SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [Fee Required]
For the Fiscal Year Ended December 31, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [No Fee Required]
For the Transition Period from ____________ to ____________
Commission File Number 1-3573
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Illinois 42-0673189
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One RiverCenter Place,
106 East Second Street, Davenport, Iowa 52801
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code
(319) 326-7111
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Common Shares Chicago Stock Exchange
Common Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
<PAGE>
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 and 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 ____
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (X)
The aggregate market value of the Company's Common Shares
was approximately $648 million based upon the New York Stock
Exchange composite transaction closing price as of February 27,
1995. The Company's $7.80 and $5.25 Series Cumulative Preference
Shares are traded in the over-the-counter market. Bid and asked
prices on all such shares are not regularly quoted. As of
February 27, 1995, 99.8% of the Company's voting shares were
owned by nonaffiliates.
The aggregate number of the Company's Common Shares
outstanding at February 27, 1995 was 29,781,296.
Documents of Which Portions are Incorporated by Reference
Part of Form 10-K Document Incorporated by Reference
I and II Annual Report to Shareholders for the year
ended December 31, 1994
III Proxy Statement dated March 15, 1995
Only the portions of such documents which are specifically
incorporated by reference herein shall be deemed to be filed as a
part of this Form 10-K.
<PAGE>
Part I
Item 1. Business
(a) General Development of Business
Iowa-Illinois Gas and Electric Company (the Company or Iowa-
Illinois) was incorporated under the laws of the State of
Illinois in 1940 and is engaged in the business of generating,
transmitting, distributing and selling electric energy and
distributing, selling and transporting natural gas in the States
of Illinois and Iowa. Through a wholly owned subsidiary,
InterCoast Energy Company, the Company engages in non-regulated
energy-related businesses. The Company's principal executive
offices are located at One RiverCenter Place, 106 East Second
Street, Davenport, Iowa 52801 (telephone: 319-326-7111).
On December 21, 1994, the shareholders of the Company,
Midwest Resources Inc. (Midwest Resources) and Midwest Power
Systems Inc. (Midwest Power) approved a strategic merger of
equals to form MidAmerican Energy Company (MidAmerican).
MidAmerican will be structured as a utility with the Company,
Midwest Resources and Midwest Power being merged into the new
company.
Pursuant to the terms of the merger agreement, Midwest
Resources' common shareholders will receive one share of
MidAmerican common stock for each Midwest Resources share and the
Company's common shareholders will receive 1.47 shares of
MidAmerican common stock 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 Iowa Utilities Board (IUB), the
Illinois Commerce Commission (ICC) and the Federal Energy
Regulatory Commission (FERC). Approval by the Nuclear Regulatory
Commission (NRC) of the transfer of the Quad-Cities Nuclear Power
Station (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 electric 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 during 1995.
The management of the Company believes that 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,
management believes that 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. In terms of the
competitive position of MidAmerican, the industrial rates of both
Iowa-Illinois and Midwest Power are well below national and
regional averages.
Management believes that 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 Iowa-Illinois and
Midwest Power are well below national averages.
Management believes that 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 Power have announced plans to
reduce their combined utility 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 salaried
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.
(b) Financial Information About Industry Segments
Financial information on the Company's segments of business
is included under the Note "Segment Information" on pages 36 and
37 of the Company's Annual Report to Shareholders for 1994 which
pages are incorporated herein by reference. This information is
also included in Exhibit 13.A.4 to this Form 10-K.
(c) Narrative Description of Business
General
The Company distributes electric energy in the Quad-Cities
(Davenport and Bettendorf, Iowa and Rock Island, Moline and East
Moline, Illinois), Iowa City and Fort Dodge, Iowa and a number of
adjacent communities and areas.
The Company distributes natural gas in the Quad-Cities, and
in Iowa City, Cedar Rapids, Fort Dodge and Ottumwa, Iowa and a
number of adjacent communities and areas.
Electric and/or gas service is provided in 22 incorporated
communities in Illinois and 48 incorporated communities in Iowa.
Franchises with various expiration dates have been obtained from
all 70 communities. The length of term of the franchises is
typically 25 years.
The population of the Company's electric service territory
is approximately 425,000 and the population of its gas service
territory is approximately 600,000. As of December 31, 1994, the
Company had 202,003 retail electric customers and 244,062 gas
customers.
The Company has a residential, agricultural commercial and
diversified industrial customer group, in which no single
industry or customer accounted for more than 8.6% (primary metal
industry) of the Company's total 1994 electric operating revenues
or 4.7% (real estate) of its total 1994 gas operating revenues.
Among the primary industries served by the Company are those
which are concerned with the manufacturing, processing and
fabrication of primary metals, real estate, food products, farm
and other non-electrical machinery, cement and gypsum products.
For the year ended December 31, 1994, the Company derived
approximately 64.1% of its gross utility operating revenues from
its electric business and 35.9% from its gas business. For 1993
and 1992, the corresponding percentages were 62.1% electric and
37.9% gas, and 62.8% electric and 37.2% gas, respectively.
Historical electric sales (kwh) by customer class as a
percent of total electric sales and retail electric sales data
(kwh) by jurisdiction are shown below:
Total Electric Sales
By Customer Class
1994 1993 1992
Residential 20.1% 19.9% 19.4%
Small Commercial and
Industrial 22.3 21.5 21.5
Large Commercial and
Industrial 34.3 31.9 34.9
Public Street Lighting 0.4 0.3 0.5
Public Authorities 1.6 1.6 1.6
Sales for Resale 21.3 24.8 22.1
Total 100.0% 100.0% 100.0%
Retail Electric Sales
By Jurisdiction
1994 1993 1992
Iowa 67.1% 67.0% 65.4%
Illinois 32.9 33.0 34.6
Total 100.0% 100.0% 100.0%
Historical gas sales (ccf), including transportation, by
customer class and by jurisdiction are shown below:
Total Gas Sales
By Customer Class
1994 1993 1992
Residential 33.9% 36.5% 36.6%
Commercial 19.7 20.7 20.8
Industrial 6.0 5.3 6.5
Processing & Boiler Fuel - 0.2 0.6
Transportation 40.4 37.3 35.5
Total 100.0% 100.0% 100.0%
Retail Gas Sales
By Jurisdiction
1994 1993 1992
Iowa 81.1% 80.1% 79.4%
Illinois 18.9 19.9 20.6
Total 100.0% 100.0% 100.0%
There are seasonal variations in the Company's electric and
gas businesses, which are principally related to the use of
energy for air conditioning and heating. In 1994, 39.2% of the
Company's electric revenues were reported in the months of June,
July, August and September, reflecting the use of electricity for
cooling, and 63.1% of the Company's gas revenues were reported in
the months of January, February, March and December, reflecting
the use of gas for heating.
At December 31, 1994, the Company had 1,387 employees, of
which 1,289 were employed in utility operations and 98 were
employed by InterCoast Energy Company.
Rate Matters
Under Illinois law, new rates may be put into effect by the
Company 45 days after filing with the ICC, or on such earlier
date as the ICC may approve, subject to the power of the ICC to
suspend the proposed new rates for a period not to exceed eleven
months after filing, pending a hearing.
Under Iowa law, temporary collection of higher rates can
begin (subject to refund) 90 days after filing with the IUB for
that portion of such higher rates approved by the IUB based on
prior ratemaking principles and a rate of return on common equity
previously approved. If the IUB has not issued a final order
within ten months after the filing date, the temporary rates
cease to be subject to refund and any balance of the requested
rate increase may then be collected subject to refund.
Exceptions to the ten month limitation are provided for
extensions due to a utility's lack of due diligence in the rate
proceeding, judicial appeals and situations involving new
generating units being placed in service.
In October 1994, the Company filed an application with the
IUB to recover the costs of state-mandated energy-efficiency
programs offered to Iowa electric and gas customers since 1992.
Costs of the programs are to be recovered over four years, as
required by Iowa law. The overall annual rate increase
requested, including a return on deferred amounts and an
allowance for performance rewards, is approximately $4.7 million
(1.4%). The proposed effective date for cost-recovery additions
on customer bills is June 1995.
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 costs through rates.
The Company has established an external trust for the
investment of funds collected for nuclear decommissioning.
Electric tariffs in effect for 1995 include provisions for annual
decommissioning costs of approximately $8.6 million. In
Illinois, nuclear decommissioning costs are included in customer
billings through a mechanism that permits annual adjustments. In
Iowa, such costs are reflected in base rates.
The Company's Iowa electric tariffs contain a Uniform
Electric Energy Adjustment Clause under which the Company's
billings reflect changes in the cost of all fuels used for
electric generation, including nuclear fuel disposition costs, as
well as the net effect of energy transactions (other than
capacity) with other utilities. Changes in the cost of gas to
the Company are reflected in its Iowa gas rates through the Iowa
Uniform Purchased Gas Adjustment Clause.
Under Illinois electric tariffs, the Company's Fuel Cost
Adjustment Clause reflects changes in the cost of all fuels used
for electric generation, including allowable fuel transportation
costs, nuclear fuel disposition costs and the effects of energy
transactions (other than capacity and margins on interchange
sales) with other utilities. Changes in the cost of gas to the
Company are reflected in its Illinois gas rates through the
Illinois Uniform Purchased Gas Adjustment Clause.
Electric Operations
The Company's accredited 1994 summer net generating capacity
was 1,430,868 kilowatts, consisting of (a) 384,750 kilowatts from
the Company's 25% undivided interest in the Quad-Cities Station,
jointly owned with ComEd, (b) 914,918 kilowatts from interests in
wholly or jointly owned coal-fired units, (c) 128,000 kilowatts
from wholly owned gas/oil fired units, and (d) 3,200 kilowatts
from wholly owned hydro-electric units. In February 1995, the
Mid-Continent Area Power Pool approved an increase in the
accreditation of the Louisa Generating Station from 650 megawatts
to 675 megawatts effective as of June 7, 1994. This action
increased the Company's summer net generating capacity from
1,430,868 kilowatts to 1,441,618 kilowatts. The net generating
capacity at any time may be less due to regulatory restrictions,
fuel restrictions and generating units being temporarily out of
service for inspection, maintenance, refueling or modifications.
On August 26, 1993, the Company established its record one-hour
peak electric demand of 1,084,965 kilowatts.
Fuel Supply for Electric Operations
The Company's sources of fuel for electric generation have
been as follows for the periods shown:
Year Ended December 31,
Fuel Source 1994 1993 1992
Coal 73.63% 63.18% 63.95%
Nuclear 25.80 36.52 35.56
Gas 0.46 0.28 0.45
Oil 0.11 0.02 0.04
In 1995 the Company projects its electric generation
requirements will be met as follows: coal - 59%, nuclear - 41%.
The average costs of fuels (including transportation and
handling costs) in cents per million BTU's consumed have been as
follows for the periods shown:
Year Ended December 31,
Fuel Source 1994 1993 1992
Nuclear 47.40 47.36 44.57
Coal 97.49 105.79 102.97
Gas 345.09 373.25 313.33
Oil 378.36 440.95 412.80
Total Weighted Average 84.93 86.62 83.93
The average cost of coal (including transportation and
handling costs) per ton for the years 1994, 1993 and 1992 has
been $17.13, $18.22 and $17.57, respectively.
The Company has been advised by ComEd that the majority of
its uranium concentrate and uranium conversion requirements for
the Quad-Cities Station for 1995 can be met under existing
supplies or commitments. ComEd foresees no problem in obtaining
the remaining requirements now or obtaining future requirements.
ComEd further advises that all enrichment requirements have been
contracted for through 1999. Commitments for fuel fabrication
have been obtained at least through 2000. ComEd does not
anticipate that it will have any difficulty in contracting for
uranium concentrates for conversion, enrichment or fabrication of
nuclear fuel needed for the Quad-Cities Station.
In June 1985, the Company satisfied its financial obligation
for Quad-Cities Station disposal costs for fuel burned prior to
April 1983 by making a lump sum payment of $24.8 million to the
Department of Energy (DOE). The payment was made principally
from funds previously collected from customers. Disposal costs
for fuel burned after April 1983 are paid quarterly. Such costs
are included in the cost of fuel and recovered through fuel and
energy adjustment clause billings. See Nuclear Regulation herein
for further information concerning the disposal of spent nuclear
fuel.
The Company believes its sources of coal for its fossil-
fueled generating stations are and will be satisfactory. Renewal
of expiring contracts and negotiations of new agreements will be
pursued as required. The coal requirements for the Riverside
Station are being met primarily through spot purchases.
Contracts for low-sulfur Wyoming coal have been executed for the
Neal Unit 3, Council Bluffs, Ottumwa and Louisa units which will
supply a portion of requirements through the years 1996, 1999,
2001 and 2003, respectively. Unit trains are being used for
transporting coal for the Riverside, Neal, Council Bluffs,
Ottumwa and Louisa units. The Company has negotiated certain
modifications to existing contracts to achieve flexibility in
volumes to be delivered while also providing reasonable assurance
of supply. In addition, the Company has used spot market
purchases of coal to effectively manage inventory levels and take
advantage of near term coal market opportunities. The Company is
continuing to monitor existing contracts and coal supply
requirements, balancing coal requirements with a combination of
contract and spot purchases.
Gas Operations
During 1994, the Company purchased over 99 percent of the
gas required to supply its customers from non-pipeline gas
suppliers on a firm or interruptible basis and transported such
gas on a firm or interruptible basis through the Natural Gas
Pipeline Company of America (NGPL), ANR Pipeline Company (ANR)
and Northern Natural Gas (NNG) systems. The remainder was
purchased from NNG.
All gas supply purchased from NNG is at rates approved by
the FERC under the Natural Gas Act. Likewise, transportation
rates negotiated with NGPL, ANR and NNG are subject to FERC
approval. Non-pipeline supply prices are negotiated.
The Company withdrew approximately 94 percent of the gas in
leased storage during the 1993-94 heating season. Storage gas
was replaced during the summer for the 1994-95 heating season.
Beginning in December 1993, the Company has rebundled a
portion of its firm pipeline transportation with firm supply from
a third party supplier. This citygate service replaces bundled
sales service previously purchased from one of the Company's
pipeline suppliers.
The Company provides natural gas transportation service
through its distribution system for end-use customers.
Transportation of customer-owned gas was 40.4 percent of the
total Company throughput during 1994.
For the 1994-95 heating season, the Company's peak-day
supply delivery availability consists of firm capacity on the
NGPL, ANR and NNG systems for the transportation of firm non-
pipeline gas. In addition, peak-day supply is available from gas
previously purchased by the Company and held in leased pipeline
storage. The Company leases storage from NGPL, ANR and NNG.
Liquefied natural gas (LNG) stored in the Company's LNG facility
is also available for peak-day use. Following are the current
peak-day supply sources for the Company which are available for
the 1994-95 heating season by volume and proportions:
Millions Percent
of Cubic of
Feet Total
Underground Storage 205.1 42.1
Firm Non-Pipeline Supply 141.4 29.0
Rebundled Service 96.9 19.9
LNG Facility 40.0 8.2
Pipeline System
Management Service 4.0 0.8
487.4 100.0
Peak-day firm demand for the 1994-95 heating season was
projected to be 464.4 million cubic feet for the Company. The
actual highest demand for peak-day firm sales for the 1994-95
heating season for the Company was 353 million cubic feet on
January 4, 1995. The average temperature on that day was 1
degree above zero.
On January 17, 1994, a new record was set for total Company
gas throughput (sales and transportation) of 516 million cubic
feet.
In the Spring of 1995, the Company will begin construction
on a 63-mile, 16-inch diameter pipeline from NNG's main line near
Dubuque, Iowa, to the Company's facilities in Davenport, Iowa.
The interconnection will give the Company and its customers more
supply and pipeline transportation options, which will help
ensure continued access to the lowest-cost gas supplies.
A 1994 ruling by the IUB will enhance gas earnings. The
Company has firm rights to pipeline capacity to transport gas
from the production area to its service territory. With the
restructuring of the industry, if the Company does not need the
capacity (due to fluctuations in anticipated system demand), it
can "sublease" such capacity to other companies. To provide
incentives for the achievement of optimum use of available
transportation capacity, the IUB ruling allows the Company to
retain 30% of Iowa revenues earned on the "subleased" capacity
and returns 70% to customers through the purchased gas
adjustment.
See Rate Matters for a discussion of certain transition
costs.
Construction Program
The table below shows actual construction expenditures for
1994 and budgeted expenditures for 1995 and for the period 1996-
1999:
1994 1995 1996-99
Actual Budgeted Budgeted
(Thousands of Dollars)
Electric
Production $ 18,279 $ 15,651 $ 56,497
Transmission 1,429 1,307 6,912
Distribution 10,128 13,345 37,196
Gas 12,246 31,118 59,268
General Plant 26,875 13,633 19,982
Subtotal 68,957 75,054 179,855
Nuclear Fuel 11,316 9,283 35,669
Total $ 80,273 $ 84,337 $215,524
The amounts shown above include allowance for funds used
during construction. Of the $72.1 million of budgeted electric
production expenditures for the 1995-1999 period, $35.9 million
are for expenditures at the Quad-Cities Station. In addition to
the amounts shown above, the Company also expects to contribute a
total of $43.2 million to an external trust for nuclear
decommissioning during the 1995-1999 period. The Company's above
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. Such expenditures are currently not expected to be
required. See Nuclear Regulation.
General Regulation
The Company is a public utility under the laws of Illinois
and is regulated by the ICC as to retail rates, services,
accounts, issuance of securities, affiliate transactions,
construction, acquisition and sale of utility property,
acquisition and sale of securities and in other respects as
provided by the laws of Illinois. The Company is also a public
utility under the laws of Iowa and is regulated by the IUB as to
retail rates, services, accounts, construction of utility
property and in other respects as provided by the laws of Iowa.
The Company is subject to the jurisdiction of the FERC with
respect to certain matters, including short-term borrowings,
rates for transmission and sale of electric energy at wholesale,
interconnection of electric transmission facilities, acquisition
and sale of certain electric utility property, installation and
replacement of certain gas utility property and accounting
policies and practices.
Nuclear Regulation
The Company is subject to the jurisdiction of the NRC with
respect to the Quad-Cities Station. The NRC regulations control
the granting of permits and licenses for the construction and
operation of nuclear generating stations and subject such
stations to continuing review and regulation. The NRC review and
regulatory process covers, among other things, operations,
maintenance, and environmental and radiological aspects of such
stations. The NRC may modify, suspend or revoke licenses and
impose civil penalties for failure to comply with the Atomic
Energy Act, the regulations under such Act or the terms of such
licenses. Attempts are made from time to time by various
individuals or citizen groups to prohibit the development or use
of nuclear power through initiation of proceedings before the
NRC, other agencies or courts. Such proceedings frequently
involve attacks on the validity of NRC rules which, if
successful, could provide a basis for challenges to permits and
licenses granted by the NRC in the past.
The Illinois Department of Nuclear Safety (IDNS) has
jurisdiction over certain activities in Illinois relating to
nuclear power and safety and radioactive materials. Effective
June 1987, the IDNS replaced the NRC as the regulator and
licensor of certain source, by-product and special nuclear
material in quantities not sufficient to form a critical mass,
including such material contained in various measuring devices
used at fossil-fuel power plants. The IDNS has promulgated
regulations which are substantially similar to the corresponding
federal regulations. The IDNS also has authority to license a
low-level radioactive waste disposal facility and to regulate
alternative methods for disposing of materials which contain only
trace amounts of radioactivity.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE
is responsible for the selection and development of repositories
for, and the permanent disposal of, spent nuclear fuel and high-
level radioactive wastes. ComEd, as required by the NWPA, has
signed a contract with the DOE to provide for the disposal of
spent nuclear fuel and high-level radioactive waste beginning not
later than January 1998. The DOE has stated, however, that the
delivery schedule for spent nuclear fuel may be delayed, and
ComEd expects that it will be significantly delayed. The costs
incurred by the DOE for disposal activities will be financed by
fees charged to owners and generators thereof. The primary
responsibility for the interim storage of spent nuclear fuel and
high-level radioactive wastes will rest with the owners and
generators thereof. ComEd has informed the Company that there is
on-site storage capability at the Quad-Cities Station sufficient
to permit such interim storage at least through 2009. Meeting
spent nuclear fuel storage requirements beyond such time could
require a new and separate storage facility, the cost of which
has not been determined at this time. Industry activities are
underway to utilize dry cask storage for high-level radioactive
waste. This may provide an alternative for interim on-site
storage of such waste. ComEd anticipates the possibility of
serious difficulties in disposing of high-level radioactive
waste.
The federal Low-Level Radioactive Waste Policy Act of 1980
provides that states may enter into compacts to provide for
regional disposal facilities for such waste, subject to approval
by the U.S. Congress of each such compact. Under the 1985
amendments to that Act, a compact could restrict the use of a
region's disposal facilities after January 1993 to wastes
generated within the region. Illinois has entered into a compact
with the State of Kentucky which has been approved by Congress.
The IDNS had previously estimated that a low-level radioactive
waste disposal facility would be operational in Illinois by March
1994 at the earliest. However, in 1992 an independent panel
rejected the only site in Illinois then being considered for a
low-level disposal facility. Illinois has since enacted
legislation changing the procedures for siting a low-level waste
disposal facility. Since the loss of access to the only low-
level radioactive waste site (at Barnwell, South Carolina)
available to the Quad-Cities Station, effective June 30, 1994,
Quad-Cities Station has constructed a temporary storage facility
for on-site storage of this material. Quad-Cities Station will
continue to store all low-level radioactive waste on-site until
an off-site facility is again available. ComEd anticipates the
possibility of serious difficulties in disposing of low-level
radioactive waste.
The continuing viability of commercial nuclear power is
subject to resolution of the issues of spent nuclear fuel storage
and disposal of radioactive waste.
Quad-Cities Station continues to be considered by the NRC as
a plant that is safe to operate. However, the NRC has
characterized the plant as "adversely trending" with respect to
certain performance expectations. ComEd has undertaken measures
to correct this performance trend.
Federal regulations provide that any operating facility may
be required to cease operation if the NRC determines there are
deficiencies in state, local or utility emergency preparedness
plans relating to such facility and the deficiencies are not
corrected within four months of such determination. Under the
regulations, the NRC may permit operation of facilities, even
though the emergency preparedness plans are deficient, upon an
examination of other factors, including whether the deficiencies
are significant for the facility in question, whether adequate
interim compensatory actions have been or will be taken promptly
and whether other compelling reasons exist for operation
consistent with public health and safety. ComEd has advised the
Company that emergency preparedness plans for the Quad-Cities
Station have been approved by the NRC. ComEd has also advised
the Company that state and local plans relating to the Quad-
Cities Station have been approved by the Federal Emergency
Management Agency. ComEd continues to cooperate with the NRC and
appropriate state and local agencies on emergency preparedness
issues.
In June 1988, the NRC adopted final regulations with respect
to the decommissioning of nuclear power plants. Among other
things the regulations address the planning and funding of the
eventual decommissioning of nuclear power plants. In response to
these regulations, the Company submitted a report to the NRC in
July 1990 indicating that it will provide "reasonable assurance"
that funds will be available to pay the costs of decommissioning
its nuclear power plants by making monthly deposits to an
external trust fund.
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 and the replacement of such piping is not
expected to be required. Accordingly, the Company's budgeted
construction expenditures do not include the amounts which would
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 is estimated
to 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.
The Company is a member of Nuclear Mutual Limited (NML), an
industry mutual insurer established to provide property damage
coverage for members' nuclear generating facilities. The Company
would be subject to a maximum retrospective premium assessment of
approximately $2 million based on its 25% share of the NML
premium for Quad-Cities coverage in the event covered losses of
NML members exceed the financial resources of the insurance
company. A reserve has been established for this contingency.
At December 31, 1994, NML had accumulated capital to a level that
would make it unlikely the Company would have an exposure to a
retrospective premium assessment in the event of a single
incident to a member's facility.
The Company is also a member of Nuclear Electric Insurance
Limited (NEIL), an industry mutual insurance company, and an
insured of American Nuclear Insurers/Mutual Atomic Energy
Liability Underwriters (ANI/MAELU). The related policy
provisions provide that expenses for decontamination and the
removal of debris shall be paid before any payment in respect of
claims for property damage. A separate NEIL insurance policy
covers the extra costs that would be incurred in obtaining
replacement power during a prolonged covered outage of a member's
nuclear plant. The Company is subject to retrospective premium
assessments of approximately $4.1 million and $843,000 for its
25% share of the premium under the NEIL portion of the property
damage coverage and the replacement power coverage, respectively.
At December 31, 1994, NEIL had accumulated capital to a level
that would make it unlikely the Company would have an exposure to
a retrospective premium assessment in the event of a single
incident to a member's facility.
A Master Worker Policy issued by ANI/MAELU provides coverage
for worker tort claims filed for bodily injury caused by the
nuclear energy hazard. The coverage applies to workers whose
"nuclear related employment" began after January 1, 1988. Under
this policy, the Company could be subject to a maximum
retrospective premium assessment of $1.5 million.
Under the Price-Anderson federal legislation adopted in
1988, nuclear public liability coverage is supported by a
mandatory industry-wide program under which owners of nuclear
generating facilities could be assessed in the event of nuclear
incidents. The Company would currently be subject to a maximum
assessment of $39.6 million in the event of an incident, to be
paid in increments of no more than $5 million per year per
incident.
Environmental Regulation
The Company is subject to regulation regarding air, water,
solid waste, hazardous and toxic materials and noise pollution by
agencies of the federal government and of the States of Illinois
and Iowa and may become subject to additional regulation as to
these and other matters in the future. The Quad-Cities Station
is subject to the jurisdiction of the NRC and IDNS as to atomic
radiation.
State and federal environmental laws and regulations as
currently in effect have, and future modifications may have, the
effect of (i) increasing the lead time for the construction of
new facilities, (ii) significantly increasing the total cost of
new facilities, (iii) requiring modification of certain of the
Company's existing facilities, (iv) increasing the risk of delay
on construction projects, (v) increasing the Company's cost of
waste disposal and (vi) possibly reducing the reliability of
service provided by the Company and the amount of energy
available from the Company's facilities. Any of such items could
have a substantial impact on amounts required to be expended by
the Company in the future.
Air Quality. Air quality regulations, promulgated by both
the Iowa and Illinois pollution control boards in accordance with
federal standards, impose restrictions on the emission of sulfur
dioxide, nitrogen oxides and other air pollutants and require
permits from the respective state environmental protection agency
for the operation of emission sources. Permits authorizing
operation of the Company's fossil-fueled generating facilities
subject to this requirement have been obtained and, when such
permits are to expire, the Company has, in a timely manner, filed
applications for renewal.
Clean Air Act legislation was signed into law in November
1990. Under the acid deposition control section of this
legislation, national utility emissions of sulfur dioxide will be
reduced in phased increments by 10 million tons from 1980 levels
by the year 2000 and permanently capped at that level. National
nitrogen oxide emissions will also be reduced in phased
increments by 2 million tons from 1980 levels by the year 2000.
In addition, continuous emission monitoring systems will be
required at all affected facilities. This legislation also
requires the government to study what controls, if any, should be
imposed on utilities to control air toxics. The impact, if any,
of the air toxics study on the Company cannot be determined at
this time.
The Company has four jointly and one wholly owned coal-fired
generating stations, which represent approximately 65 percent 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 percent of the Company's electric
generating capability, is impacted by the emission reduction
requirements effective in 1995. Under such requirements,
beginning in 1995, this unit is 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.
Water Quality. Under the Federal Water Pollution Control
Act Amendments of 1972, as amended, the Company is required to
obtain National Pollutant Discharge Elimination System (NPDES)
permits to discharge effluents (including thermal discharges)
from its properties into various waterways. All NPDES permits
are subject to renewal after specified time periods not to exceed
five years. The Company has obtained all necessary NPDES permits
for its generating stations and, when such permits are expected
to expire, the Company will file applications for renewal.
Hazardous Materials and Waste Management. 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. Approximately
$218,000 and $154,000 has been budgeted in 1995 and 1996,
respectively, for site studies. 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.
Pursuant to the Toxic Substances Control Act, a federal law
administered by the Environmental Protection Agency, the Company
developed a comprehensive program for the use, handling, control
and disposal of all polychlorinated biphenyls (PCB's) contained
in electrical equipment. The future use of equipment containing
PCB's will be minimized. Capacitors, transformers and other
miscellaneous equipment are being purchased with a non-PCB
dielectric fluid. The Company's exposure to PCB liability has
been reduced through the orderly replacement of a number of such
electrical devices with similar non-PCB electrical devices.
An unresolved issue is whether exposure to electric and
magnetic fields (EMFs) may result in adverse health effects.
EMFs are produced by all devices carrying or using electricity,
including transmission and distribution lines and home
appliances. The Company cannot predict the effect on
construction costs of electric utility facilities if EMF
regulations were to be adopted. Although the Company is not the
subject of any suit involving EMFs, litigation has been filed in
a number of jurisdictions against a variety of defendants
alleging that EMFs had an adverse effect on health. If such
litigation were successful, the impact on the Company and on the
electric utility industry generally could be significant.
InterCoast Energy Company
InterCoast Energy Company (InterCoast) is a wholly owned
non-regulated subsidiary of the Company. The non-regulated
activities emphasize energy-related diversification, credit
quality and liquidity.
InterCoast takes advantage of a core expertise in energy,
participating in the energy industry through three non-regulated
business groups: oil and gas (Medallion Production Company),
energy services (InterCoast Energy Services Company) and
financial investments (InterCoast Capital Company).
Medallion Production Company (Medallion) is an independent
oil and gas company based in Tulsa, Oklahoma. Medallion's oil
and gas assets at December 31, 1994 and 1993 were $142.4 million
and $121 million, respectively. In September 1993, Medallion
acquired DKM Resources, Inc. The transaction totaled in excess
of $50 million and more than doubled Medallion's oil and gas
reserve base. Medallion's reserves totaled 32.1 million barrels
of oil equivalent at December 31, 1994. Principal oil and gas
production facilities are in Texas, Louisiana, California,
Oklahoma and Colorado.
InterCoast Energy Services Company (Energy Services)
consolidates passive energy investment activities with actively
managed energy operations through development efforts and
acquisitions to provide a full spectrum of energy services.
Energy Services' assets at December 31, 1994 and 1993 were $50.3
million and $48.8 million, respectively.
InterCoast Power Marketing Company (IPM), a subsidiary of
Energy Services, was established in September 1993 to offer
wholesale power brokering and marketing services to utilities and
other power supply agencies. IPM brokers wholesale electric
power nationwide. In August 1994, FERC conditionally accepted
IPM's request for marketer status to enable it to directly buy
and sell power. FERC's acceptance of IPM's request was
conditioned upon Iowa-Illinois filing an open access, comparable
services electric transmission tariff within 30 days of its
order. In September 1994, FERC granted IPM an extension of time
in which Iowa-Illinois or MidAmerican could file such tariffs,
and on or about November 10, 1994, the tariffs were filed by
MidAmerican. While IPM can continue to broker power, it will not
be able to market power until the MidAmerican open access,
comparable services transmission tariffs become effective.
Continental Power Exchange, Inc. (CPE), a subsidiary of
Energy Services, was established in March 1994. CPE was formed
to operate a computerized 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. In August 1994,
the FERC issued an order disclaiming jurisdiction over CPE and
its proposed National Interchange Agreement (NIA). Although the
FERC disclaimed jurisdiction over CPE, it accepted for filing on
January 9, 1995 the formula rates submitted in conjunction with
the NIA by Central Illinois Public Service Company (CIPS), the
utility sponsor of CPE. Other utilities may either apply to the
FERC to use the same rate formulas as CIPS or transact business
through CPE's system under rate schedules or tariffs already on
file with the FERC.
InterCoast Gas Marketing Company, a subsidiary of Energy
Services, owns a 50 percent partnership interest in Tenaska
Marketing Ventures (TMV), a natural gas marketer located in
Omaha, Nebraska. TMV provides a full range of natural gas
related services to industrial and utility customers, with
primary emphasis on owners of natural gas-fired electric
generation.
Energy Services also has indirect investments in a variety
of non-regulated energy production technologies including wind,
solar, hydroelectric, and natural gas and coal-fueled generation.
A subsidiary of Energy Services has an ownership interest in a 70
megawatt wind plant that operates in northern California and has
ownership interests in four solar electric generating stations in
southern California's Mojave Desert. In addition, IWG Co. 8, a
subsidiary of Energy Services, has an equity interest in a
hydroelectric operating and development company located in
Annapolis, Maryland and is a participant in a closed-end fund
created to invest in independent power projects. Energy Services
also has equity investments in two developing companies which
produce products and services for the electric and gas utility
industries.
InterCoast Capital Company (InterCoast Capital),
headquartered in Dallas, Texas, manages InterCoast's financial
investments. Such investments consist primarily of investment
grade marketable securities. InterCoast Capital also has
investments in aircraft leases, special purpose funds and real
estate. InterCoast Capital's total financial investments at
December 31, 1994 and 1993 were $297.1 million and $332.1
million, respectively.
InterCoast Capital's marketable securities portfolio,
totaling $199.5 million and $233.4 million at December 31, 1994
and 1993, respectively, focuses on energy securities consisting
primarily of preferred stocks issued by utility companies. All
such preferred stocks have been issued by companies having
investment grade senior debt ratings by Moody's or Standard &
Poor's. In addition to the preferred stocks, InterCoast Capital
has investments in independently managed mutual funds.
InterCoast Capital holds InterCoast's equity participations
in equipment leases for passenger and freight transport aircraft.
Such investments totaled $57.3 million and $56.6 million at
December 31, 1994 and 1993, respectively. InterCoast Capital
also had invested $2.8 million and $3.3 million at December 31,
1994 and 1993, respectively, in safe harbor leases under the
provisions of the Economic Recovery Tax Act of 1981, as amended.
Such safe harbor lease transactions are considered leases for
income tax purposes only.
InterCoast Capital has equity interests in special purpose
funds that invest in venture capital and leveraged buyout
opportunities totaling $34.8 million and $36 million at December
31, 1994 and 1993, respectively.
InterCoast Capital has interests in two real estate
partnerships totaling $2.7 million and $2.8 million at December
31, 1994 and 1993, respectively.
Item 2. Properties
The Company's utility properties consist of physical assets
necessary and appropriate to rendering electric and gas service
in its service territories.
Electric property may be classified principally as
distribution, transmission or generation.
Gas property consists principally of distribution plant,
including feeder lines to communities served from natural gas
pipelines owned by others.
The following table sets forth certain information with
respect to the Company's accredited 1994 summer net generating
capacity. All electric energy generated by the Company is 60-
cycle alternating current, and the Company's generating units are
steam turbine, combustion turbine, and hydro.
<PAGE>
1994
Year Nameplate Total Summer
Placed Ratings of Nameplate Net
In Generators Rating Capacity
Station Service in KW In KW in KW Fuel
Quad-Cities 1972 207,079(1) 414,158(1) 384,750(1) Nuclear
Nuclear 207,079(1)
Power
Station
Cordova,
Illinois
Neal Station, 1975 159,445(2) 159,445(2) 149,350(2) Coal
Unit No. 3,
Sergeant
Bluff, Iowa
Council 1978 235,175(3) 235,175(3) 218,700(3) Coal
Bluffs
Station,
Unit No. 3,
Council
Bluffs, Iowa
Ottumwa 1981 134,282(4) 134,282(4) 132,368(4) Coal
Station,
Chillicothe,
Iowa
Louisa 1983 317,379(5) 317,379(5) 279,500(5) Coal
Station,
Fruitland,
Iowa
Riverside 1949 5,000 141,000 135,000 Coal-Gas
Station, 1961 136,000
Bettendorf,
Iowa
Moline 1970 4 @ 18,000 72,000 64,000 Gas-Oil
Station, 1941-42 4 @ 900 3,600 3,200 Hydro
Moline,
Illinois
Coralville 1970 4 @ 18,000 72,000 64,000 Gas-Oil
Station,
Coralville,
Iowa
1,549,039 1,430,868(5)
(1) Company's share (25%) of jointly owned station with ComEd
(operator of the station). Station has two units each
having a generator nameplate rating of 828,315 KW (920,350
KVA at 0.90 power factor).
(2) Company's share (29%) of jointly owned unit with Midwest
Power Systems Inc. (operator of the unit) and IES Utilities,
Inc. Unit has a generator nameplate rating of 549,810 KW
(610,900 KVA at 0.90 power factor).
(3) Company's share (32.4%) of jointly owned unit with Midwest
Power Systems Inc. (operator of the unit), Cedar Falls
Municipal Electric Utility, Central Iowa Power Cooperative,
Corn Belt Power Cooperative, Inc., and Atlantic Municipal
Utilities. Unit has a generator nameplate rating of 725,850
KW (806,500 KVA at 0.90 power factor).
(4) Company's share (18.5%) of jointly owned unit with IES
Utilities, Inc. (operator of the unit) and Midwest
Power Systems Inc. Unit has a generator nameplate
rating of 725,850 KW (806,500 KVA at 0.90 power
factor).
(5) Company's share (43%) of jointly owned station with Midwest
Power Systems Inc., Central Iowa Power Cooperative,
Interstate Power Company, the city of Geneseo, Illinois and
the cities of Waverly, Harlan, Tipton and Eldridge, Iowa.
Station has one unit with a generator nameplate rating of
738,090 KW (820,100 KVA at 0.90 power factor). The Company
is the operator of this station.
In February 1995, the Mid-Continent Area Power Pool approved
an increase in the accreditation of the Louisa Generating
Station from 650 MW to 675 MW effective as of June 7, 1994.
This action increased the Company's summer net generating
capacity from 1,430,868 KW to 1,441,618 KW.
The electric system of the Company at December 31, 1994
included 305 miles of 345-kV transmission lines, 381 miles of
161-kV lines and 282 miles of 69-kV lines. Distribution lines
included 13,959 miles of overhead conductor and 1,510 miles of
underground conductor at December 31, 1994.
The gas distribution facilities of the Company at December
31, 1994 included 4,271 miles of gas mains.
Substantially all of the fixed utility property and
franchises of the Company, consisting principally of electric
generating plants, electric transmission and distribution lines
and systems, gas feeder and distribution lines and systems and
buildings, are subject to the lien of the Company's Indenture of
Mortgage and Deed of Trust dated as of March 1, 1947, as amended
and supplemented, relating to its First Mortgage Bonds.
The Company's principal plants and properties, insofar as
they constitute real estate, are owned in fee, except for minor
encroachments and other inconsequential defects of title not
interfering, in the opinion of counsel for the Company, with the
Company's operations or use of its property. The Company's
electric and gas distribution facilities and its electric
transmission lines (which constitute a substantial portion of the
Company's investment in physical property) are located over and
under streets, alleys, highways and other public places or on
property owned by others for which permits, grants, easements and
licenses (deemed satisfactory but without examination of
underlying land titles) have been obtained. Some of the
Company's overhead lines and appurtenant equipment are attached
to poles owned by others pursuant to contractual arrangements and
certain transformer vaults and other property are located in
buildings owned by others.
Item 3. Legal Proceedings
See Item 1. Business for discussion of merger, rate and
environmental matters.
Item 4. Submission of Matters to a Vote of Security Holders
At a special meeting held December 21, 1994, shareholders of
the Company approved the Merger Agreement, providing for the
merger of the Company, Midwest Resources Inc. and Midwest Power
Systems Inc. with and into MidAmerican. The votes cast were as
follows:
Number of Votes
Common Preference Total
For 22,480,332 396,250 22,876,582
Against 557,579 - 557,579
Abstain 343,884 6,000 349,884
Broker
Non-votes 4,023,425 97,750 4,121,175
Item 4a. Executive Officers of the Registrant
Age at
Position Incumbent Dec. 31, 1994
Chairman, President
and Chief Executive
Officer Stanley J. Bright (a) 54
Vice President-Finance
and Chief Financial
Officer Lance E. Cooper (b) 51
Vice President Brent E. Gale (c) 43
Vice President Stephen E. Hollonbeck (d) 44
Vice President David J. Levy (e) 40
Vice President Stephen E. Shelton 47
Vice President Ronald W. Stepien (f) 48
Controller Peter E. Burks (g) 59
President and Chief
Operating Officer,
InterCoast Energy
Company Donald C. Heppermann (h) 51
All incumbents have held their respective positions for at
least five years, except where noted. Officers are elected
annually by the Board of Directors.
(a) Elected May 1, 1991. Prior to that time Mr. Bright was
President and Chief Operating Officer (elected
effective April 1, 1990) and Vice President-Finance and
Chief Financial Officer (elected effective September 1,
1986).
(b) Elected effective October 9, 1991. Prior to that time
Mr. Cooper was Vice President-Control, Atlantic City
Electric Company.
(c) Elected effective January 23, 1992. Prior to that time
Mr. Gale was General Counsel, Associate General
Counsel, Assistant General Counsel and Attorney.
(d) Elected effective April 1, 1990. Prior to that time
Mr. Hollonbeck was Manager, Gas Department and Manager,
Gas Supply and System Design.
(e) Elected effective July 1, 1993. Prior to that time Mr.
Levy was Director, Energy Services and Director,
Marketing and Industrial Engineering.
(f) Elected effective August 15, 1990. Prior to that time
Mr. Stepien was Manager for International Parts and
Service After Market Sales of General Electric Company.
(g) Elected effective April 1, 1990. Prior to that time
Mr. Burks was Director, Accounting.
(h) Elected effective June 1, 1990. Prior to that time Mr.
Heppermann was Vice President and Treasurer of Pinnacle
West Capital Corporation. Previous to that position,
he was Vice President-Finance and Administration with
Enron Corporation.
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters
Incorporated by reference to the caption "Shareholders of
Record (1994)" on page 39 and "Stock Listings" on page 41 of the
Company's Annual Report to Shareholders for 1994. This
information is also included in Exhibit 13.A.1 to this Form 10-K.
The quarterly high and low prices for the Company's Common
Shares as reported on the New York Stock Exchange Composite
Transactions Tape for the years 1994 and 1993 are as follows:
1994 High Low 1993 High Low
1st Quarter $24.75 $22.38 1st Quarter $22.88 $19.25
2nd Quarter 24.50 19.88 2nd Quarter 23.75 22.38
3rd Quarter 22.50 19.25 3rd Quarter 26.63 23.63
4th Quarter 20.63 18.88 4th Quarter 26.38 22.63
The $1.73 per Common Share annual dividend was paid
quarterly in 1994 and 1993.
Item 6. Selected Financial Data
Incorporated by reference to the following captions for the
years 1990-1994 on page 39 of the Company's Annual Report to
Shareholders for 1994:
(1) Utility Revenues
(2) Net Income
(3) Net Income on Common Shares
(4) Common Share Statistics-Earnings per Share
(5) Total Assets
(6) Capitalization
(7) Common Share Statistics-Annual Dividend Rate at
December 31
This information is also included in Exhibit 13.A.2 to this Form
10-K.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Incorporated by reference to pages 17-21 of the Company's
Annual Report to Shareholders for 1994. This information is also
included in Exhibit 13.A.3 to this Form 10-K.
<PAGE>
Item 8. Financial Statements and Supplementary Data
Incorporated by reference to pages 22-38 of the Company's
Annual Report to Shareholders for 1994. This information is also
included in Exhibit 13.A.4 to this Form 10-K.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Not applicable.
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant
Information relating to directors is incorporated by
reference to pages 2-5 of the Company's Proxy Statement dated
March 15, 1995. Information relating to executive officers is
set forth in Part I, Item 4a. of this Annual Report of Form 10-K.
Item 11. Executive Compensation
Incorporated by reference to: the last paragraph of page 4,
page 6 -- "Executive Compensation" and pages 7 and 8 -- "Pension
Plan", "Long-Term Incentive Plan (LTIP) Awards Table",
"Supplemental Retirement Plan for Designated Officers" and
"Severance Plan" of the Company's Proxy Statement dated March 15,
1995.
Item 12. Principal Holders of Voting Securities and Security
Ownership of Management
Incorporated by reference to pages 1 and 5 of the Company's
Proxy Statement dated March 15, 1995.
Item 13. Certain Relationships and Related Transactions
NONE
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a)(1) Financial Statements
The following financial statements (including the
notes thereto) and the related audit reports,
incorporated herein by reference, are included in
the Company's 1994 Annual Report to Shareholders
(except as noted):
Page No.
in 1994
Annual
Report
to Share-
holders
22 Consolidated statements of income and retained
earnings for the three years ended December 31,
1994
23,24 Consolidated balance sheets and statements of
capitalization as of December 31, 1994 and 1993
25 Consolidated statements of cash flows for the
three years ended December 31, 1994
26-37 Notes to consolidated financial statements
38 Independent Auditors' Report - 1994 and 1993
Report of Independent Public Accountants - 1992
(included in this Report on Form 10-K at page 33)
(2) Financial statement schedule
The following schedule is included herein:
Page No.
of this
Annual
Report on
Form 10-K
34 Independent Auditors' Report - 1994 and 1993
35 Report of Independent Public Accountants - 1992
36 II Valuation and qualifying accounts for the
years ended December 31, 1994, 1993 and 1992.
(3) Exhibits
See Exhibit Index on pages 39 through 46.
(b) A report on Form 8-K dated December 21, 1994 was
filed. The report included under "Item 5 Other Events"
information related to the special meeting held
December 21, 1994 at which the shareholders of the
Company approved the merger of the Company, Midwest
Resources Inc. and Midwest Power Systems Inc. with and
into MidAmerican Energy Company.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of
Iowa-Illinois Gas and Electric Company:
We have audited the consolidated balance sheet and statement of
capitalization of Iowa-Illinois Gas and Electric Company (an Illinois
corporation) and Subsidiary Company as of December 31, 1992, and the
related consolidated statements of income, retained earnings and cash
flows for the year then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Iowa-
Illinois Gas and Electric Company and Subsidiary Company as of
December 31, 1992, and the results of their operations and their cash
flows for the year then ended, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 28, 1993
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of Iowa-Illinois Gas and Electric Company:
We have audited the consolidated financial statements of Iowa-Illinois
Gas and Electric Company as of December 31, 1994 and 1993 and for each
of the two years in the period ended December 31, 1994, and have
issued our report thereon dated January 25, 1995; such financial
statements and report are included in your 1994 Annual Report to
Shareholders and are incorporated herein by reference. Our audits
also included the financial statement schedule of Iowa-Illinois Gas
and Electric Company as of December 31, 1994 and 1993 and for each of
the two years in the period ended December 31, 1994, listed in Item
14. The financial statement schedule is the responsibility of the
Company's management. Our responsibility is to express an opinion
based on our audits. In our opinion, such financial statement
schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects
the information set forth therein.
Deloitte & Touche LLP
Davenport, Iowa
January 25, 1995
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Iowa-Illinois Gas and Electric Company:
We have audited in accordance with generally accepted auditing
standards, the consolidated balance sheet and statement of
capitalization of Iowa-Illinois Gas and Electric Company and
Subsidiary Company as of December 31, 1992, and the related
consolidated statements of income, retained earnings and cash flows
for the year then ended, included in the Company's annual report to
shareholders incorporated by reference in this Form 10-K, and have
issued our report thereon dated January 28, 1993.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in Item
14(a)(2) as of December 31, 1992, and for the year then ended is the
responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's
rules and is not part of the basic financial statements. This
financial statement schedule has been subjected to the auditing
procedures applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects the financial
data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 28, 1993
<TABLE>
<CAPTION>
SCHEDULE II
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E
Balance Additions Balance
Beginning Charged to End of
Description of Period Income Deductions Period
YEAR ENDED DECEMBER 31, 1994
<S> <C> <C> <C> <C>
ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS:
Uncollectible Accounts $1,164,997 $1,504,048 ($1,504,040) $1,165,005
ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS:
Property Insurance 2,561,285 200,000 (536,950) 2,224,335
Injuries and Damages 974,539 473,452 (444,168) 1,003,823
YEAR ENDED DECEMBER 31, 1993
ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS:
Uncollectible Accounts $1,171,314 $882,951 ($889,268) $1,164,997
ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS:
Property Insurance 2,426,440 134,845 2,561,285
Injuries and Damages 741,663 591,998 (359,122) 974,539
YEAR ENDED DECEMBER 31, 1992
ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS:
Uncollectible Accounts $1,149,069 $825,283 ($803,038) $1,171,314
ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS:
Property Insurance 2,605,000 43,000 (221,560) 2,426,440
Injuries and Damages 795,943 671,860 (726,140) 741,663
</TABLE>
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
March 22, 1995 By L. E. Cooper
L. E. Cooper
Vice President-Finance and CFO
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
Signature Title Date
S. J. Bright Chairman, President, Chief
S. J. Bright Executive Officer and Director
(Principal executive officer) March 22, 1995
L. E. Cooper Vice President-Finance, Chief
L. E. Cooper Financial Officer and Director
(Principal financial officer) March 22, 1995
P. E. Burks Controller March 22, 1995
P. E. Burks (Principal accounting officer)
John W. Colloton Director March 22, 1995
John W. Colloton
Frank S. Cottrell Director March 22, 1995
Frank S. Cottrell
William C. Fletcher Director March 22, 1995
William C. Fletcher
Mel Foster, Jr. Director March 22, 1995
Mel Foster, Jr.
Signature Title Date
Nancy L. Seifert Director March 22, 1995
Nancy L. Seifert
S. E. Shelton Director March 22, 1995
S. E. Shelton
W. Scott Tinsman Director March 22, 1995
W. Scott Tinsman
L. L. Woodruff Director March 22, 1995
L. L. Woodruff
<PAGE>
EXHIBIT INDEX
EXHIBITS FILED HEREWITH
13.A.1 "Shareholders of Record (1994)" appearing on page 39 and
"Stock Listing" appearing on page 41 of the Company's
Annual Report to Shareholders for 1994, incorporated by
reference into Item 5 of this Form 10-K.
13.A.2 "Utility Revenues," "Net Income," "Net Income on Common
Shares," "Common Share Statistics--Earnings per Share,"
"Total Assets," "Capitalization" and "Common Share
Statistics--Annual Dividend Rate at December 31" for the
years 1990-1994, appearing on page 39 of the Company's
Annual Report to Shareholders for 1994, incorporated by
reference into Item 6 of this Form 10-K.
13.A.3 "Management's Discussion and Analysis of Financial
Condition and Results of Operations," appearing on pages
17-21 of the Company's Annual Report to Shareholders for
1994, incorporated by reference into Item 7 of this Form
10-K.
13.A.4 "Financial Statements and Supplementary Data," appearing
on pages 22-38 of the Company's Annual Report to
Shareholders for 1994, incorporated by reference into
Items 1(b), 8 and 14(a)(1) of this Form 10-K.
21 Subsidiaries of the Registrant.
23.A Consent of Deloitte & Touche LLP.
23.B Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
EXHIBITS INCORPORATED BY REFERENCE
The following Exhibits previously filed with the Commission are
incorporated herein by reference. The file number for the
Company's Annual Reports on Form 10-K and Quarterly Reports on
Form 10-Q is 1-3573.
Ex. File No. or Previous
No. Description Ex. No. Description of Document
2 Registration 2(a) Agreement and Plan of Merger
Statement dated as of July 26, 1994 as
on Form S-4 amended and restated as of
(33-56153) of September 27, 1994 among Iowa-
MidAmerican Illinois, Midwest Resources,
Energy Co. Inc., an Iowa corporation, and
Midwest Power Systems, an Iowa
corporation and a subsidiary of
Resources, and a newly-formed
corporation MidAmerican Energy
Company.
3.A Form 10-K 3.A First Restated Articles of
1993 Incorporation of Iowa-Illinois
Gas and Electric Company.
3.B Form 10-Q 3.A Article Eleven of the First
6/30/94 Restated Articles of
Incorporation of Iowa-Illinois
Gas and Electric Company.
3.C Form 10-K 3.B By-laws as amended through April
1993 25, 1991.
4.B.1 2-6922 7B Indenture of Mortgage and Deed of
Trust, dated as of March 1, 1947.
4.B.2 2-6922 7C Supplemental Indenture dated as
of March 1, 1947.
4.B.3 2-8112 7B Second Supplemental Indenture
dated as of October 1, 1949.
4.B.4 2-9990 4.04 Third Supplemental Indenture
dated as of January 15, 1953.
4.B.5 2-62330 2.03E Resignation and appointment of
successor Individual Trustee.
4.B.6 2-17786 2.06 Fourth Supplemental Indenture
dated as of April 15, 1960.
4.B.7 2-26675 2.07 Fifth Supplemental Indenture
dated as of May 1, 1961.
4.B.8 2-28806 2.08 Sixth Supplemental Indenture
dated as of July 1, 1967.
4.B.9 2-34089 2.10 Seventh Supplemental Indenture
dated as of April 1, 1969.
4.B.10 2-38102 2.10 Eighth Supplemental Indenture
dated as of August 15, 1969.
4.B.11 2-38102 2.12 Ninth Supplemental Indenture
dated as of September 1, 1970.
4.B.12 2-45994 2.04L Resignation and appointment of
successor Individual Trustee.
4.B.13 2-53814 2.03M.2 Tenth Supplemental Indenture
dated as of June 15, 1975.
4.B.14 2-55527 2.03N.1 Eleventh Supplemental Indenture
dated as of March 15, 1976.
4.B.15 2-57912 2.03O.1 Twelfth Supplemental Indenture
dated as of January 15, 1977.
4.B.16 2-58838 2.03P Thirteenth Supplemental Indenture
dated as of October 1, 1977.
4.B.17 2-62330 2.03Q.1 Fourteenth Supplemental Indenture
dated as of September 1, 1979.
4.B.18 2-66779 2.03R Fifteenth Supplemental Indenture
dated as of July 15, 1979.
4.B.19 2-66779 2.03S Sixteenth Supplemental Indenture
dated as of January 15, 1980.
4.B.20 2-68600 2.03T Seventeenth Supplemental
Indenture dated as of June 15,
1980.
4.B.21 Form 10-K 4.B.21 Eighteenth Supplemental Indenture
1980 dated as of February 15, 1981.
4.B.22 Form 10-K 4.B.22 Nineteenth Supplemental Indenture
1981 dated as of October 1, 1981.
4.B.23 Form 10-Q 4.B.23 Twentieth Supplemental Indenture
6/30/82 dated as of May 1, 1982.
4.B.24 Form 10-Q 4.B.24 Twenty-First Supplemental
6/30/82 Indenture dated as of July 1,
1982.
4.B.25 Form 10-K 4.B.25 Twenty-Second Supplemental
1983 Indenture dated as of February
15, 1984.
4.B.26 Form 10-K 4.B.26 Twenty-Third Supplemental
1984 Indenture dated as of November 1,
1984.
4.B.27 Form 10-Q 4.B.27 Twenty-Fourth Supplemental
9/30/85 Indenture dated as of September
1, 1985.
4.B.28 Form 10-Q 4.B.28 Twenty-Fifth Supplemental
9/30/86 Indenture dated as of September
15, 1986.
4.B.29 Form 10-K 4.B.29 Twenty-Sixth Supplemental
1986 Indenture dated as of February
15, 1987.
4.B.30 Reg. No. 4.B.30 Resignation and Appointment of
33-39211 successor Individual Trustee.
4.B.31 Form 8-K 4.31.A Twenty-Seventh Supplemental
dated Indenture dated as of October 1,
10/1/91 1991.
4.B.32 Form 8-K 4.31.B Twenty-Eighth Supplemental
dated Indenture dated as of May 15,
5/21/92 1992.
4.B.33 Form 8-K 4.32.A Twenty-Ninth Supplemental
dated Indenture dated as of March 15,
3/24/93 1993.
4.B.34 Form 8-K 4.34.A Thirtieth Supplemental Indenture
dated dated as of October 1, 1993.
10/7/93
10.A.1 2-62331 5.01A Quad-Cities Station Ownership
Agreement dated as of March 17,
1967 between the Company and
Commonwealth Edison Company.
10.A.2 2-45994 5.01B Amendment No. 1 dated as of April
20, 1972 to Quad-Cities Station
Ownership Agreement and Quad-
Cities Operating Agreement.
10.A.3 2-45994 5.02 Quad-Cities Operating Agreement
dated as of November 24, 1967
between the Company and
Commonwealth Edison Company.
10.B 2-45994 5.03 Agreement dated February 2, 1971
re Unit 3 George Neal Generating
Station between the Company, Iowa
Power and Light Company, Iowa
Southern Utilities Company and
Iowa Public Service Company.
10.C 2-45994 5.04 Transmission Facilities Agreement
dated July 28, 1972 between the
Company, Iowa Power and Light
Company, Iowa Southern Utilities
Co. and Iowa Public Service Co.
10.D 2-45994 5.07 Financing Agreement dated as of
April 15, 1972 among the Company,
The First National Bank of Saint
Paul, First National Bank of
Muscatine, the institutions named
in Section 2 thereof and United
States Trust Company of New York.
10.E Form 10-K 10.E Mid-Continent Area Power Pool
1981 Agreement as amended through
Amendment No. 14 effective May 1,
1982.
10.F.1 2-49376 5.08 Agreement dated July 31, 1973 re
Unit 3 Council Bluffs Generating
Station between the Company,
Cedar Falls Municipal Electric
Utility, Central Iowa Power
Cooperative, Inc., Corn Belt
Power Co-operative, Inc., Eastern
Iowa Light and Power Cooperative
Inc. and Iowa Power and Light Co.
10.F.2 2-57912 5.08B Amendment No. 1 to Council Bluffs
Generating Station Unit 3 Agree-
ment, dated January 31, 1975.
10.F.3 2-57912 5.08C Amendment No. 2 to Council Bluffs
Generating Station Unit 3 Agree-
ment, dated September 5, 1975.
10.G 2-53814 5.09 Agreement dated April 16, 1975 re
Unit 1 Ottumwa Generating Station
between the Company, Iowa Power
and Light Company, Iowa Southern
Utilities Company and Iowa Public
Service Company.
10.H.1 2-53814 5.10 Ownership Agreement dated as of
August 15, 1974 re Units 1 and 2
Carroll County Station among the
Company, Commonwealth Edison Co.
and Interstate Power Company.
10.H.2 2-53814 5.11 Operating Agreement dated as of
August 15, 1974 re Units 1 and 2
Carroll County Station among the
Company, Commonwealth Edison Co.
and Interstate Power Company.
10.I.1 2-58838 5.12 Agreement dated October 4, 1977
re Unit 1 Louisa Generating
Station among the Company, Iowa
Power and Light Company, Iowa
Public Service Company, Eastern
Iowa Light and Power Cooperative
and City of Tipton.
10.I.2 Form 10-K 10.J.2 Amendment No. 1 to Unit 1 Louisa
1980 Generating Station Agreement,
dated May 23, 1980.
10.I.3 Form 10-K 10.I.3 Amendment No. 2 to Unit 1 Louisa
1982 Generating Station Agreement,
dated April 26, 1982.
10.I.4 Form 10-K 10.I.4 Amendment No. 3 to Unit 1 Louisa
1982 Generating Station Agreement,
dated February 2, 1983.
10.I.5 Form 10-K 10.I.5 Amendment No. 4 to Unit 1 Louisa
1983 Generating Station Agreement,
dated May 26, 1983.
10.I.6 Form 10-K 10.I.6 Amendment No. 5 to Unit 1 Louisa
1983 Generating Station Agreement
dated October 11, 1983.
10.I.7 Form 10-K 10.I.7 Amendment No. 6 to Unit 1 Louisa
1985 Generating Station Agreement
dated May 29, 1985.
10.J Form 8-K II Rights Agreement dated as of
dated February 25, 1992 between the
2/26/92 Company and First Chicago Trust
Co. of New York, as Rights Agent.
10.K.1* Form 10-K 10.K.1 Severance Plan In The Event Of A
1993 Change In Control, as amended as
of July 1, 1993.
10.K.2* Form 10-K 10.K.2 Supplemental Retirement Plan for
1993 Principal Officers, as amended as
of July 1, 1993.
10.K.3* Form 10-K 10.K.2 Compensation Deferral Plan for
1993 Principal Officers, as amended as
of July 1, 1993.
10.K.4* Form 10-K 10.K.4 Board of Directors' Compensation
1992 Deferral Plan.
10.K.5* Form 10-K 10.K.5 Trust Agreement.
1992
10.K.6* Form 10-K 10.K.6 Key Employee Sustained
1993 Performance Plan.
10.L.1 Form 10-K 10.L.1 Employee Stock Purchase Plan.
1992
10.M Registration 2(a) Agreement and Plan of Merger
Statement dated as of July 26, 1994 as
on Form S-4 amended and restated as of
(33-56153) of September 27, 1994 among Iowa-
MidAmerican Illinois, Midwest Resources,
Energy Co. Inc., an Iowa corporation, and
Midwest Power Systems, an Iowa
corporation and a subsidiary of
Resources, and a newly-formed
corporation MidAmerican Energy
Company.
* Compensatory Plan or Arrangement for Directors or Executive
Officers of the Company.
Exhibit 13.A.1
Iowa-Illinois Gas and Electric Company
1994
Shareholders of Record
Common 22,839
Preferred and Preference 3
Stock Listings:
Iowa-Illinois' common stock is listed on the New York Stock
Exchange and on the Chicago Stock Exchange under the ticker
symbol "IWG." Preference shares are traded in the over-the-
counter market.
Many daily newspapers carry quotes on the common stock.
Exhibit 13.A.2
Iowa-Illinois Gas and Electric Company
Selected Financial Data
(Dollars in thousands, except per share amounts)
(1) Utility Revenues
1994: 555,084
1993: 545,414
1992: 497,534
1991: 512,537
1990: 511,672
(2) Net Income
1994: 59,136
1993: 59,228
1992: 45,433
1991: 54,367
1990: 55,490
(3) Net Income on Common Shares
1994: 54,065
1993: 54,233
1992: 40,404
1991: 50,020
1990: 53,490
(4) Common Share Statistics-Earnings per Share
1994: $ 1.83
1993: $ 1.85
1992: $ 1.45
1991: $ 1.86
1990: $ 1.99
(5) Total Assets
1994: 1,849,899
1993: 1,783,070
1992: 1,648,450
1991: 1,520,049
1990: 1,404,162
(6) Capitalization
First Mortgage Bonds
1994: 323,745
1993: 323,625
1992: 293,727
1991: 296,466
1990: 293,757
<PAGE>
Exhibit 13.A.2
Iowa-Illinois Gas and Electric Company
Selected Financial Data
(Dollars in thousands, except per share amounts)
Other Long-Term Debt
1994: 48,133
1993: 48,275
1992: 37,453
1991: 37,682
1990: 37,910
Long-Term Debt of InterCoast Energy Company
1994: 239,000
1993: 242,500
1992: 257,000
1991: 215,100
1990: 159,000
Preferred/Preference -- nonredeemable
1994: -
1993: 19,829
1992: 19,829
1991: 19,829
1990: 19,829
Preferred/Preference -- redeemable
1994: 50,000
1993: 50,000
1992: 48,625
1991: 49,200
1990: 9,775
Common Equity
1994: 502,242
1993: 499,412
1992: 495,582
1991: 443,608
1990: 436,855
Total
1994: 1,163,120
1993: 1,183,641
1992: 1,152,216
1991: 1,061,885
1990: 957,126
(7) Common Share Statistics-Annual Dividend Rate at December 31
1994: $ 1.73
1993: $ 1.73
1992: $ 1.73
1991: $ 1.71
1990: $ 1.67
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.
<TABLE>
<CAPTION>
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December, 31
1994 1993 1992
(In thousands, except per share amounts)
<S> <C> <C> <C>
OPERATING REVENUES
Electric $355,955 $338,593 $312,667
Gas 199,129 206,821 184,867
555,084 545,414 497,534
OPERATING EXPENSES AND TAXES
Operation-
Cost of gas sold 135,197 141,712 125,317
Cost of fuel, energy and capacity 68,748 64,619 58,266
Other operation 105,916 104,281 102,311
Maintenance 46,665 44,524 39,536
Provision for depreciation 61,829 58,647 53,941
Depreciation and equity funds recovered
under Louisa Phase-In Clause - 2,370 4,515
Income taxes 29,185 24,477 16,320
Property and other taxes 33,903 33,401 33,827
481,443 474,031 434,033
OPERATING INCOME 73,641 71,383 63,501
OTHER INCOME
InterCoast Energy Company -
Oil and gas revenues 59,685 54,979 28,478
Other income 30,717 29,105 27,350
Expenses, including interest and
provision for income taxes (81,386) (71,583) (46,351)
Net income of InterCoast Energy Company 9,016 12,501 9,477
Miscellaneous 380 461 (984)
9,396 12,962 8,493
INCOME BEFORE UTILITY INTEREST CHARGES 83,037 84,345 71,994
UTILITY INTEREST CHARGES
Interest on long-term debt 23,731 24,471 25,793
Other interest expense 1,644 1,625 1,872
Allowance for borrowed funds
used during construction (1,474) (979) (1,104)
23,901 25,117 26,561
NET INCOME 59,136 59,228 45,433
PREFERRED AND PREFERENCE
DIVIDEND REQUIREMENTS 5,071 4,995 5,029
NET INCOME ON COMMON SHARES $54,065 $54,233 $40,404
AVERAGE COMMON SHARES OUTSTANDING 29,492 29,338 27,944
NET INCOME PER AVERAGE
COMMON SHARE OUTSTANDING $1.83 $1.85 $1.45
CASH DIVIDENDS DECLARED AND PAID PER COMMON SHARE $1.73 $1.73 $1.73
<FN>
The accompanying notes to consolidated financial statements are an integral part of
these statements.
-1-
</TABLE>
<TABLE>
<CAPTION>
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1994 1993 1992
(In thousands)
<S> <C> <C> <C>
BALANCE BEGINNING OF YEAR $219,371 $216,082 $224,345
ADD-NET INCOME 59,136 59,228 45,433
DEDUCT:
Cash dividends declared-
Preferred and preference shares 4,661 4,978 5,026
Common shares 50,955 50,756 48,592
Premium paid to reacquire preferred and
preference shares 312 173 -
Other, primarily loss on reissuance of
treasury shares 38 32 78
55,966 55,939 53,696
BALANCE END OF YEAR $222,541 $219,371 $216,082
<FN>
The accompanying notes to consolidated financial statements are an integral part of
these statements.
-2-
</TABLE>
<TABLE>
<CAPTION>
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1994 1993
(In thousands)
<S> <C> <C>
PROPERTY AND OTHER ASSETS
UTILITY PLANT, at original cost
Electric $1,281,027 $1,270,103
Gas 279,118 270,446
1,560,145 1,540,549
Less--Accumulated provision for depreciation 638,493 605,708
921,652 934,841
Nuclear fuel, net of accumulated amortization 31,103 25,120
Construction work in progress 51,316 22,791
1,004,071 982,752
CURRENT ASSETS
Cash and cash equivalents 24,740 17,844
Accounts receivable, less reserves of $1,165 41,498 43,389
Accrued unbilled revenues 21,637 22,182
Inventories 37,328 35,597
Deferred gas expense 4,471 5,794
Other 16,262 18,246
145,936 143,052
INVESTMENTS
InterCoast Energy Company 489,830 501,829
Nuclear decommissioning trust fund 49,432 39,470
Corporate-owned life insurance 14,338 12,836
553,600 554,135
OTHER ASSETS
Regulatory assets 133,427 92,828
Other 12,865 10,303
146,292 103,131
1,849,899 1,783,070
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See accompanying statements) 1,163,120 1,183,641
CURRENT LIABILITIES
Notes payable 67,500 31,000
Debt redeemable within one year 64,145 59,232
Accounts payable 37,785 44,847
Accrued taxes 26,240 24,913
Accrued interest 10,987 11,413
Accrued gas expense 9,499 11,745
Other 20,921 17,865
237,077 201,015
OTHER LIABILITIES
Accumulated provision for nuclear decommissioning 49,432 39,470
Other 69,650 42,984
119,082 82,454
ACCUMULATED DEFERRED INCOME TAXES 291,426 274,605
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 39,194 41,355
$1,849,899 $1,783,070
<FN>
The accompanying notes to consolidated financial statements are an integral part of
these statements.
-3-
</TABLE>
<TABLE>
<CAPTION>
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1994 1993
(In thousands,
except share amounts)
<S> <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY
Common shares-authorized 80,000,000 shares-
outstanding 29,783,486 and 29,352,173 shares stated at $288,692 $280,009
Retained earnings 222,541 219,371
Other (8,991) 32
Total 502,242 43% 499,412 42%
PREFERRED SHARES-authorized 400,000 shares, cumulative-
Not subject to mandatory redemption-outstanding-
$4.36 Series Preferred, 60,000 shares - 6,000
$4.22 Series Preferred, 40,000 shares - 4,000
$7.50 Series Preferred, 98,288 shares - 9,829
Total - - 19,829 2%
PREFERENCE SHARES-authorized 2,386,250 shares, cumulative-
Subject to mandatory redemption-outstanding-
$5.25 Series Preference, 100,000 shares 10,000 10,000
$7.80 Series Preference, 400,000 shares 40,000 40,000
Total 50,000 4% 50,000 4%
LONG-TERM DEBT
First Mortgage Bonds-
5-7/8% Series, due 1997 22,000 22,000
Adjustable Rate Series, due 1997 (7.6%) 25,000 25,000
5.05% Series, due 1998 50,000 50,000
6.0% Series, due 2000 35,000 35,000
8.15% Series, due 2001 40,000 40,000
7.70% Series, due 2004 60,000 60,000
5.8% Series, due 2007 12,750 12,750
7.45% Series, due 2023 30,000 30,000
6.95% Series, due 2025 50,000 50,000
324,750 324,750
Pollution Control Obligations-
5.75%, due 2003 3,683 3,828
Variable Rate-
Due 2016 (5.7% and 2.5%) 33,700 33,700
Due 2017 (5.7% and 2.5%) 3,900 3,900
Due 2023 (5.6% and 3.2%) 6,850 6,850
Unamortized debt premium and discount, net (1,005) (1,128)
Total utility 371,878 371,900
InterCoast Energy Company-
Senior Notes-
9.80%, due 1995 - 9,000
10.01%, due 1995 - 15,000
8.27%, due 1995 - 32,000
9.30%, due 1995 and 1996 9,000 17,000
10.20%, due 1996 and 1997 60,000 60,000
7.34%, due 1998 20,000 20,000
7.76%, due 1999 45,000 45,000
8.52%, due 2000-2002 70,000 -
Borrowings under unsecured revolving
credit facility (6.6% and 4.1%) 35,000 44,500
Total InterCoast Energy Company 239,000 242,500
Total 610,878 53% 614,400 52%
$1,163,120 100% $1,183,641 100%
<FN>
The accompanying notes to consolidated financial statements are an integral part of these statements.
-4-
</TABLE>
<TABLE>
<CAPTION>
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
(In thousands)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $59,136 $59,228 $45,433
Adjustments to reconcile net income
to net cash from operating activities -
Depreciation 65,880 63,839 58,374
Depletion 17,949 12,880 8,517
Depreciation and equity funds recovered
under Louisa Phase-In Clause - 2,370 4,515
Nuclear fuel amortization 5,334 7,989 7,860
Deferred income taxes, net 11,047 9,707 5,128
Tax credits, net (2,161) (2,208) (2,326)
Net gain on disposition of securities (5,187) (3,289) (4,261)
Changes in current assets and liabilities -
Accounts receivable 1,891 2,434 (2,937)
Accrued unbilled revenues 545 (1,567) (2,340)
Inventories (1,731) 4,550 (349)
Deferred and accrued gas expense (923) 3,310 (7,641)
Accounts payable (7,162) 5,038 3,529
Accrued taxes 1,327 (2,643) 2,794
Other current assets and liabilities 4,423 (4,659) (6,568)
Energy-efficiency program cost deferrals (7,641) (5,669) (4,005)
Other 2,222 3,054 (5,743)
Net cash from operating activities 144,949 154,364 99,980
CASH FLOWS FROM INVESTING ACTIVITIES
Utility plant expenditures (68,957) (60,162) (64,385)
Nuclear fuel expenditures (11,317) (6,795) (9,313)
Nuclear decommissioning trust fund (9,044) (7,918) (4,469)
Oil and gas investments (39,384) (73,538) (22,169)
Purchase of available-for-sale investments (123,714) - -
Sale of available-for-sale investments 142,272 - -
Purchase of investments - (206,139) (216,264)
Sale of investments - 208,271 173,941
Other 1,975 (1,151) (6,826)
Net cash from investing activities (108,169) (147,432) (149,485)
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 8,812 - 61,563
Preference shares issued - 10,000 -
Preferred and preference shares redeemed (20,141) (9,373) (575)
Long-term debt issued - 175,784 59,830
Long-term debt retired (232) (143,493) (62,626)
Increase (decrease) in short-term borrowings 36,500 (21,500) -
Long-term borrowings of InterCoast
Energy Company -
Senior Notes issued 70,000 - 65,000
Senior Notes retired (59,000) (8,000)
Increase (decrease) in unsecured
revolving credit facility (9,500) 44,500 (15,100)
Dividends paid (55,953) (55,745) (53,630)
Issuance expense (370) (2,088) (3,187)
Net cash from financing activities (29,884) (9,915) 51,275
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 6,896 (2,983) 1,770
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 17,844 20,827 19,057
CASH AND CASH EQUIVALENTS AT END OF YEAR $24,740 $17,844 $20,827
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the year for -
Interest (net of amounts capitalized) $50,121 $51,295 $48,036
Income taxes 15,728 18,014 10,074
<FN>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
-5-
</TABLE>
<PAGE>
Iowa-Illinois Gas and Electric Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies:
(A) Principles of Consolidation
The consolidated financial statements include the Company
and its wholly owned non-regulated subsidiary, InterCoast Energy
Company (InterCoast). Intercompany transactions have been
eliminated.
_________________________________________________________________
(B) Regulation
The Company's utility operations are subject to the
regulation of the Iowa Utilities Board (IUB), the Illinois
Commerce Commission (ICC) and the Federal Energy Regulatory
Commission (FERC). The Company's accounting policies and the
accompanying Consolidated Financial Statements conform to
generally accepted accounting principles applicable to rate-
regulated enterprises and reflect the effects of the ratemaking
process. Such effects concern mainly the time at which various
items enter into the determination of net income in accordance
with the principle of matching costs and revenues.
The following regulatory assets represent probable future
revenue to the Company because provisions for these costs are
expected to be included in charges to utility customers through
the ratemaking process:
December 31,
1994 1993
(In thousands)
Income taxes recoverable
through future rates............ $ 61,150 $50,571
FERC Order 636 transition costs... 23,465 -
Unamortized premium on reacquired
debt............................ 10,645 11,513
Deferred energy-efficiency
program costs................... 18,432 10,791
United States Department of Energy
(DOE) nuclear enrichment
facilities decontamination and
decommissioning fee............. 9,807 10,656
Manufactured gas plant site
related costs................... 7,682 7,768
Other, primarily deferred pension
costs........................... 2,246 1,529
$133,427 $92,828
Refer to Note 4 for information regarding income taxes
recoverable through future rates.
Refer to Note 2B for information regarding gas transition
costs.
Consistent with regulatory treatment, the premiums paid to
reacquire debt prior to scheduled maturity dates are deferred and
amortized over the life of the debt issued to finance the
reacquisitions.
In 1991, the Company filed a comprehensive three-year
energy-efficiency plan with the IUB in compliance with 1990 Iowa
legislation. The legislation permits recovery of deferred
energy-efficiency program costs, and related carrying charges, so
long as the utility's programs are cost effective or, if not cost
effective, planned and implemented in a prudent and reasonable
manner. The legislation also allows for performance rewards. In
October 1994, the Company filed an application for recovery of an
aggregate $18.6 million of deferred energy-efficiency program
costs, associated returns and performance rewards over a four-
year period.
The National Energy Policy Act of 1992 established funding
for the decontamination and decommissioning of nuclear enrichment
facilities operated by the 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,
respectively, of such payments were charged to fuel expense and
recognized in the energy adjustment clauses.
In Illinois, costs related to the litigation, investigation
and remediation of former manufactured gas plant sites are
recovered through gas and electric adjustment riders. Costs from
1992 and 1993 were deferred pursuant to an ICC order for recovery
beginning in 1994. All such costs are to be amortized over a
five-year period and no carrying charges are assigned to the
unamortized balances. In Iowa, costs related to the litigation,
investigation and remediation of former manufactured gas plant
sites are being expensed as incurred. The Company's current Iowa
gas rates include an annual provision of $250,000 for such costs.
Refer to Note 14 for information regarding former manufactured
gas plant sites.
Refer to Note 5 for information regarding deferred pension
costs.
_________________________________________________________________
(C) Customer Receivables and Operating Revenues
The Company's customer receivables, gas and electric sales
and gas transportation revenue are derived from supplying and
delivering electricity and natural gas to a well-diversified base
of residential, commercial and industrial customers located in
central and eastern Iowa and western Illinois. Customer accounts
receivable include the following amounts by class of customer:
December 31,
1994 1993
(In thousands)
Residential.................... $ 18,174 $ 18,525
Commercial..................... 10,897 11,107
Industrial..................... 9,602 9,795
Other.......................... 1,531 1,557
Revenues are recorded as services are rendered to customers.
The Company records unbilled revenues, and related energy costs,
representing the estimated amount customers will be billed for
services rendered between the meter-reading dates in a particular
month and the end of such month.
_________________________________________________________________
(D) Energy Costs
The energy (electric fuel and energy and purchased gas) rate
provisions in the Company's tariffs are designed to provide for
separately stated energy billings that cover changes in
applicable net energy costs from levels incorporated in base
rates. Differences between applicable energy costs incurred and
energy rate revenues billed in any given period are accounted for
as other current assets or other current liabilities, pending the
disposition of such differences through reconciliation provisions
in the energy adjustment clauses.
_________________________________________________________________
(E) Nuclear Fuel Costs
Included as a part of the cost of nuclear fuel is a
provision for its estimated disposal cost, which is being
recognized at a rate of 1 mill per kilowatt-hour of nuclear
generation in conformance with DOE rules. Such amounts are
recoverable through the energy adjustment clauses.
_________________________________________________________________
(F) Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC)
includes the costs of equity and borrowed funds used to finance
construction, which are capitalized in accordance with rules
prescribed by the FERC. In 1994, 1993 and 1992, the Company's
AFUDC rates were 5.6%, 3.3% and 3.8%, respectively, compounded
semi-annually. While currently capitalized AFUDC does not
represent a current source of cash, it does represent a basis for
future sources of cash through the inclusion in rates of
depreciation charges and allowance for returns on investment.
_________________________________________________________________
(G) Depreciation
Depreciation is computed using the straight-line method.
Provisions for depreciation, expressed as an annual percentage of
the cost of average depreciable plant in service, were as follows
for the periods shown:
Year Ended December 31,
1994 1993 1992
Electric........................ 4.3% 4.2% 4.0%
Gas............................. 3.6 4.0 3.8
An allowance for the estimated decommissioning costs of the
Quad-Cities Nuclear Power Station (Quad-Cities) is included in
depreciation expense. The Company's share of the cost to
decommission the Quad-Cities units is estimated to be $181.9
million in 1994 dollars. Such decommissioning costs include the
cost of decontamination, dismantlement and site restoration.
Electric tariffs included provisions for the costs of nuclear
decommissioning of $9.1 million, $7.9 million and $5.0 million
for 1994, 1993 and 1992, respectively.
The Company has established an external trust for the
investment of funds collected for nuclear decommissioning.
Electric tariffs for 1995 include provisions for annual
decommissioning costs of approximately $8.6 million. In
Illinois, nuclear decommissioning costs are included in customer
billings through a mechanism that permits annual adjustments. In
Iowa, such costs are reflected in base rates.
_________________________________________________________________
(H) Scheduled Nuclear Refueling Outage Costs
Incremental operation and maintenance costs due to scheduled
nuclear refueling outages are accrued, based upon the planned
outage schedules and the estimated costs for such outages, over
the estimated periods between scheduled outages. Any differences
between accrued and actual outage costs are expensed in the
periods in which the outages occur.
_________________________________________________________________
(I) Marketable Securities
InterCoast's holdings of marketable securities generally
consist of preferred stocks, common stocks and mutual funds.
Prior to 1994, InterCoast's holdings of marketable securities
were stated at the lower of aggregate cost or market. A decline
in the market value of marketable equity securities below their
cost basis was recognized in the consolidated financial
statements through the establishment of a valuation allowance,
which was reflected as a reduction of Other Common Shareholders'
Equity.
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities (SFAS 115). Upon
adoption, InterCoast classified its entire holdings of marketable
securities as available-for-sale reflecting management's
intention to hold such securities for indefinite periods of time.
Under this statement, InterCoast's investments in marketable
securities that are classified as available-for-sale are reported
at fair value with net unrealized gains and losses reported as a
net of tax amount in Other Common Shareholders' Equity until
realized. On August 31, 1994, InterCoast transferred certain
sinking fund preferred stocks with a market value of $40.6
million from the available-for-sale category to the held-to-
maturity category. This transfer, which is at market value and
is the new cost basis of such securities, was based on
management's intent and ability to hold such securities until
maturity. The $1.5 million excess of amortized cost over market
value at August 31, 1994 will be amortized over the life of such
securities. InterCoast's investments in marketable securities
that are classified as held-to-maturity are reported at amortized
cost. An other-than-temporary decline in the value of a
marketable security is recognized through a write-down or write-
off of the investment to earnings.
Investments held by the nuclear decommissioning trust fund
are classified as available-for-sale and are reported at fair
value with net unrealized gains and losses reported as
adjustments to the accumulated provision for nuclear
decommissioning.
The adoption of SFAS 115 did not have a material effect on
the financial position or results of operations of the Company.
_______________________________________________________________
(J) Oil and Gas
InterCoast uses the full cost method of accounting for oil
and gas activities. Under the full cost method, all acquisition,
exploration and development costs are capitalized and amortized
over the estimated production from proved oil and gas reserves.
Under the full cost method, net capitalized costs may not exceed
the present value of proved reserves as determined under the
rules of the Securities and Exchange Commission.
_________________________________________________________________
(K) Consolidated Statements of Cash Flows
For purposes of the Consolidated Balance Sheets and the
Consolidated Statements of Cash Flows, the Company considers all
highly liquid debt instruments held that have original maturities
of three months or less to be cash equivalents. No material non-
cash investing or financing transactions occurred during 1994,
1993 or 1992.
_________________________________________________________________
(L) Reclassification
Certain 1993 and 1992 amounts have been reclassified to
conform to the current year presentation.
_________________________________________________________________
(2) Rate Matters:
(A) Iowa Energy-Efficiency Programs Filing
In October 1994, the Company filed an application with the
IUB to recover the costs of state-mandated energy-efficiency
programs offered to Iowa electric and gas customers since 1992.
Costs of the programs are to be recovered over four years, as
required by Iowa law. The overall annual rate increase
requested, including a return on deferred amounts and an
allowance for performance rewards, is approximately $4.7 million
(1.4%). The proposed effective date for cost-recovery additions
on customer bills is June 1995.
_________________________________________________________________
(B) Federal Gas Transition Costs
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 costs through rates.
_________________________________________________________________
(3) InterCoast Energy Company:
The Company's non-regulated businesses are managed by
InterCoast, a wholly owned subsidiary. The non-regulated
activities emphasize energy-related diversification, credit
quality and liquidity. InterCoast takes advantage of a core
expertise in energy, participating in the energy industry through
three non-regulated business groups: oil and natural gas; energy
services; and financial investments.
Condensed consolidated financial information of InterCoast
and its subsidiaries follows.
Consolidated Statements of Income
Year Ended December 31,
1994 1993 1992
(In thousands)
Income:
Oil and gas revenues.......... $59,685 $54,979 $28,478
Dividends and interest........ 18,144 19,103 18,917
Realized gains, net........... 5,187 3,289 4,261
Other income.................. 7,386 6,713 4,172
Total income.................... 90,402 84,084 55,828
Expenses:
Oil and gas................... 46,106 38,749 20,285
Interest...................... 25,794 24,573 20,994
Other expenses................ 11,215 8,885 6,240
Provision for income taxes.... (1,729) ( 624) ( 1,168)
Total expenses.................. 81,386 71,583 46,351
Net income...................... $ 9,016 $12,501 $ 9,477
Consolidated Balance Sheets
December 31,
1994 1993
(In thousands)
Current assets.................. $ 29,597 $ 21,926
Investments:
Marketable securities......... 199,514 233,386
Oil and gas................... 142,378 120,952
Equipment leases.............. 60,134 59,937
Energy projects............... 50,316 48,777
Special-purpose funds......... 34,767 36,021
Real estate................... 2,721 2,756
Total investments............... 489,830 501,829
Other assets.................... 3,788 2,961
Total assets.................... $523,215 $526,716
December 31,
1994 1993
(In thousands)
Long-term debt maturing
within one year............... $ 64,000 $ 59,000
Other current liabilities....... 13,977 20,682
Long-term debt.................. 239,000 242,500
Accumulated deferred income
taxes......................... 61,112 59,433
Shareholder's equity............ 145,126 145,101
Total liabilities and
shareholder's equity.......... $523,215 $526,716
InterCoast is subject to certain restrictions under the
terms of its borrowing arrangements. Such restrictions include
provisions that limit the amounts that can be expended for
dividends. At December 31, 1994 and 1993, $23.2 million and
$16.5 million, respectively, of InterCoast's equity was available
for dividends.
_________________________________________________________________
(4) Income Taxes:
The IUB has primarily limited the use of deferred income tax
accounting to federal income taxes deferred as a result of the
use of accelerated tax depreciation, as mandated by the
normalization provisions of the Internal Revenue Code. The ICC,
however, generally permits deferral of the tax effect of all book
and tax differences.
Investment tax credits (ITC) on the Company's investments in
utility plant have been deferred and are being amortized to
income over the life of the related property.
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.
The Company recognizes deferred income tax assets and
liabilities, based on enacted tax laws, for all temporary
differences between the financial reporting and tax bases of
assets and liabilities. The portion of the Company's deferred
tax liability applicable to utility operations that has not been
reflected in service rates represents income taxes recoverable
through future rates.
Income tax expense is reflected in the Consolidated
Statements of Income as follows:
Year Ended December 31,
1994 1993 1992
(In thousands)
Included in Operating Expenses:
Current -Federal............. $20,227 $16,398 $12,607
-State............... 5,551 4,429 3,464
Deferred -Federal............. 5,042 5,318 2,532
-State............... 527 539 43
Deferred federal ITC, net..... ( 2,162) ( 2,207) ( 2,326)
Total included in Operating
Expenses.................... 29,185 24,477 16,320
Included in Other Income........ ( 2,117) ( 666) ( 1,763)
Total income tax expense........ $27,068 $23,811 $14,557
The components of the net deferred tax liability are as
follows:
December 31,
1994 1993
(In thousands)
Accelerated depreciation methods..... $ 270,321 $267,942
Income taxes recoverable
through future rates............... 84,550 75,212
AMT credit carryforward.............. (34,555) (37,756)
Deferred ITC refundable
through future rates............... (23,400) (24,641)
Nuclear reserves and decommissioning. (8,551) (6,708)
Other deferred taxes, net............ 3,061 556
Accumulated deferred income taxes.... $ 291,426 $274,605
The following is a reconciliation of the statutory federal
income tax rate to the overall effective income tax rate
(computed by dividing income taxes, including income tax amounts
applicable to other income, by net income before the deduction of
such taxes):
Year Ended December 31,
1994 1993 1992
Statutory federal income
tax rate...................... 35.0% 35.0% 34.0%
State income taxes, net of
federal income tax benefit.... 4.4 4.7 3.3
Investment and energy tax
credits....................... ( 2.5) ( 2.7) ( 3.9)
Excess of book depreciation over
tax depreciation not deferred. 1.7 1.6 2.2
Dividends received deduction.... ( 4.9) ( 5.2) ( 6.9)
Adjustment for method of
deducting property taxes...... ( 1.4) ( 1.4) ( 2.0)
Other items, net................ ( 0.9) ( 3.3) ( 2.4)
Overall effective income
tax rate...................... 31.4% 28.7% 24.3%
_________________________________________________________________
(5) Pensions and Other Employee Benefits:
The Company has a noncontributory defined benefit retirement
income plan covering substantially all regular employees.
Benefits under the plan are based on participants' compensation,
years of service and age at retirement. Funding is based upon
the actuarially determined costs of the plan and the requirements
of the Internal Revenue Code and the Employee Retirement Income
Security Act.
Provisions for pension costs are determined under generally
accepted accounting principles, which include the use of the
projected unit credit actuarial cost method. A regulatory
adjustment has been made to the pension cost amounts to reflect
only the amount of pension cost recognized through the ratemaking
process. Net pension cost, part of which was charged to utility
plant or billed to others, was $466,000 in 1994, $562,000 in 1993
and $175,000 in 1992. The components of the 1994, 1993 and 1992
pension cost provisions are as follows:
<PAGE>
Year Ended December 31,
1994 1993 1992
(In thousands)
Cost of benefits earned during
the year...................... $ 3,581 $ 3,283 $ 2,769
Interest on projected benefit
obligation.................... 10,303 10,480 9,519
Actual investment return on
plan assets................... ( 3,433) (17,009) (12,340)
Net amortization and deferral... ( 9,303) 4,712 548
Pension cost.................... 1,148 1,466 496
Regulatory adjustment........... ( 682) ( 904) ( 321)
Net pension cost................ $ 466 $ 562 $ 175
The expected long-term rate of return on plan assets used in
determining pension cost was 8.75% for 1994, 1993 and 1992.
A reconciliation of plan assets and liabilities to the
accrued pension costs included in the Consolidated Balance Sheets
is presented below:
December 31,
1994 1993
(In thousands)
Fair market value of pension plan
assets, invested primarily in
equity and fixed-income
securities.................... $147,046 $151,134
Actuarial present value of
benefits for services
rendered to date:
Accumulated benefits to date,
including vested benefits
of $99,370 and $118,300
for 1994 and 1993,
respectively.............. 102,171 122,221
Additional benefits based
on estimated future
compensation levels....... 23,188 29,478
Projected benefit obligation.... 125,359 151,699
Plan assets in excess of (or less
than) projected benefit
obligation.................... 21,687 ( 565)
Unamortized balance of plan net
assets existing at
January 1, 1986, being
amortized over 17 years....... ( 9,160) ( 10,305)
Unrecognized prior service cost. 16,614 18,849
Unrecognized net gain........... ( 32,802) ( 10,492)
Accrued pension cost............ $( 3,661) $( 2,513)
Assumed discount rate........... 8.5% 7.0%
Assumed rate of increase in
future compensation levels.... 5.0% 5.0%
The Company currently provides certain health care and life
insurance benefits for retired employees. Substantially all of
the Company's employees become eligible for these additional
benefits if they reach retirement age while employed by the
Company.
Provisions for these postretirement health care and life
insurance benefits are accrued over the years the employees are
expected to render the necessary service. The Company is
externally funding all such provisions.
The components of the 1994 and 1993 net postretirement
benefits other than pensions cost provision are as follows:
Year Ended December 31,
1994 1993
(In thousands)
Cost of benefits earned
during the year..................$ 492 $ 474
Interest on accumulated
postretirement benefit
obligation....................... 914 1,061
Actual investment return
on plan assets................... 31 (6)
Net amortization and deferral...... 614 688
Net postretirement benefits
other than pensions cost.........$ 2,051 $ 2,217
A reconciliation of such postretirement benefit plan assets
and liabilities to the amounts included in the Consolidated
Balance Sheets is presented below:
December 31,
1994 1993
(In thousands)
Fair market value of plan assets,
invested primarily in short-
term securities.................. $ 1,584 $ 976
Actuarial present value of
benefits for services
rendered to date:
Active plan participants........ 5,488 6,941
Fully eligible plan participants 1,864 2,321
Retirees........................ 4,141 3,792
Accumulated postretirement
benefit obligation............... 11,493 13,054
Accumulated postretirement
benefit obligation in excess
of plan assets................... ( 9,909) (12,078)
Unamortized balance of plan
obligation existing at
January 1, 1993, being
amortized over 20 years.......... 12,154 12,829
Unrecognized net gain.............. ( 2,245) ( 751)
Accrued postretirement benefit
other than pensions cost......... $ - $ -
For measurement purposes, the health care cost trend rate
assumed for pre-65 coverage is 12% for 1995, decreasing 1% per
year to 5% in 2002 and thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported.
To illustrate, increasing the assumed health care cost trend rate
by one percentage point in each year would increase the
accumulated postretirement benefit obligation for health care
costs as of December 31, 1994 by $722,000 and the aggregate of
the 1994 service and interest cost components of net
postretirement health care cost by $112,000. The discount rate
used was 8.5%.
The Company has adopted voluntary Compensation Deferral and
Supplemental Retirement plans for designated executives. Such
plans are unfunded and the liabilities thereunder are payable
from general funds of the Company. To provide for its
liabilities under these plans, the Company has purchased, owns
and is the beneficiary of life insurance policies on the lives of
participating executives. Returns on such policies are expected
to cover the full cost of the related plans.
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 112, Employers' Accounting for
Postemployment Benefits, which requires the accrual of the
estimated cost of benefits provided to former or inactive
employees after employment but before retirement. Adoption did
not have a material effect on financial position or results of
operations.
_________________________________________________________________
(6) Jointly Owned Generating Stations:
Under joint ownership agreements with other utility
companies, the Company has undivided interests in one nuclear and
four coal-fired electric generating stations. Information
concerning each of the jointly owned stations follows:
Nuclear Coal-fired
Council
Quad-Cities Neal Bluffs Ottumwa Louisa
Units Unit Unit Unit Unit
No. 1 & 2 No.3 No.3 No.1 No.1
In service date..... 1972 1975 1978 1981 1983
Company share of
utility plant in
service (in
millions)......... $194.6 $46.5 $120.3 $73.8 $260.4
Total plant capacity
-megawatts........ 1,539 515 675 716 650
Company share
-percent.......... 25.0% 29.0% 32.4% 18.5% 43.0%
The Consolidated Financial Statements reflect the Company's
portions of all plant investments and all operating costs
associated with these units. Depreciation reserves by individual
station are not maintained.
Although the Louisa Unit No. 1 is operated and maintained by
the Company, each of the other units is operated and maintained
by another utility company. Each participant has provided the
financing for its share of the total investment in each project.
________________________________________________________________
(7) Inventories:
Inventories include the following amounts:
December 31,
1994 1993
(In thousands)
Materials and supplies,
at average cost............ $14,871 $15,151
Coal stocks, at Last-In,
First-Out (LIFO) cost...... 8,750 6,385
Fuel oil, at average cost......... 288 249
Gas in storage, at LIFO cost...... 13,419 13,812
$37,328 $35,597
At December 31, 1994 prices, the current costs of coal
stocks and gas in storage were $9.0 million and $21.3 million,
respectively.
_________________________________________________________________
(8) Fair Value of Financial Instruments:
The following methods and assumptions were used to estimate
the fair value at December 31, 1994 and 1993 of each class of
financial instruments for which it is practicable to make such
estimates. Tariffs for the Company's utility services are
established based on historical cost ratemaking. Therefore, the
impact of any realized gains or losses related to financial
instruments applicable to the Company's utility operations is
dependent on the treatment authorized under future ratemaking
proceedings.
Cash and cash equivalents - The carrying amount approximates
fair value due to the short maturity of these instruments.
Nuclear decommissioning trust fund - Fair value is based on
quoted market prices of the investments held by the fund.
Marketable securities - Fair value is based on quoted market
prices.
Debt securities - Fair value is based on the discounted
value of the future cash flows expected to be received from such
investments.
Equity investments carried at cost - Fair value is based on
an estimate of the Company's share of partnership equity or on
the discounted value of the future cash flows expected to be
received from such investments.
Equity investments in developing companies - It is not
practicable to determine the fair value of such investments as
they represent new ventures for which no market price exists.
Notes payable - Fair value is estimated to be the carrying
amount due to the short maturity of these issues.
Preference shares - Fair value of preference shares with
mandatory redemption provisions is estimated based on the quoted
market prices for similar issues.
Long-term debt - Fair value of long-term debt is estimated
based on the quoted market prices for the same or similar issues
or on the current rates offered to the Company for debt of the
same remaining maturities.
December 31, 1994 December 31, 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Electric and gas utility:
Nuclear decommissioning
trust fund............. $ 49,432 $ 49,432 $ 39,470 $ 41,588
Preference shares....... 50,000 50,836 50,000 54,850
Long-term debt,
including current
portion................ 372,023 346,241 372,132 384,954
InterCoast Energy Company:
Marketable securities... 199,514 198,140 233,386 239,114
Debt securities......... 14,804 12,994 14,195 16,124
Equity investments
carried at cost........ 22,352 23,930 27,141 27,789
Long-term debt,
including current
portion................ 303,000 294,762 301,500 317,700
The amortized cost, gross unrealized gains and losses and
estimated fair value of investments in debt and equity securities
at December 31, 1994 are summarized as follows:
<PAGE>
December 31, 1994
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
(In thousands)
Investments in debt and
equity securities--
Electric and gas utility:
Nuclear decommissioning
trust fund:
Available-for-sale
Cash equivalents...... $ 5,836 $ - $ - $ 5,836
Municipal bonds....... 43,034 749 (1,773) 42,010
Other................. 1,586 - - 1,586
$ 50,456 $ 749 $ (1,773) $ 49,432
InterCoast Energy Company:
Available-for-sale
Equity securities..... $171,201 $ 2,388 $ (14,703) $158,886
Held-to-maturity
Equity securities..... 40,628 - ( 1,374) 39,254
Debt securities....... 14,804 39 ( 1,849) 12,994
At December 31, 1994, the debt securities held by the
nuclear decommissioning trust fund and InterCoast had the
following maturities:
Nuclear Decommissioning
Trust Fund InterCoast
Amortized Fair Amortized Fair
Cost Value Cost Value
(In thousands)
Within 1 year $ 2,862 $ 2,757 $ 1,791 $ 1,782
1 through 5 years 9,405 9,018 501 451
5 through 10 years 16,409 16,023 5,157 4,144
Over 10 years 14,358 14,212 7,355 6,617
The proceeds and the gross realized gains and losses on the
disposition of investments held by the nuclear decommissioning
trust fund and InterCoast for 1994 are as follows:
Year Ended December 31,
1994
(In thousands)
Nuclear Decommissioning Trust Fund:
Proceeds from sales................ $ 2,214
Gross security gains............... 2
Gross security losses.............. (85)
InterCoast Energy Company:
Proceeds from sales................ 133,555
Gross security gains............... 10,336
Gross security losses.............. (5,149)
_________________________________________________________________
(9) Common Shareholders' Equity:
Changes in the Company's outstanding common shares for the
years 1994, 1993 and 1992 are as follows:
Year Ended December 31,
Amount
1994 1993 1992
(In thousands)
Outstanding, beginning of year. $280,009 $280,055 $220,819
Public sale of shares........ - - 61,563
Dividend reinvestment........ 8,812 - -
Capital stock expense........ ( 45) ( 122) ( 2,392)
Treasury shares
Purchased.................. ( 771) ( 689) ( 632)
Reissued................... 687 765 697
Outstanding, end of year....... $288,692 $280,009 $280,055
Shares
1994 1993 1992
Outstanding, beginning of year. 29,352,173 29,349,177 26,845,687
Public sale of shares........ - - 2,500,000
Dividend reinvestment........ 435,624 - -
Treasury shares
Purchased.................. (37,445) ( 31,100) ( 25,000)
Reissued................... 33,134 34,096 28,490
Outstanding, end of year....... 29,783,486 29,352,173 29,349,177
The components of Other Common Shareholders' Equity are as
follows:
December 31,
1994 1993
(In thousands)
Premium on Preferred shares.... $ - $ 32
Marked to market valuation,
net of deferred tax.......... (8,991) -
$(8,991) $ 32
The Company has an Employee Stock Purchase Plan. The
purchase of common shares under this Plan is made on the open
market. At December 31, 1994 and 1993, 4,750 and 439 treasury
shares acquired in the open market for this Plan were held for
reissuance.
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 made by shareholders.
_________________________________________________________________
(10) Long-Term Debt, Maturities and Sinking Fund Requirements:
The 1994 sinking fund requirements for First Mortgage Bonds
and Senior Notes were satisfied through the reacquisition of debt
or the bonding of additional property. The aggregate maturities
and sinking fund requirements for long-term debt outstanding at
December 31, 1994 are as follows:
1995 1996 1997 1998 1999
(In thousands)
First Mortgage Bonds. $ 220 $ 220 $47,200 $50,200 $ 200
Pollution Control
Obligations........ 145 145 145 145 145
Senior Notes of
InterCoast......... 64,000 39,000 30,000 20,000 45,000
Unsecured Revolving
Credit Facility of
InterCoast......... - 35,000 - - -
Total................ $64,365 $74,365 $77,345 $70,345 $45,345
Included in the above amounts are annual sinking fund
requirements related to First Mortgage Bonds of $220,000 for 1995
and 1996, which may be reduced by certifying net property
additions not previously bonded, in accordance with the terms of
the Company's Indenture of Mortgage securing its First Mortgage
Bonds.
The interest rate on the Company's Adjustable Rate Series
First Mortgage Bonds is reset every two years at 160 basis points
over the average yield to maturity of 10-year Treasury
securities. The rate was reset in 1993.
The Company's Variable Rate Pollution Control Obligations
bear interest at rates that are periodically established through
remarketing of the bonds in the short-term tax-exempt market.
The Company, at its option, may change the mode of interest
calculation for these bonds by selection from among several
alternative floating or fixed rate modes. The interest rates
shown in the Consolidated Statements of Capitalization are the
weighted average interest rates as of December 31, 1994 and 1993.
The Company maintains backup long-term letters of credit and a
dedicated long-term revolving line of credit providing liquidity
for holders of these issues.
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.
The Company's First Mortgage Bonds are secured by
substantially all fixed property and franchises of the Company
devoted to its utility businesses.
InterCoast's unsecured Senior Notes (Notes) are issued in
private placement transactions. All Notes are issued without
recourse to the parent Company.
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 $35.0 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%.
_________________________________________________________________
(11) Preferred and Preference Shares:
The $5.25 Series Preference Shares, which are not redeemable
prior to November 1, 1998 for any purpose, are subject to
mandatory redemption on November 1, 2003 at $100 per share. The
$7.80 Series Preference Shares, which are not redeemable prior to
May 1, 1996 for any purpose, have sinking fund requirements under
which 66,600 shares will be redeemed at $100 per share each May
1, beginning in 2001 through May 1, 2006.
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.
_________________________________________________________________
(12) Notes Payable:
The Company's notes payable reflect borrowings that have
been obtained solely through its short-term commercial paper
program. Information regarding short-term debt follows:
1994 1993 1992
(Dollars in thousands)
Balance at year-end............. $67,500 $31,000 $52,500
Weighted average interest rate
on year-end balance........... 6.1% 3.4% 3.6%
Maximum amount outstanding
during the year............... $67,500 $73,000 $77,000
Average daily amount outstanding
during the year............... $28,605 $43,291 $39,973
Weighted average interest rate
on average daily amount
outstanding during the year... 4.5% 3.3% 3.8%
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.
_________________________________________________________________
(13) Leases:
Rental payments under non-cancellable operating leases for
1994, 1993 and 1992 were $2,123,000, $2,013,000 and $1,941,000,
respectively. At December 31, 1994, the future minimum lease
payments under non-cancellable operating leases are as follow:
Amount
(In thousands)
1995 ................................... $ 2,238
1996 ................................... 2,147
1997 ................................... 1,867
1998 ................................... 1,648
1999 ................................... 1,553
After 1999 ............................. 13,422
________________________________________________________________
(14) Commitments and Contingencies:
Utility construction expenditures for 1995 are estimated to
be $84 million, including $9 million for nuclear fuel. 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.
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 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. 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 Company is a member of Nuclear Mutual Limited (NML), an
industry mutual insurer established to provide property damage
coverage for members' nuclear generating facilities. The Company
would be subject to a maximum retrospective premium assessment of
approximately $2 million based on its 25% share of the NML
premium for Quad-Cities coverage in the event covered losses of
NML members exceed the financial resources of the insurance
company. A reserve has been established for this contingency.
At December 31, 1994, NML had accumulated capital to a level that
would make it unlikely the Company would have an exposure to a
retrospective premium assessment in the event of a single
incident to a member's facility.
The Company is also a member of Nuclear Electric Insurance
Limited (NEIL), an industry mutual insurance company, and an
insured of American Nuclear Insurers/Mutual Atomic Energy
Liability Underwriters (ANI/MAELU). The related policy
provisions provide that expenses for decontamination and the
removal of debris shall be paid before any payment in respect of
claims for property damage. A separate NEIL insurance policy
covers the extra costs that would be incurred in obtaining
replacement power during a prolonged covered outage of a member's
nuclear plant. The Company is subject to retrospective premium
assessments of approximately $4.1 million and $843,000 for its
25% share of the premium under the NEIL portion of the property
damage coverage and the replacement power coverage, respectively.
At December 31, 1994, NEIL had accumulated capital to a level
that would make it unlikely the Company would have an exposure to
a retrospective premium assessment in the event of a single
incident to a member's facility.
A Master Worker Policy issued by ANI/MAELU provides coverage
for worker tort claims filed for bodily injury caused by the
nuclear energy hazard. The coverage applies to workers whose
"nuclear related employment" began after January 1, 1988. Under
this policy, the Company could be subject to a maximum
retrospective premium assessment of $1.5 million.
Under the Price-Anderson federal legislation adopted in
1988, nuclear public liability coverage is supported by a
mandatory industry-wide program under which owners of nuclear
generating facilities could be assessed in the event of nuclear
incidents. The Company would currently be subject to a maximum
assessment of $39.6 million in the event of an incident, to be
paid in increments of no more than $5 million per year per
incident.
_________________________________________________________________
(15) Merger
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 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 during 1995.
_________________________________________________________________
(16) Segment Information:
Information related to segments of the Company's business is
as follows:
Year Ended December 31,
1994 1993 1992
(In thousands)
Operating information
Electric-
Operating revenues.......... $ 355,955 $ 338,593 $ 312,667
Operating expenses
excluding income taxes.... 266,706 257,493 245,753
Pre-tax operating income.... 89,249 81,100 66,914
Income taxes................ 24,961 20,171 12,959
Operating income............ 64,288 60,929 53,955
Allowance for funds used
during construction
(AFUDC)................... 1,563 886 1,019
Operating income and AFUDC.. 65,851 61,815 54,974
Depreciation expense........ 53,237 50,379 46,236
Depreciation and equity
funds recovered under
Louisa Phase-In
Clause ................... - 2,370 4,515
Total depreciation expense.. 53,237 52,749 50,751
Capital expenditures........ 53,924 49,976 52,922
Gas-
Operating revenues.......... 199,129 206,821 184,867
Operating expenses
excluding income taxes.... 185,552 192,061 171,960
Pre-tax operating income.... 13,577 14,760 12,907
Income taxes................ 4,224 4,306 3,361
Operating income............ 9,353 10,454 9,546
AFUDC....................... 376 93 85
Operating income and AFUDC.. 9,729 10,547 9,631
Depreciation expense........ 8,592 8,268 7,705
Capital expenditures........ $ 26,350 $ 16,981 $ 20,776
<PAGE>
Year Ended December 31,
1994 1993 1992
(In thousands)
InterCoast Energy Company-
Income...................... $ 90,402 $ 84,084 $ 55,828
Expenses excluding
income taxes.............. 83,115 72,207 47,519
Pre-tax operating income.... 7,287 11,877 8,309
Depreciation, depletion
and amortization.......... 19,417 13,920 9,267
Capital expenditures........ $ 13,681 $ 68,147 $ 64,096
December 31,
1994 1993 1992
(In thousands)
Asset information
Identifiable assets-
Electric (a)................ $1,019,519 $ 988,264 $ 936,025
Gas (a)..................... 273,444 235,510 215,491
Used in overall utility
operations................ 33,721 32,580 30,799
InterCoast Energy Company... 523,215 526,716 466,135
Total assets.................. $1,849,899 $1,783,070 $1,648,450
(a) Utility plant less accumulated provision for depreciation,
accounts receivable, accrued unbilled revenues, inventories,
deferred gas expense, energy adjustment clause balance,
nuclear decommissioning trust fund and regulatory assets.
As of December 31, 1994, 1993 and 1992, respectively, the
major classes of utility plant are as follows:
December 31,
1994 1993 1992
(In thousands)
Electric-
Production.................... $ 745,242 $ 641,810 $ 617,761
Transmission.................. 158,590 147,080 138,887
Distribution.................. 307,969 285,699 262,450
Other......................... 69,226 195,514 206,358
Total Electric................ 1,281,027 1,270,103 1,225,456
Gas-
Distribution.................. 232,531 206,498 195,863
Other......................... 46,587 63,948 63,999
Total Gas..................... $ 279,118 $ 270,446 $ 259,862
_________________________________________________________________
<PAGE>
(17) Quarterly Results (Unaudited):
1994 Quarter Ended
December September June March
31 30 30 31
(In thousands, except per share amounts)
Operating revenues....... $131,867 $123,921 $114,432 $184,864
Operating income......... 12,336 24,909 17,592 18,804
Net income on common
shares................. 5,744 19,427 13,007 15,887
Net income per average
common share
outstanding............ $ .19 $ .66 $ .44 $ .54
1993 Quarter Ended
December September June March
31 30 30 31
(In thousands, except per share amounts)
Operating revenues....... $141,210 $127,720 $114,614 $161,870
Operating income......... 10,592 23,871 16,608 20,312
Net income on common
shares................. 7,215 17,921 12,099 16,998
Net income per average
common share
outstanding............ $ .25 $ .61 $ .41 $ .58
The quarterly data reflect seasonal variations common in the
utility industry.
<PAGE>
Report of Management
Management is responsible for the preparation of all
information contained in this Annual Report, including the
financial statements. The statements and related financial
information have been prepared in conformity with generally
accepted accounting principles. In the opinion of management,
the financial position, results of operation and cash flows of
the Company are reflected fairly in the statements. The
statements have been audited by the Company's independent public
accountants, Deloitte & Touche LLP, whose report appears below.
The Company maintains a system of internal controls which is
designed to provide reasonable assurance, on a cost effective
basis, that transactions are executed in accordance with
management's authorization, the financial statements are reliable
and the Company's assets are properly accounted for and
safeguarded. The Company's internal auditors continually
evaluate and test the system of internal controls and actions are
taken when opportunities for improvement are identified.
Management believes that the system of internal controls is
effective.
The financial statements have been reviewed by the Audit
Committee of the Board of Directors. The Audit Committee, the
members of which are directors who are not employees of the
Company, meets regularly with management, the internal auditors
and Deloitte & Touche LLP to discuss accounting, auditing,
internal control and financial reporting matters. The Company's
independent public accountants are appointed annually by the
Board of Directors on recommendation of the Audit Committee. The
internal auditors and Deloitte & Touche LLP each have full access
to the Audit Committee, without management representatives
present.
Stanley J. Bright
Chairman and Chief Executive Officer
Lance E. Cooper
Vice President-Finance and Chief Financial Officer
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors of Iowa-Illinois Gas
and Electric Company:
We have audited the accompanying consolidated balance sheets
and statements of capitalization of Iowa-Illinois Gas and
Electric Company and subsidiary as of December 31, 1994 and 1993,
and the related consolidated statements of income, retained
earnings, and cash flows for the years then ended. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits. The consolidated
financial statements of the companies for the year ended December
31, 1992 were audited by other auditors whose report, dated
January 28, 1993, expressed an unqualified opinion on those
statements.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements
present fairly, in all material respects, the financial position
of the companies as of December 31, 1994 and 1993, and the
results of their operations and their cash flows for the years
then ended in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Davenport, Iowa
January 25, 1995
EXHIBIT 21
Iowa-Illinois Gas and Electric Company has one wholly owned
subsidiary, InterCoast Energy Company, a Delaware corporation.
CONSENT OF INDEPENDENT AUDITORS
Iowa-Illinois Gas and Electric Company:
We consent to the incorportion by reference in Registration
Statement No. 33-23081 on Form S-8, Registration Statement No.
33-20329 on Form S-8 and Registration Statement No. 33-53249 on
Form S-3 of our reports dated January 25, 1995, appearing in and
incorporated by reference in this Annual Report on Form 10-K of
Iowa-Illinois Gas and Electric Company for the year ended
December 31, 1994.
DELOITTE & TOUCHE LLP
Davenport, Iowa
March 22, 1995
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference in Registration Statement No. 33-23081
on Form S-8 and Registration Statement No. 33-20329 on Form S-8
and Registration Statement No. 33-53249 on Form S-3 of our report
dated January 28, 1993, covering the consolidated balance sheet
and statement of capitalization of Iowa-Illinois Gas and Electric
Company and Subsidiary Company as of December 31, 1992, and the
related statements of income, retained earnings and cash flows
for the year then ended, included in the Company's Form 10-K for
the year ended December 31, 1994 (Commission file number 1-3573).
It should be noted that we have not audited any financial
statements of the Company subsequent to December 31, 1992, or
performed any audit procedures subsequent to the date of our
report.
ARTHUR ANDERSEN LLP
Chicago, Illinois
March 20, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated balance sheet of Iowa-Illinois Gas and Electric Company as of
December 31, 1994 and the related consolidated statements of income and cash
flows for the twelve months ended December 31, 1994 and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $1,004,071
<OTHER-PROPERTY-AND-INVEST> 553,600
<TOTAL-CURRENT-ASSETS> 145,936
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 146,292
<TOTAL-ASSETS> 1,849,899
<COMMON> 288,692
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 222,541
<TOTAL-COMMON-STOCKHOLDERS-EQ> 502,242
50,000
0
<LONG-TERM-DEBT-NET> 610,878
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 67,500
<LONG-TERM-DEBT-CURRENT-PORT> 64,145
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 546,143
<TOT-CAPITALIZATION-AND-LIAB> 1,849,899
<GROSS-OPERATING-REVENUE> 555,084
<INCOME-TAX-EXPENSE> 29,185
<OTHER-OPERATING-EXPENSES> 452,258
<TOTAL-OPERATING-EXPENSES> 481,443
<OPERATING-INCOME-LOSS> 73,641
<OTHER-INCOME-NET> 9,396
<INCOME-BEFORE-INTEREST-EXPEN> 83,037
<TOTAL-INTEREST-EXPENSE> 23,901
<NET-INCOME> 59,136
5,071
<EARNINGS-AVAILABLE-FOR-COMM> 54,065
<COMMON-STOCK-DIVIDENDS> 50,961
<TOTAL-INTEREST-ON-BONDS> 23,731
<CASH-FLOW-OPERATIONS> 144,949
<EPS-PRIMARY> $1.83
<EPS-DILUTED> $1.83
</TABLE>
