Exhibit 13.A.3
Iowa-Illinois Gas and Electric Company
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The operating results and financial condition of Iowa-
Illinois Gas and Electric Company (the Company) reflect the
Company's regulated utility operations and the operations of its
wholly owned non-regulated subsidiary, InterCoast Energy Company
(InterCoast).
The Company's regulated utility operations are concerned
with the generation, transmission and distribution of electric
energy and the purchase, sale and transportation of natural gas.
The business strategy of InterCoast is focused on areas
closely related to the Company's core electric and gas utility
businesses. These activities are: oil and natural gas; energy
services; and financial investments.
OVERVIEW
Contributions to consolidated earnings per share for the
last three years are:
1994 1993 1992
Utility operations....... $1.52 $1.42 $1.11
InterCoast............... .31 .43 .34
Earnings per share....... 1.83 1.85 1.45
The utility's ratio of earnings to fixed charges (pretax),
excluding the income of InterCoast, was 3.93 in 1994 and 3.54 in
1993. The return on average consolidated common equity was 10.8%
for 1994 and 10.9% for 1993.
In January 1995, the Board of Directors declared the
quarterly dividend of 43.25 cents per common share, the rate
established in January 1992.
RESULTS OF OPERATIONS
Operating Revenues
Electric revenues increased in 1994 compared to 1993
primarily due to higher retail rates, increased retail unit sales
reflecting increases in commercial and industrial usage and
increased fuel and energy cost billings to retail customers.
These increases were partially offset by lower sales for resale.
Variations in fuel and energy cost billings reflect corresponding
changes in fuel and purchased energy costs from levels included
in base rates and, thus, do not affect net income.
On July 26, 1993, the Company implemented temporary electric
rates in its Iowa jurisdiction designed to increase annual
electric revenues by $6.8 million. The Iowa Utilities Board
(IUB) approved final rates at the $6.8 million increase level,
which became effective April 15, 1994.
On July 28, 1993, an annual electric rate increase in
Illinois of $9.6 million became effective following Illinois
Commerce Commission (ICC) approval. On January 15, 1994, an
additional annual electric increase of $230,000 related to the
increase in the federal corporate income tax rate became
effective on rehearing. Also on rehearing, the ICC approved a
rate rider that permits the Company to recover costs of
investigation, remediation and litigation relating to former
manufactured gas plant sites. In addition, on January 1, 1994,
nuclear decommissioning costs included in Illinois customer
billings through a rate rider were increased by $1.2 million
annually. The previously mentioned rate increases were partially
offset by a $3.2 million decrease in revenues in 1994 reflecting
the expiration of the Company's Louisa Phase-In Clause (LPIC) on
June 30, 1993. Increased revenues collected through rate riders
relating to former manufactured gas plant sites and nuclear
decommissioning and the decreased revenues from expiration of the
LPIC did not affect net income due to a corresponding increase or
decrease in costs.
Electric revenues increased in 1993 compared to 1992
primarily due to increased revenues reflecting higher retail
rates, increased retail sales volumes reflecting more typical
temperatures (approximately 40% warmer in 1993 than 1992) and
increased sales for resale.
The Company began billing higher electric rates of $7.5
million on an annual basis in Iowa in July 1992. Effective
January 1, 1993, the IUB approved a permanent annual increase in
that rate proceeding of $10.4 million, including $4.8 million
related to nuclear decommissioning costs, which did not affect
net income due to a corresponding increase in expense. (See
Provision for Depreciation.) As previously mentioned, rates were
also increased in July of 1993 in Iowa and Illinois. These rate
increases were partially offset by a $3.3 million decrease in
revenues in 1993 reflecting the expiration of the LPIC on June
30, 1993. In addition, the Company began billing its customers
for the costs of electric energy-efficiency plans in Illinois in
April of 1993. Such billings of approximately $700,000 did not
affect net income due to a corresponding amortization of
previously deferred costs. Partially offsetting these increases
were lower fuel and energy cost billings to retail customers.
The changes in electric revenues are shown below:
Revenue Increase (Decrease) from Prior Year
1994 1993
(In thousands)
Change in Retail Unit Sales..... $ 6,900 $ 7,900
Change in Retail Fuel and Energy
Adjustment Clause Billings.... 3,400 ( 600)
Change in Sales for Resale...... ( 1,800) 5,900
Change Due to the Effect of
Higher Retail Rates........... 8,900 12,700
$ 17,400 $ 25,900
Gas revenues decreased in 1994 compared to 1993. The
principal factors contributing to the decrease were decreased
sales volumes reflecting temperatures that were 7% warmer than
1993 and lower purchased gas cost billings. Higher rates in
Illinois, as discussed below, were partially offset by a decrease
of $1.1 million in energy-efficiency plan billings. Changes in
energy-efficiency plan billings do not affect net income due to
corresponding changes in cost. Variations in purchased gas cost
billings reflect corresponding changes in cost of gas sold and,
thus, do not affect net income.
On July 28, 1993, an annual gas rate increase in Illinois of
$2 million became effective following ICC approval. On January
15, 1994, an additional annual gas increase of $49,000 related to
the increase in the federal corporate income tax rate became
effective on rehearing. As noted previously, also on rehearing,
the ICC approved a rate rider that permits the Company to recover
costs of investigation, remediation and litigation relating to
former manufactured gas plant sites.
Gas revenues increased in 1993 compared to 1992. The
principal factors contributing to the increase were increased
sales volumes reflecting temperatures that were 10% colder than
1992, higher purchased gas cost billings and higher rates. In
addition to the higher rates in Illinois, as discussed
previously, the Company began billing higher gas rates of $4.7
million on an annual basis in Iowa in July 1992. Effective
January 1, 1993, the IUB approved a permanent annual increase of
$5.4 million. In addition, the Company began billing its
customers for the costs of gas energy-efficiency plans in
Illinois in April of 1993. Such billings of approximately $1.1
million did not affect net income due to a corresponding
amortization of previously deferred costs.
The changes in gas revenues are shown below:
Revenue Increase (Decrease) from Prior Year
1994 1993
(In thousands)
Change in Purchased Gas
Adjustment Clause Billings.... $( 400) $ 8,600
Change in Unit Sales............ (7,700) 9,000
Change Due to the Effect of
Higher Rates.................. 400 4,400
$(7,700) $22,000
Operation
Changes in the cost of electric fuel, energy and capacity
reflect fluctuations in generation mix, fuel cost and energy and
capacity purchases. Increased fuel, energy and capacity costs in
1994 compared to 1993 are primarily due to increased average unit
fuel and energy costs.
Increased fuel, energy and capacity costs in 1993 compared
to 1992 are primarily due to increased sales.
Cost of gas sold decreased in 1994 compared to 1993
primarily due to decreased purchased gas costs from suppliers and
lower gas storage withdrawals reflecting warmer temperatures in
1994. Substantially offsetting these decreases were increased
pipeline demand and transition costs.
Cost of gas sold increased in 1993 compared to 1992
primarily due to increased purchased gas costs from suppliers and
higher gas purchases reflecting colder temperatures in 1993.
Other operation and maintenance increased in 1994 compared
to 1993 and in 1993 compared to 1992 primarily due to increased
costs at the Quad-Cities Nuclear Power Station (Quad-Cities
Station). In January 1994, the Company was advised by ComEd,
operator and 75 percent owner of the Quad-Cities Station, that
the Nuclear Regulatory Commission (NRC) had placed the station on
its list of plants with adverse performance trends. The NRC
concerns with the Quad-Cities Station include deficiencies in the
condition of certain station equipment and the effectiveness of
the operators of the units in identifying and responding to
certain operational problems. ComEd has provided written and
verbal responses to the NRC and is working to resolve the
concerns. As of February 1995, the Quad-Cities Station remains
on the list of plants with adverse performance trends. The
Company anticipates that it will need to make operating and
capital expenditures in future years in connection with the
resolution of the noted deficiencies at the Quad-Cities Station.
In addition, increases were experienced in other operation and
maintenance expense in 1994 related to costs associated with the
merger with Midwest Resources Inc. and an ice storm in the Quad-
Cities service area. The increase in other operation expense in
1993 also reflects adoption of Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions, and amortization of previously
deferred costs of energy-efficiency programs.
Provision for Depreciation
The provision for depreciation increased in 1994 compared to
1993 and in 1993 compared to 1992 primarily due to a greater
provision for nuclear decommissioning, consistent with current
ratemaking treatment, and greater utility plant investment.
Depreciation and Equity Funds
Recovered Under Louisa Phase-In Clause
The decreases in the amount being recovered under the LPIC
in 1994 compared to 1993 and in 1993 compared to 1992 reflect the
expiration of the LPIC on June 30, 1993.
Operating Income Taxes
Income tax expense increased in 1994 compared to 1993 and in
1993 compared to 1992 primarily due to higher taxable income.
The Omnibus Budget Reconciliation Act of 1993 (the Act) was
signed into law on August 10, 1993. In accordance with Statement
of Financial Accounting Standards No. 109, Accounting for Income
Taxes, which the Company adopted January 1, 1993, the adjustments
required as a result of the increase in income tax rates included
in the Act were recorded in the third quarter of 1993. The
primary financial effect of the new tax law was an increase in
net regulatory assets and deferred income tax liabilities of
approximately $8 million.
Oil and Gas Revenues of InterCoast Energy Company
Oil and gas revenues of InterCoast increased in 1994
compared to 1993 primarily due to higher production volumes
reflecting additional acquired reserves and successful drilling
results, partially offset by lower oil and gas prices. In the
event that 1995 oil and gas prices are below such prices for
1994, oil and gas operating income could be reduced from 1994
levels.
Oil and gas revenues of InterCoast increased in 1993
compared to 1992 primarily due to higher production volumes
reflecting additional acquired reserves, successful drilling
results and higher gas prices, partially offset by lower oil
prices.
Other Income of InterCoast Energy Company
Other income of InterCoast increased in 1994 compared to
1993 primarily due to greater income from special-purpose funds
and increased gains on the disposition of direct holdings in
common stock, substantially offset by lower energy project
income.
Expenses of InterCoast Energy Company
Expenses of InterCoast increased in 1994 compared to 1993
primarily due to greater oil and gas expenses, increased interest
expense reflecting higher rates and greater other operating
expenses.
Expenses of InterCoast increased in 1993 compared to 1992
primarily due to greater oil and gas expenses, increased interest
expense reflecting InterCoast's additional long-term debt
outstanding and greater other operating expenses.
Utility Interest Charges
Decreased interest on long-term debt in 1994 compared to
1993 and in 1993 compared to 1992 reflects refinancing of several
series of long-term debt at lower interest rates.
Allowance for Funds Used During Construction
The increase in the total allowance for funds used during
construction (AFUDC) for 1994 compared to 1993 is primarily due
to a higher AFUDC rate, 5.6% compared to 3.3%, and higher
construction work in progress balances.
Other Matters
On December 21, 1994, the shareholders of the Company,
Midwest Resources Inc. and Midwest Power Systems Inc. approved a
strategic merger of equals to form MidAmerican Energy Company
(MidAmerican). MidAmerican will be structured as a utility with
the Company, Midwest Resources Inc. and Midwest Power Systems
Inc. being merged into the new company.
Pursuant to the terms of the merger agreement, Midwest
Resources' common shareholders will receive one share of
MidAmerican for each Midwest share and the Company's shareholders
will receive 1.47 shares of MidAmerican for each Company share.
At the effective date of the merger, each series of the Company's
preference shares then outstanding will be converted into an
equal number of shares of MidAmerican preferred stock.
Approval of the merger is required from the following
regulatory agencies: the IUB, the ICC and the Federal Energy
Regulatory Commission (FERC). The NRC approval for the transfer
of the Quad-Cities Station license to MidAmerican must also be
obtained.
Applications for approval of the merger were filed with the
IUB and the ICC in October 1994. An application for approval of
the merger was filed with the FERC in November 1994. At the same
time, consistent with FERC policy, the Company filed open access,
comparable services tariffs with the FERC, which tariffs will
allow others to use MidAmerican's electric transmission system in
a manner comparable to its use by MidAmerican. In January 1995,
the IUB issued an order approving the merger. The ICC and FERC
are expected to issue orders on the merger by mid 1995. A filing
with the NRC was made in November 1994. Completion of the merger
is expected in the second half of 1995.
The formation of MidAmerican will create a larger, stronger
company, which will be better positioned to grow and succeed
within the emerging competitive utility industry. In this new
environment, successful utilities will need financial strength,
market leadership and low costs. The merger will address these
elements.
The Company expects that competitive pressures in the
electric industry initially will be focused on industrial sales.
While about 25% of Iowa-Illinois' electric revenues come from
industrial customers, only about 20% of MidAmerican's electric
revenues will come from this customer group. The industrial
rates of both Iowa-Illinois and Midwest Resources are well below
national and regional averages, providing MidAmerican with a
strong competitive position in the industrial sector.
MidAmerican also will be well-positioned for competition in
the natural gas industry, with low-cost reliable gas supply
portfolios and multiple pipeline suppliers. The residential gas
rates of both companies are well below national averages.
The merger will provide opportunities to achieve significant
long-term benefits for shareholders, customers, employees and the
communities served by the two companies. These benefits are:
increased size and stability, better use of generating capacity,
coordination of dispatch, savings on purchases, coordination of
non-regulated businesses and reduced administrative costs. It is
estimated the merger will result in savings of nearly $500
million over 10 years.
Iowa-Illinois and Midwest Resources have announced plans to
reduce their combined work forces by a total of approximately 15
percent in conjunction with development of a restructured
organization to be effective at the completion of the merger. As
part of these reductions, the companies are offering incentive
retirement and severance programs to employees. The companies
estimate these programs will reduce 1995 after-tax earnings of
MidAmerican by approximately $9 million, or 9 cents a share, if
the merger is consummated in 1995.
Since utility properties are accounted for, and reflected in
the cost of service on which utility rates are based, at
historical cost, the potentially material effect of inflation and
changing prices is not reflected in the consolidated financial
statements.
The strategy of the non-regulated business is focused on
areas that relate closely to the Company's core utility
businesses: oil and natural gas; energy services; and financial
investments.
Changes in the electric utility industry may provide some
new opportunities for InterCoast. Continental Power Exchange
Inc. (CPE), a subsidiary of InterCoast, was established in March
1994. CPE was formed to operate an information system
facilitating the real-time exchange of power in the electric
industry. The services will be initially available to those who
buy and sell bulk power in the next-hour bulk power market.
LIQUIDITY AND CAPITAL RESOURCES
In 1994, 1993 and 1992, net cash from utility operating
activities, after dividends, was $67 million, $68 million and $30
million, respectively.
Utility construction expenditures totaled $80.3 million in
1994. The Company's current utility construction program
forecast calls for expenditures of $84.3 million in 1995. In
excess of 75% of these expenditures are expected to be met from
cash generated from operations. The Company's utility capital
requirements for the years 1995-1999 include budgeted
construction expenditures of $299.9 million, expected
contributions to nuclear decommissioning trust funds of $43.2
million and maturities, sinking funds and redemptions related to
long-term debt of $98.3 million. The estimated 1995-1999
construction expenditures include $72.1 million for electric
production construction (principally at the Quad-Cities Station),
$58.8 million for electric transmission and distribution system
construction, $45.0 million for nuclear fuel, $90.4 million for
gas plant construction and $33.6 million for general plant
construction, all of which are expected to be met by cash
generated from operations.
The Company has a Dividend Reinvestment and Share Purchase
Plan. Effective with the June 1994 dividend, this Plan provides
for the issuance of new shares with dividends reinvested and
optional cash investments by shareholders.
The Company's budgeted construction expenditures do not
include any amounts that may be required to pay the Company's
share of the cost of replacing certain stainless steel piping at
the Quad-Cities Station. Although such expenditures could be
required, they are not expected to be required.
Accumulated deferred income taxes at December 31, 1994
include offsetting benefits related to federal and state
Alternative Minimum Tax (AMT) in the amounts of $29.2 million in
federal AMT and $5.4 million in state AMT. The AMT credits may
be carried forward indefinitely to offset future regular tax
liabilities.
On December 15, 1994, the Company redeemed all of its
outstanding preferred shares. The redemption was made at a
premium, which resulted in a charge to net income on common
shares of $312,000.
In January 1995, $12.75 million of floating rate Pollution
Control Refunding Revenue Bonds, due 2025, were issued. Proceeds
from this financing will be used to redeem $12.75 million of
collateralized Pollution Control Revenue Bonds, 5.8% Series, due
2007.
In 1993, the Company sold $176.1 million principal amount of
First Mortgage Bonds and Pollution Control Obligations to
refinance $160.2 million principal amount of First Mortgage
Bonds, Pollution Control Obligations and short-term debt. In
addition, the Company sold $10.0 million of Preference Stock
principally to refinance $8.6 million of Preference Stock. The
balance of such proceeds was used for general corporate purposes.
The aggregate amounts of maturities and cash sinking fund
requirements for long-term debt outstanding at December 31, 1994
are $145,000 for 1995 and $98.2 million for the years 1996-1999.
At December 31, 1994, the Company had bank lines of credit
of $72.8 million to provide short-term financing for its utility
operations. All such lines of credit were unused. The Company
generally maintains compensating balances under its bank line of
credit arrangements. The Company has regulatory authority to
incur up to $100 million of short-term debt for its utility
operations. At December 31, 1994, the Company had $67.5 million
of outstanding short-term commercial paper notes.
The capitalization ratios for the Company's utility
businesses (including short-term debt, long-term debt maturing
within one year and preference shares redeemable within one year)
at the end of each of the last three years were as follows:
December 31,
1994 1993 1992
Long-term debt.............. 43.9% 45.0% 40.8%
Short-term debt............. 8.0 3.7 6.4
Total debt............... 51.9 48.7 47.2
Preferred and Preference
stock equity.............. 5.9 8.5 8.4
Common stock equity......... 42.2 42.8 44.4
100.0% 100.0% 100.0%
The Company's selections of long-term financing alternatives
are affected by provisions of its Mortgage relating to its First
Mortgage Bonds.
Under the Mortgage, the Company may issue First Mortgage
Bonds on the basis of 60% of available net property additions,
provided net earnings available for interest (before income
taxes) are at least two times annual interest charges on First
Mortgage Bonds and Prior Lien Bonds then to be outstanding. Not
more than 10% of such net earnings can be derived from certain
sources, principally non-operating income (which includes AFUDC).
As of December 31, 1994, available net property additions would
have permitted the issuance of at least $240 million principal
amount of additional First Mortgage Bonds.
Under the Articles of Incorporation, the Company may not
become liable for debt (other than short-term indebtedness not
exceeding 10% of the sum of items (a) and (b) below, or
indebtedness issued for purposes of refunding, reacquiring or
retiring certain securities) if, after becoming liable, the total
principal amount of all indebtedness (excluding short-term
indebtedness, as defined above) would exceed 65% of the aggregate
of (a) the total principal amount of all long-term indebtedness
and (b) the capital and surplus of the Company.
The Company's First Mortgage Bond ratings as assigned by
Duff & Phelps Inc., Fitch Investors' Service, Moody's Investor
Services Inc. and Standard & Poor's Corporation are AA-, AA, Aa3
and AA-, respectively.
In April 1992, the FERC issued Order No. 636, directing a
restructuring by interstate pipeline companies for their natural
gas sales and transportation services. The FERC Order
contemplated that transitional gas supply realignment costs
related to this restructuring may be billed by interstate
pipelines to their customers. At December 31, 1994, a regulatory
asset of $23.5 million, with an offsetting non-current Other
Liability, has been recorded. In addition, the Company estimates
it may incur other future billings of approximately $15 million
related to such restructuring. The Company is currently
recovering such cost through rates.
The Company is investigating five properties currently owned
by the Company which were, at one time, sites of gas
manufacturing plants. The purpose of these investigations is to
determine whether waste materials are present, whether such
materials constitute an environmental or health risk, and whether
the Company has any responsibility for remedial action. One site
is located in Illinois and four sites are located in Iowa. With
regard to the Illinois property, the Company has signed a working
agreement with the Illinois Environmental Protection Agency to
perform further investigation to determine whether waste
materials are present and, if so, whether such materials
constitute an environmental or health risk. At December 31,
1994, an estimated liability of $3.3 million has been recorded
for litigation, investigation and remediation related to the
Illinois site. A regulatory asset has been recorded reflecting
anticipated cost recovery through rates in Illinois. With regard
to the Iowa sites, no agreement or consent order has been
negotiated to perform any site investigations or remediation.
The Company has recorded a $4 million estimated liability for the
Iowa sites. A regulatory asset has been recorded based on the
current regulatory treatment of comparable costs in Iowa. The
estimated recorded liabilities for these properties are based
upon preliminary data. Thus, actual costs could vary
significantly from the estimates. In addition, insurance
recoveries for some or all of the costs may be possible, but the
liabilities recorded have not been reduced by any estimate of
such recoveries. Although the timing of incurred costs,
recoveries and the inclusion of provision for such costs in rates
may affect the results of operations in individual periods,
management believes that the outcome of these issues will not
have a material adverse effect on the Company's financial
position or results of operations.
Clean Air Act legislation was signed into law in November
1990. The Company has four jointly and one wholly owned coal-
fired generating stations, which represent approximately 65% of
the Company's electric generating capability. Each of these
facilities will be affected to varying degrees by the
legislation.
Only one unit at the wholly owned generating station,
representing approximately 10% of the Company's electric
generating capability, will be impacted by the emission reduction
requirements effective in 1995. Beginning in 1995, this unit
will be required to hold allowances, issued by the federal
government, in order to emit sulfur dioxide. The compliance
strategy for this unit includes modifications to allow for
burning low-sulfur coal, modifications for nitrogen oxide control
and installation of a new emission monitoring system. The
Company's remaining construction expenditures relative to this
work are estimated to be $2.5 million.
The four generating stations not affected until 2000 already
burn low-sulfur coal, so additional capital costs will not be
incurred for sulfur dioxide emission reduction requirements.
Beginning in 2000, these facilities will be required to hold
allowances, issued by the federal government, in order to emit
sulfur dioxide. Installation of low nitrogen oxide burners is
required at one of these facilities and existing emission
monitoring systems at all four facilities require upgrading. The
Company's remaining construction cost for this work is estimated
to be $1.4 million.
It is anticipated that any costs incurred by the Company to
comply with the Clean Air Act legislation would be included in
the cost of service on which the Company's rates for utility
service are based.
The National Energy Policy Act of 1992 established funding
for the decontamination and decommissioning of nuclear enrichment
facilities operated by the Department of Energy (DOE). A portion
of such funding is to be collected over a 15-year period, which
began in 1992, from electric utilities that had previously
purchased enrichment services from the DOE. At December 31,
1994, the Company's liability for its share of such funding was
$9.2 million. In 1994, 1993 and 1992, $849,000, $770,000 and
$200,000 of such payments were charged to fuel expense and
recognized in the energy adjustment clauses.
In September 1993, Medallion Production Company acquired all
the outstanding capital stock of DKM Resources Inc. from the
Dyson-Kissner-Moran Corporation, New York. Medallion is the oil
and gas business of InterCoast. The transaction totaled more
than $50 million and more than doubled Medallion's oil and gas
reserve base.
Capital expenditures for InterCoast during 1995 are
estimated to be approximately $65 million. Actual capital
expenditures for InterCoast are dependent on overall InterCoast
performance and general market conditions.
InterCoast's unsecured Senior Notes (Notes) are issued in
private placement transactions. All Notes are issued without
recourse to the parent Company. In November 1994, InterCoast
issued $70 million of 8.52% Notes due 2002 in a private placement
transaction with four insurance companies. The Notes have
sinking fund requirements in 2000 and 2001.
InterCoast's aggregate amounts of maturities and cash
sinking fund requirements for long-term debt outstanding at
December 31, 1994 are $64 million for 1995 and $169 million for
the years 1996-1999. Amounts due in 1995 are expected to be
refinanced with debt instruments and operating cash flow.
InterCoast has a $110 million unsecured revolving credit
facility agreement, which matures in February 1996. Borrowings
under this agreement may be on a fixed rate, floating rate or
competitive bid rate basis. All such borrowings are without
recourse to the parent Company. Borrowings at December 31, 1994
were $35 million at a weighted average interest cost of 6.6%.
Borrowings at December 31, 1993 were $44.5 million at a weighted
average interest cost of 4.1%.
InterCoast is subject to certain restrictions under the
terms of its borrowing arrangements. Such restrictions include
provisions which limit the amounts that can be expended for
dividends and the issuance of additional debt. At December 31,
1994, $23.2 million was available for dividends. In addition, at
December 31, 1994, under the most restrictive of such provisions,
additional debt up to $11 million could be issued.
The Company's consolidated capitalization ratios (including
short-term debt, long-term debt maturing within one year and
preference shares redeemable within one year) at the end of each
of the last three years were as follows:
December 31,
1994 1993 1992
Long-term debt............... 52.1% 52.9% 49.2%
Short-term debt.............. 5.2 2.4 4.3
Total debt................ 57.3 55.3 53.5
Preferred and Preference
stock equity............... 3.9 5.5 5.7
Common stock equity.......... 38.8 39.2 40.8
100.0% 100.0% 100.0%
Quarterly common stock dividends were paid in 1994 and 1993
at a rate of 43.25 cents per share, a total of $1.73 for each of
the years.