EX-13
INTERSTATE POWER COMPANY
Annual Report to Stockholders
1995
MANAGEMENT'S DISCUSSION AND ANALYSIS
MERGER
The Company, WPL Holdings, Inc. (WPLH) and IES Industries Inc. (IES) have
entered into an Agreement and Plan of Merger (Merger Agreement), dated
November 10, 1995, providing for: a) Interstate Power Company (IPC)
becoming a wholly-owned subsidiary of WPLH and b) the merger of IES with
and into WPLH, which merger will result in the combination of IES and WPLH
as a single holding company (collectively, the Proposed Merger). The new
holding company will be named Interstate Energy Corporation (Interstate
Energy) and IES will cease to exist. The Proposed Merger, which will be
accounted for as a pooling of interests, is subject to approval by the
shareholders of each company as well as several federal and state
regulatory agencies. The companies expect to receive the shareholder
approvals in the second quarter of 1996 and the regulatory approvals by
the second quarter of 1997.
The business of Interstate Energy will consist of utility operations and
various non-utility enterprises, and it is expected that its utility
subsidiaries will serve more than 870,000 electric customers and 360,000
natural gas customers in Iowa, Illinois, Minnesota and Wisconsin.
Under the terms of the Merger Agreement, the outstanding shares of WPLH's
common stock will remain unchanged and outstanding as shares of Interstate
Energy. Each outstanding share of IES common stock will be converted to
0.98 shares of Interstate Energy's common stock. Each share of the
Company's common stock will be converted to 1.11 shares of Interstate
Energy's common stock. It is anticipated that Interstate Energy will
retain WPLH's common share dividend payment level as of the effective time
of the merger. On January 24, 1996, the Board of Directors of WPLH
declared a quarterly dividend of 49.25 cents per share. This represents an
equivalent annual rate of $1.97 per share.
WPLH is a holding company headquartered in Madison, Wisconsin, and is the
parent company of Wisconsin Power and Light Company (WP&L) and Heartland
Development Corporation (HDC). WP&L supplies electric and gas service to
approximately 377,000 and 146,000 customers, respectively, in south and
central Wisconsin. HDC and its principal subsidiaries are engaged in
businesses in three major areas: environmental engineering and consulting,
affordable housing and energy services.
IES is a holding company headquartered in Cedar Rapids, Iowa, and is the
parent company of IES Utilities Inc. (Utilities) and IES Diversified Inc.
(Diversified). Utilities supplies electric and gas service to
approximately 333,000 and 174,000 customers, respectively, in Iowa.
Diversified and its principal subsidiaries are primarily engaged in the
energy-related, transportation and real estate development businesses.
Interstate Energy will be the parent company of Utilities, WP&L and IPC
and will be registered under the Public Utility Holding Company Act of
1935 (1935 Act), as amended. The merger agreement provides that these
operating utility companies will continue to operate as separate entities
for a minimum of three years beyond the effective date of the merger. In
addition, the non-utility operations of IES and WPLH will be combined
shortly after the effective date of the merger under one entity to manage
the diversified operations of Interstate Energy. The corporate
headquarters of Interstate Energy will be in Madison.
The Securities and Exchange Commission (SEC) historically has interpreted
the 1935 Act to preclude registered holding companies, with limited
exceptions, from owning both electric and gas utility systems. Although
the SEC has recently recommended that registered holding companies be
allowed to hold both gas and electric utility operations if the affected
states agree, it remains possible that the SEC may require as a condition
to its approval of the Proposed Merger that the Company, WPLH and IES
divest their gas utility properties, and possibly certain non-utility
ventures of IES and WPLH, within a reasonable time after the effective
date of the Proposed Merger.
Legislation to repeal the 1935 Act was introduced in Congress in 1995 and
is pending. No assurance can be given as to when or if such legislation
will be considered or enacted. The Staff of the SEC has also recommended
that the SEC "permit combination systems by registered holding companies
if the affected states concur", and the SEC has proposed rules that would
relax current restrictions on investment by registered holding companies
in certain "energy related", non-utility businesses. No prediction can be
made as to the outcome of these legislative and regulatory proposals.
LIQUIDITY AND CAPITAL RESOURCES
Cash flow from operating activities was $61 million in 1995. The funds
were primarily used to pay the company's construction program, to redeem
$14 million of 4 5/8% First Mortgage Bonds which matured, and to pay
common and preferred dividends. It is management's opinion that the
company has adequate access to capital markets and will be able to satisfy
anticipated capital requirements.
Construction expenditures were $29, $41 and $34 million in 1995, 1994 and
1993, respectively. For the five year period from 1996 through 2000,
construction expenditures are estimated to be $180 million. The company
anticipates that approximately 75% of the construction funds for years
1996 and 1997 will be generated internally. The 1996 and 1997 construction
programs are estimated to be $32 and $36 million, respectively. Budgeted
construction expenditures for 1997 and 1998 include approximately $14
million for a baghouse/precipitator at the Lansing unit #4 plant to comply
with the Clean Air Act.
The company has authorization from the Federal Energy Regulatory
Commission (FERC) to issue up to $70 million in short-term debt. At year
end 1995, a $55 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 1995, the company had $39.3 million
of commercial paper payable. The company projects that the short-term debt
will decline to $36 million at year end 1996.
At December 31, 1995, 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 $200 million of
additional first mortgage bonds. The company's fixed charge coverage ratio
was 3.7 times for 1995 and 2.7 times for 1994 and 1993.
The company's stock price increased from $23.75 at year end 1994 to
$33.125 at year end 1995. 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 anticipates that it will resume the issuance of new stock to
satisfy Dividend Reinvestment and Stock Purchase Plan requirements in the
third quarter of 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.
NEW ACCOUNTING STANDARD - SFAS 121
The Company will be required to adopt Statement of Financial Accounting
Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" in 1996. The new
standard imposes stricter standards for regulatory assets by requiring
that such assets be probable of future recovery at each balance sheet
date. The company believes that the initial adoption of SFAS 121 will not
have a material impact on its financial position or results of operations.
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 255 MW of
capacity 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, $24.6 and $24.1 million in 1995, 1994 and 1993,
respectively. Over the remaining life of the contracts, total capacity
payments will be approximately $130 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.
The rate structure approved by the Minnesota Public Utilities Commission
(MPUC) does not provide for full recovery of purchased power costs
applicable to the Minnesota jurisdiction. A 1992 rate order by the MPUC
held that the company had 100 MW of excess capacity. The company is
seeking to adjust this disallowance in its current rate case.
The company has not filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and FERC jurisdictions. The
payments of approximately $2.5 million annually are expensed as incurred.
CLEAN AIR ACT
The company meets the existing federal and state environmental
regulations. The Federal Clean Air Act Amendments of 1990 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. To comply with Phase 1, the
company has switched 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.
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. The company has identified nine sites
which may contain hazardous waste from former coal gasification plants and
has recorded an estimated liability for its pro rata share of expenses
applicable to the sites.
Previous actions by Iowa, Illinois and Minnesota regulators have permitted
utilities to recover prudently incurred unreimbursed investigation and
remediation costs.
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. In 1995, a settlement was reached with KCPL for sharing of costs
to remediate the site. A Remedial Investigation and Feasibility Study has
been approved and the company has assumed responsibility for managing the
remediation of the Mason City site. The current estimated cost of soil
remediation is $2.6 million, which will be paid by KCPL.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post-remediation
groundwater monitoring is underway. From 1991 through 1995, the company
incurred costs aggregating $6.7 million applicable to the Rochester site.
In addition to the Rochester site, the company owned or operated four
other manufactured gas plant sites in Minnesota: Albert Lea, Austin, New
Ulm and Owatonna. Potentially hazardous wastes associated with former coal
gasification operations have been identified at each site. The company
anticipates that these sites will be investigated in 1996 or 1997. When
the investigation process is complete, the company will be able to
determine if any remediation will be necessary.
In April 1995, the company received an accounting order from the MPUC
which allows the deferral of investigation and remediation costs
applicable to the Rochester and Albert Lea sites and further allows the
company to seek recovery in a rate case. The company's Minnesota gas rate
case filed in May 1995 seeks recovery of $4.9 million. The company filed a
petition in June 1995 for an accounting order which would allow it to
defer and seek recovery in a future rate case the costs applicable to the
three other Minnesota sites (Austin, Owatonna and New Ulm). Action by the
MPUC is pending.
In addition, the company has identified three other sites: Galena and
Savanna, Illinois, and Clinton, Iowa. Potentially hazardous wastes
associated with former coal gasification operations have been identified
at each of these sites. Little or no activity is expected at any of these
sites in 1996.
In 1994, the company filed a lawsuit against certain of its insurers to
recover the costs of investigating and remediating the former coal
gasification plants. Two insurers paid the company a total of $0.3 million
in 1995 in order to be discharged from the lawsuit. The trial against the
remaining insurers is expected to begin in Iowa in 1997. 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.
LARGE ELECTRIC CUSTOMERS
The company's six largest electric customers consumed a total of 1,752,340
MWH of electricity in 1995, which accounts for over 32 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
weather variations. The company is not aware of any plan by these
customers to significantly reduce consumption. Electric consumption by
these customers increased 4.9 percent over 1994, while 1994 consumption
was 3.0 percent over 1993. The aggregate 1995 rate for these customers was
approximately 3.4 cents per KWH.
DEMAND SIDE MANAGEMENT COSTS
Regulations in Iowa and Minnesota require that utilities conduct demand
side management or energy efficiency programs. The company's long-term
forecast projects that these programs may offset the need for
approximately 150 MW of generating capacity by the year 2001. Program
costs and related carrying costs are deferred pending regulatory prudency
reviews.
The company's Minnesota rates recover jurisdictional demand side
management expenditures and lost revenues. Other operating expenses for
1995, 1994 and 1993 include $0.6, $0.5 and $0.5 million, respectively, for
the amortization of Minnesota demand side management costs. A 1994 Iowa
Utilities Board (IUB) Order allows recovery of $6.7 million of deferred
Iowa demand side management costs incurred through 1992 over a four year
period; such recovery began October 1994. Other operating expenses for
1995 and 1994 include $1.2 and $0.3 million, respectively, for the
amortization of Iowa demand side management costs. As of December 31, 1995
and 1994, the total demand side management costs deferred were $23.1 and
$17.0 million, respectively. Of the $23.1 million deferred, approximately
$19.8 million relates to demand side management costs incurred in 1995,
1994 and 1993. The company anticipates filing in Iowa in 1996 for recovery
of costs incurred through 1995. Management believes that the amounts
deferred meet the criteria established for recovery as demand side
management costs.
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.
Order 636 provides a mechanism under which pipelines can recover prudently
incurred transition costs associated with the restructuring process. The
company paid $2.0 million of transition costs in 1995 and is currently
recovering these costs from customers through the purchased gas adjustment
clause. 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 $3.2 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. Twenty-one large customers currently purchase
a majority of their gas requirements from producers or gas marketers.
Consumption for the three largest gas customers was up 4.4% over 1994 and
currently accounts for approximately 66% of system throughput. The
company's largest gas customer, which represents 31% of the company's
total gas throughput, is committed by contract for the next six years.
GAS SYSTEM PROFITABILITY
Over the last five years, gas operating income before income taxes has
averaged 5.5% of net gas utility plant. Environmental remediation costs,
unfavorable rate treatment and the offering of incentive rates contributed
to the low return. The company is seeking recovery of environmental
remediation costs from insurance as well as through rates.
RATE MATTERS
The company filed for rate increases in 1995 in the Iowa electric, Iowa
gas, Minnesota electric, and Minnesota gas jurisdictions. Such
applications seek to recover the costs associated with the purchased power
contracts, the environmental clean-up of former manufactured gas plant
sites, jurisdictional post-retirement benefit costs, an increased return
on common equity and attrition due to inflation.
The company filed an Iowa electric rate increase application in March
1995. The application requested an annual increase of $13.1 million.
Interim rates in an annual amount of $7.1 million were placed in effect on
June 29, 1995, subject to refund. A December 1995 IUB Order allowed an
annual increase of $6.6 million, including a return on common equity of
11.35%. In 1996, the company will refund to customers approximately
$250,000 collected in 1995 in excess of the final order. The 1995
financial statements include a provision for the refund.
The company filed an Iowa gas rate increase application in August 1995.
The application requested an annual increase of $2.2 million. Interim
rates in an annual amount of $1.3 million were placed in effect on October
20, 1995, subject to refund. The company and other parties to the rate
application have agreed on an increase of $1.1 million subject to approval
by the IUB. An IUB Order is expected by June 1996.
The company filed a Minnesota electric rate increase application in June
1995. The application requested an annual increase of $4.6 million (later
adjusted by the company to $3.3 million). Interim rates were not
requested. A MPUC Order is expected by April 1996.
The company filed a Minnesota gas rate increase application in May 1995.
The application requested an annual increase of $2.4 million, including a
return on common equity of 11.75%. Interim rates in an annual amount of
$1.5 million were placed in effect in June 1995, subject to refund. A MPUC
Order is expected by March 1996.
As discussed under Demand Side Management Costs, the company anticipates
filing in 1996 for recovery of Iowa demand side management costs incurred
in 1995, 1994 and 1993.
RESULTS OF OPERATIONS
The company's results of operations and financial condition are affected
by numerous factors, including weather, general economic conditions and
rate changes.
Earnings per share of common stock were $2.63 for 1995, compared with
$1.92 for 1994 and $1.73 for 1993. Hot summer weather, electric and gas
rate increases and cost cutting efforts contributed to the increased
earnings. The 1995 return on common equity was 13.0%, compared with 9.5%
for 1994 and 8.5% in 1993.
Electric retail sales for 1995 were unusually high primarily because of
warm and humid weather during the air conditioning season. KWH use per
residential customer was 8,280; 7,799 and 7,816 for years 1995, 1994 and
1993, respectively.
Electric "margin" is defined as electric revenue less the cost of fuel and
power purchased. Electric margins for years 1995, 1994 and 1993 were
$155.1, $142.0 and $137.8 million, respectively. The hot summer weather
boosted the 1995 electric margin for residential sales by approximately
$3.6 million. The Iowa electric rate increase implemented in June 1995
increased the electric margin by approximately $3.6 million.
Gas "margin" is defined as gas revenue less purchased gas cost. The gas
margins for 1995, 1994 and 1993 were $17.8, $15.0 and $15.4 million,
respectively. An increase in residential and transportation gas volumes of
2.3% and 7.8%, respectively, contributed to the higher gas margin. In
addition, interim rate increases in the Minnesota and Iowa gas rate cases
contributed $0.6 and $0.3 million, respectively.
Other operating expenses, excluding a MPUC deferred accounting order, were
$51.1, $51.9 and $48.6 million for 1995, 1994 and 1993, respectively.
Other operating expenses for 1995 include $1.5 million of merger and
strategic planning expenses. Other operating expenses for the years 1995,
1994 and 1993, include $1.0, $1.8 and $3.8 million, respectively, for
environmental investigation, remediation and litigation costs.
Maintenance expense for 1995 was $14.9 million, compared to $17.2 million
in 1994 and $16.8 million in 1993. The reduction is primarily due to cost
cutting efforts.
Depreciation expense was $29.3, $27.8 and $26.3 million, for 1995, 1994
and 1993, respectively. The increase is primarily due to additional
investment in pollution control equipment and the implementation of higher
depreciation rates approved by the MPUC.
Property taxes were $13.4, $13.7 and $14.5 million, for 1995, 1994 and
1993, respectively. The majority of the decline is applicable to a
decrease in assessed values in the state of Iowa.
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 $14.8, $15.4 and $16.2 million for 1995,
1994 and 1993, respectively. The decline is attributable to a 1994
Pollution Control Bond refinancing, as well as the maturity of $14 million
of 4 5/8% First Mortgage Bonds on May 1, 1995, and the 1993 maturity of $6
million of 4 3/8% First Mortgage Bonds. The percentage of total
capitalization attributable to long-term debt has declined from 45.4% at
year end 1994 to 44.8% at year end 1995.
Other interest charges for 1995 were $2.3 million, compared with $1.8
million for 1994 and $0.6 million for 1993. Interest on commercial paper
payable was $2.1, $0.7 and $0.3 million for 1995, 1994 and 1993,
respectively. The increased commercial paper interest expense is primarily
attributable to a higher average balance outstanding. At year end 1995,
the company had $39.3 million of short-term commercial paper payable,
compared with $35.6 million at year end 1994.
The company's investment in coal stockpiles was $15.8 million at December
31, 1995 and $19.4 million at December 31, 1994. Refinements to the
company's fuel delivery process have decreased the amount of inventory
required to carry the company over the winter.
The company's investment in gas stored underground was $2.4, $3.7 and $4.6
million at December 31, 1995, 1994 and 1993, respectively. The decline is
attributable to low gas prices during the summer injection season of 1995
and the cancellation of a storage service which had been used in the prior
two years.
Gas Sales 1995 MCF VOLUMES
Average 1995
Revenue 1995 vs. 1994
per MCF % of Total % Change
Three Largest Transportation $0.07 66.3% 4.4%
All Other Transportation 0.32 8.4 45.3
Residential 5.13 13.7 2.3
Commercial 4.31 8.0 1.0
Industrial 3.24 3.2 (28.2)
Other 2.91 0.4 144.3
100.0% 5.0%
Electric Sales 1995 KWH SALES
Average 1995 1994
Revenue 1995 vs. 1994 vs. 1993
per KWH % of Total % Change % Change
Six Largest Industrial 3.4 cents 32.3% 4.9% 3.0%
All Other Industrial 4.4 cents 27.4 4.6 8.9
Residential (Non-Heat) 7.6 cents 17.3 9.0 2.1
General Service (Commercial) 6.3 cents 10.7 1.4 (5.8)
Sales for Resale 3.6 cents 5.6 (36.0) 53.6
Farm 7.7 cents 2.9 0.1 (0.9)
Residential (Electric Heat) 6.4 cents 2.0 1.4 (4.3)
All Other Categories 7.8 cents 1.8 (8.9) (11.1)
Total Company 5.0 cents 100.0% 1.0% 5.8%
Statements of Income and Retained Earnings
For the years ended December 31 1995 1994 1993
(Thousands of Dollars)
OPERATING REVENUES:
Electric $274,873 $261,730 $255,759
Gas 43,669 45,920 53,709
Total operating revenues 318,542 307,650 309,468
OPERATING EXPENSES:
Operation:
Fuel for electric generation 62,164 61,384 64,059
Power purchased 57,566 58,339 53,936
Cost of gas sold 25,888 30,905 38,309
Other operating expenses 45,717 51,917 48,567
Maintenance 14,881 17,160 16,771
Depreciation and amortization 29,560 28,212 26,955
Income taxes:
Federal current 11,608 1,395 4,694
State current 3,549 454 1,445
Deferred taxes - net 6,506 7,092 3,856
Investment tax credit amortization (1,028) (1,028) (1,028)
Property and other taxes 15,990 16,298 17,080
Total operating expenses 272,401 272,128 274,644
OPERATING INCOME 46,141 35,522 34,824
OTHER INCOME AND DEDUCTIONS (1,690) 1,990 780
INCOME BEFORE INTEREST CHARGES 44,451 37,512 35,604
INTEREST CHARGES:
Long-term debt 14,811 15,405 16,166
Other interest charges 2,325 1,772 596
Borrowed funds used during construction (341) (332) (145)
Total interest charges 16,795 16,845 16,617
NET INCOME 27,656 20,667 18,987
PREFERRED AND PREFERENCE STOCK DIVIDENDS (2,458) (2,454) (2,861)
INCOME AVAILABLE FOR COMMON STOCK 25,198 18,213 16,126
RETAINED EARNINGS BEGINNING OF YEAR 55,893 57,397 60,648
DIVIDENDS ON COMMON STOCK (19,941) (19,717) (19,377)
RETAINED EARNINGS END OF YEAR $ 61,150 $ 55,893 $ 57,397
EARNINGS PER AVERAGE COMMON SHARE
OUTSTANDING based on 9,564,287;
9,478,741 and 9,316,387 shares,
respectively $ 2.63 $ 1.92 $ 1.73
DIVIDENDS PAID PER COMMON SHARE $ 2.08 $ 2.08 $ 2.08
The accompanying notes are an integral part of these financial statements.
Balance Sheets
ASSETS
As of December 31
1995 1994
(Thousands of Dollars)
UTILITY PLANT:
In Service:
Electric:
Production $374,489 $369,828
Transmission 183,858 178,891
Distribution 221,645 211,731
General 54,232 50,460
Total Electric 834,224 810,910
Gas 63,303 61,447
897,527 872,357
Less - accumulated depreciation 402,685 379,216
494,842 493,141
Held for future use 590 592
Construction work in progress 3,095 6,948
Net utility plant 498,527 500,681
OTHER PROPERTY AND INVESTMENTS 555 522
CURRENT ASSETS:
Cash and cash equivalents 1,537 1,537
Accounts receivable, less reserves of $200 27,797 22,350
Inventories - at average cost:
Fuel 19,332 24,220
Materials and supplies 5,509 5,208
Prepaid pension cost 3,870 3,702
Prepaid income tax 6,690 6,197
Other prepayments and current assets 614 2,252
Total current assets 65,349 65,466
DEFERRED DEBITS:
Regulatory assets 62,841 54,958
Unamortized debt expense 5,915 6,116
Other 1,129 1,102
Total deferred debits 69,885 62,176
TOTAL $634,316 $628,845
The accompanying notes are an integral part of these financial statements.
Balance Sheets
CAPITALIZATION AND LIABILITIES
As of December 31
1995 1994
(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 1995 and 1994 $ 33,475 $ 33,475
Additional paid-in capital 103,145 103,137
Retained earnings 61,150 55,893
Total common equity 197,770 192,505
Preferred stock (optional sinking fund) 10,819 10,819
Preferred stock (mandatory sinking fund) 24,036 23,933
Long-term debt 188,880 189,032
Total capitalization 421,505 416,289
CURRENT LIABILITIES:
Commercial paper 39,300 35,600
Long-term debt maturing within one year - 14,000
Accounts payable 11,868 14,133
Dividends payable - preferred stock 599 599
Payrolls accrued 2,846 2,634
Taxes accrued 16,758 13,778
Interest accrued 2,819 2,930
FERC Order 636 transition costs 3,200 5,200
Other 4,756 2,878
Total current liabilities 82,146 91,752
DEFERRED CREDITS AND OTHER NON-CURRENT
LIABILITIES:
Accumulated deferred income taxes 95,518 88,176
Accumulated deferred investment tax credits 18,041 19,069
Deferred pension cost 4,900 4,827
Accrued postretirement benefit cost 2,792 2,869
Environmental clean-up costs 6,860 3,470
Other 2,554 2,393
Total deferred credits and other non-current
liabilities 130,665 120,804
COMMITMENTS AND CONTINGENCIES
TOTAL $634,316 $628,845
Statements of Cash Flows
For the years ended December 31
1995 1994 1993
(Thousands of Dollars)
RECONCILIATION OF NET INCOME TO CASH FLOWS
FROM OPERATING ACTIVITIES:
Net Income $27,656 $20,667 $18,987
Adjustment for non-cash items:
Depreciation and amortization 29,560 28,212 26,955
Deferred income taxes 6,912 5,488 5,259
Investment tax credit amortization (1,028) (1,028) (1,028)
Equity funds used during construction (AFUDC) - (166) (68)
Prepaid pension cost 74 9 812
Changes in assets and liabilities:
Accounts receivable - net (5,447) 3,710 (1,998)
Inventories 4,599 (1,536) 3,751
Accounts payable and other current liabilities (6,415) 4,324 3,686
Accrued and prepaid taxes 2,379 (1,011) (2,602)
Interest accrued (111) (160) (1,061)
Other prepayments and current assets 1,469 (656) (249)
Rate refund payable 256 - (4,064)
Regulatory assets - deferred demand side
management costs (6,177) (7,295) (5,005)
Regulatory assets - other 4,263 (8,267) -
Other operating activities 3,275 721 1,930
Cash flows from operating activities 61,265 43,012 45,305
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (28,238) (40,600) (33,904)
Borrowed funds used during construction (AFUDC) (341) (332) (145)
Other 137 (658) (231)
Cash flows from investing activities (28,442) (41,590) (34,280)
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
Retirement of long-term debt (14,235) (13,487) (88,784)
Redemption of preferred and preference stock - - (25,474)
Debt and stock discount and financing expenses - (357) (8,795)
Dividends on common, preferred and preference
stock (22,288) (22,111) (22,331)
Sale of commercial paper - net 3,700 15,500 11,100
Cash flows from financing activities (32,823) (2,968) (10,248)
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS $ - $(1,546) $ 777
CASH AND CASH EQUIVALENTS:
Beginning of year $ 1,537 $ 3,083 $ 2,306
End of year $ 1,537 $ 1,537 $ 3,083
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of interest capitalized) $16,655 $16,773 $17,588
Income taxes $11,134 $ 8,066 $ 8,863
The accompanying notes are an integral part of these financial statements.
Statements of Capitalization
As of December 31 1995 1994
(Thousands of Dollars)
COMMON EQUITY $197,770 46.9% $192,505 46.2%
CUMULATIVE PREFERRED STOCKS:
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 2.6%
Preferred with mandatory sinking fund provisions:
6.40% 545,000 $53.20 27,250 27,250
Unamortized Discount on 6.40% Preferred Stock (1,990) (2,053)
Unamortized Issuance Expense on 6.40%
Preferred Stock (104) (108)
Unamortized Call Premiums on Preferred Stock (1,120) (1,156)
24,036 5.7% 23,933 5.8%
LONG-TERM DEBT:
First Mortgage Bonds:
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
161,000 161,000
Pollution Control Revenue Bonds:
5.95% due 1996 to 1998 6,300 6,525
6 3/8% due 1998 to 2007 11,400 11,400
5.75% due 2003 1,000 1,000
6.25% due 2009 1,000 1,000
6.30% due 2010 5,600 5,600
6.35% due 2012 5,650 5,650
30,950 31,175
Other Long-Term Debt 104 115
Unamortized Discount on Long-Term Debt (3,174) (3,258)
Total Long-Term Debt - net 188,880 44.8% 189,032 45.4%
TOTAL CAPITALIZATION $421,505 100.0% $416,289 100.0%
(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 company is an operating public utility engaged primarily in the
generation, transmission, distribution and sale of electricity. The
company also distributes and sells natural gas. The company is subject to
seasonal variations common to the utility industry.
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 1995 and 1994 and 3.4% in
1993.
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. It was capitalized at gross rates of
6.0% for 1995, 6.3% for 1994 and 6.0% for 1993. Gross AFUDC rates are
computed in accordance with the FERC regulations, including approval to
incorporate demand side management costs in 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 a fuel adjustment clause 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.
REGULATORY ASSETS
Regulatory assets represent probable future revenue associated with
certain incurred costs. 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".
Regulatory assets of $62.8 million are classified as deferred debits on
the balance sheet. Deferred income taxes, environmental clean-up costs and
FERC Order 636 transition costs have corresponding deferred credits.
Demand side management costs (DSM) and Minnesota deferred employee/retiree
benefits do not have corresponding liabilities. Regulators allow the
company to earn a return on DSM costs, but not on the other regulatory
assets.
At December 31, 1995, regulatory assets were as follows:
Regulatory Assets
(Millions of Dollars)
Deferred income taxes (Note 9) $27.8
Deferred demand side management (Note 12) 23.1
Environmental clean-up (Note 2) 6.2
FERC Order No. 636 transition costs (Note 8) 3.2
Employee/retiree benefits (Note 7) 2.4
Other 0.1
Total $62.8
NEW ACCOUNTING STANDARD
The company will be required to adopt SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" in 1996. The new standard imposes stricter standards for regulatory
assets by requiring that such assets be probable of future recovery at
each balance sheet date. The company believes that the initial adoption of
SFAS 121 will not have a material impact on its financial position or
results of operations.
SIGNIFICANT ESTIMATES
Significant estimates used in the preparation of the accompanying
financial statements include environmental remediation costs, depreciation
and projection of future employee pension and medical benefits. Such
estimates are based on informed judgement with appropriate consideration
to materiality. In the opinion of management, the financial statements
fairly state the company's financial position and the results of
operations.
CONCENTRATION OF SALES
The company provides service to six large electric customers which account
for over 32% of electric MWH sales. The company provides transportation
service to three large gas customers, which account for 66% of system
throughput. The company does not take title to the gas consumed by these
transportation customers. The Management's Discussion and Analysis section
of the Annual Report provides additional information regarding these large
electric and gas customers.
In addition, the company provides electric service to 163,394 electric
customers in 234 communities and 48,823 gas customers in 39 communities.
Credit risk for these customers is spread over a diversified base of
residential, commercial and small industrial customers.
RECLASSIFICATIONS
Certain reclassifications have been made to the prior years financial
statements to conform with the presentation for 1995. Such
reclassifications had no impact on net income or stockholders' equity.
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 requires reductions in certain
emissions from power plants. The company has switched to a low sulfur coal
and installed low nitrogen oxide burners at the 217 MW plant affected by
Phase 1, which became effective January 1, 1995. Management anticipates
that additional costs incurred to comply with Phase 2 environmental
standards, which take effect January 1, 2000, will be recovered through
customer rates.
The company has identified nine sites which may contain hazardous waste
from former coal gasification plants and has recorded an estimated
liability for its pro rata share of expenses applicable to the sites.
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. In 1995, a settlement was reached with KCPL for sharing of costs
to remediate the site. A Remedial Investigation and Feasibility Study has
been approved and the company has assumed responsibility for managing the
remediation of the Mason City site. The current estimated cost of soil
remediation is $2.6 million, which will be paid by KCPL.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post-remediation
groundwater monitoring is underway. From 1991 through 1995, the company
incurred costs aggregating $6.7 million applicable to the Rochester site.
In addition to the Rochester site, the company owned or operated four
other manufactured gas plant sites in Minnesota: Albert Lea, Austin, New
Ulm and Owatonna. Potentially hazardous wastes associated with former coal
gasification operations have been identified at each site. The company
anticipates that these sites will be investigated in 1996 or 1997. When
the investigation process is complete, the company will be able to
determine if any remediation will be necessary.
In April 1995, the company received an accounting order from the Minnesota
Public Utilities Commission (MPUC) which allows the deferral of
investigation and remediation costs applicable to the Rochester and Albert
Lea sites and further allows the company to seek recovery in a rate case.
The company's Minnesota gas rate case filed in May 1995 seeks recovery of
$4.9 million. The company filed a petition in June 1995 for an accounting
order which would allow it to defer and seek recovery in a future rate
case of costs applicable to the three other Minnesota sites (Austin,
Owatonna and New Ulm). Action by the MPUC is pending.
In addition, the company has identified three other sites: Galena and
Savanna, Illinois, and Clinton, Iowa. Potentially hazardous wastes
associated with former coal gasification operations have been identified
at each of these sites. Little or no activity is expected at any of these
sites in 1996.
In 1994, the company filed a lawsuit against certain of its insurers to
recover the costs of investigating and remediating the former coal
gasification plants. Two insurers paid the company a total of $0.3 million
in 1995 in order to be discharged from the lawsuit. The trial against the
remaining insurers is expected to begin in Iowa in 1997. 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 unreimbursed investigation and
remediation costs.
3. Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments at year
end 1995 and 1994 did not vary significantly from their carrying values.
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.
4. Preferred, Preference and Common Stock
In 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 $2.1 million as of year end 1995 are reflected as an offset to
preferred stock and are being amortized to common equity.
Call premiums related to the 1993 retirement of the preferred and
preference stock in the amount of $1.1 million as of year end 1995 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 to common equity over the life of the refunding 6.40%
issue, but has no effect on net income.
In 1993, the company retired preferred and preference stock as follows:
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
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 176,971; 44,868
and 60,299 shares of common stock on the open market during 1995, 1994 and
1993, 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 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
On May 1, 1995, $14 million of 4 5/8% First Mortgage Bonds matured. Total
debt maturities for the years 1996 through 2000 are $0.2, $17.2, $6.3,
$0.4 and $0.4 million, respectively.
Annual sinking fund requirements are $2.0, $1.8, $1.8, $1.8 and $1.8
million for the years 1996 through 2000, respectively. Such sinking fund
requirements for first mortgage bonds may be satisfied with property
additions at the rate of 167% of such requirements. Sinking fund
requirements for 1995 were met by property additions.
6. Short-Term Borrowings
The company had available bank lines of credit aggregating $55.0 million
at December 31, 1995. 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 1995, 1994
and 1993 was $46.8, $35.6 and $20.1 million, respectively, all in
commercial paper, with the average outstanding borrowing during the year
of $36.2, $15.6 and $9.4 million, respectively. The average interest rate
on borrowings was 5.96%, 4.73% and 3.29% for the years 1995, 1994 and
1993, respectively. At December 31, 1995, the interest rate was 5.85%.
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,
1995, 1994 and 1993 were $3.4, $3.4 and $2.8 million, respectively. In
addition to the pension plan, the company has a non-qualified supplemental
retirement plan which, as amended in 1995, provides a retirement benefit
for 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 cumulative difference
between the higher funded amount and the accounting pension cost amount is
a deferred credit on the balance sheet.
Pension Cost Components: 1995 1994 1993
(Thousands of Dollars)
Service cost $ 2,369 $ 2,668 $ 1,888
Return on plan assets (3,335) (1,707) (2,214)
Interest cost on projected benefit
obligation 3,778 3,710 3,504
Net amortization and deferral 196 (953) (1,270)
Net pension cost $ 3,008 $ 3,718 $ 1,908
The assumptions used for measurement purposes are as follows:
Discount rate for obligation 7.5% 7.5% 7.0%
Discount rate for expense 7.5% 7.0% 8.0%
Assumed rate of compensation increase 5.0% 5.0% 5.0%
Expected long-term rate of return 8.0% 7.0% 8.0%
Reconciliation of Funded Status
as of November 1:
Plan assets at fair value $49,568 $49,282 $48,827
Vested benefit obligation $35,024 $36,626 $34,242
Nonvested benefit obligation 1,970 2,365 1,728
Accumulated benefit obligation 36,994 38,991 35,970
Additional benefits based on
estimated future salary levels 16,972 13,547 13,872
Projected benefit obligation $53,966 $52,538 $49,842
Plan assets greater or (less) than
the projected benefit obligation $(4,398) $(3,256) $(1,015)
Unrecognized net obligation at
October 31, 1986, being amortized
over 16.1 years 2,412 2,753 3,094
Unrecognized prior service cost 911 3,487 399
Unrecognized net (gain)loss 4,945 718 2,340
Net prepaid pension cost $ 3,870 $ 3,702 $ 4,818
In addition to providing pension benefits, the company provides life
insurance for retired employees and health care benefits for 930 retirees
and spouses. Substantially all of the company's 902 full-time employees
and spouses become eligible for benefits if they reach retirement age
while working for the company. The estimated future cost of providing
these postretirement benefits is accrued during the employees' service
periods, and was $4.1, $4.9 and $4.9 million for 1995, 1994 and 1993,
respectively. Funding of the benefit obligation is concurrent with
recovery in customer rates. Plan assets consist of high-grade debt
securities. Assuming a one percent increase in the medical cost trend
rate, the company's 1995 cost of postretirement benefits would increase by
$0.5 million and the accumulated benefit obligation would increase by $4.1
million.
The table below sets forth the postretirement health care plan's
accumulated benefit obligation (in thousands):
December 31, 1995 January 1, 1995
Retirees $21,168 $18,902
Active plan participant 13,141 12,642
Total accumulated benefit obligation 34,309 31,544
Less fair value of plan assets 6,640 4,072
Accumulated postretirement benefit
obligation in excess of plan assets 27,669 27,472
Unrecognized net gain or (loss) 812 1,756
Unrecognized transition obligation (23,991) (25,253)
Accrued postretirement benefit cost $ 4,490 $ 3,975
The components of the estimated cost of postretirement benefits other than
pensions for the twelve months ended December 31, 1995 and 1994, are as
follows (in thousands):
1995 1994
Service cost $1,097 $1,205
Return on plan assets (440) (48)
Interest cost on accrued postretire-
ment benefit obligation 2,291 2,345
Amortization of transition obligation 1,543 1,543
Net amortization and deferral (377) (159)
Net cost $4,114 $4,886
The assumptions used for measurement purposes are as follows:
1996 1995
Discount rate for obligations 7.5% 7.5%
Discount rate for expense 7.5% 7.0%
Initial medical cost trend rate 8.0% 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. Rate Matters
IOWA
The company filed an Iowa electric rate increase application in March
1995. The application requested an annual increase of $13.1 million.
Interim rates in an annual amount of $7.1 million were placed in effect on
June 29, 1995, subject to refund. A December 1995 Iowa Utilities Board
(IUB) Order allowed an annual increase of $6.6 million, including a return
on common equity of 11.35%. In 1996, the company will refund to customers
approximately $250,000 collected in 1995 in excess of the final order. The
1995 financial statements include a provision for the refund. The company
filed an Iowa gas rate increase application in August 1995. The
application requested an annual increase of $2.2 million. Interim rates in
an annual amount of $1.3 million were placed in effect on October 20,
1995, subject to refund. The company and other parties to the rate
application have agreed on an increase of $1.1 million subject to approval
by the IUB. An IUB Order is expected by June 1996.
MINNESOTA
The company filed a Minnesota electric rate increase application in June
1995. The application requested an annual increase of $4.6 million (later
adjusted by the company to $3.3 million). Interim rates were not
requested. A MPUC Order is expected by April 1996. The company filed a
Minnesota gas rate increase application in May 1995. The application
requested an annual increase of $2.4 million, including a return on common
equity of 11.75%. Interim rates in an annual amount of $1.5 million were
placed in effect in June 1995, subject to refund. A MPUC Order is expected
by March 1996.
FEDERAL ENERGY REGULATORY COMMISSION (FERC)
FERC Order 636 provides a mechanism under which gas pipelines can recover
transition costs from local distribution companies. The company estimates
its remaining share of transition costs will aggregate approximately $3.2
million payable in declining annual installments from 1996 to 2005. The
company is recovering transition costs from customers.
9. Income Taxes
A deferred tax asset or liability is recognized for each temporary
book/tax difference. Corresponding regulatory assets or liabilities,
reflecting the anticipated future rate treatment, have also been
recognized. The balance sheet as of December 31, 1995, includes regulatory
assets and deferred tax liabilities in an equal amount of $27.8 million.
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, 1995 and 1994, balance sheet
are shown below:
Item: Thousands of Dollars
1995 1994
Property $84,865 $80,484
Energy Conservation Costs 7,589 5,195
Call Premiums on Reacquired Bonds 1,948 2,005
Unbilled Revenue (3,348) (3,310)
Other (2,226) (2,396)
Total $88,828 $81,978
Gross deferred assets $(6,690) $(6,197)
Gross deferred liabilities 95,518 88,175
Total $88,828 $81,978
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.
1995 1994 1993
Federal statutory tax rate 35.0% 35.0% 35.0%
Increases (reductions) in taxes resulting from:
State income taxes net of federal income tax benefit 5.7% 4.0% 4.7%
Investment tax credit amortization (2.2%) (3.4%) (3.6%)
Additional depreciation deducted for book purposes 1.5% 2.0% 2.0%
Other 1.3% (6.8%) (4.8%)
Overall effective income tax rate 41.3% 30.8% 33.3%
The current and deferred tax expense is comprised of (Thousands):
Federal and state currently payable $15,157 $1,849 $6,139
Deferred income tax - federal and state:
Additional tax depreciation - net 3,673 3,270 3,256
Coal contract buyout - - (526)
Energy efficiency costs 2,394 2,413 1,466
Environmental clean-up 154 2,010 (1,166)
Other 285 (601) 826
Investment tax credit amortization (1,028) (1,028) (1,028)
Federal and state currently payable -
other income and deductions (1,182) 1,276 497
Total $19,453 $9,189 $9,464
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. Amounts at December 31, 1995 and
1994, included in utility plant were $82.0 million and the accumulated
provision for depreciation was $40.8 and $38.6 million, respectively. In
addition, the company has a long-term participation power purchase for
25,000 KW of Neal #4 generating capacity which expires in 2003. Minimum
future capacity payments under the participation power purchase agreement
are approximately $15.7 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% (28,000 KW) interest in a 675,000 KW coal-fired
unit (Louisa #1), completed in 1983. Utility plant at December 31, 1995
and 1994, was $24.8 million and the accumulated provision for depreciation
was $9.6 and $8.8 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 255
megawatts of capacity 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,
$24.6 and $24.1 million in 1995, 1994 and 1993, respectively. Over the
remaining period of the contracts, total capacity payments will be
approximately $130 million.
In Iowa the IUB has concluded that the capacity purchases were prudent and
allowed recovery of costs in rates.
The rate structure approved by the MPUC does not provide for full recovery
of purchased power applicable to the Minnesota jurisdiction. A 1992 rate
order by the MPUC held that the company had 100 MW of excess capacity. The
company is seeking to adjust this disallowance in its current rate case.
The company has not filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and FERC jurisdictions. The
payments of approximately $2.5 million annually are expensed as incurred.
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. Demand Side Management Costs
Minnesota and Iowa regulations require that utilities conduct energy
efficiency and demand side management programs. Demand side management
expenditures applicable to the Minnesota jurisdiction in an annual amount
of approximately $0.6 million are currently being recovered through rates.
Iowa jurisdiction tariffs which provide for the recovery of demand side
management costs incurred through December 31, 1992, were placed in effect
in October 1994. The Iowa tariffs provide for the recovery of $6.7 million
of demand side management costs over a four year period. The company
anticipates filing in 1996 for recovery of costs incurred through 1995. As
of December 31, 1995 and 1994, the amounts deferred were $23.1 and $17.0
million, respectively.
13. 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)
1995 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $82,765 $72,054 $86,340 $77,383
Operating income 11,815 10,880 15,283 8,163
Net income 7,757 3,865 11,731 4,303
Earnings per share of common stock .74 .34 1.16 .38
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
Net income for the fourth quarter of 1995 was $4.3 million, compared with
$3.2 million in 1994. Increased electric and gas sales, electric and gas
rate increases and cost containment efforts were major factors.
Residential electric sales for the fourth quarter of 1995 increased 6.2%
over the same period of 1994, while large power and light sales increased
2.8%. The electric margin for the fourth quarter of 1995 (revenue minus
cost of fuel and purchased power) was $36.1 million compared to $33.2
million for the same period of 1994. The Iowa electric rate increase
implemented in June 1995 contributed $1.4 million to the fourth quarter
electric margin.
The gas margin for the fourth quarter of 1995 (revenue minus cost of gas
sold) was $5.3 million compared to $2.8 million for the same period of
1994. Residential and transportation gas volumes increased 29.5% and 6.9%,
respectively. Minnesota and Iowa interim rate increases in an annual
amount of $1.5 and $1.3 million, respectively, were implemented in June
and October 1995.
Other operating expense for the fourth quarter of 1995 includes $1.3
million of legal and consulting fees related to the proposed merger of
Interstate Power Company, IES Industries and WPL Holdings.
14. Commitments and Contingencies
The company has a barge transportation contract, coal supply contracts, 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 $110.7 million.
The company has two natural gas supply contracts, four natural gas
transportation contracts, and two natural gas storage contracts, which
collectively obligate the company for a minimum annual commitment of
approximately $9.8 million. Such agreements individually expire from 1996
through 2001.
15. Merger
The Company, WPL Holdings, Inc. (WPLH) and IES Industries Inc. (IES) have
entered into an Agreement and Plan of Merger (Merger Agreement), dated
November 10, 1995, providing for: a) Interstate Power Company (IPC)
becoming a wholly-owned subsidiary of WPLH and b) the merger of IES with
and into WPLH, which merger will result in the combination of IES and WPLH
as a single holding company (collectively, the Proposed Merger). The new
holding company will be named Interstate Energy Corporation (Interstate
Energy) and IES will cease to exist. The Proposed Merger, which will be
accounted for as a pooling of interests, is subject to approval by the
shareholders of each company as well as several federal and state
regulatory agencies. The companies expect to receive the shareholder
approvals in the second quarter of 1996 and the regulatory approvals by
the second quarter of 1997.
Under the terms of the Merger Agreement, the outstanding shares of WPLH's
common stock will remain unchanged and outstanding as shares of Interstate
Energy. Each outstanding share of IES common stock will be converted to
0.98 shares of Interstate Energy's common stock. Each share of the
Company's common stock will be converted to 1.11 shares of Interstate
Energy's common stock. It is anticipated that Interstate Energy will
retain WPLH's common share dividend payment level as of the effective time
of the merger. On January 24, 1996, the Board of Directors of WPLH
declared a quarterly dividend of 49.25 cents per share. This represents an
equivalent annual dividend rate of $1.97 per share.
WPLH is a holding company headquartered in Madison, Wisconsin, and is the
parent company of Wisconsin Power and Light Company (WP&L) and Heartland
Development Corporation (HDC). WP&L supplies electric and gas service to
approximately 377,000 and 146,000 customers, respectively, in south and
central Wisconsin. HDC and its principal subsidiaries are engaged in
businesses in three major areas: environmental engineering and consulting,
affordable housing and energy services.
IES is a holding company headquartered in Cedar Rapids, Iowa, and is the
parent company of IES Utilities Inc. (Utilities) and IES Diversified Inc.
(Diversified). Utilities supplies electric and gas service to
approximately 333,000 and 174,000 customers, respectively, in Iowa.
Diversified and its principal subsidiaries are primarily engaged in the
energy-related, transportation and real estate development businesses.
Interstate Energy will be the parent company of Utilities, WP&L and IPC
and will be registered under the Public Utility Holding Company Act of
1935 (1935 Act), as amended. The merger agreement provides that these
operating utility companies will continue to operate as separate entities
for a minimum of three years beyond the effective date of the merger. In
addition, the non-utility operations of IES and WPLH will be combined
shortly after the effective date of the merger under one entity to manage
the diversified operations of Interstate Energy. The corporate
headquarters of Interstate Energy will be in Madison.
The Securities and Exchange Commission (SEC) historically has interpreted
the 1935 Act to preclude registered holding companies, with limited
exceptions, from owning both electric and gas utility systems. Although
the SEC has recently recommended that registered holding companies be
allowed to hold both gas and electric utility operations if the affected
states agree, it remains possible that the SEC may require as a condition
to its approval of the Proposed Merger that the Company, WPLH and IES
divest their gas utility properties, and possibly certain non-utility
ventures of IES and WPLH, within a reasonable time after the effective
date of the Proposed Merger.
The operating revenues, net income from continuing operations and total
assets of the companies were as follows:
PRO FORMA
COMBINED
IES WPLH IPC (Unaudited)
(in thousands)
1995 operating revenues $851,010 $807,255 $318,542 $1,976,807
1995 net income from
continuing operations 64,176 71,618 25,198 160,992
Assets at December 31, 1995 1,985,591 1,872,414 634,316 4,492,321
16. Segments of Business
Information about the company's operations in different segments of
business for 1995, 1994 and 1993 are shown in the table below.
Electric Gas Total
(Thousands of Dollars)
1995
Revenue $274,873 $43,669 $318,542
Operating income (Before income taxes) $ 57,255 $ 9,521 $ 66,776
Depreciation and amortization expense $ 27,442 $ 2,118 $ 29,560
Capital expenditures $ 26,583 $ 2,117 $ 28,700
Utility plant - net $459,250 $39,277 $498,527
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
Independent Auditors' Report
DELOITTE & TOUCHE LLP
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, 1995 and
1994 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,
1995. 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, 1995 and
1994 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1995 in conformity with
generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Davenport, Iowa
January 26, 1996
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
1995 1994 1993 1992 1991
(Thousands of Dollars)
Operating revenues $318,542 $307,650 $309,468 $285,298 $291,805
Operation 191,335 202,545 204,871 181,391 172,709
Maintenance 14,881 17,160 16,771 16,966 17,567
Depreciation and
amortization 29,560 28,212 26,955 25,887 25,303
Income taxes 20,635 7,913 8,967 9,337 17,113
Property and other taxes 15,990 16,298 17,080 16,533 15,315
272,401 272,128 274,644 250,114 248,007
Operating income 46,141 35,522 34,824 35,184 43,798
Other income
(deductions) - net (1,690) 1,990 780 724 1,269
Income before interest
charges 44,451 37,512 35,604 35,908 45,067
Interest charges 16,795 16,845 16,617 16,691 15,557
Net income 27,656 20,667 18,987 19,217 29,510
Preferred and preference
dividends 2,458 2,454 2,861 2,975 3,075
Earnings available for
common stock $ 25,198 $ 18,213 $ 16,126 $ 16,242 $ 26,435
Average number of common
shares outstanding 9,564,287 9,478,741 9,316,387 9,297,748 9,297,748
Earnings per common share $ 2.63 $ 1.92 $ 1.73 $ 1.74 $ 2.84
Common dividends declared
per share $ 2.08 $ 2.08 $ 2.08 $ 2.08 $ 2.04
Total assets $634,316 $628,845 $604,361 $558,100 $550,631
Long-term debt and
mandatory sinking fund
preferred stock $212,916 $212,965 $227,007 $207,958 $220,818
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 $2.08 per share. As of December 31, 1995,
there were 15,127 holders of common stock and 173 holders of preferred
stock. Historical quarterly data for the company's common stock is shown
below:
Avg. Shares
Dividends Price Range Outstanding
Quarter Ended Paid High Low 12 Months Ended
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
March 31, 1995 $0.52/Share 25 1/4 - 23 9,519,098
June 30, 1995 $0.52/Share 25 - 23 1/2 9,548,054
Sept. 30, 1995 $0.52/Share 27 1/4 - 23 1/4 9,563,020
Dec. 31, 1995 $0.52/Share 33 1/4 - 27 1/8 9,564,287