SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C 20549
FORM 10-K
For the fiscal year ended December 31, 1994 Commission file number 1-3632
(Mark One)
(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
INTERSTATE POWER COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 42-0329500
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1000 Main St., P.O. Box 769, Dubuque, IA 52004-0769
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code 319-582-5421
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Common Stock Par Value $3.50 Per Share ) New York Stock Exchange
) Chicago Stock Exchange
) Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: N O N E
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X . No .
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. [ ]
As of March 1, 1994 the aggregate market value of the voting stock held
by non-affiliates of the registrant was $233,129,495.
Indicate the number of shares outstanding of each of the issuer's
classes of common stock.
Shares Outstanding
March 1, 1995
Common Stock Par Value $3.50 Per Share 9,564,287
Documents incorporated by reference - portions of the Annual Report to
Stockholders for 1994 (Exhibit EX-13) are incorporated by reference in Parts
I, II and IV; portions of the Annual Proxy Statement for 1995 are
incorporated by reference in Part III.
INTERSTATE POWER COMPANY
1994 Form 10-K Annual Report
Table of Contents
Page
Part I
Item 1. Business 1
General 1
Construction Program 1
Electric Operations 1
Sources and Availability of Raw Materials 2
Duration and Effect of Electric Patents and Franchises 3
Electric Seasonal Business 3
Working Capital Items 3
Electric Governmental Regulations 3
Electric Competitive Conditions 4
Other Sources of Power 5
Other Electric Operations 7
Gas Operations 7
Gas Sources and Availability of Raw Materials 7
Duration and Effect of Gas Patents and Franchises 9
Gas Seasonal Business 9
Gas Governmental Regulations 9
Gas Competitive Conditions 9
Dependence of Segment Upon a Single Customer 10
Research and Development 10
Electric and Magnetic Fields 10
Environmental Regulations 10
Employees 13
Accounting Matters 13
Item 2. Properties 14
Electric Properties 14
Generating Stations 15
Gas Properties 16
General Properties 16
Titles 16
Item 3. Legal Proceedings 16
Item 4. Submission of Matters to a Vote of Security Holders 17
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 17
Item 6. Selected Financial Data 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 8. Financial Statements and Supplementary Data 17
Item 9. Disagreements on Accounting and Financial Disclosure 17
Part III
Item 10. Executive Officers of the Registrant 18
Item 11. Executive Compensation 18
Item 12. Security Ownership of Certain Beneficial Owners and
Management 18
Item 13. Certain Relationships and Related Transactions 19
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 19
PART I
ITEM 1. BUSINESS
(General)
Interstate Power Company, (the company), is an operating public
utility incorporated in 1925 under the laws of the State of Delaware.
The company is engaged in the generation, purchase, transmission,
distribution and sale of electricity. It owns property in portions
of twenty-five counties in the northern and northeastern parts of
Iowa, in portions of twenty-two counties in the southern part of
Minnesota, and in portions of four counties in northwestern Illinois.
The company also engages in the distribution and sale of natural gas
in Albert Lea, Minnesota; Clinton, Mason City and Clear Lake, Iowa;
Fulton and Savanna, Illinois and in a number of smaller Minnesota,
Iowa and Illinois communities, and in the transportation of natural
gas within Iowa, Minnesota and in interstate commerce.
For information pertaining to industry segments and lines of business
please refer to pages 26 and 27 of Exhibit EX-13 (the Annual Report
to Stockholders).
(Construction Program)
The table below shows actual construction expenditures for 1994 and
estimated expenditures for the period 1995 through 1999:
(Thousands of Dollars)
1994 Actual $ 40,600
1995 Est. $ 29,500
1996 Est. $ 40,400
1997 Est. $ 37,200
1998 Est. $ 46,700
1999 Est. $103,500
Refer to (Environmental Regulations) on page 10 for additional
information on construction expenditures related to compliance with
the regulations of the Clean Air Act of 1990.
(Electric Operations)
Of the 234 communities served with electricity, Dubuque, Iowa, is the
largest with a population of approximately 58,000. Other major cities
served are Albert Lea, Minnesota and Clinton and Mason City, Iowa.
The remainder of the communities served are under 15,000 population,
of which 193 or 84% are less than 1,000 population. The company
sells electricity at wholesale to 19 small communities which have
municipal distribution systems, 13 of which are total requirements
customers, and 6 of which are partial requirements customers.
The territory served with electricity at retail by the company is a
residential, agricultural and widely diversified industrial area with
an estimated population of 338,000.
There have been no significant changes since the beginning of the
fiscal year in the kind of products produced, services rendered,
markets or method of distribution.
The facilities owned or operated by the company include facilities
for the transmission of electric energy in interstate commerce or the
sale of electric energy at wholesale in interstate commerce.
(Sources and Availability of Raw Materials)
Electricity generated by the company in 1994 was 92.6% from coal as a
fuel, 0.3% from oil and 7.1% from natural gas. In 1995, the sources
of such generation are estimated to be: 97.3% from coal, 0.6% from
middle distillate oils, and 2.1% from natural gas. In 1994, 84.0% of
the company's coal requirements came from long-term contracts. In
1995, the company anticipates that 75.8% of its coal requirements
will be from long-term contracts. These contracts have expiration
dates ranging through August 31, 1999.
The company entered into a contract effective March 1, 1995 through
August 31, 1999, for a total of 450,000 tons per year of 0.5% sulfur
Colorado coal for its Kapp #2, a 217 MW unit at Clinton, Iowa because
of sulfur dioxide restrictions mandated by the Clean Air Act
Amendments of 1990.
The company will purchase coal on an annual basis for the Dubuque
Power Plant and for Lansing Units #1, #2 and #3.
The company has a contract for 500,000 tons per year for its 260 MW
Lansing #4 unit. Lansing Unit #4 requires low sulfur coal, which is
being purchased in the Powder River Basin of Wyoming. The company
has this coal shipped by rail and then transloaded to barge, using
facilities near Keokuk, Iowa. A contract with Orba-Johnson
Transshipment Company, Inc., covers rail to barge coal transloading.
Coal required for the company's generation by Neal #4 unit, located
near Sioux City, Iowa is contracted for by the operator, Midwest
Power Systems, under terms of the Unit Participation Agreement.
Similar arrangements prevail with respect to the company's
participation in Louisa #1 located near Muscatine, Iowa and operated
by Iowa-Illinois Gas and Electric Company.
The company owns 120 coal cars and has an undivided ownership
(21.528%) in 372 coal cars in connection with Neal #4. The company
has an undivided ownership (4%) in 136 cars in connection with Louisa
#1. Coal requirements in 1995 will require using leased cars for the
Louisa #1 coal supply.
The company burned 1,110,491 gallons of No. 2 and No. 6 oil in 1994
and has 6,477,000 gallons of oil storage capacity in which to store
adequate reserves during periods of high demand on refineries. The
company relies on spot purchases of oil.
The company presently has interruptible natural gas available for its
electric generation station at Clinton, Iowa through Natural Gas
Pipeline Company of America. At the Fox Lake and Dubuque plants,
interruptible gas is available through Peoples Natural Gas Company.
There is no assurance that interruptible gas will continue to be
available as fuel for electric generating plants.
(Duration and Effect of Electric Patents and Franchises)
The company owns no patents.
The company has, in the opinion of its legal counsel, all necessary
franchises or other rights from the incorporated communities and
other governmental subdivisions now served, required for the
operation of its properties. With 196 electric franchises in effect
in cities and villages, and with the majority of such franchises
being for a term of 25 years, the renewal of such franchises is a
continuing process. Thirty-two percent (62) of the franchises have
been secured since January 1, 1985.
(Electric Seasonal Business)
The effects of air conditioning in summer and heating in winter have
a seasonal impact on the business of the registrant. The air
conditioning sales in the summer months are primarily related to the
residential and commercial customer classes, however, the company
does not meter air conditioning sales separately. During the past
five years, the highest and lowest average residential consumption in
the peak summer month has been 891 Kwh (July 1991) and 565 Kwh (June
1990), respectively, compared to 811 Kwh (January 1991) and 635 Kwh
(February 1990) during the peak winter month. Refer to the section
(Electric Governmental Regulations) for discussion of Iowa seasonal
rates.
(Working Capital Items)
Three of the company's generating stations are located on the
Mississippi River at Clinton, Dubuque and Lansing, Iowa, with their
coal supply being delivered by barge during the barging season
(approximately April 1st to December 1st). Coal in the stockpile at
December 1st of each year has been sufficient to supply the normal
requirements of these generating stations until the reopening of the
Mississippi River for barge traffic. Coal shipments to the company's
Neal #4 and Louisa #1 generating stations are able to continue
year-round because river transportation is not involved.
(Electric Governmental Regulations)
In August 1993, the company implemented a revised electric tariff
structure. The new tariffs give greater weight to the demand
component of electric usage, and include a provision for a higher
rate during the summer cooling season (June-September), but did not
change the company's overall annual electric revenue.
The company filed an Iowa electric rate increase application in
August 1993. The application requested an annual increase of $11.5
million, including a return on common equity of 12.35%. Interim
rates at an annual amount of $11.0 million were placed in effect on
October 28, 1993, subject to refund. An IUB order issued in June
1994 allowed an annual increase of $7.4 million based on a return on
common equity of 11.0%. A second quarter 1994 entry to record the
refund liability included $0.9 million of revenue reduction
applicable to the first quarter of 1994 and $0.5 million applicable
to the fourth quarter of 1993. Refunds to customers, including $0.2
million of interest, were made in October 1994.
In July 1994, the company filed an application with the FERC for an
increase in annual firm electric wholesale rates of $1.4 million. In
August 1994, in accord with the settlement of a wholesale customer
complaint, the company withdrew the rate request. The settlement
also required the company to pay the wholesale customers a cash
settlement of $0.3 million, and prohibits another firm wholesale rate
case with an effective date prior to February 28, 1996. The
wholesale customer complaint, which was initially filed in 1992,
alleged that the company had been imprudent by entering into certain
long-term coal contracts, an associated transloading agreement, and a
rail transportation agreement.
The company's Minnesota rates recover jurisdictional energy
efficiency expenditures and lost revenues. Other operating expenses
for 1994, 1993, and 1992 include $0.5, $0.5, and $0.6 million,
respectively, for the amortization of Minnesota energy efficiency
costs. A May 1994 IUB Order allows recovery of $6.7 million of
deferred Iowa energy efficiency costs incurred through December 31,
1992, over a four year period; such recovery began October 1994.
Other operating expenses for 1994 include $0.3 million for the
amortization of Iowa energy efficiency costs. As of December 31,
1994, and 1993, the total energy efficiency costs deferred were $17.0
and $9.7 million, respectively. Of the $17.0 million total deferred,
approximately $11.8 million relates to Iowa energy efficiency costs
incurred in calendar 1993 and 1994. The company anticipates filing
in late 1995 for recovery of those costs. Management believes that
amounts deferred meet the criteria established by the respective
commissions for recovery as energy efficiency costs.
The company's electric rate tariffs provide for recovery of the cost
of fuel through energy adjustment clauses, which clauses are subject
to revision from time to time by the regulatory authority having
jurisdiction. These clauses are designed to pass on to the consumer
the increases or decreases in the cost of fuel without formal rate
proceedings. Purchased capacity costs are not recovered from
customers through energy adjustment clauses, but rather must be
addressed in base rates in a formal rate proceeding. In the
company's 1991 Iowa electric rate case, the IUB required that any
jurisdictional revenue from capacity sales to other utilities be
returned to Iowa customers through the fuel adjustment clause.
(Electric Competitive Conditions)
In 1993 the Illinois Commerce Commission entered an order determining
that Interstate, and not Jo-Carroll Electric Cooperative, had the
right to provide electric service to a large new freezer service
plant near East Dubuque, IL. The company is providing service to
that plant pursuant to Commission order. Jo-Carroll filed for
judicial review of the Commission action in the Illinois 15th
Judicial Circuit, which court remanded the proceeding to the
Commission for further hearings. Proceedings on remand are now
pending before the Commission.
The Energy Policy Act of 1992 (Act) allows FERC to order utilities to
grant access to transmission systems by third-party power producers.
The Act specifically prohibits federally-mandated wheeling of power
for retail customers. The company's industrial rates generally
compare favorably with those of neighboring utilities. For the
company's six largest industrial customers, the aggregate 1993 rate
was approximately 3.4 cents per KWH. This rate also compares
favorably with that of potential independent power producers and
electric wholesale generators. The company's favorable rates
mitigate the incentive that these customers might otherwise have to
relocate, self-generate or purchase electricity from other suppliers.
The company anticipates that its generating cost will decline
slightly over the next several years as long-term coal purchase and
transloading contracts expire and are renegotiated.
The company has no competition from the same type of public utility
service in the sale of electricity in any of the incorporated
communities served by it. Interstate may be subject to competition
in unincorporated areas. In the States of Iowa, Illinois and
Minnesota, territorial laws govern the question of possible service
to customers in such unincorporated areas, and such laws regulate
competition in such areas. Laws and statutory regulations in the
different states in which service is rendered provide, under varying
terms and conditions, for municipal ownership of electric generating
plants and distribution systems. Certain franchises under which
utility service is rendered give the municipality the right to
purchase the system of the company within said municipality upon
certain terms and conditions. However, no such purchase option and
no right of condemnation of the company's properties has been
exercised and no municipal generating plant or municipal distribution
system has been established in the territory now served by the
company during the past twenty-five years.
The Iowa Utilities Board, the Illinois Commerce Commission and the
Minnesota Public Utilities Commission have each approved tariffs that
allow the company to offer interruptible electric service for
qualifying customers. The availability of this service provides
price incentives to those customers having the ability to interrupt
their connected load. The primary objective of the incentives is to
reduce the system peak. The incentives also serve to retain existing
customers and attract new customers.
(Other Sources of Power)
The company has been a participant in the Mid-Continent Area Power
Pool (MAPP) Agreement since March 31, 1972. MAPP had a total
coincident 1994 summer peak of 23,863 MW at which time the net
capacity of the pool was 31,107 MW.
Membership in the pool permits sharing of reserve capacities of the
members which affects reductions in plant facilities investment for
MAPP members. The minimum reserve margin for participants in MAPP
has been established at 15%.
Parties to the MAPP Agreement include, as participants, 29 electric
power suppliers consisting of 10 investor-owned utilities, the United
States Department of Interior (Western Area Power Administration), a
Canadian system, public power districts and rural electric generating
and transmission cooperative associations, municipal electric supply
agencies and, as associate participants, 16 other electric power
suppliers operating in Canada and in the North Central region of the
United States. The pool coordinates planning and operation of power
suppliers in Minnesota, Wisconsin, Montana, Iowa, Nebraska, North
Dakota and South Dakota and provides reliability and economy for the
company's bulk power supply. The MAPP Agreement was filed with the
FERC and accepted as an initial rate filing effective December 1,
1972 and has been in operation since that time.
In addition to MAPP, the company has interchange connections with
certain Missouri and Illinois utilities through 345 KV transmission
systems. Future interconnections are planned to meet transmission
requirements for the next ten years.
In 1992, the company entered into three long-term power purchase
contracts with other utilities. The contracts provide for the
purchase of 230 to 255 MW of capacity over the period from May 1992
through April 2001. Energy is available at the company's option at
approximately 100% to 110% of monthly production costs for the
designated units. The three power purchase contracts required
capacity payments of $24.6, $24.1, and $16.3 million in 1994, 1993,
and 1992, respectively. Over the remaining life of the contracts,
total capacity payments will be approximately $155 million. The
purchased power contract payments are not for debt service
requirements of the selling utility, nor do they transfer risk or
rewards of ownership.
A portion of the purchased power capacity payments is not presently
being recovered through rates:
A 1992 rate order by the MPUC held that the company had 100 MW
of excess capacity. The Minnesota jurisdictional portion of the
100 MW of disallowed capacity is approximately $1.9 million
annually.
An additional 25 MW of purchased power contracts became
effective after 1992. Annual electric rates do not provide for
the recovery of $0.8 and $0.2 million, respectively, applicable
to the Iowa and Minnesota jurisdictions.
The company has not yet filed for rate recovery of the allocable
portions of the purchased power payments in the Illinois and
FERC jurisdictions. The annual Illinois and FERC jurisdictional
portions are approximately $1.7 and $0.9 million, respectively.
The amounts which are not being recovered through rates are expensed
as incurred. The impact of not recovering the purchased power
payments is mitigated to the extent that load growth has occurred
since the last rate case.
The company has contracts with several governmental power agencies
whereby the company provides transmission service to their
customer/members. During 1994, the company received $1,171,806 for
transmission service to customers of the Western Area Power
Administration (WAPA), and $1,267,322 from Cooperative Power
Association (CPA) for wheeling power to nine of its member
distribution cooperatives.
The company's contract with CPA also provides for payment by the
company for needed mutually utilized facilities constructed and owned
by CPA. During 1994, these payments amounted to $336,736.
The company and Southern Minnesota Municipal Power Agency (SMMPA)
have agreed by contract to compensate each other if
over/underinvestment in the shared transmission system occurs.
During 1994, SMMPA made payments to the company in the amount of
$524,700.
The company's contract with Central Iowa Power Cooperative (CIPCO)
provides for compensation to each other if over/underinvestment in
the shared transmission system occurs. During 1994, the company owed
CIPCO $59,195 for underinvestment in the Liberty Substation property,
of which $41,038 was paid in 1995.
(Other Electric Operations)
The 1994 peak of 932,081 KW occurred on June 17, 1994 between 2:00
and 3:00 in the afternoon. At the time of its 1994 peak the company
had a net effective electric capability of 1,308,600 KW. Of this net
effective capability at the time of peak, 901,300 KW was in steam
generation, 113,500 KW was in combustion turbine and the balance was
in internal combustion units and purchases. The previous historical
system net peak load for a sixty-minute period, of 927,366 KW, was
reached on August 26, 1993.
(Gas Operations)
The company supplies retail gas service in 39 communities and serves
approximately 48,500 gas customers.
There have been no significant changes since the beginning of the
fiscal year in the kind of products produced, markets or methods of
distribution.
(Gas Sources and Availability of Raw Materials)
The natural gas industry was recently restructured as a result of
Order 636, issued by the Federal Energy Regulatory Commission (FERC)
on April 8, 1992. This Order required the interstate pipelines to
provide transportation capacity unbundled (separated) from the sales
of gas supply, as well as to provide open access to their storage
facilities. The company no longer purchases a bundled gas supply
from Northern Natural Gas Company (NNG) and Natural Gas Pipeline
Company of American (NGPL). The company purchases pipeline capacity
(space) from these companies to deliver a gas supply purchased from
others. During 1994 the company purchased gas from eleven non-
traditional suppliers, i.e. producers, brokers and marketers, at
market responsive rates. The FERC continues to approve the tariffs
of NNG and NGPL, but only with regard to capacity and storage rates,
subject to change as rate cases are filed.
A section of the Order permits the interstate pipelines to pass on
industry transition costs to their customers. Transition costs are
comprised of gas supply realignment costs, unrecovered gas cost,
stranded costs and new facilities costs. As a customer of NGPL and
NNG, Interstate is subject to a share of those costs. The FERC has
approved the Order 636 Settlements between NNG, NGPL and their
customers.
Gas for the company's Mason City, Albert Lea and Savanna service
areas is transported by NNG under capacity contracts for 36,533 Mcf
daily, and for an additional 15,657 Mcf in the November to March time
frame. The majority, 27,194 Mcf, of the above capacities is from the
producing areas of New Mexico, Oklahoma and Texas, etc. These
contracts expire in October, 1997. Gas is supplied by producers,
marketers and brokers, as well as from storage services, to meet the
peak heating season requirements. The Company had 22,302 Mcf/day of
storage, with the necessary pipeline capacity, available for the
1994-1995 heating season.
Gas for its Clinton service area is transported by NGPL under
capacity contracts for 19,751 Mcf annually, with expiration dates of
December 1, 1995 (6,949), December 1, 1995 (2,832), February 28, 1996
(4,970), and November 30, 1996 (5,000). This gas is supplied by
producers, marketers and brokers. The company supplements this
capacity with storage gas, which has the pipeline capacity embedded
in its FERC approved rate. The company had 11,779 Mcf of storage
available for the 1994-1995 heating season.
During 1994, the company utilized approximately 39.2% of its
annualized daily contract gas available from its firm suppliers. The
Company's total throughput level of 33,653,839 Mcf represents a 1.0%
decrease for 1994, as compared to 1993. The total throughput was
composed of contract supply gas (26.3%), spot gas (0.9%) and customer
transportation gas (72.8%).
During 1994, eighteen of Interstate's customers transported a total
of 24,498,793 Mcf of their own gas over the company's pipeline and
distribution systems. In 1992, sixteen of Interstate's customers
transported a total of 23,547,107 Mcf, and in 1993, nineteen
customers transported a total of 23,994,891 Mcf. The customer owned
gas was delivered by interstate pipeline companies for those
customers' accounts to Interstate's town border stations, and is
subsequently delivered to the customers under tariffs approved by
respective state commissions. Company policy is to assist any
customer in exploring its options relative to purchasing gas directly
from the producing sector.
The Company owns propane-air gas plants in Albert Lea, Minnesota and
Clinton and Mason City, Iowa. The daily output capacities are:
5,500 Mcf, 4,000 Mcf and 9,600 Mcf of propane-air mix gas
respectively.
The requirement for gas on the peak winter day of the 1993-1994
season was 128,041 Mcf, including both firm and interruptible
customers. This peak consisted of 38.2% jurisdictional sales gas,
0.0% spot gas, 37.3% customer purchased gas, 23.7% storage gas and
0.8% propane-air from the company's peak-shaving plant. The maximum
daily firm gas sales during the 1993-1994 season were as follows:
Albert Lea 15,826 Mcf; Savanna 2,950 Mcf; Clinton 26,523 Mcf; Mason
City 33,073 Mcf, or 61.2% of the peak winter day throughput.
(Duration and Effect of Gas Patents and Franchises)
The company owns no patents.
The company has, in the opinion of its legal counsel, all necessary
franchises or other rights from the incorporated communities and
other governmental subdivisions now served, required for the
operation of its properties. With 34 gas franchises in effect in
cities and villages, and with the larger majority of such franchises
being for a term of 25 years, the renewal of such franchises is a
continuing process. Fifty percent (17) of the franchises have been
secured since January 1, 1985.
(Gas Seasonal Business)
The effects of heating sales to the residential and commercial
classes of customers have a significant seasonal impact on the
business of the registrant. The heating sales in the winter months
account for 98% of the total annual sales to these classes of
customers. The average consumption for a residential customer during
the peak winter months is 18.6 Mcf compared to the average of 2.6 Mcf
during the summer. The average consumption for a commercial customer
during the peak winter months is 90.6 Mcf compared to the average of
13.2 Mcf during the summer.
(Gas Governmental Regulations)
Order 636 provides a mechanism under which pipelines can recover
prudently incurred transition costs associated with the restructuring
process. The company's pipeline suppliers have filed with the FERC
to recover transition costs from the local distribution companies.
The company incurred $2.1 million of transition costs in 1994 and is
currently recovering these costs from customers through the purchased
gas adjustment clause. While the ultimate level of transition costs
could vary as Order 636 filings are revised and proceedings
completed, the company estimates that the remainder will aggregate
approximately $5.2 million payable in declining installments from
1995 to 2004. The company anticipates that under customary
ratemaking practices, future transition costs will be recovered from
customers, and has recorded on its balance sheet a liability and a
corresponding regulatory asset in the amount of $5.2 million.
(Gas Competitive Conditions)
The company has no competition from the same type of public utility
service in the sale of gas in any of the incorporated communities
serviced by it. Certain major industrial customers of the company
purchase their own gas supply from producers and have that gas
transported by the company as described in the "Gas Sources and
Availability of Raw Materials" section. Laws and statutory
regulations in the different states in which service is rendered
provide, under varying terms and conditions, for municipal ownership
of distribution systems. Certain franchises, under which utility
service is rendered, give the municipality the right to purchase the
system of the company within said municipality upon certain terms and
conditions. However, no such purchase option and no right of
condemnation of the company's properties has been exercised and no
municipal distribution system has been established in the territory
now serviced by the company during the past twenty-five years.
(Dependence of Segment Upon a Single Customer)
In 1994, 1993 and 1992, the company had no single customer or
industry for which electric and/or gas sales accounted for 10% or
more of the company's consolidated revenues. In 1994, the company's
three largest industrial customers accounted for 1,339,433,851 Kwh of
electric sales ($43,779,424) and 22,523,696 Mcf of gas sales and
transportation ($2,155,958). The company's largest gas customer,
which represents 30% of the company's total gas throughput, is
committed by contract for the next seven years.
(Research and Development)
The company has no full-time professional employees engaged in
research activities and had no company-sponsored research programs
during 1994, 1993 and 1992. In the public utility industry, research
is commonly and traditionally done by manufacturers of equipment,
trade organizations to which the company belongs, and university
research programs. In 1994 approximately $1,072,871 was paid for
research activities compared with $1,090,184 in 1993 and $1,013,003
in 1992.
(Electric and Magnetic Fields)
The possibility that exposure to electric and magnetic fields
emanating from power lines and other electric sources may result in
adverse health effects has been a subject of increased public,
governmental and media attention. A considerable amount of
scientific research has been conducted on this topic with no
definitive results. Research is continuing. It is not possible to
tell what, if any, impact these actions may have on the company's
financial condition.
(Environmental Regulations)
The company is subject to various federal and state government
environmental regulations. The company meets existing air and water
regulations. The Federal Clean Air Act Amendments of 1990 requires
reductions in certain emissions from power plants. The legislation
has two deadlines for compliance, Phase 1 (January 1, 1995) and Phase
2 (January 1, 2000). The company has switched to a low sulfur coal
and installed low nitrogen oxide burners at the 217 MW plant affected
by Phase 1. Additional capital expenditures of $11 million will be
required in 1995 and 1996 to comply with environmental standards
applicable to power plants. Management anticipates that additional
costs incurred will be recovered through customer rates.
The United States EPA, via the Clean Water Act, and the states have
promulgated discharge limits necessary to meet water quality
standards. A National Pollutant Discharge Elimination System (NPDES)
permit is required for all discharges. The company has current NPDES
permits for all discharges and meets or or falls within the required
discharge limits.
Early this century, various utilities including the company operated
plants which produced manufactured gas for cooking and lighting. The
company's facilities ceased operations approximately 40 years ago
when natural gas pipelines were extended into the upper Midwest. Some
of the former gasification sites contain coal tar waste products
which may present an environmental hazard.
In 1957, the company purchased facilities in Mason City, Iowa, from
Kansas City Power & Light Company (KCPL) which included land
previously used for a coal gasification plant. Coal tar waste was
discovered on the property in 1984. A Remedial Investigation and a
Feasibility Study have been approved by the U.S. EPA, and the company
anticipates that remediation will begin in 1995 following U.S. EPA
designation of the clean-up process. The Federal District Court ruled
in 1993 that KCPL is liable to the company regarding the response
costs at the Mason City site. (KCPL is an A rated company with total
assets in excess of $2 billion.) Additional court proceedings will be
held in 1995 to determine the extent of that liability. The company
anticipates that it may incur additional costs to clean-up the site,
but that such costs should be recoverable from KCPL or from gas
customers. In 1994, the company recorded an additional $2.3 million
liability for the estimated clean-up costs, and based on the current
regulatory treatment, an equal regulatory asset. The company did not
expense any investigation and remediation costs related to the Mason
City site in 1994 or 1993; it has expensed $2.5 million of
investigation and remediation costs applicable to the site since the
discovery of the coal tar waste.
The company formerly operated a manufactured gas plant in
Rochester,Minnesota. This facility was sold to another utility, which
later demolished the plant. The site is currently owned by a utility
and the City of Rochester. Agreements have been reached between the
Minnesota Pollution Control Agency and all three parties noted above
regarding the clean-up process. The remediation process began in 1994
and is expected to be completed in early 1995. Pursuant to the
settlements described above, with total cost not to exceed $9.662
million, the company has agreed to pay approximately two-thirds of
the cost of investigation and clean-up. The company accrued
(expensed) $0.8, $3.5, $1.2, and $0.2 million in 1994, 1993, 1992,
and 1991, respectively.
In addition, the company has identified, or has been identified, as
an owner or operator of seven other manufactured gas plant sites in
the Midwest: sites in Savanna and Galena, Illinois; a site in
Clinton, Iowa; and sites in Albert Lea, Austin, New Ulm and Owatonna,
Minnesota. The Savanna, Illinois, and Clinton, Iowa, sites are
currently owned by the company; the remaining sites are owned by
third parties. Potentially hazardous wastes allegedly associated with
former coal gasification operations have been identified at all
sites. Investigation of site conditions are in various stages at all
of the sites.
The company's accrued environmental liabilities of $3.5 million at
December 31, 1994, will cover known expenses for investigative and
remediation work. Additional liabilities, if any, cannot be
determined until further investigative work is performed.
In 1994, the company filed a lawsuit against certain of its insurers
to recover the costs of investigating and cleaning up, as necessary,
the former coal gasification plants. Neither the company nor its
legal counsel is able to predict the amount of any insurance
recovery, and accordingly, no potential recovery has been recorded.
Previous actions by Iowa, Illinois, and Minnesota regulators have
permitted utilities to recover prudently incurred investigation,
remediation and legal costs (response costs). The company anticipates
that costs applicable to the Iowa and Illinois jurisdictions will be
recovered from customers. Effective February 1993, a representative
level of investigation, remediation and legal costs of $0.7 million
per year applicable to the two Iowa sites is being recovered from
customers through gas rates. Investigation and remediation costs
through December 31, 1993, have been charged to expense. In
accordance with the established practice of the Iowa Utilities Board
(IUB), the 1994 accrual of $2.3 million for future remediation costs
has been offset by a regulatory asset. Such costs will be charged to
expense as they are incurred in the future. The company's Illinois
electric and gas tariffs provide for a rider to recover prudently
incurred investigation and remediation costs. In 1994, $0.3 million
of costs applicable to Illinois were charged to a regulatory asset
and will be amortized to expense as they are recovered from customers
beginning in 1995.
While the company is currently seeking an accounting order which
would allow the deferral of a portion or all of the remediation costs
applicable to its Minnesota jurisdiction, it may be difficult for the
company to recover all costs applicable to the Minnesota sites. The
MPUC has indicated that this type of cost should not be shared by
electric customers, and the company has relatively few Minnesota gas
customers. To-date, all estimated Minnesota jurisdictional costs have
been charged to expense.
Under the Federal Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA), a past waste generator can be designated
by the United States Environmental Protection Agency (U.S. EPA) as a
Potentially Responsible Party (PRP). Certain types of used
transformer oil (primarily those containing polychlorinated
biphenyls, or "PCBs") have been designated as hazardous substances by
the U.S. EPA. The company has been cited as a PRP by the U.S. EPA for
the clean-up of the facilities formerly operated by Martha C. Rose
Chemicals, Inc. in Holden, Missouri. Clean-up of the site began in
1994, with final completion scheduled for early 1995. The Martha Rose
Chemical Steering Committee has estimated that total clean-up cost
may be up to $22.8 million. The company's proportionate share of
clean-up costs has been $0.3 million to-date. The Steering Committee
has indicated that it has more than adequate funds to complete the
clean-up.
In 1988, the U.S. EPA designated the company a PRP for the clean-up
of former salvage facilities operated by the Missouri Electric Works,
Inc. (MEW) in Cape Girardeau, Missouri. A portion of the
PCB-contaminated equipment found at the site was formerly owned by
the company. The company has notified the U.S. EPA that it disclaims
responsibility for the site, as the equipment was in proper operating
condition when sold by the company to a third party, which
subsequently made arrangements to transport this equipment to MEW.
The U.S. EPA has not responded to the company's disclaimer. The
company has not recorded any liability for the MEW site, and
management believes that it will be able to successfully defend
itself against any claims applicable to the site.
(Employees)
The company has 978 regular employees consisting of 940 full-time and
38 part-time employees.
(Accounting Matters)
The company adopted SFAS No. 106, "Accounting for Postretirement
Benefits Other Than Pensions" in 1993. SFAS 106 requires that the
cost of providing such future postretirement benefits be accrued over
the employees' service periods. The postretirement benefit
obligation at January 1, 1993 (transition obligation) was $30.9
million and is being amortized over a 20 year period. The annual
SFAS 106 cost for 1994 and 1993 was $4.9 million with the pay-as-you-
go amount of $1.9 and $1.7 million, respectively. Recovery of SFAS
106 costs must be addressed in rate proceedings. The Iowa Utilities
Board (IUB) allowed recovery of $0.3 million per year of additional
SFAS 106 expense in gas rates effective May 1993, and the recovery of
$1.6 million in electric rates effective November 1993. The company
has deferred the difference between the SFAS 106 costs and the pay-
as-you-go amount applicable to the FERC electric and Minnesota
electric and gas jurisdictions until rate cases are filed to recover
the additional costs. Based on precedent established by the FERC and
Minnesota Public Utilities Commission (MPUC), the company believes
that amounts deferred as of December 31, 1994, meet the criteria
established by the Financial Accounting Standards Board. SFAS 106
costs in excess of the pay-as-you-go amount included on the balance
sheet as regulatory assets were $2.6 million at year-end 1994 and
1993. In Illinois, SFAS 106 costs are expensed currently since
deferral accounting is not allowed.
ITEM 2. PROPERTIES
The principal power plants and other materially important physical
properties of the Company are maintained in accordance with sound
operating practices. Their general character and location are
described below:
(Electric Properties)
The Company has been a participant in the Mid-Continent Area Power
Pool (MAPP) Agreement since March 31, 1972. As a part of this power
network the Company is the owner of a 55.0 mile section of the 345 KV
transmission line extending from St. Louis, Missouri to Minneapolis,
Minnesota; a 15.5 mile section of the 345 KV transmission line
between Minneapolis, Minnesota and Kansas City, Missouri; a 5.0 mile
345 KV transmission line from near Clinton, Iowa to near Cordova,
Illinois; a 49.8 mile 345 KV transmission line from near Clinton,
Iowa to a substation south of Dubuque, Iowa; and three associated
345/161 KV substations.
The Company's electric generating stations at year-end consist of six
steam plants, three combustion turbine stations, and five internal
combustion facilities. Pertinent information regarding each electric
generating station is shown on the following page:
INTERSTATE POWER COMPANY GENERATING STATIONS
Net
Generating Units December 31, 1994 Output
Nameplate Capability in KWH
Unit Capacity Year KW KW (000's)
Location Number KW Installed (Gross) (Net) 1994
STEAM:
Dubuque, IA 2 15,000 1929 82,500 78,000 151,312
3 25,000 1952
4 33,000 1959
Clinton, IA 1 15,000 1947 254,900 235,000 973,638
(M.L.Kapp Plt.) 2 212,284 1967
Lansing, IA 1 15,000 1948 337,800 320,000 837,454
2 11,500 1949
3 33,000 1957
4 252,649 1977
Sherburn, MN 1 11,500 1950 113,500 108,000 267,653
(Fox Lake Plt.) 2 11,500 1951
3 75,000 1962
Sioux City, IA 4* 125,924 1979 142,000 134,300 1,006,325
(Neal Unit #4)
Louisa County, IA 1** 27,400 1983 28,400 27,000 172,353
(Louisa Unit #1)
TOTAL STEAM 959,100 902,300 3,408,735
GAS TURBINE:
Montgomery, MN 1 26,535 1974 22,200 22,200 611
Sherburn, MN 4 26,535 1974 21,300 21,300 321
(Fox Lake Plt.)
Mason City, IA 1 37,520 1991 70,400 70,000 2,073
(Lime Creek Plt.) 2 37,520 1991
TOTAL GAS TURBINE 113,900 113,500 3,005
INTERNAL COMBUSTION:
Dubuque, IA 1 2,000 1966 4,600 4,600 (83)
2 2,000 1966
Hills, MN 2 2,000 1960 2,000 2,000 (63)
Lansing, IA 1 1,000 1970 2,000 2,000 5
2 1,000 1971
New Albin, IA 1 685 1970 700 700 (34)
Rushford, MN 1 2,000 1961 2,000 2,000 (88)
TOTAL INTERNAL COMBUSTION 11,300 11,300 (263)
TOTAL COMPANY 1,084,300 1,027,100 3,411,477
* Interstate owns 21.528% of a 584,931 KW unit operated by Midwest Re-
sources.
** Interstate owns 4.0% of a 685,000 KW unit operated by Iowa-Illinois
Gas and Electric Company.
(Gas Properties)
The company owns and operates natural gas distributing systems in
Albert Lea, Minnesota; Savanna, Illinois; Clinton, Mason City and
Clear Lake, Iowa and in a number of smaller Minnesota, Illinois and
Iowa communities. At Albert Lea, the company owns 14 tanks with a
liquid propane storage capacity of 357,000 gallons; at Clinton, there
are 12 tanks with 306,000 gallons capacity and at Mason City, 22
tanks with 561,000 gallons capacity.
The company also owns 100 gas regulating stations and approximately
966 miles of gas distribution mains.
(General Properties)
The company owns numerous miscellaneous properties in various parts
of its territory which are used for office, service and other
purposes. The most important of these are three General Office
buildings in Dubuque and the district office buildings at Clinton,
Decorah, Dubuque, Mason City and Oelwein, Iowa and Albert Lea, and
Winnebago, Minnesota and the distribution service buildings in each
of those locations. The company, as lessee, leases office space at
various locations. The company also leases a few small parcels of
land for storage of poles and miscellaneous temporary uses.
(Titles)
In the opinion of legal counsel for the company, the company has
satisfactory title to its properties for use in its utility
businesses subject only to permitted liens as defined in the Bond
Indenture and to minor defects and encumbrances customarily found in
cases of like size and character and which do not materially
interfere with the use of such properties.
Properties such as electric transmission and electric and gas
distribution lines are constructed principally on rights-of-way which
are maintained under franchise or held by easement only.
All properties of the company, other than "excepted property" as
defined in the Bond Indenture, are subject to the lien of the
company's Bond Indenture dated as of January 1, 1948, as
supplemented, securing the company's outstanding First Mortgage
Bonds.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to "Electric Governmental Regulations", "Electric
Competitive Conditions" and "Environmental Regulations" under "Item
1. Business" for certain pending legal proceedings and proceedings
known to be contemplated by governmental authorities. Reference is
also made to Note 9 to Financial Statements of the Annual Report to
Stockholders, included herein as EX-13. Other than these items,
there are no material pending legal proceedings, or proceedings known
to be contemplated by governmental authorities, other than ordinary
routine litigation incidental to the business, to which the company
is a party or of which any of the company's property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There was no submission of matters to a vote of security holders
during the fourth quarter of the 1994 year.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
For information pertaining to common stock market data required by
Item 201 of Regulation S-K please refer to page 32 of Exhibit EX-13
(the Annual Report to Stockholders).
ITEM 6. SELECTED FINANCIAL DATA
For information pertaining to selected financial data required by
Item 301 of Regulation S-K please refer to page 31 of Exhibit EX-13
(the Annual Report to Stockholders).
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
For information pertaining to management's discussion and analysis
required by Item 303 of Regulation S-K please refer to pages 1
through 11 of Exhibit EX-13 (the Annual Report to Stockholders).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial statements and supplementary data incorporated by reference
to Exhibit EX-13 (the Annual Report to Stockholders for 1994):
Statements of Income and Retained Earnings Page 12
Statements of Cash Flows Page 13
Balance Sheets Pages 14 & 15
Statements of Capitalization Page 16
Notes to Financial Statements Pages 17 - 28
Independent Auditors' Report Page 29
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Offices Held Past 5 Years
W. H. Stoppelmoor 61 1-1-87 - President & Chief Executive
Officer
5-1-90 - President, Chief Executive Officer
& Chairman of the Board
M. R. Chase 56 1-1-91 - Vice President-Production
5-7-91 - Vice President-Power Production
A. D. Cordes 63 1-1-86 - Vice President-District
Administration
5-1-90 - Vice President-District
Administration & Public Affairs
R. R. Ewers 50 5-1-90 - Vice President-Administrative
Services
D. E. Hamill 58 9-1-80 - Vice President-Budgets &
Regulatory Affairs
G. L. Kopischke 63 9-1-80 - Vice President-Electric Operations
J. C. McGowan 57 2-1-89 - Secretary & Treasurer
R. P. Richards 58 1-1-91 - Vice President-Gas Operations
W. C. Troy 56 5-1-86 - Controller
All officers are elected and serve as such until the next annual
meeting of directors. There are no arrangements or understandings
with respect to election of any person as an officer.
For information pertaining to directors, and other data required by
Items 401 and 405 of Regulation S-K, refer to pages 3 through 6 of
the company's Official Proxy Statement filed with the Securities and
Exchange Commission on March 21, 1995.
ITEM 11. EXECUTIVE COMPENSATION
Refer to information on pages 8, 9, 10, 11 and 12 of the company's
Official Proxy Statement filed with the Securities and Exchange
Commission on March 21, 1995 for data required by Item 402 of
Regulation S-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Refer to information on pages 6 and 7 of the company's Official Proxy
Statement filed with the Securities and Exchange Commission on
March 21, 1995 for data required by Item 403 of Regulation S-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with Management and Others:
In 1994 there were no transactions and there are presently proposed
no transactions with management, to which the company or its
subsidiary was or is to be a party, of the character as to which
answer is called for in response to Item 404(a) of Regulation S-K.
Indebtedness of Management:
No director or officer, or nominee for election as a director, or any
associate of any thereof, was indebted to the company or its
subsidiary during 1994, as to which answer is called for in response
to Item 404(b) of Regulation S-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) List of documents filed as part of this report:
1. The financial statements, including
supporting schedules, are listed in the Index
to Financial Statements, Schedules and
Exhibits filed as part of this Annual Report.
2. Exhibits which are filed herewith, including
those incorporated by reference are listed in
the Index to Financial Statements, Schedules
and Exhibits filed as part of this Annual
Report.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed with the
Securities and Exchange Commission during the last
quarter of 1994.
INDEX TO FINANCIAL STATEMENTS, SCHEDULES AND EXHIBITS
The 1994, 1993 and 1992 financial statements, together with the
Independent Auditors' Report thereon of Deloitte & Touche LLP, dated
February 2, 1995, appearing on pages 12 through 29 of Exhibit EX-13
(the 1994 Annual Report to Stockholders), are incorporated in this
Form 10-K Annual Report. The following additional data, as attached
on EX-23.a, EX-23.b, and S-1 should be read in conjunction with the
financial statements in such Exhibit EX-13.
Schedules and other historical financial information not included with
this additional financial data have been omitted because they are not
applicable or the required information is shown in the financial
statements or notes thereto.
Page or Exhibit Reference
Exhibit EX-13
Form (Annual Report to
10-K Stockholders)
Report of Independent Auditors EX-23.a
Consent of Independent Auditors EX-23.b
Financial Statements:
Statements of Income and Retained Earnings
for the years ended December 31, 1994,
1993 and 1992 12
Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992 13
Balance Sheets, December 31, 1994 and 1993 14 & 15
Statements of Capitalization, December 31,
1994 and 1993 16
Notes to Financial Statements 17 - 28
Selected Financial Data 31
Common Stock Market Data 32
Management's Discussion and Analysis 1 - 11
Schedule II: Valuation and Qualifying Accounts
and Provisions S-1
INDEX TO FINANCIAL STATEMENTS, SCHEDULES AND EXHIBITS (CONT'D.)
Exhibits filed as part of this report:
EX-4 Statement regarding availability upon request of Loan Agreement
and Pollution Control Indenture.
EX-10.a Coal Supply Agreement between Interstate Power Company and
Powderhorn Coal Company filed under Form SE as confidential and
non-public.
EX-13 The Company's 1994 Annual Report to Stockholders.
EX-23.a Report of Independent Auditors
EX-23.b Consent of Independent Auditors
EX-27 Financial Data Schedule
EX-99.a Listing of current material contracts, indentures and other
exhibits and identified as having been previously filed with the
Commission.
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.
INTERSTATE POWER COMPANY
Date March 16, 1995 By /s/ W. H. STOPPELMOOR
(W. H. Stoppelmoor,
President and Chief
Executive Officer)
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 date indicated.
Signature Title
/s/ W. H. STOPPELMOOR President and Chief Executive
(W. H. Stoppelmoor) Officer (Principal Executive
Officer and Principal
Financial Officer)
/s/ W. C. TROY Controller (Principal
(W. C. Troy) Accounting Officer)
/s/ A. B. ARENDS Director
(A. B. Arends)
Director
(J. E. Byrns)
/s/ A. D. CORDES Director
(A. D. Cordes)
/s/ J. L. HANES Director
(J. L. Hanes)
/s/ G. L. KOPISCHKE Director
(G. L. Kopischke)
/s/ N. J. SCHRUP Director
(N. J. Schrup)
Date March 16, 1995
SCHEDULE II
INTERSTATE POWER COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND PROVISIONS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
(Thousands of Dollars)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE AT CHARGED CHARGED DEDUCTION BALANCE
BEGINNING TO TO OTHER FROM AT END
DESCRIPTION OF YEAR INCOME ACCOUNTS RESERVES OF YEAR
YEAR ENDED DEC. 31, 1994
Valuation account
deducted from caption
of which it applies -
accumulated provision
for doubtful accounts $203 $243 $148 (a) $394 (b) $200
Provision for medical
benefits, injuries
and damages $4,105 $7,240 $2,757 $9,431 (c) $4,671
YEAR ENDED DEC. 31, 1993
Valuation account
deducted from caption
of which it applies -
accumulated provision
for doubtful accounts $206 $225 $134 (a) $362 (b) $203
Provision for medical
benefits, injuries
and damages $1,506 $4,302 $3,521 $5,224 (c) $4,105
YEAR ENDED DEC. 31, 1992
Valuation account
deducted from caption
of which it applies -
accumulated provision
for doubtful accounts $206 $152 $115 (a) $267 (b) $206
Provision for medical
benefits, injuries
and damages $1,655 $4,103 $838 $5,090 (c) $1,506
(a) Recoveries on accounts previously written off.
(b) Accounts written off.
(c) Claims and damages paid and expenses in connection therewith.
S-1
INDEX OF EXHIBITS
EX-4 Statement regarding availability upon request of Loan
Agreement and Pollution Control Indenture.
EX-10.a Coal Supply Agreement between Interstate Power Company and
Powderhorn Coal Company filed under Form SE as confidential
and non-public.
EX-13 The Company's 1994 Annual Report to Stockholders.
EX-23.a Report of Independent Auditors
EX-23.b Consent of Independent Auditors
EX-27 Financial Data Schedule
EX-99.a Listing of current material contracts, indentures and other
exhibits and identified as having been previously filed with
the Commission.
EX-4
Subject to the Commission's Rule 447 under the Securities Act of 1933 and
Rule 12b-32 under the Securities Exchange Act of 1934 exempting the filing
of instruments defining rights of the holders of long-term debt not being
registered in those cases where the total amount of securities authorized
thereunder does not exceed 10% of the total assets of the registrant and its
subsidiaries on a consolidated basis if there is filed an agreement to
furnish a copy of such agreement to the Commission upon request, the company
agrees to furnish upon request by the Commission a copy of the following:
Clinton Series A Bonds
Loan Agreement dated as of June 1, 1994 from Clinton to Interstate
Power Company (the "Company").
Indenture of Trust dated as of June 1, 1994 between Clinton and Norwest
Bank Iowa, N.A. as trustee (the "Trustee").
Clinton Series B Bonds
Loan Agreement dated as of June 1, 1994 between Clinton and the
Company.
Indenture of Trust dated as of June 1, 1994 between Clinton and the
Trustee.
Lansing Series A Bonds
Loan Agreement dated as of June 1, 1994 between Lansing and the
Company.
Indenture of Trust dated as of June 1, 1994 between Lansing and the
Trustee.
Lansing Series B Bonds
Loan Agreement dated as of June 1, 1994 between Lansing and the
Company.
Indenture of Trust dated as of June 1, 1994 between Lansing and the
Trustee.
INTERSTATE POWER COMPANY
/s/ J. C. McGowan
J. C. McGowan, Secretary-Treasurer
Dated: February 9, 1995
EX-10.a
COAL SUPPLY AGREEMENT
BETWEEN
INTERSTATE POWER COMPANY
AND
POWDERHORN COAL COMPANY
(A Confidential Agreement)
FORM SE
FILED ON MARCH 22, 1995
EX-13
INTERSTATE POWER COMPANY
Annual Report to Stockholders
1994
MANAGEMENT'S DISCUSSION AND ANALYSIS
The company's results of operations and financial condition are affected by
numerous factors, including weather, general economic conditions, and rate
changes. The following comments are designed to explain the financial
statements on pages 12-28 and the financial and statistical data on pages 31
and 32.
LIQUIDITY AND CAPITAL RESOURCES
The company's primary capital requirements include construction activities,
payment of dividends, and the funding of debt retirements. It is
management's opinion that the company has adequate access to capital markets
and will be able to satisfy anticipated capital requirements.
The dividend of $2.08 per common share annually and $0.52 per quarter has
been maintained, however, the Board of Directors will be monitoring future
dividend levels and a reduction cannot be ruled out.
Uncertainty as to the continuation of the current dividend level, rising
interest rates and greater perceived risk associated with increased
competition in the electric industry contributed to a decline in the
company's stock price from $30.125 at year-end 1993 to $23.75 at year-end
1994. To reduce the need for outside financing in 1995 and raise earnings to
an acceptable level, the company cut back its construction program, is
reviewing cost control procedures, and plans to file for rate increases in
the Iowa, Minnesota, and FERC jurisdictions.
Effective December 1994, the company elected to purchase shares of common
stock for the Dividend Reinvestment and Stock Purchase Plan on the open
market rather than issuing new stock. The company received $4.2 million for
174,446 shares of new common stock issued in the first eleven months of 1994
and $2.8 million for 92,093 shares issued in the third and fourth quarters
of 1993.
Construction expenditures were $41, $34, and $32 million in 1994, 1993, and
1992, respectively. A major construction project in 1994 included $4.5
million for low nitrogen oxide (NOX) burners (pollution control equipment
required to comply with Phase 1 of the Clean Air Act), at the company's Kapp
power plant. The 1995 and 1996 construction programs are estimated to be $30
and $41 million, respectively. There will be several pollution control
projects, including $3.6 million for additional low NOX burners, $3.5
million for fly ash disposal facility improvements, and $1.6 million for
sulfur trioxide conditioning. The company anticipates that approximately 75%
of the construction funds for years 1995 and 1996 will be generated
internally. For the five year period from 1995 through 1999, construction
expenditures are estimated to be $250 million.
In mid-1994, the company refinanced $13.25 million of Pollution Control
Revenue Bonds at interest rates ranging from 5.75% to 6.35%. The refinancing
will reduce annual cash outlays for interest by approximately $120,000. A
second quarter 1993 refinancing of first mortgage bonds and preferred stock
resulted in lower annual interest charges of approximately $285,000 and
reduced annual cash outlays for preferred and preference dividends by
approximately $520,000.
At December 31, 1994, based upon the most restrictive earnings test
contained in the company's Indenture pursuant to which first mortgage bonds
are issued, the company could issue in excess of $100 million of additional
first mortgage bonds. The company's ratio of earnings before income taxes to
interest charges (fixed charge coverage) was 2.7 times for 1994, 1993, and
1992. At December 31, 1994, the ratio of common equity to total
capitalization was 46.2%. The company's long-term goal is to increase common
equity to approximately 50% of total capitalization. The increase in common
equity is expected to be accomplished over time. A common stock public
offering of approximately $25 million, originally planned for 1995, has been
delayed to 1996. Also, the company intends to resume the issuance of new
stock in 1996 to satisfy Dividend Reinvestment and Stock Purchase Plan
requirements.
Ratings for the company's first mortgage bonds did not change in 1994. The
company's bonds are rated A+ by Standard and Poor's rating agency and A1 by
Moody's Investors Service. The rating agencies have indicated that future
ratings will be more stringent due to changes in the business environment,
slow growth in demand, growing cost pressures, and the regulatory climate in
which the company operates.
The company has authorization from the Federal Energy Regulatory Commission
(FERC) to issue up to $70 million in short-term debt. At year-end 1994, a
$43.3 million line of credit was available. Lines of credit are generally
used in support of commercial paper, which is the primary source of
short-term financing. At year-end 1994, the company had $35.6 million of
short-term commercial paper payable. The company anticipates that, due to
construction outlays and the retirement of $14 million of 4 5/8% First
Mortgage Bonds which mature on May 1, short-term debt will increase to
approximately $52 million by year-end 1995. The company projects that the
short-term debt will decline to $37 million at year-end 1996.
Electric and gas rates include a fuel adjustment clause and a purchased gas
adjustment clause whereby increases or decreases in fuel and purchased gas
costs are included in current revenue without having changes in base rates
approved in formal hearings. Under present regulations, electric capacity
costs are not recovered from customers through fuel adjustment clauses, but
rather must be addressed in base rates in a formal rate proceeding. However,
any Iowa jurisdictional revenue from electric capacity sales to other
utilities is returned to customers through the fuel adjustment clause.
The company is subject to regulation which recognizes only original cost
rate base. This may result in economic losses when the effects of inflation
are not recovered from customers on a timely basis.
ACCOUNTING STANDARD ON POSTRETIREMENT BENEFITS - SFAS No. 106
The company adopted SFAS No. 106, "Accounting for Postretirement Benefits
Other Than Pensions" in 1993. SFAS 106 requires that the cost of providing
such future postretirement benefits be accrued over the employees' service
periods. The postretirement benefit obligation at January 1, 1993
(transition obligation) was $30.9 million and is being amortized over a 20
year period. The annual SFAS 106 cost for 1994 and 1993 was $4.9 million,
compared with the pay-as-you-go amount of $1.9 and $1.7 million,
respectively. Recovery of SFAS 106 costs must be addressed in rate
proceedings. The Iowa Utilities Board (IUB) allowed recovery of $0.3 million
per year of additional SFAS 106 expense in gas rates effective May 1993, and
the recovery of $1.6 million in electric rates effective November 1993. The
company has deferred the difference between the SFAS 106 costs and the
pay-as-you-go amount applicable to the FERC electric and Minnesota electric
and gas jurisdictions until rate cases are filed to recover the additional
costs. Based on precedent established by the FERC and Minnesota Public
Utilities Commission (MPUC), the company believes that amounts deferred as
of December 31, 1994, meet the criteria established by the Financial
Accounting Standards Board. SFAS 106 costs in excess of the pay-as-you-go
amount included on the balance sheet as regulatory assets were $2.6 million
at year-end 1994 and 1993. In Illinois, SFAS 106 costs are expensed
currently since deferral accounting is not allowed.
POWER PURCHASE CONTRACTS
In 1992, the company entered into three long-term power purchase contracts
with other utilities. The contracts provide for the purchase of 230 to 255
MW of capacity over the period from May 1992 through April 2001. Energy is
available at the company's option at approximately 100% to 110% of monthly
production costs for the designated units. The three power purchase
contracts required capacity payments of $24.6, $24.1, and $16.3 million in
1994, 1993, and 1992, respectively. Over the remaining life of the
contracts, total capacity payments will be approximately $155 million. The
purchased power contract payments are not for debt service requirements of
the selling utility, nor do they transfer risk or rewards of ownership.
A portion of the purchased power capacity payments is not presently being
recovered through rates:
A 1992 rate order by the MPUC held that the company had 100 MW of excess
capacity. The Minnesota jurisdictional portion of the 100 MW of disallowed
capacity is approximately $1.9 million annually.
An additional 25 MW of purchased power contracts became effective after
1992. Annual electric rates do not provide for the recovery of $0.8 and $0.2
million, respectively, applicable to the Iowa and Minnesota jurisdictions.
The company has not yet filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and FERC jurisdictions. The
annual Illinois and FERC jurisdictional portions are approximately $1.7 and
$0.9 million, respectively.
The amounts which are not being recovered through rates are expensed as
incurred. The impact of not recovering the purchased power payments is
mitigated to the extent that load growth has occurred since the last rate
case.
GENERATING CAPABILITY & PROJECTED DEMAND
The maximum demand on the company's electric system was 932 MW, which
occurred in June 1994. This compares to the prior peak of 927 MW which
occurred in August 1993. The company's net effective capability at the time
of the 1994 system peak was 1,309 MW. Forecast peak demand for the year 2001
is 1,037 MW (not including a 15% reserve of 156 MW required by the
Mid-Continent Area Power Pool).
The combination of company-owned capacity and the power purchase contracts
will provide the company with adequate electric capacity through April 2001.
Planning is currently underway as to the best way to meet the capacity needs
thereafter. The capacity planning process will include consideration of
additional owned capacity, purchased power, load/demand side management, and
unit life extension. Although capacity planning is a continuously changing
process, the company does not expect substantial cash outlays for new
electric generation over the next four years.
CLEAN AIR ACT
The company meets the existing federal and state environmental regulations.
The Federal Clean Air Act requires reductions in sulfur dioxide and nitrogen
oxide emissions from power plants. The most restrictive provisions relate to
sulfur dioxide emissions. Phase 1 of the Clean Air Act became effective
January 1, 1995, while Phase 2 is effective January 1, 2000. During Phase I,
one company unit (with a net effective capacity of 217 MW) is affected. To
comply with Phase 1, the company has switched the affected unit to low
sulfur coal and installed low nitrogen oxide burners. Although the financial
impact of Phase 2 has not been fully determined, Phase 2 regulations will
affect approximately 87% of the company's current generating capacity and
will require capital, operating and maintenance costs beyond those required
for Phase 1. The company anticipates the costs of compliance with the Clean
Air Act will be recovered through the ratemaking process.
POTENTIALLY RESPONSIBLE PARTY DESIGNATION
Under the Federal Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), a past waste generator can be designated by the
United States Environmental Protection Agency (U.S. EPA) as a Potentially
Responsible Party (PRP). Certain types of used transformer oil (primarily
those containing polychlorinated biphenyls, or "PCBs") have been designated
as hazardous substances by the U.S. EPA. The company has been cited as a PRP
by the U.S. EPA for the clean-up of the facilities formerly operated by
Martha C. Rose Chemicals, Inc. in Holden, Missouri. Clean-up of the site
began in 1994, with final completion scheduled for early 1995. The Martha
Rose Chemical Steering Committee has estimated that total clean-up cost may
be up to $22.8 million. The company's proportionate share of clean-up costs
has been $0.3 million to-date. The Steering Committee has indicated that it
has more than adequate funds to complete the clean-up.
In 1988, the U.S. EPA designated the company a PRP for the clean-up of
former salvage facilities operated by the Missouri Electric Works, Inc.
(MEW) in Cape Girardeau, Missouri. A portion of the PCB-contaminated
equipment found at the site was formerly owned by the company. The company
has notified the U.S. EPA that it disclaims responsibility for the site, as
the equipment was in proper operating condition when sold by the company to
a third party, which subsequently made arrangements to transport this
equipment to MEW. The U.S. EPA has not responded to the company's
disclaimer. The company has not recorded any liability for the MEW site, and
management believes that it will be able to successfully defend itself
against any claims applicable to the site.
COAL TAR DEPOSITS
Early this century, various utilities including the company operated plants
which produced manufactured gas for cooking and lighting. The company's
facilities ceased operations approximately 40 years ago when natural gas
pipelines were extended into the upper Midwest. Some of the former
gasification sites contain coal tar waste products which may present an
environmental hazard.
In 1957, the company purchased facilities in Mason City, Iowa, from Kansas
City Power & Light Company (KCPL) which included land previously used for a
coal gasification plant. Coal tar waste was discovered on the property in
1984. A Remedial Investigation and a Feasibility Study have been approved by
the U.S. EPA, and the company anticipates that remediation will begin in
1995 following U.S. EPA designation of the clean-up process. The Federal
District Court ruled in 1993 that KCPL is liable to the company regarding
the response costs at the Mason City site. (KCPL is an A rated company with
total assets in excess of $2 billion.) Additional court proceedings will be
held in 1995 to determine the extent of that liability. The company
anticipates that it may incur additional costs to clean-up the site, but
that such costs should be recoverable from KCPL or from gas customers. In
1994, the company recorded an additional $2.3 million liability for the
estimated clean-up costs, and based on the current regulatory treatment, an
equal regulatory asset. The company did not expense any investigation and
remediation costs related to the Mason City site in 1994 or 1993; it has
expensed $2.5 million of investigation and remediation costs applicable to
the site since the discovery of the coal tar waste.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. This facility was sold to another utility, which later demolished
the plant. The site is currently owned by a utility and the City of
Rochester. Agreements have been reached between the Minnesota Pollution
Control Agency and all three parties noted above regarding the clean-up
process. The remediation process began in 1994 and is expected to be
completed in early 1995. Pursuant to the settlements described above, with
total cost not to exceed $9.662 million, the company has agreed to pay
approximately two-thirds of the cost of investigation and clean-up. The
company accrued (expensed) $0.8, $3.5, $1.2, and $0.2 million in 1994, 1993,
1992, and 1991, respectively.
In addition, the company has identified, or has been identified, as an owner
or operator of seven other manufactured gas plant sites in the Midwest:
sites in Savanna and Galena, Illinois; a site in Clinton, Iowa; and sites in
Albert Lea, Austin, New Ulm and Owatonna, Minnesota. The Savanna, Illinois,
and Clinton, Iowa, sites are currently owned by the company; the remaining
sites are owned by third parties. Potentially hazardous wastes allegedly
associated with former coal gasification operations have been identified at
all sites. Investigation of site conditions are in various stages at all of
the sites.
The company's accrued environmental liabilities of $3.5 million at December
31, 1994, will cover known expenses for investigative and remediation work.
Additional liabilities, if any, cannot be determined until further
investigative work is performed.
In 1994, the company filed a lawsuit against certain of its insurers to
recover the costs of investigating and cleaning up, as necessary, the former
coal gasification plants. Neither the company nor its legal counsel is able
to predict the amount of any insurance recovery, and accordingly, no
potential recovery has been recorded.
Previous actions by Iowa, Illinois, and Minnesota regulators have permitted
utilities to recover prudently incurred investigation, remediation and legal
costs (response costs). The company anticipates that costs applicable to the
Iowa and Illinois jurisdictions will be recovered from customers. The
company's Iowa gas rates currently include a provision for $0.7 million of
associated response costs per year. The company's Illinois electric and gas
tariffs provide for a rider to recover prudently incurred investigation and
remediation costs.
While the company is currently seeking an accounting order which would allow
the deferral of a portion or all of the remediation costs applicable to its
Minnesota jurisdiction, it may be difficult for the company to recover all
costs applicable to the Minnesota sites. The MPUC has indicated that this
type of cost should not be shared by electric customers, and the company has
relatively few Minnesota gas customers. To-date, all estimated Minnesota
jurisdictional costs have been charged to expense.
A summary of the income statement impact to-date of the coal tar sites is as
follows:
Total Rate
Year Expense Recovery
(Millions of Dollars)
1994 $ 1.8 $0.7
1993 3.8 0.6
1992 1.8 0.0
1984-1991 3.5 0.0
Total $10.9 $1.3
CHANGING STRUCTURE OF THE ELECTRIC INDUSTRY
Current initiatives at the federal and some state levels propose to increase
competition in the electric industry. Under this scenario, customers could
purchase energy from alternate power suppliers and then pay the local
utility a wheeling fee for delivering the energy.
Under certain conditions, the Energy Policy Act of 1992 allows the FERC to
grant third party power producers nondiscriminatory access to electric
utility transmission systems, and allows wholesale customers (primarily
municipal utilities) to purchase energy from alternate power producers.
Management believes that its electric wholesale and industrial retail rates
compare favorably with those of neighboring utilities and potential
independent power producers. The company's favorable rates mitigate the
incentive that these customers might otherwise have to relocate,
self-generate or purchase electricity from other suppliers. The company
anticipates that its generating cost will decline slightly over the next
several years as long-term coal purchase and transloading contracts expire
and are renegotiated.
The company's 24 firm municipal wholesale customers take service under one
year contracts. Firm electric sales to municipal utilities account for
approximately 3.7% of the company's electric sales and 2.8% of its electric
revenue. The company's industrial customers are served on a tariff rate, and
are not required to commit to a multiple year contract for service.
DEFERRED ENERGY EFFICIENCY COSTS
Regulations in Iowa and Minnesota require that utilities conduct energy
efficiency programs. The company's long-term forecast anticipates that these
programs may offset the need for approximately 115 MW of generating capacity
by the year 2000. Program costs and related carrying costs are deferred
pending a regulatory prudency review.
The company's Minnesota rates recover jurisdictional energy efficiency
expenditures and lost revenues. Other operating expenses for 1994, 1993, and
1992 include $0.5, $0.5, and $0.6 million, respectively, for the
amortization of Minnesota energy efficiency costs. A May 1994 IUB Order
allows recovery of $6.7 million of deferred Iowa energy efficiency costs
incurred through December 31, 1992, over a four year period; such recovery
began October 1994. Other operating expenses for 1994 include $0.3 million
for the amortization of Iowa energy efficiency costs. As of December 31,
1994, and 1993, the total energy efficiency costs deferred were $17.0 and
$9.7 million, respectively. Of the $17.0 million total deferred,
approximately $11.8 million relates to Iowa energy efficiency costs incurred
in calendar 1993 and 1994. The company anticipates filing in late 1995 for
recovery of those costs. Management believes that amounts deferred meet the
criteria established by the respective commissions for recovery as energy
efficiency costs.
LARGE ELECTRIC CUSTOMERS
The company's six largest electric customers consumed a total of 1,669,835
MWH of electricity in 1994, which accounts for over 31 percent of total MWH
sales. These customers are involved in the production of agricultural,
chemical, and cement products and their usage is generally not affected by
short-term weather variations. The company does not know of any plan by
these customers to significantly reduce consumption. Electric consumption by
these customers in 1994 was 3.0 percent over 1993, while 1993 consumption
was 6.5 percent over 1992. The aggregate 1994 rate for these customers was
approximately 3.4 cents per KWH.
ORDER 636
FERC Order 636, effective in late 1993, shifted primary responsibility for
gas supply acquisition from pipelines to local distribution companies such
as the company. The company believes it has taken steps to ensure the
acquisition of an adequate supply of natural gas and the associated
transportation capacity at reasonable prices.
Order 636 effectively eliminated the gas pipelines' bundled supply function,
which was historically regulated by the FERC. State regulators now require
the company to provide more detailed analyses to justify capacity and gas
supply arrangements.
Order 636 provides a mechanism under which pipelines can recover prudently
incurred transition costs associated with the restructuring process. The
company's pipeline suppliers have filed with the FERC to recover transition
costs from the local distribution companies. The company incurred $2.1
million of transition costs in 1994 and is currently recovering these costs
from customers through the purchased gas adjustment clause. While the
ultimate level of transition costs could vary as Order 636 filings are
revised and proceedings completed, the company estimates that the remainder
will aggregate approximately $5.2 million payable in declining installments
from 1995 to 2004. The company anticipates that under customary ratemaking
practices, future transition costs will be recovered from customers, and has
recorded on its balance sheet a liability and a corresponding regulatory
asset in the amount of $5.2 million.
INDUSTRIAL AND COMMERCIAL GAS CUSTOMERS
Current regulatory rules allow industrial and commercial customers to
purchase their gas supply directly from producers and use the company's
facilities to transport the gas. Transportation customers pay the company a
fee equivalent to the margin on a retail sale. Acting as a gas transporter,
rather than as a merchant, reduces the risk applicable to taking ownership
of the gas. Eighteen large customers currently purchase a majority of their
gas requirements from producers or gas marketers. Consumption for the three
largest gas customers was up 2.6% over 1993, and currently accounts for
approximately 67% of total system MCF throughput. Their usage is primarily
dependent on the overall strength of the economy and other market factors,
and is generally not affected by short-term weather variations. The company
does not know of any plan by these customers to reduce consumption. The
company's largest gas customer, which represents 30% of the company's total
gas throughput, is committed by contract for the next seven years.
GAS SYSTEM PROFITABILITY
Over the last 5 years, gas operating income before income taxes has averaged
1.5% of net gas utility plant. Mild weather, environmental remediation
costs, rate treatment which did not compensate the company for customers
switching to a more favorable tariff, and the offering of incentive or
flexible rates contributed to the low return.
The company is seeking recovery of environmental remediation costs from
other potentially liable parties as well as through rates and insurance. In
addition, more typical heating season weather should improve the gas system
profitability. The company's long-term forecast calls for a reduction in gas
construction outlays beginning in 1996.
RATE MATTERS
In August 1993, the company implemented a revised electric tariff structure.
The new tariffs give greater weight to the demand component of electric
usage, and include a provision for a higher rate during the summer cooling
season (June - September), but did not change the company's overall annual
electric revenue.
The company filed an Iowa electric rate increase application in August 1993.
The application requested an annual increase of $11.5 million, including a
return on common equity of 12.35%. Interim rates at an annual amount of
$11.0 million were placed in effect on October 28, 1993, subject to refund.
An IUB order issued in June 1994 allowed an annual increase of $7.4 million
based on a return on common equity of 11.0%. A second quarter 1994 entry to
record the refund liability included $0.9 million of revenue reduction
applicable to the first quarter of 1994 and $0.5 million applicable to the
fourth quarter of 1993. Refunds to customers, including $0.2 million of
interest, were made in October 1994.
In July 1994, the company filed an application with the FERC for an increase
in annual firm electric wholesale rates of $1.4 million. In August 1994, in
accord with the settlement of a wholesale customer complaint, the company
withdrew the rate request. The settlement also required the company to pay
the wholesale customers a cash settlement of $0.3 million, and prohibits
another firm wholesale rate case with an effective date prior to February
28, 1996. The wholesale customer complaint, which was initially filed in
1992, alleged that the company had been imprudent by entering into certain
long-term coal contracts, an associated transloading agreement, and a rail
transportation agreement.
Electric Sales KWH Sales
1994
Average 1994 1993
Revenue 1994 vs. 1993 vs. 1992
per KWH % of Total % Change % Change
Six Largest Industrial 3.4 cents 31.1% 3.0% 6.5%
All Other Industrial 4.3 cents 26.4 8.9 5.0
Residential (Non-Heat) 7.6 cents 16.1 2.1 8.1
General Service (Commercial) 6.2 cents 10.6 (5.8) 1.3
Sales for Resale 2.8 cents 8.9 53.6 15.5
Farm 7.5 cents 2.9 (0.9) (0.6)
Residential (Electric Heat) 6.2 cents 2.0 (4.3) 6.6
All Other Categories 7.5 cents 2.0 (11.1) (1.1)
Total Company 4.8 cents 100.0% 5.8% 5.8%
The company anticipates filing for rate increases in 1995 in the Iowa
electric, Minnesota electric, Minnesota gas, and the FERC wholesale
jurisdictions. Such applications will seek to recover the costs associated
with the purchased power contracts, manufactured gas plant clean-up costs,
jurisdictional SFAS 106 costs, an increased return on common equity, and
attrition due to inflation. In addition, as discussed under Deferred Energy
Efficiency Costs, the company anticipates filing in late 1995 for recovery
of Iowa energy efficiency costs incurred in 1994 and 1993.
RESULTS OF OPERATIONS
Earnings per share of common stock were $1.92 for 1994, compared with $1.73
for 1993, and $1.74 for 1992. The return on common equity for 1994 was 9.5%,
compared with 8.5% for 1993, and 8.4% in 1992.
Electric sales for the past two years have been below expectations due to
mild summer weather. KWH use per residential customer was 7,799; 7,816; and
7,341 for years 1994, 1993, and 1992, respectively.
Electric "margin" is defined as revenue from all sales, less the cost of
fuel and power purchased. Electric margins for years 1994, 1993, and 1992
were $142.0, $137.8, and $135.4 million, respectively. The improved electric
margins are primarily attributable to increased sales, the Iowa electric
rate increase, and energy efficiency cost recovery.
Gas "margin" is defined as the revenue from all sales, less purchased gas
cost. The gas margins for 1994, 1993, and 1992 were $15.0, $15.4, and $10.9
million, respectively. The primary reason for the reduced margin is the
lower residential and commercial sales due to mild weather.
Other operating expenses were $51.9, $48.6, and $42.4 million for 1994,
1993, and 1992, respectively.
As discussed under Coal Tar Deposits, other operating expenses for the years
1994, 1993, and 1992, respectively, include $0.8, $3.5, and $1.5 million,
for environmental investigation and remediation costs. Other operating
expenses for 1994 includes $1.0 million of legal fees relating to coal tar
clean-up litigation, compared with $0.3 million in 1993 and 1992.
Employee benefits (medical, pensions and other benefits) included in other
operating expenses were $9.7, $7.1, and $6.4 million for 1994, 1993, and
1992, respectively. The additional expense applicable to SFAS 106 accounted
for $2.1 million of the 1994 increase.
Workers compensation costs included in other operating expenses were $0.6,
$0.1, and $0.2 million for 1994, 1993, and 1992, respectively, while other
injuries and damages were $1.8, $1.3, and $1.4 million, respectively. These
costs can vary considerably from year to year, dependent upon actual claims
experienced.
The States of Iowa and Minnesota enacted legislation effective in 1994 which
requires that utilities with electric generating plants pay an emission fee.
Other operating expenses for 1994 include emission fees of approximately
$0.2 million. In addition, 1994 expense includes $0.2 million of water
treatment chemicals applicable to more stringent discharge standards.
Depreciation expense was $27.8, $26.3, and $25.2 million, for 1994, 1993,
and 1992, respectively. The increase is due to additional plant investment
and the implementation of new depreciation rates upon approval of a study
performed every five years in accordance with MPUC rules.
Property taxes were $13.7, $14.5, and $14.1 million, for 1994, 1993, and
1992, respectively. The majority of the decrease is applicable to a
reduction in assessed values in the State of Iowa.
Allowance for Funds Used During Construction (AFUDC) totalled $0.5 million
in 1994 compared with $0.2 million in 1993. The average 1994 construction
work in progress balance was higher, with construction expenditures of $41
million in 1994, compared with $34 million in 1993. In addition, the average
AFUDC rate increased from 6.0% in 1993 to 6.3% in 1994. Year-end
Construction Work In Progress (CWIP) balances for 1994, 1993, and 1992 were
$6.9, $3.2, and $3.5 million, respectively.
Miscellaneous income for 1994 includes approximately $1.8 million of energy
efficiency carrying costs and energy efficiency direct load control credits.
The comparable amounts for 1993 and 1992 were $1.0 and $0.4 million,
respectively.
As discussed under Rate Matters, other income and deductions for 1994
include $0.3 million of payments to settle a wholesale customer complaint
originally filed with the FERC in 1992.
The company and the Internal Revenue Service negotiated a settlement of
income tax audits in 1994, for tax years through 1991. To reflect the
settlement, the company recorded additional interest income and reduced
income tax expense. The additional interest income and reduced income tax
expense resulted in approximately $2.1 million of additional 1994 income.
Interest on long-term debt was $15.4, $16.2, and $16.3 million for 1994,
1993, and 1992, respectively. The 1994 refinancing of Pollution Control
Bonds and the 1993 refinancing of First Mortgage Bonds (discussed in the
Liquidity and Capital Resources section), coupled with the 1993 maturity of
$6 million of 4 3/8% First Mortgage Bonds caused the decrease. The
percentage of total capitalization attributable to long-term debt has
declined from 47.5% at year-end 1993 to 45.4% at year-end 1994.
Other interest charges for 1994 were $1.8 million, compared with $0.6
million for 1993 and 1992, respectively. Interest on commercial paper
payable was $0.7, $0.3, and $0.1 million for 1994, 1993, and 1992,
respectively. At year-end 1994, the company had $35.6 million of short-term
commercial paper payable, compared with $20.1 million at year-end 1993.
Other interest charges for 1994 also included interest on the Iowa electric
rate refund.
The company's investment in coal stockpiles was $19.4, $17.3, and $22.6
million at December 31, 1994, 1993, and 1992, respectively. The company's
practice is to build up coal stockpiles during the summer shipping season,
and to draw down the stockpiles during the winter. Year-end 1993 stockpiles
were unusually low due to flooding of the Mississippi river in mid-1993.
The natural gas industry purchases gas during off-peak periods and injects
it into underground storage. This gas is withdrawn during peak usage periods
when gas purchases are traditionally more costly and interstate pipeline
capacity may be constrained. As a result of FERC Order 636, the company now
holds title to a greater quantity of storage gas. The company's investment
in gas stored underground was $3.7, $4.6, and $2.7 million at December 31,
1994, 1993, and 1992, respectively.
Statements of Income and Retained Earnings
For the years ended December 31 1994 1993 1992
(Thousands of Dollars)
OPERATING REVENUES (Notes 1 and 9):
Electric $261,730 $255,759 $239,193
Gas 45,920 53,709 46,105
Total operating revenues 307,650 309,468 285,298
OPERATING EXPENSES:
Operation:
Fuel for electric generation 61,384 64,059 58,283
Power purchased 58,339 53,936 45,497
Cost of gas sold 30,905 38,309 35,221
Other operating expenses 51,917 48,567 42,390
Maintenance 17,160 16,771 16,966
Depreciation and amortization 28,212 26,955 25,887
Income taxes (Note 8):
Federal currently payable 1,395 4,694 6,174
State currently payable 454 1,445 1,923
Deferred taxes - net 7,092 3,856 2,268
Investment tax credit amortization (1,028) (1,028) (1,028)
Property and other taxes 16,298 17,080 16,533
Total operating expenses 272,128 274,644 250,114
OPERATING INCOME 35,522 34,824 35,184
OTHER INCOME AND DEDUCTIONS:
Equity funds used during construction (Note 1) 166 68 184
Interest income 1,812 718 527
Miscellaneous 1,288 491 374
Income taxes (Note 8) (1,276) (497) (361)
Total other income and deductions 1,990 780 724
INCOME BEFORE INTEREST CHARGES 37,512 35,604 35,908
INTEREST CHARGES:
Long-term debt (Note 1) 15,405 16,166 16,292
Other interest charges 1,772 596 586
Borrowed funds used during construction (332) (145) (187)
(Note 1)
Total interest charges 16,845 16,617 16,691
NET INCOME 20,667 18,987 19,217
PREFERRED AND PREFERENCE STOCK DIVIDENDS (2,454) (2,861) (2,975)
INCOME AVAILABLE FOR COMMON STOCK 18,213 16,126 16,242
RETAINED EARNINGS BEGINNING OF YEAR 57,397 60,648 63,745
DIVIDENDS ON COMMON STOCK (19,717) (19,377) (19,339)
RETAINED EARNINGS END OF YEAR $ 55,893 $ 57,397 $ 60,648
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
based on 9,478,741; 9,316,387
and 9,297,748 shares, respectively $ 1.92 $ 1.73 $ 1.74
DIVIDENDS PAID PER COMMON SHARE $ 2.08 $ 2.08 $ 2.08
The accompanying notes are an integral part of these financial statements.
Statements of Cash Flows
For the years ended December 31
1994 1993 1992
(Thousands of Dollars)
RECONCILIATION OF NET INCOME TO CASH FLOWS
FROM OPERATING ACTIVITIES:
Net Income $20,667 $18,987 $19,217
Adjustment for non-cash items:
Depreciation and amortization 28,212 26,955 25,887
Deferred income taxes 5,488 5,259 5,170
Investment tax credit amortization (1,028) (1,028) (1,028)
Equity funds used during construction (AFUDC) (166) (68) (184)
Prepaid pension cost 9 812 322
Changes in assets and liabilities:
Accounts receivable - net 3,710 (1,998) 806
Inventories (1,536) 3,751 884
Accounts payable and other current liabilities 4,324 3,686 2,985
Accrued and prepaid taxes (1,011) (2,602) 381
Interest accrued (160) (1,061) 230
Other prepayments and current assets (656) (249) 2,788
Rate refund payable - (4,064) 4,071
Regulatory assets - deferred energy
efficiency costs (7,295) (5,005) (3,313)
Regulatory assets - other (8,267) - -
Other operating activities 721 1,930 1,884
Cash flows from operating activities 43,012 45,305 60,100
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (40,600) (33,904) (32,104)
Borrowed funds used during construction (AFUDC) (332) (145) (187)
Other (658) (231) 925
Cash flows from investing activities (41,590) (34,280) (31,366)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock 4,237 2,786 -
Issuance of preferred stock - 27,250 -
Issuance of long-term debt 13,250 94,000 25,000
Retirement of long-term debt (13,487) (88,784) (30,261)
Redemption of preferred and preference stock - (25,474) (1,356)
Debt and stock discount and financing expenses (357) (8,795) (1,965)
Dividends on common, preferred and preference
stock (22,111) (22,331) (22,343)
Sale of commercial paper - net 15,500 11,100 1,800
Cash flows from financing activities (2,968) (10,248) (29,125)
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS $(1,546) $ 777 $ (391)
CASH AND CASH EQUIVALENTS:
Beginning of year $ 3,083 $ 2,306 $ 2,697
End of year $ 1,537 $ 3,083 $ 2,306
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of interest capitalized) $16,773 $17,588 $15,941
Income taxes $ 8,066 $ 8,863 $ 6,438
The accompanying notes are an integral part of these financial statements.
Balance Sheets
ASSETS
As of December 31
1994 1993
(Thousands of Dollars)
UTILITY PLANT (Note 1):
In Service:
Electric:
Production $369,828 $362,074
Transmission 178,891 173,373
Other 262,191 245,577
Total Electric 810,910 783,024
Gas 61,447 59,520
872,357 842,544
Less - accumulated depreciation 379,216 358,330
493,141 484,214
Held for future use 592 587
Construction work in progress 6,948 3,163
Net utility plant 500,681 487,964
OTHER PROPERTY AND INVESTMENTS 522 825
CURRENT ASSETS:
Cash and cash equivalents 1,537 3,083
Accounts receivable, less reserves of $200 22,350 26,060
Inventories - at average cost:
Fuel 24,220 22,985
Materials and supplies 5,208 4,720
Prepaid pension cost (Note 7) 3,702 4,818
Prepaid income tax (Note 8) 6,197 7,994
Other prepayments and current assets 2,252 480
Total current assets 65,466 70,140
DEFERRED DEBITS:
Regulatory assets (Notes 1, 2, 7, 8 and 9) 37,997 29,731
Unamortized debt expense (Note 1) 6,116 5,941
Deferred energy efficiency (Note 12) 16,961 9,665
Other 1,102 95
Total deferred debits 62,176 45,432
TOTAL $628,845 $604,361
The accompanying notes are an integral part of these financial statements.
Balance Sheets
CAPITALIZATION AND LIABILITIES
As of December 31
1994 1993
(Thousands of Dollars)
CAPITALIZATION, per accompanying statements:
Common stock, par value $3.50 per share;
authorized - 30,000,000 shares; issued
and outstanding - 9,564,287 in 1994 and
9,389,841 in 1993 (Note 4) $ 33,475 $ 32,865
Additional paid-in capital 103,137 99,547
Retained earnings 55,893 57,397
Total common equity 192,505 189,809
Preferred stock (optional sinking fund) 10,819 10,819
Preferred stock (mandatory sinking fund)
(Note 4) 23,933 23,837
Long-term debt (Note 5) 189,032 203,170
Total capitalization 416,289 427,635
CURRENT LIABILITIES:
Commercial paper (Note 6) 35,600 20,100
Long-term debt maturing within one year (Note 5) 14,000 -
Accounts payable 14,133 11,733
Dividends payable - preferred stock 599 599
Payrolls accrued 2,634 2,181
Taxes accrued 13,778 16,586
Interest accrued 2,930 3,090
FERC Order No. 636 transition costs (Note 9) 5,200 -
Environmental clean-up cost accrued (Note 2) 3,470 5,754
Other 2,878 4,580
Total current liabilities 95,222 64,623
DEFERRED CREDITS AND OTHER NON-CURRENT
LIABILITIES:
Accumulated deferred income taxes (Note 8) 88,176 82,438
Accumulated deferred investment tax credits
(Note 8) 19,069 20,097
Deferred pension cost (Note 7) 4,827 4,818
Accrued postretirement benefit cost (Note 7) 2,869 2,516
Other 2,393 2,234
Total deferred credits and other non-current
liabilities 117,334 112,103
COMMITMENTS AND CONTINGENCIES (Notes 2, 9, 10,
11 and 15)
TOTAL $628,845 $604,361
Statements of Capitalization
As of December 31 1994 1993
(Thousands of Dollars)
COMMON EQUITY (Note 4): $192,505 46.2% $189,809 44.4%
CUMULATIVE PREFERRED STOCKS (Note 4):
Authorized:
Preferred - 2,000,000 shares at $50.00 par value
Preference - 2,000,000 shares at $1.00 par value (A)
Issued and outstanding (B):
Redemption
Series Shares Price
Preferred with optional sinking fund provisions:
4.36% 60,455 $52.30 $ 3,023 $ 3,023
4.68% 55,926 $51.62 2,796 2,796
7.76% 100,000 $52.03 5,000 5,000
$ 10,819 2.6% $ 10,819 2.5%
Preferred with Mandatory sinking fund provisions:
6.40% 545,000 $53.20 27,250 27,250
Unamortized Discount on 6.40% Preferred Stock (2,053) (2,113)
Unamortized Issuance Expense on 6.40%
Preferred Stock (108) (111)
Unamortized Call Premiums on Preferred Stock (1,156) (1,189)
$ 23,933 5.8% $ 23,837 5.6%
LONG-TERM DEBT (Note 5):
First Mortgage Bonds:
4 5/8% Series due 1995 $ - $ 14,000
6 1/8% Series due 1997 17,000 17,000
8 % Series due 2007 25,000 25,000
8 5/8% Series due 2021 25,000 25,000
7 5/8% Series due 2023 94,000 94,000
$161,000 $175,000
Pollution Control Revenue Bonds:
5.95% due 1995 to 1998 $ 6,525 $ 6,750
7 1/4% due 1997 to 2006 - 6,600
6 3/8% due 1998 to 2007 11,400 11,400
7 1/8% due 2001 to 2009 - 6,650
5.75% due 2003 1,000 -
6.25% due 2009 1,000 -
6.30% due 2010 5,600 -
6.35% due 2012 5,650 -
$ 31,175 $ 31,400
Other Long-Term Debt $ 115 $ 127
Unamortized Discount on Long-Term Debt $ (3,258) $ (3,357)
Total Long-Term Debt - net $189,032 45.4% $203,170 47.5%
TOTAL CAPITALIZATION $416,289 100.0% $427,635 100.0%
(A) None outstanding.
(B) Redeemable at the option of the company upon 30 days notice at the
current prices shown.
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
1. Summary of Accounting Policies
GENERAL
The financial statements are based on generally accepted accounting
principles, which give recognition to the ratemaking and accounting
practices of the Federal Energy Regulatory Commission (FERC) and state
commissions having regulatory jurisdiction over the company.
UTILITY PLANT
Utility plant is recorded at original cost. The cost of additions to utility
plant and replacement of units of property includes contracted labor,
company labor, materials, allowance for funds used during construction and
overheads. Repairs of property and replacement of items less than units of
property are charged to maintenance expense. The original cost of units
retired, plus removal costs, less salvage is charged to accumulated
depreciation. Substantially all property is subject to the lien of the First
Mortgage Bond Indenture.
DEPRECIATION
Depreciation is computed on the straight-line method based on net salvage
values and the estimated remaining service lives of depreciable property.
The provision for book depreciation as a percentage of the average balance
of depreciable property in service was 3.5% in 1994 and 3.4% in 1993 and
1992.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC includes the net cost of borrowed funds and a reasonable rate on
equity funds used for construction or deferred energy efficiency purposes.
It was capitalized at gross rates of 6.3% for 1994, 6.0% for 1993, and 7.4%
for 1992. Gross AFUDC rates are computed in accordance with the FERC
regulations, including approval to incorporate deferred energy efficiency
costs in the calculation of the formula. AFUDC does not contribute to the
current cash flow of the company. Under normal regulatory practices, the
company anticipates earning a fair rate of return on such capitalized costs
and recovery of those costs in customer rates after completion of the
related construction.
STATEMENTS OF CASH FLOWS
For purposes of the statements of cash flows, the company considers all
liquid investments with a maturity of three months or less to be cash
equivalents.
REVENUES AND FUEL COSTS
Annual revenues do not include unbilled revenues for service rendered from
the date of the last meter reading to year-end. The company's electric and
gas tariffs contain fuel adjustment clauses and a purchased gas adjustment
clause whereby increases or decreases in fuel costs are included in current
revenue without having changes in base rates approved in formal hearings.
Purchased capacity costs are not recovered from electric customers through
fuel adjustment clauses, but rather must be addressed in base rates in a
formal rate proceeding.
DEBT REACQUISITION PREMIUM
In accordance with normal regulatory practices, the company defers debt
redemption premiums and amortizes such costs over the life of the
replacement bonds.
RECLASSIFICATIONS
Certain reclassifications have been made to the prior years financial
statements to conform with the presentation for 1994. Such reclassifications
had no impact on net income or stockholders' equity.
REGULATORY ASSETS
The company is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain
Types of Regulation". The regulatory assets represent probable future
revenue associated with certain incurred costs.
At December 31, 1994, regulatory assets were comprised of the following
items:
Regulatory Assets
(Millions of Dollars)
Deferred income taxes (Note 8) $27.5
FERC Order No. 636 transition costs (Note 9) 5.2
Employee/retiree benefits (Note 7) 2.6
Environmental liabilities (Note 2) 2.6
Other 0.1
Subtotal 38.0
Deferred energy efficiency costs (Note 12) 17.0
Total $55.0
2. Environmental Regulations
The company is subject to various federal and state government environmental
regulations. The company meets existing air and water regulations. The
Federal Clean Air Act Amendments of 1990 requires reductions in certain
emissions from power plants. The legislation has two deadlines for
compliance, Phase 1 (January 1, 1995) and Phase 2 (January 1, 2000). The
company has switched to a low sulfur coal and installed low nitrogen oxide
burners at the 217 MW plant affected by Phase 1. Additional capital
expenditures of $11 million will be required in 1995 and 1996 to comply with
environmental standards applicable to power plants. Management anticipates
that additional costs incurred will be recovered through customer rates.
The company has identified nine sites which may contain hazardous waste from
former coal gasification plants. Remediation of one site is currently
underway, while the other sites are in the investigative stage. The company
has recorded a liability for its pro rata share of all known expenses
applicable to the former coal gasification plants.
Investigation and future remediation costs applicable to the two Illinois
sites are being recovered from electric and gas customers through an
environmental rate clause. In 1994, $0.3 million of costs applicable to
Illinois were charged to a regulatory asset and will be amortized to expense
as they are recovered from customers beginning in 1995.
Effective February 1993, a representative level of investigation,
remediation and legal costs of $0.7 million per year applicable to the two
Iowa sites is being recovered from customers through gas rates.
Investigation and remediation costs through December 31, 1993, have been
charged to expense. In accordance with the established practice of the Iowa
Utilities Board (IUB), the 1994 accrual of $2.3 million for future
remediation costs has been offset by a regulatory asset. Such costs will be
charged to expense as they are incurred in the future.
At present, the company is not recovering coal tar costs applicable to
Minnesota. The company is currently seeking an accounting order which would
allow the deferral of the investigation and remediation costs applicable to
its Minnesota jurisdiction. Pending action by the Minnesota Public Utilities
Commission (MPUC), all costs applicable to the Minnesota sites have been
charged to expense.
The company is taking steps to recover portions of the investigation,
remediation, and legal costs from insurance carriers and other responsible
parties. The Federal District Court ruled in 1993 that Kansas City Power and
Light Company (KCPL) is liable to the company regarding the response costs
at the Mason City site. Additional court proceedings will be held in 1995 to
determine the extent of that liability. In 1994, the company filed a lawsuit
against certain of its insurers to recover the costs of investigating and
cleaning up, as necessary, the former coal gasification plants. Neither the
company nor its legal counsel is able to predict the amount of any insurance
recovery, and accordingly, no potential recovery has been recorded.
3. Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments as of
December 31, 1994, and 1993, are shown in the table below. The estimated
fair values were based on quoted market prices for the same or similar
issues or on the current rates for debt of the same remaining maturities.
The preferred stock carrying amounts for 1994 and 1993 excludes $1.3 million
of unamortized call premium and issuance expense.
Fair Value of Financial Instruments
(Millions of Dollars)
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
Long-term debt $189.0 $178.4 $203.2 $215.4
Preferred stock
(mandatory sinking fund) $ 25.2 $ 23.0 $ 25.1 $ 25.3
4. Preferred, Preference and Common Stock
In May 1993, the company issued 545,000 shares of 6.40% $50 par value
preferred stock with a final redemption date of May 1, 2022. Under the
provisions of the mandatory sinking fund, beginning in 2003 the company is
required to redeem annually $1.4 million of 6.40% preferred stock (27,250
shares). The discount and other issuance expenses in an aggregate amount of
$2.2 million as of December 31, 1994, are reflected as an offset to
preferred stock and are being amortized to common equity. Such amortization
transfers the discount and other issuance expenses from preferred stock to
common stock over the life of the issue, but does not affect net income.
Call premiums related to the 1993 retirement of the preferred and preference
stock in the amount of $1.2 million as of December 31, 1994, are reflected
as an offset to preferred stock and are being amortized to common equity.
The amortization transfers the amount of the call premiums from preferred
stock to common stock over the life of the refunding 6.40% issue, but has no
effect on net income.
In June 1993, the company retired certain preferred and preference stock as
detailed below:
Number of
Shares Total Redemption
Issue Retired Price (Thousands)
8% Preferred, $50 par 63,000 $ 3,206
9% Preferred, $50 par 116,643 $ 6,113
9%-A Preferred, $50 par 128,000 $ 6,652
$2.28 Preference, $1 par 400,000 $10,712
In 1992, the company retired the following preferred stock through the
provisions of the sinking fund:
Number of
Shares Total Redemption
Issue Retired Price (Thousands)
8.00% 7,000 $ 350
9.00% 4,117 $ 206
9.00%-A 16,000 $ 800
The company's Common Stock Dividend Reinvestment and Stock Purchase Plan
gives the company the option of issuing new stock or purchasing shares on
the open market. The Dividend Reinvestment Plan acquired 44,868; 60,299 and
113,735 shares of common stock on the open market during 1994, 1993, and
1992, respectively. The company received $4.2 million for 174,446 shares of
new common stock issued in the first eleven months of 1994 and $2.8 million
for 92,093 shares of new common stock issued in the third and fourth
quarters of 1993.
None of the authorized shares of preferred, preference or common stock are
reserved for officers and employees, or for options, warrants, conversions,
and other rights.
5. Long-Term Debt
$14 million of 4 5/8% First Mortgage Bonds mature on May 1, 1995, and are
classified as a current liability on the December 31, 1994, balance sheet.
Annual sinking fund requirements are $0.8, $2.0, $1.8, $1.8, and $1.8
million for the years 1995 through 1999, respectively. Such sinking fund
requirements for first mortgage bonds may be satisfied with property
additions at the rate of 167% of such requirements. Total debt maturities
for the years 1995 through 1999 are $14.2, $0.2, $17.2, $6.3, and $0.4
million, respectively.
6. Short-Term Borrowings
The company had available bank lines of credit aggregating $43.3 million at
December 31, 1994. There are no compensating balances required, but some of
the banks require commitment fees; such fees were not significant. The
maximum amount of short-term borrowing at any month end in 1994, 1993, and
1992 was $35.6, $20.1, and $12.2 million, respectively, all in commercial
paper, with the average outstanding borrowing during the year of $15.6,
$9.4, and $4.2 million, respectively. The average interest rate on
borrowings was 4.73%, 3.29%, and 3.56% for the years 1994, 1993, and 1992,
respectively. At December 31, 1994, 1993, and 1992, the interest rate was
6.07%, 3.36%, and 3.79%, respectively.
7. Employee/Retiree Benefits
The company has a non-contributory defined benefit pension plan for all
full-time employees. Plan benefits are based primarily on years of service
and employee compensation. The company uses the "projected unit credit"
actuarial method in computing pension costs for accounting purposes. Plan
assets consist of high-grade bonds, commercial mortgages and other fixed
income investments. Company policy is to fund the plan under the "aggregate"
actuarial cost method to the extent deductible under tax regulations.
Contributions to the plan for the years ended December 31, 1994, 1993, and
1992, were $3.4, $2.8, and $0.1 million, respectively. Contributions in 1991
included $2.6 million applicable to the 1992 plan year. In addition to the
pension plan, the company has a non-qualified supplemental retirement plan
which, as amended in 1994, provides a retirement benefit for certain
officers of the company.
The company is collecting an annual funding amount in customer rates and
anticipates that it will continue to do so. The $4.8 million cumulative
difference between the higher funded amount and the accounting pension cost
amount is a deferred credit on the balance sheet.
Pension Cost Components: 1994 1993 1992
(Thousands of Dollars)
Service cost $ 2,668 $ 1,888 $ 1,894
Actual return on plan assets (1,707) (2,214) (4,330)
Interest cost on projected benefit
obligation 3,710 3,504 3,294
Net amortization and deferral (953) (1,270) 1,476
Net pension cost $ 3,718 $ 1,908 $ 2,334
Discount rate for obligation 7.5% 7% 8%
Discount rate for expense 7.0% 8% 8%
Assumed rate of compensation increase 5.0% 5% 6%
Expected long-term rate of return 7.0% 8% 8%
Reconciliation of Funded Status
as of November 1:
Plan assets at fair value $49,282 $48,827 $47,365
Vested benefit obligation $36,626 $34,242 $27,127
Nonvested benefit obligation 2,365 1,728 384
Accumulated benefit obligation 38,991 35,970 27,511
Additional benefits based on
estimated future salary levels 13,547 13,872 17,855
Projected benefit obligation $52,538 $49,842 $45,366
Plan assets greater or (less) than
the projected benefit obligation $(3,256) $(1,015) $ 1,999
Unrecognized net obligation at
October 31, 1986 being amortized
over 16.1 years 2,753 3,094 3,435
Unrecognized prior service cost 3,487 399 2,126
Unrecognized net (gain)loss 718 2,340 (3,554)
Prepaid pension cost $ 3,702 $ 4,818 $ 4,006
In addition to providing pension benefits, the company provides life
insurance for retired employees and health care benefits for 910 retirees
and spouses. Substantially all of the company's 940 full-time employees
become eligible for these benefits if they reach retirement age while
working for the company. The company adopted Statement of Financial
Accounting Standards (SFAS) No. 106, "Accounting for Postretirement Benefits
Other Than Pensions" on January 1, 1993. Under the provisions of SFAS 106,
the estimated future cost of providing these postretirement benefits is
accrued during the employees' service periods. The accumulated
postretirement benefit obligation at January 1, 1993 (transition obligation)
was $30.9 million and is being amortized over a 20 year period. The annual
SFAS 106 cost for both 1994 and 1993 was $4.9 million, compared with the
pay-as-you-go amount of $1.9, $1.7, and $1.6 million in 1994, 1993, and 1992
respectively. Except for the State of Illinois, the company defers the
difference between the SFAS 106 costs and the pay-as-you-go amount until
rate cases are filed to recover the additional costs. Funding of the benefit
obligation is concurrent with recovery in customer rates. Effective May
1993, the IUB allowed the company to recover $0.3 million of additional
annual SFAS 106 expense in gas rates. Effective November 1993, the IUB
allowed recovery of $1.6 million of additional annual SFAS 106 expense in
electric rates.
On the basis of generic hearings or specific rate orders issued to other
utilities by the MPUC and the FERC, the company believes that the amounts
deferred meet the criteria for deferral established by the Financial
Accounting Standards Board. As of December 31, 1994, $2.6 million of SFAS
106 costs in excess of the pay-as-you-go amount have been deferred.
Assuming a one percent increase in the medical cost trend rate, the
company's 1994 cost of postretirement benefits would increase by $0.5
million and the accumulated benefit obligation would increase by $3.7
million.
The table below sets forth the postretirement health care plan's accumulated
benefit obligation (in thousands):
December 31, 1994 January 1, 1994
Retirees $18,902 $19,414
Active plan participants 12,642 15,690
Total accumulated benefit obligation 31,544 35,104
Less fair value of plan assets 4,072 814
Accumulated postretirement benefit
obligation in excess of plan assets 27,472 34,290
Unrecognized net gain or (loss) 1,756 (2,454)
Unrecognized transition obligation (25,253) (29,320)
Accrued postretirement benefit cost $ 3,975 $ 2,516
The components of the estimated cost of postretirement benefits other than
pensions for the twelve months ended December 31, 1994, and 1993, are as
follows (in thousands):
1994 1993
Service cost $ 1,205 $ 979
Return on plan assets (48) -
Interest cost on accrued postretirement
benefit obligation 2,345 2,383
Amortization of transition obligation 1,543 1,543
Net amortization and deferral (159) -
Net cost $ 4,886 $ 4,905
The assumptions used for measurement purposes are as follows:
1995 1994
Discount rate for obligations 7.5% 7.0%
Discount rate for expense 7.0% 8.0%
Initial medical cost trend rate 9.0% 9.0%
Ultimate medical cost trend rate 6.0% 6.0%
Year that the medical cost trend
rate is assumed to decrease to
the ultimate rate 1997 1997
8. Income Taxes
The company adopted SFAS No. 109, "Accounting for Income Taxes", on January
1, 1993. The new standard required a deferred tax asset or liability to be
recognized for each temporary book/tax difference, including timing
differences flowed through and items not previously considered timing
differences (primarily Deferred Investment Tax Credits and Equity AFUDC).
Corresponding regulatory assets or liabilities, reflecting the anticipated
future rate treatment, have also been recognized. The balance sheet as of
December 31, 1994, includes additional regulatory assets and deferred tax
liabilities of $27.5 million as a result of the adoption of SFAS 109.
Investment tax credits have been deferred and are credited to operating
income over the lives of the property which gave rise to the credits.
The principal components of the company's deferred tax (assets) liabilities
recognized in the December 31, 1994, and 1993, balance sheet are shown
below:
Item: Thousands of Dollars
1994 1993
Property $80,484 $76,956
Energy Conservation Costs 5,195 2,782
Environmental Clean-up Costs (210) (2,366)
Call Premiums on Reacquired Bonds 2,005 1,988
Unbilled Revenue (3,310) (3,681)
Other (2,186) (1,235)
Total $81,978 $74,444
Gross deferred assets $(6,197) $(7,994)
Gross deferred liabilities 88,175 82,438
Total $81,978 $74,444
The total income tax expense produces the overall effective income tax rate
shown in the table. The percentages are computed by dividing total income
tax expense by the sum of such tax expense and net income.
1994 1993 1992
Federal statutory tax rate 35.0% 35.0% 34.0%
Increases (reductions) in taxes resulting from:
State income taxes net of federal income tax
benefit 4.0% 4.7% 4.3%
Investment tax credit amortization (3.4%) (3.6%) (3.6%)
Additional depreciation deducted for book
purposes 2.0% 2.0% 2.2%
Other (6.8%) (4.8%) (3.4%)
Overall effective income tax rate 30.8% 33.3% 33.5%
The current and deferred tax expense is
comprised of (Thousands):
Federal and state currently payable $ 1,849 $ 6,139 $ 8,097
Deferred income tax - federal and state:
Additional tax depreciation - net 3,270 3,256 3,012
Coal contract buyout - (526) (149)
Energy efficiency costs 2,413 1,466 773
Environmental clean-up 2,010 (1,166) (353)
Other (601) 826 (1,015)
Investment tax credit amortization (1,028) (1,028) (1,028)
Federal and state currently payable - other
income and deductions 1,276 497 361
Total $ 9,189 $ 9,464 $ 9,698
9. Rate Matters
IOWA
The company filed an Iowa electric rate increase application in August 1993.
The application requested an annual increase of $11.5 million, including a
return on common equity of 12.35%. Interim rates in an annual amount of
$11.0 million were placed in effect on October 28, 1993, subject to refund.
An IUB Order issued in June 1994 allowed an annual increase of $7.4 million,
including a return on common equity of 11.0%. Electric revenues for 1994 are
reduced by approximately $0.5 million of overcollection which relates to
1993.
FERC
In 1992, sixteen municipal wholesale customers filed a Complaint and Request
for Investigation and Hearing with the FERC. The complaint alleged that the
company had been imprudent by entering into certain long-term coal
contracts, an associated transloading agreement, and a rail transportation
agreement and sought recovery of approximately $4 million. In July 1994, the
company filed an application with the FERC for an increase in firm electric
wholesale rates in an annual amount of $1.4 million. On August 3, 1994, in
accord with a settlement of the wholesale customer complaint, the company
withdrew the rate request. The settlement also provided for the company to
pay the wholesale customers a cash settlement of $0.3 million, and that the
company will not file another firm wholesale rate case with an effective
date prior to February 28, 1996.
FERC Order 636, issued in 1992, provides for nondiscriminatory access to
interstate pipeline capacity. Order 636 includes a mechanism under which gas
pipelines can recover from local distribution companies prudently incurred
transition costs. The company's pipeline suppliers have filed with the FERC
to recover such transition costs. The company estimates its remaining share
of transition costs will aggregate approximately $5.2 million payable in
declining annual installments from 1995 to 2004. The company anticipates
that under customary regulatory practices, such transition costs will be
recovered from customers, and has recorded on its balance sheet a liability
and a corresponding regulatory asset in the amount of $5.2 million.
10. Jointly-Owned Utility Plant
The company has a 21.528% (134,300 KW) interest in a 624,000 KW coal-fired
unit (Neal #4), completed in 1979; the company provided financing for its
share. Amounts at December 31, 1994, and 1993, included in utility plant
were $82.0 and $81.7 million, respectively, and the accumulated provision
for depreciation was $38.6 and $36.1 million, respectively. In addition, the
company has a long-term participation power purchase for 25,000 KW of Neal
#4 generating capacity which expires 2003. Minimum future capacity payments
under the participation power purchase agreement are approximately $17.9
million. The 21.528% ownership share and the long-term participation
purchase provide the company with an aggregate of 159,300 KW of Neal #4
generating capacity.
The company also has a 4% (27,000 KW) interest in a 675,000 KW coal-fired
unit (Louisa #1), completed in 1983. $24.8 million was included in utility
plant at December 31, 1994, and 1993, and the accumulated provision for
depreciation was $8.8 and $8.1 million, respectively.
The company's share of direct expenses of Neal #4 and Louisa #1 is included
in the appropriate operating expenses in the statements of income and
retained earnings.
11. Purchased Power Contracts
The company has three long-term power purchase contracts with other electric
utilities. The contracts provide for the purchase of 230 to 255 megawatts of
capacity over the period from May 1992 through April 2001. The company is
obligated to pay the capacity charges regardless of the actual electric
demand by the company's customers. Energy is available at the company's
option at approximately 100% to 110% of monthly production costs for the
designated units.
The three power purchase contracts required capacity payments of $24.6,
$24.1, and $16.3 million in 1994, 1993, and 1992 respectively. Over the
remaining period of the contracts, total capacity payments will be
approximately $155 million.
A portion of the purchased power capacity payments is not being recovered
through rates:
A 1992 rate order by the MPUC held that the company had 100 MW of excess
capacity. The Minnesota jurisdictional portion of the 100 MW of disallowed
capacity is approximately $1.9 million annually.
An additional 25 MW of purchased power contracts became effective after
1992. Annual electric rates do not provide for the recovery of $0.8 and $0.2
million, respectively, applicable to the Iowa and Minnesota jurisdictions.
The company has not yet filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and the FERC jurisdictions.
The annual Illinois and the FERC jurisdictional portions are approximately
$1.7 and $0.9 million, respectively.
The amounts which are not being recovered through rates are expensed as
incurred. The impact of not recovering the purchased power payments is
mitigated to the extent that load growth has occurred since the last rate
case.
The purchased power contract payments are not for debt service requirements
of the selling utility, nor do they transfer risk or rewards of ownership.
12. Deferred Energy Efficiency Costs
Minnesota and Iowa regulations require that utilities conduct energy
efficiency and demand side management programs. Each utility recovers
program costs as well as related carrying costs subject to a periodic
prudency review by the state public utility commission.
Demand side management expenditures applicable to the Minnesota jurisdiction
in an annual amount of approximately $0.5 million are currently being
recovered through rates. A May 1994 IUB Order allows recovery of Iowa energy
efficiency expenditures incurred through December 31, 1992. New tariffs,
which provide for the recovery of approximately $6.7 million of energy
efficiency costs over a four year period were placed in effect in October
1994.
Management believes that the amounts deferred meet the criteria established
by the respective commissions for recovery of demand side management costs.
As of December 31, 1994, and 1993, the amounts deferred were $17.0 and $9.7
million, respectively.
13. Segments of Business
Information about the company's operations in different segments of business
for 1994, 1993 and 1992 are shown in the table below.
Electric Gas Total
(Thousands of Dollars)
1994
Revenue $261,730 $ 45,920 $307,650
Operating income (Before income taxes) $ 42,881 $ 554 $ 43,435
Depreciation and amortization expense $ 26,156 $ 2,056 $ 28,212
Capital expenditures $ 38,129 $ 2,969 $ 41,098
Utility plant - net $461,245 $ 39,436 $500,681
1993
Revenue $255,759 $ 53,709 $309,468
Operating income (Before income taxes) $ 44,573 $ (782) $ 43,791
Depreciation and amortization expense $ 24,732 $ 2,223 $ 26,955
Capital expenditures $ 29,030 $ 5,087 $ 34,117
Utility plant - net $449,430 $ 38,534 $487,964
1992
Revenue $239,193 $ 46,105 $285,298
Operating income (Before income taxes) $ 46,854 $ (2,333) $ 44,521
Depreciation and amortization expense $ 23,844 $ 2,043 $ 25,887
Capital expenditures $ 26,276 $ 6,199 $ 32,475
Utility plant - net $446,380 $ 35,676 $482,056
14. Quarterly Information (Unaudited)
The quarterly information has not been audited but, in the opinion of the
company, reflects all adjustments necessary for the fair statement of the
results of operations for each period.
The quarterly data shown below reflects seasonal and timing variations which
are common in the utility industry.
(Thousands of Dollars)
(Except Earnings Per Share)
1994 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $85,575 $71,863 $79,808 $70,404
Operating income 13,051 5,460 10,607 6,404
Net income 9,251 1,354 6,867 3,195
Earnings per share of common stock .91 .07 .65 .27
1993 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $84,989 $70,107 $77,248 $77,124
Operating income 12,417 6,331 7,089 8,987
Net income 8,389 1,980 3,519 5,099
Earnings per share of common stock .82 .11 .31 .47
Net income for the fourth quarter of 1994 was $3.2 million, compared with
$5.1 million in 1993. Mild weather, coal tar clean-up costs, additional
depreciation and other employment benefits expense depressed fourth quarter
of 1994 earnings. These factors were partially offset by increased fourth
quarter 1994 industrial sales and a favorable IRS tax audit settlement. In
addition, an overcollection of electric rates in Iowa tended to boost 1993
earnings as discussed in Note 9.
The gas margin for the fourth quarter of 1994 (revenue minus cost of gas
sold) was $2.8 million compared with $3.5 million for the same period of
1993. The decrease is primarily attributable to reduced residential and
commercial sales due to mild weather.
Other operating expense for the fourth quarter of 1994 includes $0.9 million
of estimated coal tar clean-up costs. The 1993 provisions for clean-up costs
were recorded in the first and third quarters.
Depreciation expense for the fourth quarter of 1994 increased $0.8 million
over the same period of 1993. The increase is primarily attributable to new
depreciation rates approved by the MPUC retroactive to January 1, 1994.
Other deductions for the fourth quarter of 1994 include a $0.3 million cash
settlement for the FERC municipal complaint.
Income tax expense for the fourth quarter of 1994 declined $1.7 million, due
to lower net income and the favorable settlement of an IRS audit for tax
years 1988-1991.
15. Commitments and Contingencies
The company has a coal supply contract, a rail transportation contract, and
a coal transloading agreement applicable to its power plants. Such
contracts, the last of which expires in 1999, require estimated minimum
future payments of $132.6 million.
The company has three natural gas supply contracts, six natural gas
transportation contracts, and four natural gas storage contracts, which
collectively obligate the company for a minimum annual commitment of
approximately $7.8 million. Such agreements individually expire from 1995
through 2001.
Reference is also made to Notes 2, 9, 10, and 11 for a discussion of
Environmental Matters, Rate Matters and Purchased Power Contracts.
Independent Auditors' Report
DELOITTE & TOUCHE LLP 101 West Second Street
Davenport, Iowa 52801
To the Stockholders and Board of Directors of Interstate Power Company:
We have audited the accompanying balance sheets and statements of
capitalization of Interstate Power Company as of December 31, 1994 and 1993
and the related statements of income and retained earnings and of cash flows
for each of the three years in the period ended December 31, 1994. 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.
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 financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 1994 and
1993 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles.
As discussed in notes 7 and 8 to the financial statements, in 1993 the
Company changed its method of accounting for postretirement benefits other
than pensions and for income taxes, respectively.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
February 2, 1995
REPORT OF MANAGEMENT ON FINANCIAL STATEMENT RESPONSIBILITY
Company management has prepared and is responsible for the integrity and
objectivity of the financial statements and related financial information
included in this Annual Report to Stockholders. These statements have been
prepared in conformity with generally accepted accounting principles and
necessarily include amounts based on informed judgements and estimates with
appropriate consideration to materiality of events pending at year-end.
In meeting its responsibility, management has implemented an internal
accounting system designed to safeguard the assets of the company and assure
that transactions are executed in accordance with its directives. An
organizational structure has been developed that provides for appropriate
functional responsibilities. A qualified internal audit staff is responsible
for monitoring the system of policies, procedures and methods of operation.
The company believes its system of internal controls appropriately balances
the cost/benefit relationship, and that errors or irregularities will be
detected and corrected on a timely basis.
The Audit Committee of the Board of Directors, comprised of three directors
who are not employees, periodically meets with management and with the
independent certified public accountants to discuss and evaluate auditing,
internal control and financial reporting matters.
Management believes that these policies and procedures provide reasonable
assurance that the operations of the company are in accordance with the
standards and responsibilities entrusted to management.
/s/ Wayne H. Stoppelmoor
Wayne H. Stoppelmoor
Chairman of the Board,
President and Chief
Executive Officer
Selected Financial Data
1994 1993 1992 1991 1990
(Thousands of Dollars)
Operating revenues $307,650 $309,468 $285,298 $291,805 $273,597
Operation 202,545 204,871 181,391 172,709 160,206
Maintenance 17,160 16,771 16,966 17,567 15,529
Depreciation and
amortization 28,212 26,955 25,887 25,303 24,420
Income taxes 7,913 8,967 9,337 17,113 18,132
Property and other taxes 16,298 17,080 16,533 15,315 14,785
272,128 274,644 250,114 248,007 233,072
Operating income 35,522 34,824 35,184 43,798 40,525
Other income (deductions) -
net 1,990 780 724 1,269 1,429
Income before interest
charges 37,512 35,604 35,908 45,067 41,954
Interest charges 16,845 16,617 16,691 15,557 14,928
Net income 20,667 18,987 19,217 29,510 27,026
Preferred and preference
dividends 2,454 2,861 2,975 3,075 3,158
Earnings available for
common stock $ 18,213 $ 16,126 $ 16,242 $ 26,435 $ 23,868
Average number of common
shares outstanding 9,478,741 9,316,387 9,297,748 9,297,748 9,297,748
Earnings per common
share $ 1.92 $ 1.73 $ 1.74 $ 2.84 $ 2.56
Common dividends
declared per share $ 2.08 $ 2.08 $ 2.08 $ 2.04 $ 2.00
Total assets $628,845 $604,361 $558,100 $550,631 $539,103
Long-term debt and
mandatory sinking
fund preferred stock $212,965 $227,007 $207,958 $220,818 $197,969
Common Stock Market Data
The company's common stock (IPW) is listed on the New York, Midwest and
Pacific Stock Exchanges. The company's preferred stock and first mortgage
bonds are traded in the over-the-counter market. The company was reorganized
as of March 31, 1948, and dividends on common stock have been paid each
quarter since September 20, 1948, with the annual payments rising from $0.60
per share to the February 4, 1992, level of $2.08 per share. As of December
31, 1993, there were 16,256 holders of common stock and 200 holders of
preferred stock. Historical quarterly data for the company's common stock is
shown below:
Avg. Shares
Outstanding
Price Range 12 Months
Quarter Ended Dividends Paid High Low Ended
March 31, 1992 $0.52/Share 34 3/4 - 31 5/8 9,297,748
June 30, 1992 $0.52/Share 34 3/8 - 30 5/8 9,297,748
Sept. 30, 1992 $0.52/Share 32 3/8 - 31 9,297,748
Dec. 31, 1992 $0.52/Share 31 7/8 - 28 3/8 9,297,748
March 31, 1993 $0.52/Share 34 1/8 - 30 3/8 9,297,748
June 30, 1993 $0.52/Share 32 3/4 - 29 9,297,748
Sept. 30, 1993 $0.52/Share 31 3/4 - 29 9,301,030
Dec. 31, 1993 $0.52/Share 30 3/4 - 29 1/8 9,316,387
March 31, 1994 $0.52/Share 30 1/4 - 26 3/8 9,341,751
June 30, 1994 $0.52/Share 29 - 22 1/4 9,379,249
Sept. 30, 1994 $0.52/Share 24 3/4 - 21 9,428,183
Dec. 31, 1994 $0.52/Share 23 3/4 - 20 7/8 9,478,741
EX-23.a
DELOITTE & TOUCHE LLP
Northwest Bank Building Telephone: (319) 322-4415
101 West Second Street Facsimile: (319) 322-2002
Davenport, Iowa 52801-1813
INDEPENDENT AUDITORS' REPORT
Interstate Power Company:
We have audited the financial statements of Interstate Power
Company as of December 31, 1994 and 1993, and for each of the
three years in the period ended December 31, 1994, and have
issued our report thereon dated February 2, 1995, which report
includes an explanatory paragraph as to a 1993 change in
accounting for postretirement benefits other than pensions and
for income taxes; such financial statements and report are
included in your 1994 Annual Report to Stockholders and are
incorporated herein by reference. Our audits also included the
financial statement schedule of Interstate Power Company, listed
in Item 14. This 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.
/s/ Deloitte & Touche LLP
February 2, 1995
EX-23.b
DELOITTE & TOUCHE LLP
Northwest Bank Building Telephone: (319) 322-4415
101 West Second Street Facsimile: (319) 322-2002
Davenport, Iowa 52801-1813
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration
Statement No. 33-59352 on Form S-3 and Registration Statement No.
33-32529 on Form S-8 of Interstate Power Company of our reports
dated February 2, 1995, appearing in and incorporated by reference
in the Annual Report on Form 10-K of Interstate Power Company for
the year ended December 31, 1994.
/s/ Deloitte & Touche LLP
March 17, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<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> 500,681
<OTHER-PROPERTY-AND-INVEST> 522
<TOTAL-CURRENT-ASSETS> 65,466
<TOTAL-DEFERRED-CHARGES> 62,176
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 628,845
<COMMON> 33,475
<CAPITAL-SURPLUS-PAID-IN> 103,137
<RETAINED-EARNINGS> 55,893
<TOTAL-COMMON-STOCKHOLDERS-EQ> 192,505
23,933
10,819
<LONG-TERM-DEBT-NET> 189,032
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 35,600
<LONG-TERM-DEBT-CURRENT-PORT> 14,000
0
<CAPITAL-LEASE-OBLIGATIONS> 115
<LEASES-CURRENT> 17
<OTHER-ITEMS-CAPITAL-AND-LIAB> 162,824
<TOT-CAPITALIZATION-AND-LIAB> 628,845
<GROSS-OPERATING-REVENUE> 307,650
<INCOME-TAX-EXPENSE> 7,913
<OTHER-OPERATING-EXPENSES> 264,215
<TOTAL-OPERATING-EXPENSES> 272,128
<OPERATING-INCOME-LOSS> 35,522
<OTHER-INCOME-NET> 1,990
<INCOME-BEFORE-INTEREST-EXPEN> 37,512
<TOTAL-INTEREST-EXPENSE> 16,845
<NET-INCOME> 20,667
2,454
<EARNINGS-AVAILABLE-FOR-COMM> 18,213
<COMMON-STOCK-DIVIDENDS> 19,717
<TOTAL-INTEREST-ON-BONDS> 15,124
<CASH-FLOW-OPERATIONS> (1,546)
<EPS-PRIMARY> $1.92
<EPS-DILUTED> $1.92
</TABLE>
EX-99.a
ITEM 11(a)(2). EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K.
Those financial statement schedules required to be filed by Item 8
of this Form and the financial statements required by Regulation S-X
(17 CFR 210) which are excluded from the annual report to stockholders
by Rule 14a-3(b)(1).
Listed below are current documents incorporated by reference and
identified as having been previously filed with the Commission.
The Original through the Nineteenth Supplemental Indentures of
Interstate Power Company to The Chase Manhattan Bank and Carl E.
Buckley and C. J. Heinzelmann, as Trustees, dated January 1, 1948
securing First Mortgage Bonds (physically filed in Registration
Statement No. 33-59352 dated March 11, 1993 under the Securities Act of
1933 as Exhibits (4)(b) through (4)(t)).
Twentieth Supplemental Indenture of Interstate Power Company to
The Chase Manhattan Bank and C. J. Heinzelmann, as Trustees, dated May
15, 1993 (physically filed in Registration Statement No. 33-59352 dated
March 11, 1993 under the Securities Act of 1933 as Exhibit (4)(u)).
Dividend Reinvestment and Stock Purchase Plan filed on Form S-3
covering the registration of 500,000 shares of Common Stock, dated May
11, 1993 (physically filed in Registration Statement No. 33-66244
under the Securities Act of 1933).
Guaranty Agreement between Interstate Power Company and Commerce
Union Bank as Trustee dated as of December 1, 1973 (City of Dubuque,
Iowa $4,400,000 Pollution Control Revenue Bonds) (physically filed in
Registration Statement No. 2-50685 as EXHIBIT 5-GG.1a).
Security Agreement dated as of December 1, 1973 between Interstate
Power Company (Guarantor) and Commerce Union Bank (Trustee) (City of
Dubuque, Iowa $4,400,000 Pollution Control Revenue Bonds) (physically
filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.1b).
Guaranty Agreement between Interstate Power Company and Commerce
Union Bank as Trustee dated as of December 1, 1973 (Town of Lansing,
Iowa $3,700,000 Pollution Control Revenue Bonds) (physically filed in
Registration Statement No. 2-50685 as EXHIBIT 5-GG.2a).
Security Agreement dated as of December 1, 1973 between Interstate
Power Company (Guarantor) and Commerce Union Bank (Trustee) (Town of
Lansing, Iowa $3,700,000 Pollution Control Revenue Bonds) (physically
filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.2b).
Guaranty Agreement between Interstate Power Company and Commerce
Union Bank as Trustee dated as of December 1, 1973 (City of Clinton,
Iowa $900,000 Pollution Control Revenue Bonds) (physically filed in
Registration Statement No. 2-50685 as EXHIBIT 5-GG.3a).
Security Agreement dated as of December 1, 1973 between Interstate
Power Company (Guarantor) and Commerce Union Bank (Trustee) (City of
Clinton, Iowa $900,000 Pollution Control Revenue Bonds) (physically
filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.3b).
Registration Statement No. 33-32529 on Form S-8 covering the
registration of $10,000,000 of participation interests, including the
registration of up to 402,010 shares of Common Stock, par value $3.50
per share, of Interstate Power Company pursuant to its 401(k) Plan
(filed with the Commission on December 12, 1989).
IPC Development Co. Articles of Incorporation, State of Iowa dated
May 24, 1978 (physically filed in Form 10-K for the Year Ended December
31, 1978 as EXHIBIT G).
IPC Development Co. By-Laws adopted May 10, 1978 (physically filed
in Form 10-K for the Year Ended December 31, 1978 as EXHIBIT H).
By-Laws of Interstate Power Company as adopted April 20, 1925 and
as amended May 7, 1991 (physically filed in Form 10-K for the Year
Ended December 31, 1991 as EXHIBIT W).
Restated Certificate of Incorporation of Interstate Power Company
as originally filed April 18, 1925 and as amended effective through
October 21, 1993 (filed in Form 10-K for the Year Ended December 31,
1993 as EX-3.a).
Summary Plan Description for the Interstate Power Company 401(k)
Plan dated November 30, 1993 (filed in Form 10-K for the Year Ended
December 31, 1993 as EX-99.c).
Interstate Power Company Supplemental Retirement Plan dated
October 8, 1990 (filed in Form 10-K for the Year Ended December 31,
1993 as EX-99.d).
Interstate Power Company Irrevocable Trust Agreement dated
April 30, 1990 (filed in Form 10-K for the Year Ended December 31, 1993
as EX-99.f).
Interstate Power Company Amended Deferred Compensation Plan as
amended through January 30, 1990 (filed in Form 10-K for the Year Ended
December 31, 1993 as EX-99.e).
