET INCOME 70,669 66,251 114,412 96,553 337,929 296,936
---------- ---------- ----------- ----------- ----------- ----------
PREFERRED STOCK DIVIDENDS 2,205 2,205 4,409 4,409 8,817 8,817
---------- ---------- ----------- ----------- ----------- ----------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 68,464 $ 64,046 $ 110,003 $ 92,144 $ 329,112 $ 288,119
========== ========== =========== =========== =========== ===========
</TABLE>
See Notes to Financial Statements.
-10-
<PAGE>
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
UNAUDITED
(Thousands of Dollars)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
1999 1998
---- ----
Cash Flows From Operating:
<S> <C> <C>
Net income $ 114,412 $ 96,553
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 125,655 123,981
Amortization of nuclear fuel 21,025 16,182
Allowance for funds used during construction (8,496) (5,536)
Deferred income taxes, net (2,153) (5,511)
Deferred investment tax credits, net (2,772) (2,857)
Changes in assets and liabilities:
Receivables, net (39,729) (94,796)
Materials and supplies (18,532) (2,435)
Accounts and wages payable (59,123) (41,978)
Taxes accrued 71,859 57,591
Other, net 63,718 16,742
--------- ---------
Net cash provided by operating activities 265,864 157,936
Cash Flows From Investing:
Construction expenditures (120,658) (100,525)
Allowance for funds used during construction 8,496 5,536
Nuclear fuel expenditures (19,313) (9,352)
Intercompany notes receivable (145,500) --
--------- ---------
Net cash used in investing activities (276,975) (104,341)
Cash Flows From Financing:
Dividends on common stock (123,161) (123,161)
Dividends on preferred stock (4,409) (4,409)
Redemptions -
Nuclear fuel lease (7,427) (51,152)
Short-term debt -- (21,300)
Issuances -
Nuclear fuel lease 38,430 7,620
Long-term debt 73,900 148,500
--------- ---------
Net cash used in financing activities (22,667) (43,902)
Net increase (decrease) in cash and cash equivalents (33,778) 9,693
Cash and cash equivalents at beginning of year 47,337 3,232
--------- ---------
Cash and cash equivalents at end of period $ 13,559 $ 12,925
========= =========
Cash paid during the periods:
Interest (net of amount capitalized) $ 58,025 $ 63,904
Income taxes, net $ 58,426 $ 62,138
</TABLE>
See Notes to Financial Statements.
-11-
<PAGE>
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
June 30, 1999
Note 1 - Union Electric Company (AmerenUE or the Registrant) is a wholly-owned
subsidiary of Ameren Corporation (Ameren), which is the parent company of two
utility operating companies, the Registrant and Central Illinois Public Service
Company (AmerenCIPS). Ameren is a registered holding company under the Public
Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the
merger of AmerenUE and CIPSCO Incorporated (the Merger). Both Ameren and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
operating companies are 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 companies--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. The
Registrant serves 1.1 million electric and 124,000 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
operates an electric generating and transmission facility in Illinois that
supplies 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
Securities and Exchange Commission. 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 1998
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. Registrant's financial statements were prepared to permit the
information required in the Financial Data Schedule (FDS), Exhibit 27, to be
directly extracted from the filed statements. The FDS amounts correspond to or
are calculable from the amounts reported in the financial statements or notes
thereto.
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 June 30, 1999 and 1998, are not necessarily indicative of trends for any
three-month, six-month, or twelve-month period.
Note 5 - On July 21, 1995, the Missouri Public Service Commission (MoPSC)
approved an agreement involving the Registrant's Missouri electric rates. The
Agreement included a three-year experimental alternative regulation plan that
provides that earnings in excess of a 12.61 percent regulatory return on equity
(ROE) will be shared equally between customers and shareholders and earnings
above 14 percent ROE will be credited to customers. The formula for computing
the credit uses twelve-month results ending June 30, rather than calendar year
earnings.
The Registrant recorded an estimated $43 million credit for the final year of
the original experimental alternative regulation plan. The MoPSC staff has
proposed adjustments to the Registrant's estimated $43 million credit, which if
ultimately accepted, could increase the Registrant's estimated credit up to
approximately $5 million. Hearings were held on this matter in June 1999, and a
final order from the MoPSC is expected by the end of 1999.
A new three-year experimental alternative regulation plan was included in the
joint agreement approved by the MoPSC in its February 1997 order approving the
Merger. Like the original plan, the new plan requires that earnings over a 12.61
percent ROE up to a 14 percent ROE will be shared equally between customers and
stockholders. The new three-year plan will also return to customers 90 percent
of all earnings above a 14 percent ROE up to a 16 percent ROE. Earnings above a
16 percent ROE will be credited entirely to customers. As of June 30, 1999, the
Registrant had recorded an estimated $20 million credit for the first year of
the new plan. This credit, which the Registrant expects to pay to Missouri
customers later this year, was reflected as a reduction in electric revenues.
-12-
<PAGE>
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 experimental alternative regulation plan. The MoPSC
staff proposed adjustments to the Registrant's methodology of calculating the
weather-adjusted credits. During the second quarter of 1999, the Registrant and
the MoPSC staff reached a settlement on the methodology for calculating the
weather-adjusted credits. This proposed settlement is subject to approval by the
MoPSC. In addition, the results of the regulatory proceeding associated with the
final year of the original experimental alternative regulation plan will impact
the final Missouri electric rate decrease as well. The Registrant estimates that
its Missouri electric rate decrease should approximate $15 million to $20
million on an annualized basis. A final order from the MoPSC is expected by the
end of 1999.
In conjunction with the Electric Service Customer Choice and Rate Relief Law of
1997 (the Law), a 5 percent residential electric rate decrease for the
Registrant's Illinois electric customers was effective August 1, 1998. This rate
decrease is expected to decrease electric revenues $3 million annually, based on
estimated levels of sales and assuming normal weather conditions. The Registrant
may be subject to additional 5 percent residential electric rate decreases in
each of 2000 and 2002, to the extent its rates exceed the Midwest utility
average at that time. The Registrant's rates are currently below the Midwest
utility average.
The Law also contains a provision requiring one-half of excess earnings from the
Illinois jurisdiction for the years 1998 through 2004 to be refunded to the
Registrant's customers. Excess earnings are defined as the portion of the
two-year average annual rate of return on common equity in excess of 1.5 percent
of the two-year average of an Index, as defined in the Law. The Index is defined
as the sum of the average for the twelve months ended September 30 of the
average monthly yields of the 30-year U. S. Treasury bonds plus prescribed
percentages ranging from 4 percent to 5 percent. In July 1999, Senate Bill 24
was passed which increased the prescribed percentages to 7 percent beginning in
2000. Filings must be made with the ICC on or before March 31 of each year 2000
through 2005. At this time, the Registrant is unable to determine the amount of
the credit it will be required to return to customers, if any, under the Law for
the two year period ended December 31, 1999.
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 $5 million
and $6 million, respectively, as of June 30, 1999 and December 31, 1998.
Intercompany payables included in accounts and wages payable totaled
approximately $31 million and $17 million, respectively, as of June 30, 1999 and
December 31, 1998.
In March 1999, the Registrant, along with Ameren Services Company and
AmerenCIPS, entered into a utility money pool agreement to coordinate and
provide for certain short-term cash and working capital requirements. Borrowings
under the agreement are limited to $500 million and are due on demand or within
one year. Interest is calculated on varying rates of interest depending on the
composition of internal and external funds in the money pool. The money pool is
administered by Ameren Services Company. The Registrant recorded an intercompany
note receivable of $146 million, representing funds invested in the utility
money pool as of June 30, 1999.
Note 7 - Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use" became effective on January 1,
1999. SOP 98-1 provides guidance on accounting for the costs of computer
software developed or obtained for internal use. Under SOP 98-1, certain costs,
may be capitalized and amortized over some future period. SOP 98-1 did not have
a material impact on the Registrant's financial position or results of
operations upon adoption.
The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on
the accounting for energy contracts entered into for the purchase or sale of
electricity, natural gas, capacity and transportation. The EITF reached a
consensus in EITF 98-10 that sales and purchase activities being performed need
to be classified as either trading or non-trading. Furthermore, transactions
that are determined to be trading activities would be recognized on the balance
sheet measured at fair value, with gains and losses included in earnings. EITF
98-10 includes factors or indicators to consider when determining if a
transaction is a trading or non-trading activity. Currently, AmerenEnergy, Inc.,
an energy marketing subsidiary of Ameren, enters into contracts for the sale and
purchase of energy on behalf of the Registrant. These transactions are
considered non-trading
-13-
<PAGE>
activities and are accounted for using the accrual or settlement method, which
represents industry practice. Should any of AmerenEnergy's future activities be
considered material trading activities based on the indicators provided in EITF
98-10, a change in accounting practice would be required. EITF 98-10 did not
have a material impact on the Registrant's financial position or results of
operations upon adoption.
Note 8 - Certain reclassifications were made to prior-year financial statements
to conform to current-period presentation.
-14-
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to "Electric Industry Restructuring" in Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 2 - Regulatory Matters in the Notes to Financial Statements
of the Registrant's Form 10-K for the year ended December 31, 1998 for
information regarding the Registrant's membership in the Midwest Independent
System Operator (Midwest ISO). In May 1999, the Missouri Public Service
Commission approved a stipulation and agreement authorizing the Registrant's
membership in the Midwest ISO for a six year transition period subject to
certain conditions and reporting requirements. The six year period will commence
on the first day that the Midwest ISO begins providing electric transmission
service.
Reference is made to "Liquidity and Capital Resources" in Item 7.
Management's Discussion and Analysis of Financial Conditions and Results of
Operations and Note 11 - Commitments and Contingencies in the Notes to Financial
Statements of the Registrant's Form 10-K for the year ended December 31, 1998
for information regarding the United States Environmental Protection Agency's
(EPA) issuance in 1997 of National Ambient Air Quality Standards for ozone and
particulate matter. In May 1997, the United States Court of Appeals for the
District of Columbia Circuit remanded the ambient air quality standards
regulations to EPA for reconsideration. At this time, the Registrant is unable
to predict the ultimate impact of those revised air quality standards on its
future financial condition, results of operations or liquidity.
ITEM 5. OTHER INFORMATION
Reference is made to Note 11 - Commitments and Contingencies in the
Notes to Financial Statements of the Registrant's Form 10-K for the year ended
December 31, 1998 for information concerning the expiration date of collective
bargaining agreements. The Registrant is engaged in labor negotiations with the
International Brotherhood of Electrical Workers and the International Union of
Operating Engineers and the collective bargaining agreements have been extended
so as to facilitate those negotiations. At this time, the Registrant is unable
to predict the impact of these negotiations on its future financial condition,
results of operations or cash flows.
Any stockholder proposal intended for inclusion in the proxy material
for the Registrant's 2000 annual meeting of stockholders must be received by the
Registrant by December 1, 1999.
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. At its August 1999
Board of Directors Meeting, the Registrant intends to amend its By-Laws to
change the date for holding its annual meeting of stockholders to the fourth
Tuesday of April in each year to coincide with the annual meeting date of its
parent, Ameren Corporation. Consequently, for the Registrant's 2000 annual
meeting of stockholders, written notice of any in-person stockholder proposal or
director nomination must be received not later than February 22, 2000 or earlier
than January 23, 2000.
-15-
<PAGE>
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 June
30, 1999.
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K. None.
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: August 13, 1999
Exhibit 12
UNION ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>
12 Months
Year Ended December 31, Ended
June 30,
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
Thousands of Dollars Except Ratios
<S> <C> <C> <C> <C> <C> <C>
Net Income $320,757 $314,107 $304,876 $301,655 $320,070 $337,929
Add-Extraordinary items net of tax - - - 26,967 - -
-------- -------- -------- -------- -------- --------
Net Income from continuing operations 320,757 314,107 304,876 328,622 320,070 337,929
-------- -------- -------- -------- -------- --------
Taxes based on income 203,827 207,734 196,210 199,763 212,554 227,806
-------- -------- -------- -------- -------- --------
Net income before income taxes 524,584 521,841 501,086 528,385 532,624 565,735
-------- -------- -------- -------- -------- --------
Add- fixed charges:
Interest on long term debt 117,838 121,738 120,547 125,705 124,766 119,962
Other interest 17,770 7,501 7,828 9,299 1,660 3,654
Rentals 1,299 3,330 3,458 3,727 3,416 3,635
Amortization of net debt premium, discount,
expenses and losses 5,504 5,502 4,269 3,672 3,522 3,489
-------- -------- -------- -------- -------- --------
Total fixed charges 142,411 138,071 136,102 142,403 133,364 130,740
-------- -------- -------- -------- -------- --------
Earnings available for fixed charges 666,995 659,912 637,188 670,788 665,988 696,475
======== ======== ======== ======== ======== ========
Ratio of earnings to fixed charges 4.68 4.78 4.68 4.71 4.99 5.32
======== ======== ======== ======== ======== ========
Earnings required for preferred dividends:
Preferred stock dividends 13,252 13,250 13,249 8,817 8,817 8,817
Adjustment to pre-tax basis 7,262 7,558 7,363 4,257 4,649 4,719
-------- -------- -------- -------- -------- --------
20,514 20,808 20,612 13,074 13,466 13,536
Fixed charges plus preferred stock dividend
requirements 162,925 158,879 156,714 155,477 146,830 144,276
======== ======== ======== ======== ======== ========
Ratio of earnings to fixed charges plus
preferred stock dividend requirements 4.09 4.15 4.06 4.31 4.53 4.82
======== ======== ======== ======== ======== ========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
Exhibit 27
UNION ELECTRIC COMPANY
10-Q JUNE 30, 1999
FINANCIAL DATA SCHEDULE UT
PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY HOLDING COMPANIES
APPENDIX E TO ITEM 601 (C) OF REGULATION S-K
(Thousands of Dollars)
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,341,240
<OTHER-PROPERTY-AND-INVEST> 177,402
<TOTAL-CURRENT-ASSETS> 668,688
<TOTAL-DEFERRED-CHARGES> 40,588
<OTHER-ASSETS> 762,959
<TOTAL-ASSETS> 6,990,877
<COMMON> 510,619
<CAPITAL-SURPLUS-PAID-IN> 701,896
<RETAINED-EARNINGS> 1,198,452
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,410,967
0
155,197
<LONG-TERM-DEBT-NET> 1,698,816
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 100,000
0
<CAPITAL-LEASE-OBLIGATIONS> 78,523
<LEASES-CURRENT> 19,379
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,527,995
<TOT-CAPITALIZATION-AND-LIAB> 6,990,877
<GROSS-OPERATING-REVENUE> 1,127,438
<INCOME-TAX-EXPENSE> 80,902
<OTHER-OPERATING-EXPENSES> 881,357
<TOTAL-OPERATING-EXPENSES> 962,259
<OPERATING-INCOME-LOSS> 165,179
<OTHER-INCOME-NET> 7,603
<INCOME-BEFORE-INTEREST-EXPEN> 172,782
<TOTAL-INTEREST-EXPENSE> 58,370
<NET-INCOME> 114,412
4,409
<EARNINGS-AVAILABLE-FOR-COMM> 110,003
<COMMON-STOCK-DIVIDENDS> 123,161
<TOTAL-INTEREST-ON-BONDS> 0 <F1>
<CASH-FLOW-OPERATIONS> 265,864
<EPS-BASIC> 0.00 <F2>
<EPS-DILUTED> 0.00 <F2>
<FN>
<F1> Required in fiscal year-end only.
<F2> Information not normally dislosed in financial statements and notes.
</FN>
</TABLE>
