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:
1993 1992 1991
Utility operations....... $1.42 $1.11 $1.58
InterCoast............... .43 .34 .28
Earnings per share....... $1.85 $1.45 $1.86
Earnings increased in 1993 compared to 1992 primarily due to
more typical weather, new rate levels, utility cost control
programs and an increased contribution from InterCoast.
The utility's ratio of earnings to fixed charges (pretax),
excluding the income of InterCoast, was 3.54 in 1993 and 2.77 in
1992. The return on average consolidated common equity was 10.9%
for 1993 and 8.7% for 1992.
In January 1994, 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 1993 compared to 1992
primarily due to increased revenues reflecting higher rates,
increased retail sales volumes reflecting more typical
temperatures (approximately 40% warmer in 1993 than 1992 when
measured by cooling degree days) and increased sales for resale.
The Company began billing higher electric rates in Iowa in
July 1992. Effective Jan. 1, 1993, the Iowa Utilities Board
(IUB) approved a permanent annual increase of $10.4 million,
including $4.8 million related to nuclear decommissioning costs
which will not affect net income due to a corresponding increase
in expense. (See Provision for Depreciation.) In addition, a
temporary annual electric rate increase in Iowa of $6.8 million
became effective July 26, 1993. In 1993, approximately $3.1
million was billed, subject to refund, pursuant to such temporary
rates. In February 1994, the IUB approved rates at the $6.8
million level.
On July 28, 1993, an annual electric rate increase in
Illinois of $9.6 million became effective following Illinois
Commerce Commission (ICC) approval. On Jan. 15, 1994, an
additional electric increase of $230,000 related to the increase
in the federal corporate income tax rate became effective
following ICC approval on rehearing. The ICC also approved a
rate rider which permits the Company to recover costs of
investigation, remediation and litigation relating to former
manufactured gas plant sites. Base rate increases were partially
offset by a $3.3 million decrease in revenues in 1993 reflecting
the expiration of the Company's Louisa Phase-In Clause on June
30, 1993. In addition, the Company began billing its customers
for the costs of energy-efficiency plans in Illinois in April of
1993. Such electric billings of approximately $700,000 in 1993
will not affect net income due to a corresponding amortization of
previously deferred costs.
Partially offsetting these rate increases were lower fuel
and energy cost billings to retail customers. 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.
Electric revenues decreased in 1992 compared to 1991
primarily due to decreased retail sales volumes reflecting
temperatures which were approximately 50 percent cooler in 1992.
Revenues also decreased due to lower sales for resale and lower
fuel and energy cost billings to retail customers. Partially
offsetting these decreases were increased revenues due to the
effect of higher rates in Iowa beginning in July 1992.
The changes in electric revenues are shown below:
Revenue Increase (Decrease) from Prior Year
1993 1992
(In thousands)
Change in Retail Unit Sales..... $ 7,900 $(17,800)
Change in Retail Fuel and Energy
Adjustment Clause Billings.... ( 600) ( 400)
Change in Sales for Resale...... 5,900 ( 5,000)
Change Due to the Effect of
Higher Rates.................. 12,700 4,300
$ 25,900 $(18,900)
Gas revenues increased in 1993 compared to 1992. The
principal factors contributing to the increase were increased
sales volumes reflecting temperatures which were 10% colder than
1992 (when measured by heating degree days), higher purchased gas
cost billings and higher rates. Variations in purchased gas cost
billings reflect corresponding changes in cost of gas sold from
levels included in base rates and, thus, do not affect net
income. The Company began billing higher gas rates in Iowa in
July 1992. Effective Jan. 1, 1993, the IUB approved a permanent
annual increase of $5.4 million. On July 28, 1993, an annual gas
rate increase in Illinois of $2 million became effective
following ICC approval. On Jan. 15, 1994, an additional gas
increase of $49,000 related to the increase in the federal
corporate income tax rate became effective following ICC approval
on rehearing. As noted previously, the ICC also approved a rate
rider which permits the Company to recover costs of
investigation, remediation and litigation relating to former
manufactured gas plant sites. 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 will not affect net income due to a
corresponding amortization of previously deferred costs.
Gas revenues increased in 1992 compared to 1991 due to
higher purchased gas cost billings and higher rates in Iowa
beginning in July 1992. Partially offsetting these increases
were lower residential and commercial sales due to temperatures
which were warmer than 1991 and a change in sales mix reflecting
decreased industrial sales and increased transportation volumes.
Transportation volumes have a lower revenue rate because they
exclude the commodity cost of gas. However, the margins which
had been realized on the industrial sales have been maintained on
transportation volumes resulting in no significant effect on net
income.
The changes in gas revenues are shown below:
Revenue Increase (Decrease) from Prior Year
1993 1992
(In thousands)
Change in Purchased Gas
Adjustment Clause Billings.... $ 8,600 $ 4,500
Change in Unit Sales............ 9,000 (2,600)
Change Due to the Effect of
Higher Rates.................. 4,400 2,000
$22,000 $ 3,900
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
1993 compared to 1992 are primarily due to increased sales.
Decreased fuel, energy and capacity costs in 1992 compared
to 1991 are primarily due to lower sales.
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.
Cost of gas sold decreased in 1992 compared to 1991
primarily due to warmer temperatures in the first quarter of the
year and an increase in transportation volumes of customer-owned
gas. Substantially offsetting these decreases were increased
costs of gas purchased from suppliers.
Other operation and maintenance increased in 1993 compared
to 1992 and in 1992 compared to 1991 primarily due to increased
costs at the Quad-Cities Nuclear Power Station (Quad-Cities). In
addition, the increase in other operation expense in 1993
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.
In 1993, a Nuclear Regulatory Commission (NRC) "diagnostic
evaluation team" inspected the Quad-Cities Station. The NRC
team's report noted deficiencies in management and equipment at
the station. In their response to the NRC, Commonwealth Edison
Company, the operator of the station, has committed to fully
resolve the leadership, process and plant performance weaknesses
at the Quad-Cities Station by 1996 at the latest. The station
operator also plans to resolve the plant equipment deficiencies
during the next four refueling outages. The Company anticipates
that it will need to make additional operating and capital
expenditures in future years in connection with the resolution of
the noted deficiencies at the Quad-Cities Station.
Provision for Depreciation
The provision for depreciation increased in 1993 compared to
1992 and in 1992 compared to 1991 primarily due to a greater
provision for nuclear decommissioning consistent with current
ratemaking treatment as well as greater utility plant investment.
Depreciation and Equity Funds
Recovered Under Louisa Phase-In Clause
The decrease in the amount being recovered under the Louisa
Phase-In Clause in 1993 compared to 1992 reflects the expiration
of the Louisa Phase-In Clause on June 30, 1993.
Operating Income Taxes
Income tax expense increased 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 Aug. 10, 1993. In accordance with Statement
of Financial Accounting Standards No. 109, Accounting for Income
Taxes, which the Company adopted Jan. 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.
Income tax expense decreased in 1992 compared to 1991
primarily due to lower taxable income.
Oil and Gas Revenues of InterCoast Energy Company
Oil and gas revenues of InterCoast increased in 1993
compared to 1992 and in 1992 compared to 1991 primarily due to
higher production volumes reflecting additional acquired
reserves, successful drilling results and higher gas prices,
partially offset by lower oil prices.
In the event that 1994 oil and gas prices are below such
prices for 1993, oil and gas operating income could be reduced
from 1993 levels.
Expenses of InterCoast Energy Company
Expenses of InterCoast increased in 1993 compared to 1992
and in 1992 compared to 1991 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 1993 compared to
1992 and in 1992 compared to 1991 reflects refinancing of several
series of long-term debt at lower interest rates.
Miscellaneous
The change in 1993 compared to 1992 is due primarily to the
receipt of non-recurring interest income related to federal
income tax refunds.
Other Matters
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 Company's efforts continue to focus on achievement of
business growth through the application of marketing and economic
development programs to achieve energy-efficient growth in its
sales of utility services, pursuit of off-system electric sales
and development of its non-regulated energy businesses. The
Company currently forecasts average annual growth in electric and
gas sales of 1.7% and 1.4%, respectively, for the next ten years.
The Company's electric generation and transmission systems are
sufficient to meet future demands and the Company has access to
multiple suppliers of natural gas.
The National Energy Policy Act (NEPA) of 1992 will likely
have a significant effect on electric utility companies. With
passage of NEPA, the Company could be required to open its
transmission lines to non-utility energy producers. Although the
Company cannot now predict the ultimate impact of NEPA, the
Company believes it is likely that the competitive factors which
impact its utility businesses will continue to increase. In
light of this belief, in rate cases filed in 1992 and 1993, the
Company took steps to more fully implement "cost-of-service"
pricing.
The Company is also continuing to work to more closely
balance its electric generating capacity with customers' energy
demands.
The Company's corporate improvement program, begun in 1992,
focuses on the achievement of major productivity gains.
The strategy of the non-regulated business is focused on
areas which relate closely to the Company's core utility
businesses: oil and natural gas, energy services and financial
investments.
Deregulation of the electric utility industry may provide
some new opportunities for InterCoast. InterCoast Power
Marketing Company (IPM), a subsidiary of InterCoast which was
established in October 1993, has filed a petition with the
Federal Energy Regulatory Commission (FERC) seeking "marketer"
status. IPM currently acts as a broker for buyers and sellers of
wholesale electric power. With marketer status, IPM also could
acquire and resell power.
LIQUIDITY AND CAPITAL RESOURCES
In 1993, 1992 and 1991, net cash from utility operating
activities, after dividends, was $68 million, $30 million and $58
million, respectively.
Utility construction expenditures totaled $67 million in
1993. The Company's current utility construction program
forecast calls for expenditures of $87.6 million in 1994.
Approximately 65% of these expenditures are expected to be met
from cash generated from operations. The Company's utility
capital requirements for the years 1994-1998 include budgeted
construction expenditures of $319.6 million, expected
contributions to nuclear decommissioning trust funds of $45.7
million and maturities, sinking funds and redemptions related to
long-term debt of $98.2 million. The estimated 1994-1998
construction expenditures include $67.6 million for electric
transmission and distribution system construction, $79.9 million
for electric production construction (principally at the Quad-
Cities Station), $57.8 million for general plant construction,
$51.6 million for nuclear fuel and $62.7 million for gas plant
construction. Approximately 95% of these construction
expenditures are expected to be met by cash generated from
operations.
The Company presently plans to take the necessary steps in
1994 to convert its Dividend Reinvestment Plan from one where its
common shares are purchased for participants in the open market
to one providing for original issue shares. The additional cash
obtained is expected to be used to fund current and future
utility construction expenditures.
Inter-granular stress corrosion was discovered in 1983 in
certain stainless steel piping at the Quad-Cities Station.
Remedial actions intended to avoid the need to replace such
piping continue. Accordingly, the Company's budgeted
construction expenditures do not include any amounts which may be
required to pay the Company's share of the cost of replacing such
piping. If replacement of all such piping were required, the
Company's share of the costs of such replacement would be
approximately $55 million at current price levels. Replacement
of such piping would result in an extended outage and require the
purchase of replacement power.
In 1993 and prior years, additional current income tax
liability resulted and accumulated deferred income tax benefits
have been recorded due to the application of federal and state
Alternative Minimum Tax (AMT). The accumulated provision for
these additional taxes at Dec. 31, 1993, in the amounts of $32.3
million in federal AMT and $5.5 million in state AMT, represents
AMT credits which may be carried forward indefinitely to offset
future regular tax liabilities.
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 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 Dec. 31, 1993 are
$200,000 for 1994 and $98.2 million for the years 1994-1998.
At Dec. 31, 1993, 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 Dec. 31, 1993, the Company had $31 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:
Dec. 31,
1993 1992 1991
Long-term debt, including
current maturities........ 45.0% 40.8% 42.7%
Short-term debt............. 3.7 6.4 6.7
Total debt............... 48.7 47.2 49.4
Preferred and Preference
stock equity.............. 8.5 8.4 8.9
Common stock equity......... 42.8 44.4 41.7
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 and its Articles of Incorporation relating to
Preferred Shares.
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
allowance for funds used during construction). As of Dec. 31,
1993, 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
relating to this restructuring may be billed by interstate
pipelines to their customers. The amount of transition costs
which the FERC may ultimately authorize the pipelines to bill the
Company is estimated to be $35 to $50 million. The Company
expects to be allowed to include provisions for such costs in its
customer billings.
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 Dec. 31, 1993, an
estimated liability of $3.4 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 and U.S. Environmental Protection Agency rulemaking
proceedings are underway. 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 impacted 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. 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 $5.4 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.
Installation of low nitrogen oxide burners is required at one of
these facilities and existing emission monitoring systems at all
four facilities will require upgrading. The Company's remaining
construction cost for this work is estimated to be $2.1 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 Dec. 31, 1993,
the Company's liability for its share of such funding is $10.7
million. In 1993 and 1992, $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.
The forecasted 1994 capital expenditures for InterCoast are
approximately $82.6 million. Actual expenditures 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.
InterCoast's aggregate amounts of maturities and cash
sinking fund requirements for long-term debt outstanding at Dec.
31, 1993 are $59 million for 1994 and $256.5 million for the
years 1994-1998. Amounts due in 1994 are expected to be
refinanced with debt instruments and operating cash flow.
In January 1994, InterCoast renegotiated its unsecured
revolving credit facility agreement. The renegotiation increased
the amount of capital available from $65 million to $110 million.
The amended credit agreement matures Feb. 14, 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 Dec. 31, 1993 were
$44.5 million at a weighted average interest cost of 4.1%. No
such borrowings were outstanding at Dec. 31, 1992.
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 Dec. 31, 1993,
$16.5 million was available for dividends. In addition, at Dec.
31, 1993, under the most restrictive of such provisions,
additional debt up to $17 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:
Dec. 31,
1993 1992 1991
Long-term debt, including
current maturities......... 52.9% 49.2% 49.3%
Short-term debt.............. 2.4 4.3 4.7
Total debt................ 55.3 53.5 54.0
Preferred and Preference
stock equity............... 5.5 5.7 6.2
Common stock equity.......... 39.2 40.8 39.8
100.0% 100.0% 100.0%
Quarterly common stock dividends were paid in 1993 and 1992
at a rate of 43.25 cents per share, a total of $1.73 for each of
the years.