EX-13
INTERSTATE POWER COMPANY
Annual Report to Stockholders
1993
MANAGEMENT'S DISCUSSION AND ANALYSIS
The company's results of operations and financial condition are affected by
numerous factors, including weather, sales, and the amount of changes in
customer rates. The following comments are designed to explain the financial
statements on pages 12 - 29 and the financial and stock market data on pages
32 and 33.
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 have sufficient internal and external capital resources to meet
anticipated capital requirements.
Construction expenditures were $34 million in 1993, $32 million in 1992, and
$33 million in 1991. The 1994 construction program is estimated to be $46.5
million, and 1995 is estimated to be $39.0 million. The company anticipates
that 54% of the construction funds for years 1994 and 1995 will be generated
internally. For the five year period from 1994 through 1998, total
construction expenditures are estimated to be $225 million. Expenditures for
1994 and 1995 include $10.9 million for pollution control equipment
necessary to comply with the Clean Air Act.
In the second quarter of 1993, the company filed registration statements
with the Securities and Exchange Commission (SEC) for $125 million of first
mortgage bonds and 745,000 shares of $50 par value preferred stock. In May
1993, the company issued $94 million of 7 5/8% first mortgage bonds and
545,000 shares of 6.40% $50 par value preferred stock. The proceeds were
used to redeem higher-rate debt and preferred and preference stock. The
refinancing lowered the embedded cost of first mortgage bonds from 8.3% to
8.0%. A further advantage of the refinancing was to extend the final
maturity dates for a significant portion of the company's capitalization.
The new bonds have a maturity date of 2023, while the new preferred stock
has a final maturity date of 2022. While the company does not currently plan
to issue the remainder of the securities registered with the SEC ($31
million of bonds and 200,000 shares of preferred stock), the shelf
registration does provide the company additional flexibility. If interest
rates remain favorable, the company anticipates refinancing $13.25 million
of outstanding pollution control revenue bonds in 1994. The pollution
control revenue bonds for which refinancing is contemplated have coupon
rates from 7 1/8% to 7 1/4%.
The company amended its Common Stock Dividend Reinvestment and Stock
Purchase Plan in 1993. The amended plan allows the company's residential and
farm customers to participate in the plan, and gives the company the option
of issuing new common stock as an alternative to purchasing shares on the
open market. The company received $2.8 million for 92,093 shares of new
common stock issued in the third and fourth quarters of 1993 under the
amended plan.
At December 31, 1993, 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 1993 and 1992,
and 3.8 times for 1991. The primary reason for the reduced ratio is lower
net income. As discussed later, the lower net income was caused by the
accrual of future environmental clean-up costs and additional payments for
electric capacity purchases.
At December 31, 1993, the ratio of common equity to total capitalization was
44.4%. 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 primarily through issuance of additional shares
through the amended Dividend Reinvestment Plan and through a common stock
public offering of approximately $30 million in 1995.
Standard and Poor's rating agency (S&P) recently announced more stringent
guidelines for analyzing utilities' credit quality and financial strength,
while Moody's Investors Service (Moody's) has indicated that ratings for
utilities "will come under growing pressure over the next three to five
years as a result of changes in the business environment." The rating
agencies cite industry-wide factors such as a slow-growth period in terms of
demand, growing cost pressures and the fact that competition will provide
customers additional options for electric supply in succeeding years. In
addition, the rating agencies will consider the utility's service territory,
the regulatory climate in which the utility operates, its competitive
position, fuel mix, and operating reliability. In the second quarter of
1993, S&P and Moody's reaffirmed their previous ratings of the company's
first mortgage bonds. The company's bonds are rated A+ by S&P and A1 by
Moody's.
The company has authorization from the Federal Energy Regulatory Commission
(FERC) to issue up to $60 million in short-term debt. At year-end 1993, a
$39.6 million line of credit was available. Lines of credit are generally
used in support of commercial paper, which represents a primary source of
short-term financing. At year-end 1993, the company had $20.1 million of
short-term commercial paper payable. The company anticipates that, due to
its construction program, short-term debt will increase to approximately $36
million by year-end 1994. The company plans to retire the short-term debt
with the proceeds from the planned 1995 common stock financing.
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. 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 Iowa Utilities Board (IUB) required that any jurisdictional
revenue from capacity sales to other utilities be returned to Iowa
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.
NEW ACCOUNTING STANDARDS
The company adopted Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes", in 1993. The new standard requires 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 expected future rate treatment, have also been recognized.
For this reason, the new standard did not have a significant effect on the
income statement, but did result in increased regulatory assets and deferred
tax liabilities. The balance sheet as of December 31, 1993 includes
additional regulatory assets and deferred tax liabilities of $27.0 million
as a result of the adoption of SFAS 109.
The company adopted SFAS No. 106, "Accounting for Postretirement Benefits
Other Than Pensions" in 1993. Under the provisions of SFAS 106, the
estimated future cost of providing these postretirement benefits is accrued
during 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 1993 is $4.9
million, compared to the 1993 pay-as-you-go amount of $1.7 million. The
company is deferring the difference between the SFAS 106 costs and the pay-
as-you-go amount until rate cases are filed to recover the additional costs.
Effective May 1993, the IUB allowed the company to recover $300,000 annually
of additional SFAS 106 expense in gas rates. Effective November 1993, the
IUB allowed recovery of $1.6 million annually of additional SFAS 106 expense
in electric rates, subject to refund upon final determination. On the basis
of generic hearings or specific rate orders issued to other utilities by the
Minnesota Public Utilities Commission (MPUC), FERC and the Illinois Commerce
Commission (ICC), the company believes that amounts deferred meet the
criteria for deferral established by the Financial Accounting Standards
Board. As of December 31, 1993, $2.6 million of SFAS 106 costs in excess of
the pay-as-you-go amount have been deferred.
GENERATING CAPABILITY & PROJECTED DEMAND
The company established a new system peak of 927 MW in August 1993. This
compares to the prior peak of 919 MW which occurred in August 1988. The
company's net effective capability at the time of the 1993 system peak was
1,296 MW. Forecast peak demand for the year 2000 is 1,117 MW (not including
a 15% reserve of 168 MW required by the Mid-Continent Area Power Pool).
The company's total capacity includes three long-term power purchase
contracts with other electric 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 $24.1 million in 1993
and $16.3 million in 1992. Over the remaining life of the contracts, total
capacity payments will be approximately $180 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 payments is not being recovered through
rates. The company has not yet filed for rate recovery in the Illinois and
FERC jurisdictions. A 1992 rate order by the MPUC held that the company's
total capacity exceeded, by 100 MW, what they considered reasonably
necessary for the efficient and reliable provision of utility service and
disallowed recovery of $1.9 million per year. The Minnesota Court of Appeals
affirmed the MPUC disallowance in May 1993. Such amount is being expensed as
incurred.
The company's 1991 Iowa electric rate case requested recovery of $17.4
million of the new purchased power capacity costs applicable to the Iowa
jurisdiction. The IUB order held that the capacity purchases were prudent
and allowed recovery of the costs in rates. In order to match the capacity
costs with the associated revenues, however, the IUB projected Iowa electric
retail jurisdiction sales for the twelve month period ending April 1993. A
comparison to 1992 and 1993 actual sales indicates an overprojection by the
IUB. To the extent that projected sales have not been met, the company has
experienced reduced electric margins. The company filed a new Iowa electric
rate application on August 4, 1993. Interim rates in an annual amount of
$11.0 million were placed in effect October 28, 1993, subject to refund.
Through December 31, 1993, approximately $1.7 million has been collected
subject to refund. A decision is expected by June 1994.
CLEAN AIR ACT
The company is subject to environmental regulations promulgated and enforced
by federal and state governments. The company believes that it presently
meets existing regulations. The Federal Clean Air Act Amendments of 1990
will require reductions in sulfur dioxide and nitrogen oxide emissions from
power plants. The legislation sets two deadlines for compliance, Phase 1
(January 1, 1995) and Phase 2 (January 1, 2000). The most restrictive
provisions relate to sulfur dioxide emissions. During Phase I, only one of
the company's units is affected. That unit's net effective capacity is 217
MW. Present plans for the affected unit are to switch to lower sulfur coal
and install low nitrogen oxide burners. Phase 2 compliance will require
additional capital, operating and maintenance costs beyond those required
for Phase 1. The Phase 2 regulations will affect approximately 87% of the
company's current generating capacity. The company's long-range construction
forecast (through the year 2000) contains estimated Phase 1 capital
expenditures of approximately $6.5 million and estimated Phase 2 capital
expenditures in the range of $35.0 million. Estimated expenditures for 1994
and 1995 include $10.9 million for facilities necessary to comply with the
Clean Air Act. The estimated expenditures include provisions for low nox
burners, emission monitors, and flue gas conditioning systems. The company
anticipates the costs of compliance with the Clean Air Act will be recovered
through the ratemaking process.
COAL TAR DEPOSITS
Early this century, various utilities including the company operated plants
which used coal, coke and/or oil to produce manufactured gas for cooking and
lighting. These facilities were abandoned 40 to 60 years ago when natural
gas pipelines were extended into the upper Midwest. Some of the former
gasification sites contain waste products which may present an environmental
hazard. Waste remediation costs can vary significantly, dependent on the
disposal method and type of contaminants. Current estimates range from $75
to $1,200 per ton of waste material.
In 1957, the company purchased facilities in Mason City, Iowa from Kansas
City Power & Light Company (KCPL) which included a parcel of land previously
used for coal gasification. In 1986 and again in 1991, the company entered
into Consent Orders with the Environmental Protection Agency (EPA) which
obligate the company to conduct a Remedial Investigation and Feasibility
Study at the Mason City site. A Remedial Investigation has been completed
and has been approved by the EPA. The company is continuing to perform
investigative testing to determine the limits of potential groundwater
contamination at the Mason City site. The remediation process will not begin
until the EPA has approved the scope of the project and the appropriate
process for cleaning up the site. To-date, a total of 1,200 tons of
contaminated soil has been identified. To-date, all costs have been charged
to expense. The company spent $300,000 on the Mason City project in 1993; it
has spent $1.7 million on the site since the discovery of the tar wastes in
1984. In 1991, the company recorded estimated future expenditures of $1.4
million for groundwater monitoring, construction of an interim groundwater
treatment facility and design of site remediation. In addition, the company
expensed an additional $200,000 in 1992 to cover the estimated cost to
remediate 1,200 tons of waste presently in a storage pile. The company is
pursuing recovery of response costs from KCPL. The Federal District Court
ruled in the third quarter of 1993 that KCPL is liable to the company
regarding the response costs at the Mason City site. (KCPL is a strong A
rated company with total assets in excess of $2 billion.) Additional court
proceedings will be held in 1994 or 1995 to determine the extent of that
liability. In the opinion of the company, presently accrued liabilities of
$800,000 are adequate to cover the company's share of future expenses at
this site.
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. The limits of contaminated soil have been identified and are
estimated to be 50,000 tons. Tentative agreements have been reached between
the Minnesota PCA and all three parties noted above regarding the clean-up
process. The remediation process will begin in early 1994. The total costs
to clean-up this site are estimated to be $7.8 million. A verbal agreement
has been reached among the parties regarding cost sharing and a written
agreement is expected in the near future. The company has agreed to pay for
$4.9 million of the estimated costs ($3.5 million was recorded in 1993, $1.2
million in 1992, $200,000 in 1991). To-date, all costs have been charged to
expense.
The company owned and operated a manufactured gas facility in Albert Lea,
Minnesota and is solely responsible for the site. Testing for contaminated
soil and groundwater has taken place and additional testing will take place
in 1994. Based on the past testing, contamination is at a low level. All
costs have been charged to expense. $80,000 was spent in 1993 and $243,000
has been spent to-date. Estimated investigative and remedial expenditures in
the amount of $400,000 were expensed in 1991. The company anticipates that
a risk assessment will be completed by late 1994. Remediation requirements
will not be known until the risk assessment is completed.
The company owned and operated a manufactured gas plant at Clinton, Iowa.
The company believes that the coal gasification waste was removed subsequent
to plant decommissioning, and therefore it is not necessary to accrue for
any future liability. If hazardous wastes are found at the site, the EPA may
name several potentially responsible parties in addition to the company, as
other industrial operations have been conducted on or adjacent to the site.
In September 1992, the company prepared a consent order (the agreement to
investigate and, if necessary, remediate the site) and forwarded it to the
Iowa Department of Natural Resources - Department of Environmental Quality.
On November 24, 1993, the company was notified that the site was referred to
the Federal EPA.
In addition, the company has identified four other sites in the Midwest for
which the company is potentially responsible. The company has not conducted
an investigation of these sites, nor has the EPA requested that any
investigations be initiated. No environmental response costs have been
recorded for these sites, as no evidence has been brought forth to indicate
that any of these sites contain hazardous materials. In January 1994, the
company was notified by an Illinois property owner of a site which contains
hazardous materials which may have come from a former manufactured gas
plant. Investigations are underway to determine if the company has any
responsibility for the site.
The company has retained an outside law firm to pursue recovery from
insurance carriers of environmental remediation costs applicable to the coal
gasification sites. While the company's insurance carriers have stated that
they are not liable, the company believes that it has coverage. Neither the
company nor its legal counsel is able to predict the amount or timing of any
insurance recovery, and accordingly, no potential recovery has been
recorded.
Previous actions by Iowa, Minnesota and Illinois regulators have permitted
utilities to recover prudently incurred remediation and legal costs
(response cost). The company anticipates that any unreimbursed costs
applicable to the Iowa, Illinois and Albert Lea, Minnesota jurisdictions
should be recovered from gas customers. It is uncertain whether the company
will recover any uninsured costs applicable to the Rochester, Minnesota
site, as the company no longer serves that city, and no Minnesota precedent
has been established for recovery in a similar situation.
POTENTIALLY RESPONSIBLE PARTY DESIGNATION
Under the Federal Comprehensive Environmental Response, Compensation and
Liability Act, a past waste generator can be designated by the 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 EPA. The company has been cited as
a PRP by the EPA in three instances which involve used transformer oil.
The company was identified in 1986 by the EPA as a PRP for the clean-up of
the facilities formerly operated by Martha C. Rose Chemicals, Inc. (Rose) in
Holden, Missouri. Rose, pursuant to permits issued by the EPA, was engaged
in decontamination of PCB fluids and processing of PCB-contaminated
electrical equipment for disposal including equipment sent to them by the
company. Rose ceased operations in 1986, was declared bankrupt, and did not
comply with EPA orders for site clean-up. Final clean-up activities at the
site will not begin until 1994. The Martha Rose Chemical Steering Committee
has estimated that total clean-up cost may be up to $18 million. The
company, along with 14 other steering committee members, has filed suit
against non-participating potentially liable entities to recover their
ratable share of the costs. The company has paid clean-up costs of $317,000
to-date. The Steering Committee has indicated that it has adequate funds for
clean-up, and the company anticipates that additional assessments, if any,
will not be material.
In 1988, the EPA designated the company a PRP for the clean-up of former
salvage facilities operated by B&B Salvage in Warrensburg, Missouri. The EPA
pursued recovery of costs from several PRPs, although not from the company.
The PRPs sued by the EPA in turn named the company as a Third Party
Defendant in an attempt to recover a ratable share of the costs. In April
1993, the company paid $69,000 in full settlement of its liability for the
claims asserted in that litigation.
In 1988, the 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 notified the 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 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.
DEFERRED ENERGY EFFICIENCY COSTS
Regulations in Iowa and Minnesota mandate utilities to conduct energy
efficiency programs. The company's long-term forecast anticipates that these
programs may offset the need for approximately 100 MW of generating capacity
by the year 2000. Program costs as well as an appropriate carrying cost are
deferred. The company's Minnesota rates currently recover jurisdictional
energy efficiency expenditures. Other operating expenses for 1993, 1992 and
1991 include $543,000, $604,000 and $74,000, respectively, for the
amortization of Minnesota energy efficiency costs. In July 1993, the company
filed an application with the IUB to recover energy efficiency costs through
December 31, 1992 and related costs incurred in an aggregate amount of $6.0
million. A March 1994 IUB Order allows recovery of these costs over a four-
year period. As of December 31, 1993 and 1992, amounts deferred were $9.7
million and $4.7 million, respectively. Management believes that amounts
deferred meet the criteria established by the respective commissions for
recovery as energy efficiency costs.
COMPETITION IN THE ELECTRIC INDUSTRY
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. The company's favorable rates reduce any incentive that these
customers might otherwise have to relocate, self-generate or purchase
electricity from other suppliers.
LARGE ELECTRIC CUSTOMERS
The company's six largest electric customers consumed a total of 1,621,952
MWH of electricity in 1993, which accounts for over 30 percent of total KWH
sales. These customers are involved in the production of agricultural,
chemical, and cement products and usage is generally not affected by weather
variations. Electric consumption by these customers in 1993 was 6.5 percent
over 1992, while 1992 consumption was 1.7 percent over 1991.
ORDER 636
FERC Order 636, effective in late 1993, shifted primary responsibility for
gas acquisition, transportation and peak day supply from pipelines to local
distribution companies such as the company. Although pipelines continue to
transport gas, they no longer provide sales service. The company believes it
has taken appropriate steps to ensure the continued acquisition of adequate
gas supplies at reasonable prices.
Order 636 eliminates FERC's regulation of the pipeline gas acquisition
function. Accordingly, the company anticipates increased regulatory scrutiny
at the state level. State regulators may require detailed analyses to
justify capacity and gas supply arrangements, and may perform additional
prudency reviews.
Order 636 also 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 FERC to recover
transition costs from the local distribution companies. The company
estimates its portion of transition costs will aggregate approximately $5.8
million and will be payable in declining annual installments from 1994 to
2005. The company anticipates that under customary ratemaking practices,
such transition costs will be recovered from customers.
LARGE GAS CUSTOMERS
The mix of gas firm retail sales, interruptible retail sales, firm
transportation service and interruptible transportation service has changed
significantly over the past several years. The deregulation of the gas
industry allows large industrial and commercial customers to purchase their
gas supply directly from producers and use the company's facilities
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.
Nineteen large customers currently purchase a majority of their gas
requirements from producers and and use the company's facilities to
transport the gas. Consumption for the three largest gas customers was 5.6%
over 1992, and currently accounts for approximately 65% 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
weather variations.
RATE MATTERS
The company filed an application with the IUB in September 1991 which
requested an electric rate increase of $22.4 million. Interim rates of $16.2
million were placed in effect in May 1992 subject to refund. In July 1992,
the IUB granted an annual revenue increase of $9.0 million. Revenue
collected in excess of the IUB ordered level in the amount of $3,835,000
plus $236,000 of interest was reserved in 1992 and refunded in February
1993.
On May 26, 1993, the IUB approved electric tariffs which more closely track
costs incurred by the company. Individual customers experienced an increase
or decrease in their electric bill, but the adoption of the new tariffs did
no change the company's overall revenue. The new tariffs, which were
implemented in August 1993, 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), and a lower rate during the remainder of
the year. Due to implementation of the seasonal rates, revenue for the third
and fourth quarters of 1993 is not comparable to the corresponding quarters
of prior years.
The company filed an Iowa electric rate increase application on May 14,
1993. The IUB ruled on June 4, 1993 that the company's rate design docket
approved by the IUB on May 26, 1993 constituted a change in rates. Thus,
pursuant to a section of the Iowa Code which limits a utility to one rate
application at a time, the rate filing was rejected. The company refiled in
August 1993. The revised 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, which include a provision to recover SFAS
106 costs, were placed in effect on October 28, 1993, subject to refund. A
decision on the rate increase is expected by the end of the second quarter
of 1994.
The company filed an application with the MPUC in August 1991. The
application requested an electric rate increase of $8.0 million. The MPUC
allowed an interim increase of $4.2 million effective October 1991. In June
1992, the MPUC issued an order granting an annual revenue increase of $4.9
million, and a return on common equity of 10.9%. The MPUC order stated that
the company has 100 MW of excess capacity and disallowed recovery of $1.9
million per year applicable to the excess capacity. In instances where final
rates are higher than interim rates, Minnesota law allows the utility to
recover the difference. Settlement rates, including a temporary increase to
recover the difference between the interim and final rates over a six month
period ending May 1993, were placed into effect in December 1992. In May
1993, the Minnesota Court of Appeals affirmed the MPUC order.
In June 1992, sixteen municipal wholesale customers filed a Complaint and
Request for Investigation and Hearing with FERC. The complaint alleges that
the company had been imprudent by entering into certain long-term coal
contracts, an associated transloading agreement, and a rail transportation
agreement and seeks recovery of $4 million. The issue will be presented
before an administrative law judge, with hearings currently scheduled to
commence in August 1994. The decision by the administrative law judge is
expected to be presented to the full Commission in 1995. Under this process
an appeal of the FERC decision most likely would not occur until 1996 or
later.
In November 1992, the company filed an application with the IUB for an
increase in gas rates in an annual amount of $4.1 million. Increased interim
rates were placed in effect in February 1993. Additional interim rates in an
annual amount of $263,000 were placed in effect in May 1993 after the IUB
approved the company's trust agreement arrangements for additional
postretirement benefits expense to be recognized under SFAS 106. On August
31, 1993, the IUB issued a final order allowing an annual increase of $3.3
million. Due to customers subsequently shifting to alternate tariffs, the
company estimates that it will realize an annual increase of $2.8 million.
The company anticipates filing for rate increases in 1994 in its Illinois
electric and gas jurisdictions. Such applications will seek to recover SFAS
106 costs, the costs associated with the new purchased power contracts, and
attrition due to inflation.
RESULTS OF OPERATIONS
Earnings per share of common stock were $1.73 for 1993, compared with $1.74
for 1992 and $2.84 for 1991. The return on common equity for 1993 was 8.5%,
compared with 8.4% in 1992 and 13.9% in 1991. Earnings for 1993 were
depressed by accrual of environmental clean-up costs and additional payments
to other utilities to transport electricity.
Electric sales for the past two years have been below expectations due to
relatively cool summer weather. KWH use per residential customer was 7,816;
7,341 and 8,145 for years 1993, 1992, and 1991, respectively.
Electric Sales
1993
Average 1993 1993 1992
Revenue % of Total vs. 1992 vs. 1991
per KWH KWH Sales % Change % Change
Six Largest Industrial 3.4 cents 31.9% 6.5% 1.7%
All Other Industrial 4.3 cents 25.7 5.0 4.4
Residential (Non-Heat) 7.4 cents 16.7 8.1 (9.4)
General Service (Commercial) 6.3 cents 11.9 1.3 (2.2)
Sales for Resale 3.5 cents 6.1 15.5 (12.2)
Farm 7.1 cents 3.1 (0.6) (1.0)
Residential (Electric Heat) 6.2 cents 2.2 6.6 (9.8)
All Other Categories 7.1 cents 2.4 (1.1) (4.4)
Total Company 4.9 cents 100.0% 5.8% (1.5)%
The electric "margin" is defined as revenue from all sales, less the cost of
fuel and power purchased. Electric margins for years 1993, 1992, and 1991
were $137.8 million, $135.4 million, and $143.5 million, respectively.
Electric margins for years 1993 and 1992 were negatively impacted by new
purchased power contracts which are not being completely recovered in rates
and by cool summer weather. An interim Iowa electric rate increase of $11.0
million partially offset the negative factors, but was placed in effect too
late in the year (October 28, 1993) to have a significant impact.
Gas "margin" is defined as the revenue from all sales, less purchased gas
cost. The gas margins for 1993, 1992, and 1991 were $15.4 million, $10.9
million, and $17.3 million, respectively. Major factors contributing to the
higher gas margin were the Iowa gas rate increase and heating season
temperatures. The gas margin for 1992 was depressed due to abnormally warm
weather during the heating season and the completion in January 1992 of a
gas feeder line which allowed a major customer to contract for greater
volumes of gas at a substantially lower rate.
Other operating expenses were $48.6 million, $42.4 million, and $41.8
million for 1993, 1992, and 1991, respectively. Most of the variation can be
attributed to environmental response costs and the joint use of transmission
lines. As discussed in the section entitled "Coal Tar Deposits", other
operating expenses for the years 1993, 1992, and 1991, respectively, include
$3.5 million, $1.4 million, and $2.0 million for estimated environmental
clean-up costs.
The company paid other utilities $3.0 million, $1.3 million, and $1.0
million for the joint use of transmission lines in years 1993, 1992, and
1991, respectively. The increased use of transmission lines is attributable
to capacity purchase contracts which became effective in May 1992.
Other operating expenses also include $600,000 of additional costs
applicable to the adoption of SFAS 106, "Accounting for Postretirement
Benefits Other Than Pensions". While the adoption of SFAS 106 increased
other operating expenses, it had no significant impact on net income, as the
company does not recognize the additional costs associated with SFAS 106
until rate recovery is granted for the applicable jurisdiction.
Depreciation expense was $26.3 million, $25.2 million, and $23.8 million,
for 1993, 1992, and 1991, respectively. The increase is due to increased
investment in utility plant and the approval of new depreciation rates by
the MPUC.
Property taxes were $14.5 million, $14.1 million, and $12.9 million, for
1993, 1992, and 1991, respectively. The majority of the increase is due to
an increase in Minnesota property taxes.
Allowance for Funds Used During Construction (AFUDC) was 2 cents per share
in 1993 versus 4 cents per share in 1992 and 23 cents per share in 1991.
Year-end Construction Work in Progress (CWIP) balances for 1993, 1992, and
1991 were $3.2 million, $3.5 million, and $5.5 million, respectively.
The company's investment in coal stockpiles was $17.3 million, $22.6 million
and $22.9 million at December 31, 1993, 1992 and 1991, respectively. Company
practice is to build up coal stockpiles during the summer shipping season,
and to draw down the stockpiles during the winter. Coal inventories are
lower than usual due to record Mississippi river flooding last summer, but
management anticipates that the current stockpiles will be adequate.
The natural gas industry purchases gas during off-peak periods and injects
it into underground storage. This gas is then withdrawn during peak usage
periods when gas purchases are more costly and interstate pipeline capacity
may be restricted. As a result of FERC Order 636, the company now purchases
and holds title to a greater quantity of gas. The company's investment in
gas stored underground was $4.6 million, $2.7 million and $2.2 million at
December 31, 1993, 1992 and 1991, respectively.
The Internal Revenue Service has completed audits of the company for years
through 1987. An audit of tax years through 1990 is expected to be completed
in early 1994. The company anticipates that the tax audit will not have an
adverse impact on the financial statements.
Statements of Income and Retained Earnings
For the years ended December 31
1993 1992 1991
(Thousands of Dollars)
OPERATING REVENUES (Notes 1 and 9):
Electric $255,759 $239,193 $237,231
Gas 53,709 46,105 54,574
Total operating revenues 309,468 285,298 291,805
OPERATING EXPENSES:
Operation:
Fuel for electric generation 64,059 58,283 67,911
Power purchased 53,936 45,497 25,704
Cost of gas sold 38,309 35,221 37,312
Other operating expenses 48,567 42,390 41,782
Maintenance 16,771 16,966 17,567
Depreciation and amortization 26,955 25,887 25,303
Income taxes (Note 8):
Federal currently payable 4,694 6,174 12,401
State currently payable 1,445 1,923 3,866
Deferred taxes - net 3,856 2,268 1,874
Investment tax credit amortization (1,028) (1,028) (1,028)
Property and other taxes 17,080 16,533 15,315
Total operating expenses 274,644 250,114 248,007
OPERATING INCOME 34,824 35,184 43,798
OTHER INCOME AND DEDUCTIONS:
Equity funds used during construction 68 184 926
Interest income 718 527 472
Miscellaneous 491 374 140
Income taxes (Note 8) (497) (361) (269)
Total other income and deductions 780 724 1,269
INCOME BEFORE INTEREST CHARGES 35,604 35,908 45,067
INTEREST CHARGES:
Long-term debt (Note 1) 16,166 16,292 15,120
Other interest charges 596 586 1,605
Borrowed funds used during construction (145) (187) (1,168)
Total interest charges 16,617 16,691 15,557
NET INCOME 18,987 19,217 29,510
PREFERRED AND PREFERENCE STOCK DIVIDENDS (2,861) (2,975) (3,075)
INCOME AVAILABLE FOR COMMON STOCK 16,126 16,242 26,435
RETAINED EARNINGS BEGINNING OF YEAR 60,648 63,745 56,277
DIVIDENDS ON COMMON STOCK (19,377) (19,339) (18,967)
RETAINED EARNINGS END OF YEAR $ 57,397 $ 60,648 $ 63,745
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
based on 9,316,387; 9,297,748
and 9,297,748 shares, respectively $ 1.73 $ 1.74 $ 2.84
DIVIDENDS PAID PER COMMON SHARE $ 2.08 $ 2.08 $ 2.04
The accompanying notes are an integral part of these financial statements.
Balance Sheets
ASSETS
As of December 31
1993 1992
(Thousands of Dollars)
UTILITY PLANT (Note 1):
In Service:
Electric $783,024 $762,696
Gas 59,520 54,933
842,544 817,629
Less - accumulated depreciation 358,330 339,647
484,214 477,982
Held for future use 587 587
Construction work in progress 3,163 3,487
Net utility plant 487,964 482,056
OTHER PROPERTY AND INVESTMENTS 825 645
CURRENT ASSETS:
Cash and cash equivalents 3,083 2,306
Accounts receivable, less reserves of $200 26,060 24,062
Inventories - at average cost:
Fuel 22,985 26,550
Materials and supplies 4,720 4,448
Prepaid pension cost (Note 7) 4,818 4,006
Prepaid income tax (Note 8) 7,994 3,749
Other prepayments and current assets 480 1,043
Total current assets 70,140 66,164
DEFERRED DEBITS:
Regulatory assets (Notes 7 and 8) 29,731 84
Unamortized debt expense (Note 1) 5,941 2,516
Coal contract buyout (Note 9) - 1,305
Deferred energy efficiency (Note 12) 9,665 4,660
Other 95 670
Total deferred debits 45,432 9,235
TOTAL $604,361 $558,100
The accompanying notes are an integral part of these financial statements.
Balance Sheets
CAPITALIZATION AND LIABILITIES
As of December 31
1993 1992
(Thousands of Dollars)
CAPITALIZATION, per accompanying statements:
Common stock, par value $3.50 per share;
authorized - 30,000,000 shares; issued
and outstanding - 9,389,841 in 1993 and
9,297,748 in 1992 (Note 4) $ 32,865 $ 32,542
Additional paid-in capital 99,547 97,134
Retained earnings 57,397 60,648
Total common equity 189,809 190,324
Preference stock (Note 4) - 10,092
Preferred stock (optional sinking fund) 10,819 10,819
Preferred stock (mandatory sinking fund)
(Note 4) 23,837 14,426
Long-term debt (Note 5) 203,170 193,532
Total capitalization 427,635 419,193
CURRENT LIABILITIES:
Commercial paper (Note 6) 20,100 9,000
Long-term debt maturing within one year - 6,000
Preferred stock redeemable within one year - 956
Accounts payable 11,733 12,108
Rate refund payable (Note 9) - 4,071
Dividends payable - preferred stock 599 729
Payrolls accrued 2,181 1,941
Taxes accrued 16,586 17,784
Interest accrued 3,090 4,151
Environmental clean-up cost accrued (Note 2) 5,754 2,977
Other 4,580 3,944
Total current liabilities 64,623 63,661
DEFERRED CREDITS AND OTHER NON-CURRENT
LIABILITIES:
Accumulated deferred income taxes (Note 8) 82,438 47,311
Accumulated deferred investment tax credits 20,097 21,126
Deferred pension cost (Note 7) 4,818 4,006
Accrued postretirement benefit cost (Note 7) 2,516 -
Other 2,234 2,803
Total deferred credits and other non-current
liabilities 112,103 75,246
COMMITMENTS AND CONTINGENCIES (Notes 2, 9, 10,
11 and 15)
TOTAL $604,361 $558,100
Statements of Cash Flows
For the years ended December 31
1993 1992 1991
(Thousands of Dollars)
RECONCILIATION OF NET INCOME TO CASH FLOWS
FROM OPERATING ACTIVITIES:
Net Income $18,987 $19,217 $29,510
Adjustment for non-cash items:
Depreciation and amortization 26,955 25,887 25,303
Prepaid income taxes 5,259 5,170 2,721
Investment tax credit amortization (1,028) (1,028) (1,028)
Equity funds used during construction (AFUDC) (68) (184) (926)
Prepaid pension cost 812 322 232
Changes in assets and liabilities:
Accounts receivable - net (1,998) 806 (2,459)
Inventories 3,751 884 7,168
Accounts payable and other current liabilities 3,686 2,985 448
Accrued and prepaid taxes (2,602) 381 (1,049)
Interest accrued (1,061) 230 557
Other prepayments and current assets (249) 2,788 (4,245)
Rate refund payable (4,064) 4,071 (52)
Deferred energy efficiency costs (5,005) (3,313) (1,228)
Other operating activities 1,930 1,884 1,713
Cash flows from operating activities 45,305 60,100 56,665
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (33,904) (32,104) (33,488)
Borrowed funds used during construction (AFUDC) (145) (187) (1,168)
Other (231) 925 827
Cash flows from investing activities (34,280) (31,366) (33,829)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock 2,786 - -
Issuance of preferred stock 27,250 - -
Issuance of long-term debt 94,000 25,000 25,000
Retirement of long-term debt (88,784) (30,261) (9,464)
Redemption of preferred and preference stock (25,474) (1,356) (956)
Debt and stock discount and financing expenses (8,795) (1,965) (1,059)
Dividends on common, preferred and preference
stock (22,331) (22,343) (22,063)
Sale of commercial paper - net 11,100 1,800 (13,600)
Cash flows from financing activities (10,248) (29,125) (22,142)
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS $ 777 $ (391) $ 694
CASH AND CASH EQUIVALENTS:
Beginning of year $ 2,306 $ 2,697 $ 2,003
End of year $ 3,083 $ 2,306 $ 2,697
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of interest capitalized) $17,588 $15,941 $14,742
Income taxes $8,863 $6,438 $17,592
The accompanying notes are an integral part of these financial statements.
Statements of Capitalization
As of December 31 1993 1992
(Thousands of Dollars)
COMMON EQUITY (Note 4): $189,809 44.4% $190,324 45.4%
CUMULATIVE PREFERENCE STOCK (Note 4):
Authorized 2,000,000 shares at $1.00 par
value; issued and outstanding:
$2.28 series - par value $ - $ 400
Premium on $2.28 series - 9,692
$ - -% $ 10,092 2.4%
CUMULATIVE PREFERRED STOCK (Note 4):
Authorized 2,000,000 shares at $50.00 par
value; issued and outstanding: (A)
12/31/93 Redemption
Series Shares Price
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 2.5% $ 10,819 2.6%
Mandatory sinking fund provisions:
8.00% - $ - $ 2,800
9.00% - - 5,626
9.00-A% - - 6,000
6.40% 545,000 $53.20 27,250 -
Unamortized Discount on 6.40% Preferred Stock (2,113) -
Unamortized Issuance Expense on 6.40%
Preferred Stock (111) -
Unamortized Call Premiums on Preferred Stock (1,189) -
$ 23,837 5.6% $ 14,426 3.4%
LONG-TERM DEBT (Note 5):
First Mortgage Bonds:
4 5/8% Series due 1995 $ 14,000 $ 14,000
6 1/8% Series due 1997 17,000 17,000
7 3/4% Series due 1999 - 8,000
8 5/8% Series due 2001 - 25,000
8 3/8% Series due 2002 - 13,000
8 % Series due 2007 25,000 25,000
9 % Series due 2008 - 35,000
8 5/8% Series due 2021 25,000 25,000
7 5/8% Series due 2023 94,000 -
$175,000 $162,000
Pollution Control Revenue Bonds (Due Serially):
1993 5.7 % $ - $ 225
1994 to 1998 5.95 % 6,750 6,750
1997 to 2006 7 1/4% 6,600 6,600
1998 to 2007 6 3/8% 11,400 11,400
2001 to 2009 7 1/8% 6,650 6,650
$ 31,400 $ 31,625
Other Long-Term Debt $ 127 $ 1,686
Unamortized Discount on Long-Term Debt $ (3,357) $ (1,779)
Total Long-Term Debt - net $203,170 47.5% $193,532 46.2%
TOTAL CAPITALIZATION $427,635 100.0% $419,193 100.0%
(A) 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 3.4% in 1993 and 1992, and 3.5% in
1991.
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 6.0% for 1993, 7.4% for 1992 and 8.5%
for 1991. Gross AFUDC rates are computed in accordance with FERC
regulations, including approval to incorporate deferred energy-efficiency
costs in the calculation of the debt component 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 recover them 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 energy adjustment clauses 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 customers through energy 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 1993. Such reclassifications
had no impact on net income and stockholders' equity.
2. Environmental Regulations
The company is subject to various federal and state government environmental
regulations. While the company believes that it presently meets existing air
and water regulations, the Federal Clean Air Act Amendments of 1990 will
require reductions in certain emissions from power plants. The legislation
sets two deadlines for compliance, Phase 1 (January 1, 1995) and Phase 2
(January 1, 2000). The company plans to switch to a lower sulfur coal and
install low nitrogen oxide burners at the 217 MW plant affected by Phase 1.
Additional capital expenditures of $10.9 million will be required in 1994
and 1995 to comply with emission standards. Management anticipates that
additional costs incurred will be recovered through customer rates.
The company has identified eight former coal gasification sites which may
contain hazardous waste. Four of these sites are in the investigative stage.
Cash outlays for investigative costs were $0.7 million, $0.6 million and
$0.5 million for 1993, 1992 and 1991, respectively, and $2.3 million to-
date. Estimated investigative costs of $2.0 million were expensed in 1991.
An additional $3.5 million and $1.4 million was expensed in 1993 and 1992,
respectively, for future remediation costs. There are no indications to-date
that the other four sites contain any hazardous materials and no
investigations have been conducted or ordered by the Environmental
Protection Agency. The company has recorded a liability for all known
expenses applicable to the eight sites. In January 1994, the company was
notified by an Illinois property owner of a site which contains hazardous
materials which may have come from a former manufactured gas plant.
Investigations are underway to determine if the company has any
responsibility for the site.
The company has retained an outside law firm to pursue recovery from
insurance companies of environmental remediation costs applicable to the
coal gasification sites. Neither the company nor its legal counsel is able
to predict the amount or timing of any insurance recovery, and accordingly,
no potential recovery has been recorded.
Previous actions by regulators indicate that the company will be allowed to
recover prudently incurred remediation and legal costs. It is uncertain
whether the company will recover any uninsured costs applicable to the
Rochester, Minnesota site as the company no longer serves that city.
3. Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments as of
December 31, 1993 and 1992 are shown in the table below. The estimated fair
values were determined 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 amount for 1993 excludes $1.3 million of
unamortized call premium and issuance expense.
1993 1992
(Millions of Dollars)
Carrying Fair Carrying Fair
Amount Value Amount Value
Long-term debt $203.2 $215.4 $193.5 $197.3
Preferred stock
(mandatory sinking fund) $ 25.1 $ 25.3 $ 14.4 $ 14.7
4. Preferred, Preference and Common Stock
On May 15, 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, 1993 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, 1993 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.
On June 30, 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 and 1991, the company retired the following preferred stock through
the provisions of the sinking fund:
1992 1991
Total Total
Number Redemption Number Redemption
Shares Price Shares Price
Issue Retired (Thousands) Retired (Thousands)
8.00% 7,000 $350 7,000 $350
9.00% 4,117 $206 4,117 $206
9.00%-A 16,000 $800 8,000 $400
The Dividend Reinvestment Plan acquired 60,299; 113,735 and 104,659 shares
of common stock on the open market during 1993, 1992 and 1991, respectively.
The company amended its Common Stock Dividend Reinvestment and Stock
Purchase Plan in mid-1993. The updated plan gives the company the option of
issuing new stock. The company received $2.8 million for 92,093 shares of
new common stock issued in the third and fourth quarters of 1993 under the
amended plan.
None of the authorized shares of preferred or common stock are reserved for
officers and employees, or for options, warrants, conversions, and other
rights.
5. Long-Term Debt Sinking Fund Requirements
Annual sinking fund requirements are $0.6, $0.8, $2.0, $1.8 and $1.8 million
for the years 1994 through 1998, 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 1994 through 1998 are $0.2, $14.2, $0.2, $17.4 and $6.5
million, respectively.
6. Short-Term Borrowings
The company had available bank lines of credit aggregating $39.6 million at
December 31, 1993. 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 1993, 1992 and
1991 was $20.1, $12.2 and $30.3 million, respectively, all in commercial
paper, with the average outstanding borrowing during the year of $9.4, $4.2
and $13.6 million, respectively. The average interest rate on borrowings was
3.29%, 3.56% and 6.13% for the years 1993, 1992 and 1991, respectively. At
December 31, 1993, 1992, and 1991 the interest rate was 3.36%, 3.79% and
4.58%, 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 "entry age
normal - frozen initial liability" actuarial method to the extent deductible
under tax regulations. Contributions to the plan for the years ended
December 31, 1993, 1992 and 1991 were $2.8, $0.1 and $5.1 million,
respectively. Contributions in 1991 included $2.6 million applicable to the
1992 plan year.
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: 1993 1992 1991
(Thousands of Dollars)
Service cost $ 1,888 $ 1,894 $ 1,885
Actual return on plan assets (2,214) (4,330) (5,468)
Interest cost on projected benefit
obligation 3,504 3,294 3,135
Net amortization and deferral (1,270) 1,476 2,716
Net pension cost $ 1,908 $ 2,334 $ 2,268
Discount rate for obligation 7% 8% 8%
Discount rate for expense 8% 8% 8%
Assumed rate of compensation increase 5% 6% 6%
Expected long-term rate of return 8% 8% 8%
Reconciliation of Funded Status
as of November 1:
Plan assets at fair value $48,827 $47,365 $46,498
Vested benefit obligation $34,242 $27,127 $25,721
Nonvested benefit obligation 1,728 384 1,593
Accumulated benefit obligation 35,970 27,511 27,314
Additional benefits based on
estimated future salary levels 13,872 17,855 15,233
Projected benefit obligation $49,842 $45,366 $42,547
Plan assets greater or (less) than
the projected benefit obligation $(1,015) $ 1,999 $ 3,951
Unrecognized net obligation at
October 31, 1986 being amortized
over 16.1 years 3,094 3,435 3,776
Unrecognized prior service cost 399 2,126 2,286
Unrecognized net (gain)loss 2,340 (3,554) (3,729)
Prepaid pension cost $ 4,818 $ 4,006 $ 6,284
In addition to providing pension benefits, the company provides life
insurance for retired employees and health care benefits for approximately
900 retirees and spouses. Substantially all of the company's 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 1993 is $4.9 million, compared with the pay-as-you-go
amount of $1.7 million in 1993, $1.6 million in 1992, and $1.5 million in
1991. The company is deferring 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 will be concurrent with
recovery in customer rates. Effective May 1993, the Iowa Utilities Board
(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,
subject to refund. On the basis of generic hearings or specific rate orders
issued to other utilities by the Minnesota Public Utilities Commission
(MPUC), FERC and the Illinois Commerce Commission, the company believes that
amounts deferred meet the criteria for deferral established by the Financial
Accounting Standards Board. As of December 31, 1993, $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 1993 cost of postretirement benefits would have increased by
$396,000 and the accumulated benefit obligation would increase by $3.5
million.
The following table sets forth the plan's accumulated postretirement benefit
obligation (in thousands):
December 31, 1993 January 1, 1993
Retirees $19,414 $18,781
Active plan participants 15,690 12,082
Total accumulated benefit obligation 35,104 30,863
Less fair value of plan assets 814 -
Accumulated postretirement benefit
obligation in excess of plan assets 34,290 30,863
Unrecognized net gain or (loss) (2,454) -
Unrecognized transition obligation (29,320) (30,863)
Accrued postretirement benefit cost $ 2,516 $ -
The components of the estimated cost of postretirement benefits other than
pensions for the twelve months ended December 31, 1993 are as follows (in
thousands):
Service cost $ 979
Interest cost on accrued postretirement
benefit obligation 2,383
Amortization of transition obligation 1,543
Net amortization and deferral -
Net cost $ 4,905
The assumptions used for measurement purposes are as follows:
1994 1993
Discount rate for obligations 7.0% 8.0%
Discount rate for expense 8.0% 8.0%
Initial medical cost trend rate 9.0% 13.5%
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 1998
SFAS No. 112, "Employers' Accounting for Postemployment Benefits", was
issued in November 1992. SFAS 112 addresses the treatment by employers of
salary continuation, health care benefits and life insurance to former
employees. The company's estimated SFAS 112 liability is not material.
8. Income Taxes
The company adopted SFAS No. 109, "Accounting for Income Taxes", on January
1, 1993. The new standard requires 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. For this reason, the new
standard did not have a significant effect on the income statement, but did
result in increased regulatory assets and deferred tax liabilities. The
balance sheet as of December 31, 1993 includes additional regulatory assets
and deferred tax liabilities of $27.0 million as a result of the adoption of
SFAS 109. This amount includes approximately $2.5 million resulting from a
one percent increase in the federal income tax rate. 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, 1993 balance sheet were as follows:
Item: Thousands of Dollars
Property $76,956
Energy Conservation Costs 2,782
Environmental Clean-up Costs (2,366)
Call Premiums on Reacquired Bonds 1,988
Unbilled Revenue (3,681)
Other (1,235)
Total $74,444
Gross deferred assets $(7,994)
Gross deferred liabilities 82,438
Total $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.
Income Taxes 1993 1992 1991
Federal statutory tax rate 35.0% 34.0% 34.0%
Increases (reductions) in taxes resulting from:
State income taxes net of federal income tax
benefit 4.7% 4.3% 5.5%
Investment tax credit amortization (3.6%) (3.6%) (2.2%)
Additional depreciation deducted for book
purposes 2.0% 2.2% 1.4%
Other (4.8%) (3.4%) (1.6%)
Overall effective income tax rate 33.3% 33.5% 37.1%
The current and deferred tax expense is
comprised of (Thousands):
Federal and state currently payable $ 6,139 $ 8,097 $16,267
Deferred income tax - federal and state:
Additional tax depreciation - net 3,256 3,012 2,474
Coal contract buyout (526) (149) (68)
Energy efficiency costs 1,466 773 543
Environmental clean-up (1,166) (353) (847)
Other 826 (1,015) (228)
Investment tax credit amortization (1,028) (1,028) (1,028)
Federal and state currently payable - other
income and deductions 497 361 269
Total $ 9,464 $ 9,698 $17,382
9. Rate Matters
IOWA
The company filed an application with the IUB in September 1991 which
requested an electric rate increase of $22.4 million. Interim rates of $16.2
million were placed in effect in May 1992, subject to refund. In July 1992,
the IUB granted an annual revenue increase of $9.0 million (with an
additional $1.4 million over the 12 months beginning November 1992 to
recover costs related to a coal contract buyout). Revenue collected in
excess of the IUB ordered level in the amount of $3,835,000 plus $236,000 of
interest was reserved in 1992 and refunded in February 1993.
On May 26, 1993, the IUB approved electric tariffs which more closely track
costs incurred by the company. Individual customers experienced an increase
or decrease in their electric bill, but the adoption of the new tariffs did
not change the company's overall revenue. The new tariffs, which were
implemented in August 1993, include a provision for a higher rate during the
summer cooling season, and a lower rate during the remainder of the year.
The company filed an Iowa electric rate increase application in May 1993.
The IUB ruled on June 4, 1993 that the company's rate design docket approved
by the IUB on May 26, 1993 constituted a change in rates. Thus, pursuant to
a section of the Iowa Code which limits a utility to one rate application at
a time, the rate filing was rejected. The company refiled in August 1993.
The revised 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, which include a provision to recover SFAS 106
costs, were placed in effect on October 28, 1993, subject to refund. A
decision on the rate increase is anticipated by the end of the second
quarter of 1994.
In November 1992, the company filed an application with the IUB for an
increase in gas rates in an annual amount of $4.1 million. Increased interim
rates were placed in effect in February 1993. Additional interim rates in an
annual amount of $263,000 were placed in effect in May 1993 after the IUB
approved the company's trust agreement arrangements for postretirement
benefits expense to be recognized under SFAS 106. On August 31, 1993, the
IUB issued a final order allowing an annual increase of $3.3 million. Due to
customers subsequently shifting to alternate tariffs, the company estimates
that it will realize an annual increase of $2.8 million.
MINNESOTA
The company filed an application with MPUC in August 1991 which requested an
electric rate increase of $8.0 million. The MPUC allowed an interim increase
of $4.2 million effective October 1991. In June 1992, the MPUC issued an
order granting an annual revenue increase of $4.9 million, and a return on
common equity of 10.9%. The MPUC Order held that the company has 100 MW of
excess capacity and disallowed recovery of $1.9 million per year applicable
to the excess capacity. In instances where final rates are higher than
interim rates, Minnesota law allows the utility to recover the difference.
Settlement rates, including a temporary increase to recover the difference
between the interim and final rates over a six month period ending May 1993,
were placed into effect in December 1992. In May 1993, the Minnesota Court
of Appeals affirmed the MPUC order.
FERC
In June 1992, sixteen municipal wholesale customers filed a Complaint and
Request for Investigation and Hearing with FERC. The complaint alleges that
the company had been imprudent by entering into certain long-term coal
contracts, an associated transloading agreement, and a rail transportation
agreement and seeks recovery of approximately $4 million. The issues will be
presented before an administrative law judge, with hearings currently
scheduled to commence in August 1994. The decision by the administrative law
judge is expected to be presented before the full Commission in 1995. Under
this process an appeal of the FERC decision most likely would not occur
until 1996 or later. The company believes that the complaint is without
merit.
FERC Order 636, issued April 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 associated with the implementation of the Order. The
company's pipeline suppliers filed with FERC in late 1993 to recover such
transition costs. The company estimates its portion of transition costs will
aggregate approximately $5.8 million and will be payable in declining annual
installments from 1994 to 2005. The company anticipates that under customary
regulatory practices, such transition costs will be recovered from
customers.
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, 1993 and 1992 included in utility plant were
$81.7 million and $81.4 million, respectively, and the accumulated provision
for depreciation was $36.1 million and $33.5 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 $20.1 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% (26,000 KW) interest in a 650,000 KW coal-fired
unit (Louisa #1), completed in 1983. Amounts at December 31, 1993 and 1992
included in utility plant were $24.8 million and $24.8 million,
respectively, and the accumulated provision for depreciation was $8.1
million and $7.3 million, respectively.
The company's share of direct expenses of Neal #4 and Louisa #1 are 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
approximately $24.1 million in 1993 and $16.3 million in 1992. Over the
remaining period of the contracts, total capacity payments will be
approximately $180 million.
The IUB Order in the company's 1991 rate case held that the capacity
purchases were prudent and allowed recovery of the costs in rates. The
company is currently unable to recover a portion of the purchased power
payments in its Minnesota electric jurisdiction as detailed in Note 9.
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
Iowa and Minnesota regulators have issued rules which mandate utilities to
conduct energy efficiency and demand side management programs. Each utility
anticipates recovery of program costs as well as related carrying costs
subject to a periodic prudency review by the applicable state public utility
commission. Demand side management expenditures applicable to the company's
Minnesota jurisdiction are currently being recovered through rates.
In July 1993, the company filed an application with the IUB to recover
energy efficiency costs incurred through December 31, 1992 and related costs
in an aggregate amount of $6.0 million. A March 1994 IUB Order allows
recovery of these costs over a four-year period.
Management believes that amounts deferred meet the criteria established by
the respective commissions for recovery of demand side management costs. As
of December 31, 1993 and 1992 amounts deferred were $9.7 million and $4.7
million, respectively.
13. Segments of Business
Information about the company's operations in different segments of business
for 1993, 1992 and 1991 are shown in the table below.
Electric Gas Total
(Thousands of Dollars)
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
1991
Revenue $237,231 $ 54,574 $291,805
Operating income (Before income taxes) $ 57,719 $ 3,192 $ 60,911
Depreciation and amortization expense $ 23,352 $ 1,951 $ 25,303
Capital expenditures $ 31,122 $ 4,460 $ 35,582
Utility plant - net $446,143 $ 31,600 $477,743
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. Due to the implementation of seasonal
rates in the Iowa electric jurisdiction which provide for a higher tariff
during the summer months and a lower tariff during the remaining months,
revenue for the third and fourth quarters of 1993 is not comparable to the
corresponding quarters of prior years. Because of changes in the number of
shares outstanding, the sum of quarterly earnings per common share may not
equal total earnings per share.
(Thousands of Dollars)
(Except Earnings Per Share)
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
1992 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $76,943 $68,590 $62,723 $77,042
Operating income 13,279 7,990 5,830 8,085
Net income 9,109 4,155 1,868 4,085
Earnings per share of common stock .89 .36 .12 .36
The electric margin for the fourth quarter of 1993 (revenue minus fuel and
purchased power costs) declined $1.8 million from the same period in 1992.
The fourth quarter 1993 electric margin decreased primarily due to the new
Iowa electric seasonal rates.
The gas margin for the fourth quarter of 1993 (revenue minus cost of gas
sold) was $3.5 million, compared to $2.6 million in 1992. The Iowa gas rate
increase and colder temperatures in the fourth quarter of 1993 contributed
to the improved margin.
Other operating expense for the fourth quarter of 1992 includes the accrual
of $1.4 million of estimated coal tar clean-up costs. The 1993 provisions
for clean-up costs were recorded in the first and third quarters.
Property tax expense for the fourth quarter of 1993 decreased $0.5 million
primarily due to lower assessed values in the State of Iowa.
In the fourth quarter of 1993, the MPUC approved new depreciation rates
retroactive to January 1, 1993. Adoption of the new depreciation rates
resulted in approximately $0.2 million of additional fourth quarter 1993
expense.
15. Commitments and Contingencies
The company has a coal supply contract, a rail transportation contract, and
a coal transloading agreement applicable to its Lansing Unit 4 power plant.
Such contracts, the last of which expires in 1998, require estimated minimum
future payments of $86.0 million.
The company has a natural gas supply contract, two natural gas
transportation contracts, and a natural gas storage contract, which
collectively obligate the company for a minimum annual commitment of
approximately $10.7 million. Such agreements individually expire from 1997
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
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, 1993 and 1992
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, 1993. 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, 1993 and
1992 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1993 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
Deloitte & Touche
February 3, 1994
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
1993 1992 1991 1990 1989
(Thousands of Dollars)
Operating revenues $309,468 $285,298 $291,805 $273,597 $275,550
Operation 204,871 181,391 172,709 160,206 159,564
Maintenance 16,771 16,966 17,567 15,529 16,753
Depreciation and
amortization 26,955 25,887 25,303 24,420 24,435
Income taxes 8,967 9,337 17,113 18,132 17,792
Property and other taxes 17,080 16,533 15,315 14,785 12,677
274,644 250,114 248,007 233,072 231,221
Operating income 34,824 35,184 43,798 40,525 44,329
Other income (deductions) -
net 780 724 1,269 1,429 1,526
Income before interest
charges 35,604 35,908 45,067 41,954 45,855
Interest charges 16,617 16,691 15,557 14,928 17,228
Net income 18,987 19,217 29,510 27,026 28,627
Preferred and preference
dividends 2,861 2,975 3,075 3,158 3,240
Earnings available for
common stock $ 16,126 $ 16,242 $ 26,435 $ 23,868 $ 25,387
Average number of common
shares outstanding 9,316,3879,297,748 9,297,7489,297,748 9,297,748
Earnings per common
share $ 1.73 $ 1.74 $ 2.84 $ 2.56 $ 2.73
Common dividends
declared per share $ 2.08 $ 2.08 $ 2.04 $ 2.00 $ 2.00
Total assets $604,361 $558,100 $550,631 $539,103 $513,607
Long-term debt and
mandatory sinking
fund preferred stock $227,007 $207,958 $220,818 $197,969 $208,326
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 17,091 holders of common stock and 217 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, 1991 $0.51/Share 28 3/4 - 24 7/8 9,297,748
June 30, 1991 $0.51/Share 30 3/8 - 28 3/8 9,297,748
Sept. 30, 1991 $0.51/Share 32 1/8 - 28 1/2 9,297,748
Dec. 31, 1991 $0.51/Share 34 1/4 - 31 3/8 9,297,748
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