EX-13
INTERSTATE POWER COMPANY
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, as amended on May 22, 1996, and August 16, 1996,
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. The new holding company will be named Interstate Energy
Corporation (Interstate Energy). The proposed merger, which will be
accounted for as a pooling of interests and is intended to be tax free for
federal income tax purposes, was approved by the shareholders of each
company on September 5, 1996. It is still subject to approval by the
Securities and Exchange Commission. The companies expect to receive
approval in 1998.
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 897,000 electric customers and 383,000
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
1.14 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. Currently that level represents an annual rate of $2.00
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 393,000 and 155,000 customers, respectively, in south and
central Wisconsin. HDC and its principal subsidiaries are engaged in
businesses in three major areas: environmental, energy services and
affordable housing 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 339,000 and 178,000 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, Wisconsin.
The Securities & 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.
LIQUIDITY AND CAPITAL RESOURCES
Cash flow from operating activities was $67 million in 1997 versus $63
million in 1996. The funds were primarily used to pay the company's
construction program 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, $31 and $29 million in 1997, 1996 and
1995, respectively. For the five year period from 1998 through 2002,
construction expenditures are estimated to be $197 million. The company
anticipates that approximately 75% of the construction funds for years
1998 and 1999 will be generated internally. The 1998 and 1999 construction
programs are estimated to be $31 and $42 million, respectively.
The company has authorization from the Federal Energy Regulatory
Commission (FERC) to issue up to $75 million in short term debt. At year
end 1997, a $41.5 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 1997, the company had $33.5
million of commercial paper payable.
At December 31, 1997, 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 4.0 times for 1997, 3.8 times for 1996 and 3.7 times for 1995.
The company's stock price decreased from $33.125 at year end 1995 to $29
at year end 1996 but attained a record high of $37.44 at year end 1997.
Effective June 1996, the company elected to issue new shares of common
stock for the Dividend Reinvestment and Stock Purchase Plan rather than
purchasing shares on the open market. The company resumed open market
purchases to satisfy the Dividend Reinvestment and Stock Purchase Plan
requirements in 1997.
Electric and gas rates include an energy 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. Electric capacity costs are not
recovered from customers through energy 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 energy 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.
PURCHASED POWER CONTRACTS
In 1992, the company entered into three long term purchased power
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 purchased power contracts required
capacity payments of $24.9 million in 1997, and $24.6 in 1996 and 1995.
Over the remaining life of the contracts, total capacity payments will be
approximately $85.6 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. The 1996 rate order by the MPUC
held that the company had 100 MW of excess capacity and disallowed
recovery of approximately $800,000 annually.
The company has not filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and FERC jurisdictions. The
company believes that increased margins from sales growth in Illinois have
largely offset the revenue deficiency.
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. No significant costs will be incurred to comply with Phase 2
environmental standards, which take effect January 1, 2000.
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 over 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 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. As of year end 1997, soil remediation of the site
is complete, however, ground water monitoring continues. The company's
total share of cost from 1984 to 1997 at this site is $2.7 million.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post remediation
groundwater monitoring is complete pending final review. From 1991 through
1997, the company incurred costs aggregating $6.9 million applicable to
the Rochester site. A MPUC decision allowed the company to recover $4.9
million over a 10 year period beginning in 1996.
The company has identified an additional seven sites, as described below,
which may contain hazardous waste from former coal gasification plants and
has recorded an estimated liability applicable to the investigation of
those sites. The company is unable to determine, at this time, the
extent, if any, of remediation necessary at these seven sites.
In Minnesota, the company owned or operated four manufactured gas plant
sites: Albert Lea, Austin, New Ulm and Owatonna. Potentially hazardous
wastes associated with former coal gasification operations have been
identified at each site. The company incurred $0.2 million in
investigation costs for these sites in 1997, and $1.5 million since the
investigation process began.
The company received accounting orders from the MPUC which allows the
deferral of investigation and remediation costs applicable to the
Minnesota sites and further allows the company to seek recovery in a rate
case.
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 these sites. Little or no activity is expected at the Illinois sites in
1998. In 1997, $3.8 million was expensed for investigation and remediation
work expected at the Clinton site in 1998.
Previous actions by Iowa and Illinois regulators have permitted utilities
to recover prudently incurred unreimbursed investigation and remediation
costs.
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. Eight insurers paid the company a total of $9.6
million in 1995, 1996 and 1997 in order to be discharged from the lawsuit.
As of December 31, 1997, $4.8 million is recorded as a deferred credit
pending regulatory disposition. Neither the company nor its legal counsel
is able to predict the amount of additional insurance recovery, and
accordingly, no potential recovery has been recorded.
LARGE ELECTRIC CUSTOMERS
The company's six largest electric customers consumed a total of 1,762,009
MWH of electricity in 1997, which accounts for over 33 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 1.0 percent from 1996, while 1996 consumption
was 0.4 percent less than 1995. The aggregate 1997 rate for these
customers was approximately 3.3 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 are subject to regulatory reviews.
The company's Minnesota rates recover jurisdictional demand side
management expenditures and lost revenues. The Iowa Utilities Board (IUB)
allows recovery of deferred Iowa costs. The 1990, 1991 and 1992 DSM costs
are being recovered over a four year period which began in October 1994.
The 1993, 1994 and 1995 DSM costs are being recovered over a four year
period which began in May 1997. Cost recovery of the DSM costs for 1996
and through September 1997 began in October 1997 and are being recovered
over a four year period. Effective October 1997, DSM costs for the period
of October 1997 through September 1998 will be recovered as they are
incurred.
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 prudent
transition costs associated with the restructuring process. The company 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 $1.3 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 two large customers currently purchase
a majority of their gas requirements from producers or gas marketers.
Consumption for the three largest gas customers was up 12% over 1996 and
currently accounts for approximately 70% of system throughput. The
company's largest gas customer, which represents 36% of the company's
total gas throughput, is committed by contract for the next four years.
RATE MATTERS
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. On April 10, 1996, the Commission issued an order allowing an
increase in electric rates of $2.3 million. The company and the Department
of Public Service filed for reconsideration by the Commission. A
Commission order issued June 26, 1996, denied reconsideration. Rates
reflecting the increase granted were implemented in August 1996. A
Commission order issued December 16, 1996, allowed the company to recover
approximately an additional $830,000 in 1997 applicable to the time period
from the original order to the date when new rates were implemented.
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. On February 29, 1996, the
Commission issued an order allowing an increase in gas rates of $2.1
million. The company, the Department of Public Service and the Office of
Attorney General filed for reconsideration by the Commission. A Commission
order after reconsideration issued July 2, 1996, affirmed the level of
increased rates at approximately $2.1 million. Rates reflecting the
increase granted were implemented in September 1996. The Department of
Public Service and the Office of Attorney General appealed the
Commission's decision. The appeal was denied by the Minnesota Court of
Appeals on February 18, 1997. On March 21, 1997, the Department of Public
Service and the Office of Attorney General appealed the decision of the
Court of Appeals (and the Commission) to the Minnesota Supreme Court. On
January 8, 1998, the Minnesota Supreme Court upheld the MPUC initial
decision allowing the company to recover $4.9 million of clean up expenses
over a 10 year period.
CHANGING STRUCTURE OF THE ELECTRIC INDUSTRY
The National Energy Policy Act of 1992 addresses several matters designed
to promote competition in the electric wholesale power generation market,
including mandated open access to the electric transmission system. As
legislation, regulations, and economic changes occur, electric utilities
will be faced with increased competitive pressure. The company currently
faces competition from other suppliers of electrical energy to wholesale
customers and from alternative energy sources and self-generation for
other customer groups, primarily industrial customers.
As a result of cost-based regulation, the company follows the accounting
practices set forth in Statement of Financial Accounting Standard (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation."
Under SFAS 71 regulators can create assets and impose liabilities that
would not be recorded by non-regulated entities. Regulatory assets and
liabilities represent probable future revenues that will be recovered from
or refunded to customers through the ratemaking process. Recoverability
of regulatory assets is assessed at each reporting period. Should the
basis of regulation for some or all of the company's business change from
cost-based regulation, existing regulatory assets and liabilities would
have to be written off unless regulators specify an alternative means of
recovery.
Year 2000
The Merged Company (see above for further discussion of the Merger)
utilizes software, embedded systems and related technologies throughout
its businesses that will be affected by the date change in the Year 2000.
An internal task force has been assembled to review and develop the full
scope, work plan and cost estimates to ensure that the merged Company's
systems continue to meet its internal and customer needs.
Phase I of the project has been completed which encompasses a review of
the necessary software modifications that will need to be made to the
Merged Company's financial and customer systems. The Merged Company
currently estimates that the remaining costs to be incurred on this phase
of the project will be approximately $4 million to $8 million in the
aggregate. The task force has also begun Phase II of the project which is
an extensive review of the Merged Company's embedded operating systems for
Year 2000 conversion issues. The Merged Company is currently unable to
estimate the costs to be incurred on this phase of the project but does
believe that the costs will be significant. An estimate of the expenses
to be incurred on this phase of the project is expected to be available by
the third quarter of 1998.
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 $2.74 for 1997, compared with
$2.69 for 1996 and $2.63 for 1995. Increased sales, electric and gas rate
increases and continuing efforts to control costs contributed to the
increased earnings. The 1997 return on common equity was 12.7%, compared
with 12.9% for 1996 and 13.0% in 1995.
Electric residential sales for 1995 were unusually high primarily because
of warm and humid weather during the air conditioning season. The 1996 and
1997 summers returned to a more normal weather pattern. KWH use per
residential customer was 7,893 for 1997; 7,972 for 1996; and 8,280 for
1995.
Electric "margin" is defined as electric revenue less certain other costs
(primarily fuel and purchased power). Electric margins for years 1997,
1996 and 1995 were $154.8, $153.5 and $151.8 million, respectively. The
Iowa electric rate increase implemented in June 1995 and the Minnesota
electric rate increase in August 1996 were the primary reasons for the
increased electric margin. Gas "margin" is defined as gas revenue less
certain other costs (primarily purchased gas cost). The gas margins for
1997, 1996 and 1995 were $19.2, $17.2 and $17.3 million, respectively.
Rate increases in the states of Minnesota and Iowa contributed to a higher
gas margin. The gas margin for 1996 was depressed due to a sharp increase
in gas costs in December of 1996. Under existing purchase gas adjustment
clauses, there normally is a delay of at least a month in collecting (or
refunding) any variations in gas costs.
Other operating expenses were $64.7, $51.7 and $50.0 million for 1997,
1996 and 1995, respectively. Other operating expenses include $1.5, $2.7
and $1.3 million for 1997, 1996 and 1995, respectively, for merger related
expenses. Other operating expenses for the years 1997, 1996 and 1995,
include $3.8, $0.4 and $1.0 million, respectively, for environmental
investigation, remediation and litigation costs.
Maintenance expense for 1997 was $17.8 million, compared to $16.2 million
in 1996 and $14.9 million in 1995. Several maintenance projects postponed
in 1995 were completed in 1996 and 1997.
Depreciation expense was $31.2, $30.6 and $29.3 million, for 1997, 1996
and 1995, respectively. The increase is primarily due to additional
investment and the implementation of higher depreciation rates approved by
the MPUC.
Interest on long-term debt was $13.9, $14.6 and $14.8 million for 1997,
1996 and 1995, respectively. On May 1, 1997, $17 million of 6 1/8% First
Mortgage Bonds were retired. As a result, the percentage of total
capitalization attributable to long term debt has declined from 44.8% at
year end 1995 to 39.8% at year end 1997.
Interest on commercial paper payable was $1.5, $1.6 and $2.1 million for
1997, 1996 and 1995, respectively. The decreased commercial paper interest
expense is primarily attributable to a slightly higher average balances
outstanding offset by lower interest rates. At year end 1997, the company
had $33.5 million of short term commercial paper payable, compared with
$28.7 million at year end 1996.
The company's investment in coal stockpiles was $10.2 million at December
31, 1997 and $13.3 million at December 31, 1996. 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 $2.7, $2.3 and $2.4 million at December 31,
1997, 1996 and 1995, respectively.
Statements of Income
For the years ended December 31 1997 1996 1995
(Thousands of Dollars)
Operating Revenues:
Electric $277,340 $276,620 $274,873
Gas 54,507 49,464 43,669
------- ------- -------
Total operating revenues 331,847 326,084 318,542
------- ------- -------
Operating Expenses:
Operation:
Fuel for electric generation 55,402 57,560 62,164
Power purchased 56,770 61,556 57,566
Cost of gas sold 33,324 31,617 25,888
Other operating expenses 64,685 51,707 44,581
Maintenance 17,782 16,164 14,881
Depreciation and amortization 31,676 31,087 29,560
Income Taxes:
Federal current 10,233 11,389 11,608
State current 3,080 3,434 3,549
Deferred taxes - net 2,430 2,787 6,506
Investment tax credit
amortization (1,028) (1,028) (1,028)
Property and other taxes 16,708 16,064 15,990
------- ------- -------
Total operating expenses 291,062 282,337 271,265
------- ------- -------
Operating Income 40,785 43,747 47,277
Other Income and Deductions 3,819 798 (2,826)
------- ------- -------
Income Before Interest Charges 44,604 44,545 44,451
------- ------- -------
Interest Charges:
Long-term debt 13,880 14,587 14,811
Other interest charges 1,730 1,885 2,325
Borrowed funds used during
construction (174) (250) (341)
------- ------- -------
Total interest charges 15,436 16,222 16,795
------- ------- -------
Net Income 29,168 28,323 27,656
Preferred Stock Dividends (2,469) (2,463) (2,458)
Income Available for Common
Stock $26,699 $25,860 $25,198
======= ======= =======
Earnings Per Average Common
Share Outstanding based on
9,724,974: 9,593,664 and
9,564,287 shares, respectively $2.74 $2.69 $2.63
======= ====== ======
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 1997 1996
(Thousands of Dollars)
Utility Plant:
In Service:
Electric:
Production $377,432 $376,338
Transmission 191,068 187,911
Distribution 246,553 234,320
General 54,071 53,847
-------- --------
Total Electric 869,124 852,416
Gas 70,201 68,047
-------- --------
939,325 920,463
Less - accumulated depreciation 450,595 426,471
-------- --------
488,730 493,992
Held for future use 591 591
Construction work in progress 5,276 3,129
-------- --------
Net utility plant 494,597 497,712
-------- --------
Other Property and Investments 6,186 453
-------- --------
Current Assets:
Cash and cash equivalents 2,897 3,072
Accounts receivable, less reserves
of $200 27,061 28,227
Inventories - at average cost:
Fuel 13,888 16,623
Materials and supplies 6,297 6,214
Prepaid pension cost 3,487 3,331
Prepaid income tax 11,317 9,483
Other prepayments and current assets 1,049 683
-------- --------
Total current assets 65,996 67,633
-------- --------
Deferred Debits:
Regulatory assets 65,818 66,786
Unamortized debt expense 5,503 5,710
Other 649 906
-------- --------
Total deferred debits 71,970 73,402
-------- --------
Total $638,749 $639,200
======== ========
The accompanying notes are an integral part of these finanical statements.
Balance Sheets
Capitalization and Liabiities
As of December 31 1997 1996
(Thousands of Dollars)
Capitalization, per accompanying statements:
Common stock, par value $3.50 per share;
authorized - 30,000,000 shares; issued
and outstanding - 9,760,821 in 1997 and
9,670,866 in 1996 $34,163 $33,848
Additional paid-in capital 108,292 105,959
Retained earnings 73,166 66,251
-------- --------
Total common equity 215,621 206,058
-------- --------
Preferred stock (optional sinking fund) 10,819 10,819
Preferred stock (mandatory sinking fund) 24,267 24,147
Long-term debt 165,280 171,506
-------- --------
Total capitalization 415,987 412,530
-------- --------
Current liabilities:
Commercial paper 33,500 28,700
Long-term debt maturing within one year 6,300 17,225
Accounts payable 13,208 14,013
Dividends payable - preferred stock 599 599
Payrolls accrued 3,385 3,291
Taxes accrued 16,014 16,953
Interest accrued 2,638 2,817
FERC order 636 transition costs 1,300 2,200
Other 4,537 2,878
-------- --------
Total current liabilities 81,481 88,676
-------- --------
Deferred Credits and Other Non-Current
Liabilities:
Accumulated deferred income taxes 104,669 99,303
Accumulated deferred investment
tax credits 15,985 17,013
Deferred pension costs 7,613 7,115
Environmental clean-up costs 5,794 7,234
Other 7,220 7,329
-------- --------
Total deferred credits and other
non-current liabilities 141,281 137,994
-------- --------
Commitments and Contingencies (Notes 1, 3 and 9)
Total $638,749 $639,200
======== ========
The accompanying notes are an integral part of these finanical statements.
Statements of Cash Flows
For the years ended December 31 1997 1996 1995
(Thousands of Dollars)
Reconciliation of Net Income to
Cash Flows
From Operating Activities:
Net Income $29,168 $28,323 $27,656
Adjustments for non-cash items:
Depreciation and amortization 31,676 31,087 29,560
Deferred income taxes 4,593 4,916 6,912
Investment tax credit
amortization (1,028) (1,028) (1,028)
Equity funds used during
construction (AFUDC) (16) (13) 0
Prepaid pension cost 672 99 74
Changes in assets and liabilities:
Accounts receivable - net 1,166 (430) (5,447)
Inventories 2,658 2,016 4,599
Accounts payable and other
current liabilities 3,885 73 (2,946)
Accrued and prepaid taxes (3,009) (2,500) 2,379
Interest accrued (179) (2) (111)
Other prepayments and
current assets (622) 470 1,469
Rate refund payable 0 (256) 256
Regulatory assets - deferred demand
side management costs (91) (6,718) (6,177)
Regulatory assets - other (3,005) 2,648 794
Other operating activities 877 4,018 3,275
------- ------- -------
Cash flows from operating
activities 66,745 62,703 61,265
------- ------- -------
Cash Flows From Investing Activities:
Additions to utility plant (28,698) (30,734) (28,238)
Borrowed funds used during
construction (AFUDC) (174) (250) (341)
Other (5,697) (243) 127
------- ------- -------
Cash flows from investing
activities (34,569) (31,227) (28,452)
------- ------- -------
Cash Flows From Financing Activities:
Issuance of common stock 2,694 3,228 0
Retirement of long-term debt (17,225) (225) (14,225)
Dividends on common and preferred
stock (22,620) (22,344) (22,288)
Commercial paper - net 4,800 (10,600) 3,700
------- ------- -------
Cash flows from financing
activities (32,351) (29,941) (32,813)
------- ------- -------
Net Increase (Decrease) in Cash and
Cash Equivalents ($175) $1,535 $0
Cash and Cash Equivalents:
Beginning of year 3,072 1,537 1,537
------- ------- -------
End of year $2,897 $3,072 $1,537
======= ======= =======
Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of interest
capitalized) $15,533 $15,678 $16,655
Income taxes $17,210 $16,330 $11,134
The accompanying notes are an integral part of these financial statements.
Statements of Capitalization
As of December 31 1997 1996
Common Equity $215,621 51.8% $206,058 49.9%
------- -------
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% 55926 $51.62 2,796 2,796
7.76% 100000 $52.03 5,000 5,000
------- -------
10,819 2.6% 10,819 2.6%
------- -------
Preferred with mandatory sinking
fund provisions:
6.40% 545000 $53.20 27,250 27,250
Unamortized Discount on 6.40%
Preferred Stock (1,847) (1,921)
Unamortized Issuance Expense on
6.40% Preferred Stock (97) (101)
Unamortized Call Premiums on
Preferred Stock (1,039) (1,081)
------- -------
24,267 5.8% 24,147 5.9%
------- -------
Long-Term Debt:
First Mortgage Bonds:
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
------- -------
144,000 144,000
------- -------
Pollution Control Revenue Bonds:
5.95% due 1997 to 1998 - 5,850
6 3/8% due 1998 to 2007 10,950 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
------- -------
24,200 30,500
------- -------
Other Long-Term Debt 86 95
------- -------
Unamortized Discount on
Long-Term Debt (3,006) (3,089)
------- -------
Total Long-Term Debt - net 165,280 39.8% 171,506 41.6%
------- -------
Total Capitalization $415,987 100.0% $412,530 100.0%
======= =======
(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.
Statements of Retained Earnings
For the years ended December 31 1997 1996 1995
(Thousands of Dollars)
Retained Earnings, Beginning
of Year $66,251 $61,150 $55,893
Net Income 29,168 28,323 27,656
Dividends on Common Stock (20,225) (19,950) (19,941)
Dividends on Preferred Stock (2,469) (2,463) (2,458)
Additional Minimum Liability of
Non-Qualified Pension Plan at
December 31 - net of taxes (347) (809) -
Unrealized Gain on Subsidiary
Securities 788 -
------- ------- -------
Retained Earnings, End of Year $73,166 $66,251 $61,150
======= ======= =======
NOTES TO FINANCIAL STATEMENTS
(dollars in millions except as otherwise indicated)
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a. General
Interstate Power Company (the Company or IPC) is an investor-owned public
utility engaged principally in the generation, transmission, distribution
and sale of electricity and the purchase, distribution, transportation and
sale of natural gas in Iowa, Minnesota and Illinois.
Refer to Note 2 for discussion of the proposed merger of the Company.
Certain reclassifications have been made to the prior years financial
statements to conform with the 1997 presentation.
b. Regulation
The financial statements are based on generally accept 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.
c. Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
d. Cash and Equivalents
Cash and equivalents are stated at cost, which approximates fair market
value, and consist of short-term liquid investments with a maturity of
three months or less from the date of acquisition.
e. Utility Plant and Other Property and Equipment
Utility plant and other property and equipment is recorded at original
cost. Utility plant costs include financing costs that are capitalized
using the FERC method for allowance for funds used during construction
(AFUDC), including approval to incorporate demand side management costs in
the formula. The AFUDC capitalization rates for 1997, 1996 and 1995 were
6.0%, 5.8% and 6.0%, respectively. Consistent with current rate making
practices, these capitalized costs are expected to be recovered in future
rates as the cost of the utility plant is depreciated.
Normal repairs, maintenance and minor items of utility plant and other
property and equipment are expensed. Ordinary utility plant retirements,
including removal costs less salvage value, are charged to accumulated
depreciation upon removal from utility plant accounts.
Substantially all property is subject to the lien of the First Mortgage
Bond Indenture.
f. 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 is as follows:
1997 1996 1995
Electric 3.6% 3.6% 3.5%
Gas 3.4% 3.4% 3.5%
g. Regulatory Assets and Liabilities
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation," provides that rate-regulated
public utilities, such as the Company, record certain costs and credits
allowed in the ratemaking process in different periods than for
unregulated entities. These are deferred as regulatory assets or
regulatory liabilities and are recognized in the statements of income at
the time they are reflected in rates. If a portion of the Company's
operations are no longer subject to the provisions of SFAS No. 71, a
write-off of regulatory assets and liabilities would be required, unless
some form of transition cost recovery is established by the appropriate
regulatory body. In addition, the Company would be required to determine
any impairment to other assets and write-down such assets to their fair
value.
As of December 31, 1997 and 1996, regulatory created assets include the
following:
1997 1996
Deferred income taxes (Note 5) $27.2 $26.6
Deferred demand side management 30.0 29.9
Environmental clean-up (Note 9 b) 6.2 6.4
FERC order No. 636 transition costs 1.3 2.2
Employee/retiree benefits (Note 4) 1.1 1.7
----- -----
$65.8 $66.8
===== =====
Refer to the individual notes referred above for a further discussion of
certain items reflected in regulatory assets. Regulators allow the
Company to earn a return on the deferred demand side managements costs but
not on the other regulatory assets. As of December 31, 1997 and 1996, the
Company had recorded regulatory related liabilities of $5.7 and $5.0,
respectively, which are primarily related to pensions.
h. Revenue 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 tariffs provide for subsequent adjustment to its electric
and natural gas rates for changes in the cost of fuel and purchased energy
and in the cost of natural gas purchased for resale. Changes in the
under/over collection of these costs are reflected in "Fuel for
production" and "Gas purchased for resale" in the statements of income.
The cumulative under or over collection is reflected in the consolidated
balance sheets as a current asset or current liability. Purchased capacity
costs are not recovered from electric customers through energy adjustment
clauses. Instead, these costs must be addressed in base rates in a formal
rate proceeding.
i. Rate Matters
MINNESOTA
In May, 1995 the Company filed an application with the Minnesota Public
Utilties Commission (MPUC) for an increase in gas rates in an annual
amount of $2.4 million. Increased interim rates in an annual amount of
$1.5 million were placed in effect in June, 1995. On February 29, 1996,
the Commission issued an order allowing an increase in gas rates of $2.1
million. Rates reflecting the increase were implemented in September,
1996. The Department of Public Service and the Office of Attorney General
appealed the Commission's decision. The appeal was denied by the Minnesota
Court of Appeals on February 18, 1997. On March 21, 1997, the Department
of Public Service and the Office of Attorney General appealed the decision
of the Court of Appeals (and the Commission) to the Minnesota Supreme
Court. On January 8, 1998, the Minnesota Supreme Court upheld the MPUC
initial decision.
FEDERAL ENERGY REGULATORY COMMISSION (FERC)
The Company, IES Utilities Inc. and Wisconsin Power & Light Company (WP&L)
proposed to freeze their wholesale electric prices for four years from the
effective date of the merger as part of their merger filing with the FERC.
The Company does not expect the merger-related proposals to have a
material adverse effect on its financial position or results of
operations.
DEMAND SIDE MANAGEMENT COSTS
The 1990, 1991 and 1992 DSM costs are being recovered over a four year
period beginning in October 1994. The 1993, 1994 and 1995 DSM costs are
being recovered over a four year period beginning in May 1997. The DSM
costs for 1996 and through September 1997 are being recovered over a four
year period beginning in October 1997. Effective October 1997, DSM costs
for the period of October 1997 through September 1998 will be recovered as
they are incurred.
j. Income Taxes
The Company follows the liability method of accounting for deferred income
taxes, which requires the establishment of deferred tax liabilities and
assets, as appropriate, for all temporary differences between the tax
basis of assets and liabilities and the amounts reported in the financial
statements using currently enacted tax rates as shown in Note 5.
Except as noted below, income tax expense includes provisions for deferred
taxes to reflect the tax effects of temporary differences between the time
when certain costs are recorded in the accounts and when they are deducted
for tax return purposes. As these normalized temporary differences
reverse, the related accumulated deferred inome taxes are reversed to
income. Investment tax credits are accounted for on a deferred basis and
reflected in income ratably over the life of the related utility plant.
Consistent with rate making practices for the Company, deferred tax
expense is not recorded for certain temporary differences (primarily
related to utility property, plant and equipment). As the current taxes
become payable, over periods exceeding 30 years for some generating plant
differences, they are eligible for recovery through rates. Accordingly,
the Company has recorded deferred tax liabilities and regulatory assets,
as identified in Note 1 (g).
k. Concentration of Sales
The Company provides service to 6 large electric customers which accounts
for over 33% of total electric MWH sales. The Company provides
transportation service to 3 large gas customers which accounts for 70% of
system throughput. Title to the gas consumed remains with these
transportation customers.
l. 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.
NOTE 2. PROPOSED MERGER OF THE COMPANY
(Unaudited)
On November 10, 1995, the Company, IES Industries Inc. (IES), and WPL
Holdings, Inc. (WPLH) entered into an Agreement and Plan of Merger, as
amended (Merger Agreement), providing for: a) the Company 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 (IEC). The
Proposed Merger, which will be accounted for as a pooling of interests and
is intended to be tax-free for federal income tax purposes, has been
approved by the respective Boards of Directors, shareholders and most of
the federal and state regulatory agencies. It is still subject to
approval by the Securities and Exchange Commission (SEC). The companies
expect to receive the SEC approval in 1998.
The summary below contains selected unaudited pro forma financial data for
the year ended December 31, 1997. The financial data should be read in
conjunction with the historical financial statements and related notes of
the Company, IES and WPLH and in conjunction with the unaudited pro forma
combined financial statements and related notes of IEC included in the
Form 10-K Annual Report of the Company. The pro forma combined earnings
per share reflect the issuance of shares associated with the exchange
ratios discussed below.
WPLH IES IPC PRO FORMA
(in millions except per (as (as (as Pro Forma COMBINED
share data) reported) reported) reported) Adjustments (Unaudited)
Operating Revenues $919.3 $930.7 $331.8 $118.8 $2300.6
Income from Continuing $61.3 $66.3 $26.7 $- $154.3
Operations
Earnings per share from $1.99 $2.18 $2.74 $- $2.02
Continuing Operations
Assets at December 31, 1997 $1861.8 $2457.2 $638.7 ($6.1) $4951.3
Long-term obligations, net $526.0 $882.4 $195.8 $- $1604.3
at December 31, 1997
Under the terms of the Merger Agreement, the outstanding shares of WPLH's
common stock will remain unchanged and outstanding as shares of IEC. Each
outstanding share of IES common stock will be converted to 1.14 shares of
IEC common stock. Each share of the Company's common stock will be
converted to 1.11 shares of IEC common stock. It is anticipated that IEC
will retain WPLH's common share dividend payment level as of the effective
time of the merger.
The Company, an operating public utility headquartered in Dubuque, Iowa,
supplies electric and gas service to approximately 166,000 and 50,000
customers, respectively, in northeast Iowa, northwest Illinois and
southern Minnesota. IES is a holding company headquartered in Cedar
Rapids, Iowa, and is the parent company of IES Utilities Inc. (IES
Utilities) and IES Diversified Inc. (IES Diversified). IES Utilities
supplies electric and gas service to approximately 339,000 and 178,000
customers, respectively, in Iowa. IES Diversified and its principal
subsidiaries are primarily engaged in the energy-related, transportation
and real estate development businesses. 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
393,000 and 155,000 customers, respectively, in south and central
Wisconsin. HDC and its principal subsidiaries are engaged in business in
three major areas: environmental, energy and affordable housing services.
IEC will be the parent company of WP&L, IES Utilities and IPC and will
be registered under the Public Utility Holding Company Act of 1935, as
amended (1935 Act). 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 the Company and IES Diversified
will be combined shortly after the effective date of the merger under one
entity to manage the diversified operations of IEC. The corporate
headquarters of IEC will be in Madison, Wisconsin.
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 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, IES and WPLH divest
their gas utility properties, and possibly certain non-utility ventures of
WPLH and IES, within a reasonable time after the effective date of the
Proposed Merger.
NOTE 3. JOINTLY OWNED UTILITY PLANTS
The Company participates with other utilities in the construction and
operation of several jointly owned utility generating plants. Each of the
respective owners is responsible for the financing of its portion of the
construction costs. Kilowatt-hour generation and operating expenses are
divided on the same basis of ownership with each owner reflecting its
respective costs in its statements of income. The chart below represents
the proportionate share of such plants as reflected in the balance sheets
at December 31, 1997 and 1996.
1997 1996
Plant Accumulated Accumulated
Ownership Inservice MW Plant in Provision for Plant in Provision for
Interest % Date Capacity Service Depreciation CWIP Service Depreciation CWIP
Coal:
Neal #4 21.5% 1979 640 $82.2 $45.8 $0 $82.4 $43.3 $0
Louisa #1 4.0% 1983 738 $24.7 $10.9 $0 $24.7 $10.2 $0
----- ----- ----- ----- ----- -----
$106.9 $56.7 $0 $107.1 $53.5 $0
===== ===== ===== ===== ===== =====
NOTE 4. EMPLOYEE BENEFIT PLANS
a. Pension Plans
The Company has a noncontributory, defined benefit retirement plan for all
full-time employees. The benefits are based upon years of service and
levels of compensation. The projected unit credit actuarial cost method
was used to compute net pension costs and the accumulated and projected
benefit obligations. The Company's policy is to fund the plan under the
"aggregate" actuarial cost method to the extent deductible under tax
regulations. Plan assets consist of high-grade bonds, commercial
mortgages and other fixed income investments. Contributions to the plan
for the years ended December 31, 1997, 1996 and 1995 were $3.9, $3.7 and
$3.4 million, respectively.
The following table sets forth the funded status of the plans and amounts
recognized in the Company's balance sheets at December 31, 1997 and 1996:
1997 1996
Accumulated benefit obligation
Vested benefits $39.7 $34.7
Non-vested benefits 1.1 1.3
----- -----
Total 40.8 36.0
Projected benefit obligation 56.2 51.6
Plan assets at fair value 51.6 51.3
----- -----
Plan assets greater or (less) than the (4.6) (0.3)
projected benefit obligation
Unrecognized net transition obligation 1.7 2.1
Unrecognized prior service cost 3.5 2.1
Unrecognized net loss 6.2 1.8
----- -----
Prepaid pension costs $6.8 $5.7
===== =====
Assumed rate of return on plan assets 8.0% 8.0%
===== =====
Discount rate of projected benefit 7.25% 7.5%
obligation ===== =====
Range of assumed rate increases for 5.0% 5.0%
future compensation levels ===== =====
Discount rate for expense 7.5% 7.5%
===== =====
The net pension cost (benefit) recognized in the statements of income for
1997, 1996 and 1995 included the following components:
1997 1996 1995
Service cost $2.4 $2.3 $2.3
Interest cost on projected 3.7 3.7 3.6
Actual return on assets (1.8) (3.6) (3.5)
Amortization and deferrals (1.8) 0.1 0.2
---- ---- ----
Net pension cost $2.5 $2.5 $2.6
==== ==== ====
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.
In addition to the pension plan, the Company has a non-qualified
supplemental retirement plan (SRP), as amended in 1995 and 1997, which
provides a retirement benefit for officers of the Company. Corporate owned
life insurance policies were purchased to provide funding for future cash
requirements. The cash value of such insurance was $1.3 million, $0.9
million and $0.6 million as of December 31, 1997, 1996 and 1995
respectively. The total accumulated benefit obligation for the SRP at
December 31, 1997 and 1996 was $3.7 million and $2.9 million,
respectively. An additional minimum liability was recorded on the balance
sheet in 1997 and 1996 for the supplemental retirement plan due to the
accumulated benefit obligation exceeding the fair value of plan assets.
b. Other Postretirement Benefits
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 872 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 $4.7, $4.3 and $4.1 million for 1997, 1996 and 1995, 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 1997 cost of
postretirement benefits would increase by $0.7 million and the accumulated
benefit obligation would increase by $6.1 million.
The following table sets forth the funded status of the plans and amounts
recognized in the Company's balance sheets at December 31, 1997 and 1996:
1997 1996
Accumulated benefit obligation
Retirees $27.8 $26.0
Fully eligible active plan 18.4 14.0
----- -----
Total 46.2 40.0
Plan assets at fair value 14.7 11.1
----- -----
Accumulated benefit obligation in excess 31.5 28.9
Unrecognized transition obligation (21.5) (22.7)
Unrecognized net loss (8.4) (3.4)
----- -----
Accrued postretirement benefits $1.6 $2.8
===== =====
Assumed rate of return on plan assets 8.00% 8.00%
===== =====
Discount rate of projected benefit 7.25% 7.50%
===== =====
Discount rate for expense 7.50% 7.50%
===== =====
Medical cost trend on paid charges:
Initial trend rate 9.00% 8.00%
===== =====
Ultimate trend rate 6.00% 6.00%
===== =====
The net postretirement benefits cost recognized in the statements of
income for 1997, 1996 and 1995 included the following components:
1997 1996 1995
Service cost $1.3 $1.2 $1.1
Interest cost on projected
benefit obligation 2.9 2.5 2.3
Actual return on assets (0.8) (0.5) (0.4)
Amortization of transition
obligation 1.5 1.5 1.5
Amortization and deferrals (0.2) (0.4) (0.4)
---- ---- ----
Net pension cost
(benefit) $4.7 $4.3 $4.1
==== ==== ====
NOTE 5. INCOME TAXES
The following table reconciles the statutory federal income tax rate to
the effective income tax rate:
1997 1996 1995
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes, net of federal
benefit 5.5 5.2 5.7
Investment tax credits restored (2.2) (2.2) (2.2)
Excess book over tax depreciation 0.6 1.3 1.5
Other differences, net (1.1) (0.3) 1.3
----- ----- -----
Effective income tax 37.8% 39.0% 41.3%
===== ===== =====
The breakdown of income tax expense as reflected in the statements of
income is as follows:
1997 1996 1995
Federal and state currently
payable $13.3 $14.8 $15.1
Deferred income tax - federal
and state
Additional tax depreciation -
net 2.2 3.0 3.7
Energy efficiency cost 0.4 2.7 2.4
Environmental costs - net 0.8 (2.4) 0.2
Other (0.9) (0.5) 0.3
Investment tax credit restored (1.0) (1.0) (1.0)
Federal and state currently
payable - other income and
deductions 2.9 1.5 (1.2)
---- ---- ----
$17.7 $18.1 $19.5
==== ==== ====
The temporary differences that resulted in accumulated deferred income
taxes (assets) and liabilities as of
December 31, 1997 and 1996, are as follows:
1997 1996
Property $89.3 $86.7
Energy conservation costs 10.7 10.3
Call premiums on reacquired bonds 1.8 1.9
Environmental costs - net (1.8) (2.6)
Unbilled revenue (3.3) (3.5)
Other (3.3) (3.0)
----- -----
$93.4 $89.8
===== =====
Gross deferred assets $(11.3) $(9.5)
Gross deferred liabilities 104.7 99.3
----- -----
$93.4 $89.8
===== =====
NOTE 6. SHORT-TERM DEBT AND LINES OF CREDIT
The Company had bank lines of credit aggregating $52.5 million at December
31, 1997, most of which are at the bank prime rates. Information
regarding short-term debt and lines of credit is as follows:
1997 1996 1995
As of year end--
Lines of credit available $52.5 $42.5 $55.0
Commercial paper outstanding $33.5 $28.7 $39.3
Notes payable outstanding - - -
Discount rates on commercial paper 5.88% 5.48% 5.85%
Interest rates on notes payable - - -
For the year ended--
Maximum month-end amount of $38.7 $32.8 $46.8
short-term debt
Average amount of short-term debt
(based on daily outstanding $28.1 $27.0 $36.2
balances)
Average interest rate on 5.60% 5.48% 5.96%
short-term debt
NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments:
Current Assets and Current Liabilities - The carrying amount approximates
fair value due to the short maturities of these financial instruments.
Preferred Stock - Based on quoted market prices for the same or similar
issues.
Long-Term Debt - Based upon the market yield of similar securities and
quoted market prices on the current rates for debt of the same remaining
maturities.
The estimated fair values of financial instruments at December 31, 1997
and 1996 are as follows:
1997 1996
Carrying Fair Carrying Fair
Value Value Value Value
Preferred stock 24.2 29.2 24.1 24.9
Long-term debt, including
current portion 165.2 173.0 171.4 177.9
NOTE 8. CAPITALIZATION
a. Common Shareowners' and Preferred Stock Investment
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 the amount
of $1.9 million at December 31, 1997 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 $1.0 million at December 31, 1997 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. This amortization has no effect on net income.
The Company's Common Stock Dividend Reinvestment and Stock Purchase Plan
provides for the option of issuing new stock or purchasing shares on the
open market. The Dividend Reinvestment Plan acquired 53,908, 39,326 and
176,971 shares of common stock on the open market during 1997, 1996 and
1995, respectively. The Company received $2.7 million for 89,955 shares
of new common stock in 1997 and $3.2 million for 106,579 shares of new
common stock issued in 1996. None of the authorized shares of preferred,
preference or common stock are reserved for officers and employees or for
options, warrants, conversions or other rights.
b. Long-Term Debt
In 1998, $5.85 million of 5.95% Pollution Control Bonds and $0.45 million
of 6.375% Pollution Control Bonds will mature. Total debt maturities for
the years 1998 through 2002 are $6.3, $0.4, $0.4, $0.4 and $0.4 million,
respectively.
Annual sinking fund requirements are $1.8 million for the years 1998
through 2001and $1.7 million for 2002. 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 1997 were met
by property additions.
NOTE 9. COMMITMENTS AND CONTINGENCIES
a. Purchased Power, Coal and Gas
The Company has entered into purchased power capacity, coal and gas
contracts. Its minimum commitments are as follows:
Power Gas Coal
Dollars MWs Dollars Therms Dollars Tons
1998 $27.8 280 $10.6 24,107 $32.6 950
1999 $28.5 280 $10.5 24,107 $14.0 450
2000 $28.2 280 $10.3 24,107 - -
2001 $9.0 25 $10.2 24,107 - -
2002 $2.0 25 $10.1 24,107 - -
Thereafter $2.0 25 $10.0 24,107 - -
The four purchased power contracts required annual capacity payments of
$27.0 million in 1997 and $26.6 million in 1996 and 1995. Over the
remaining period of the contracts, total capacity payments will be
approximately $97.3 million. In Iowa, 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. The 1996
rate order by the MPUC held that the Company had 100 MW of excess capacity
and disallowed recovery of approximately $0.8 million annually.
The Company has not filed for rate recovery of the allocable portions of
the purchased power payments in the Illinois and FERC jurisdictions.
Increased margins from sales growth in Illinois have largely offset the
revenue deficiency.
b. Environmental
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 (the Act) requires reductions in
certain emissions from power plants. The Company switched to a low sulfur
coal and installed low nitrogen oxide burners at the 217 MW plant affected
by Phase 1 of the Act, which became effective January 1, 1995. No
significant costs will be incurred to comply with Phase 2 environmental
standards, which take effect January 1, 2000.
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. As of year end 1997, soil remediation of the
site is complete, however, ground water monitoring continues. The
Company's total share of cost from 1984 to 1997 at this site was $2.7
million.
The Company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post remediation
groundwater monitoring is complete pending final review. From 1991 through
1997, the Company incurred costs aggregating $6.9 million applicable to
the Rochester site.
The Company has identified an additional seven sites, as described below,
which may contain hazardous waste from former coal gasification plants and
has recorded an estimated liability applicable to the investigation of
these sites. The Company is unable to determine, at this time, the extent
of remediation necessary at these seven sites.
In Minnesota, the Company owned or operated four manufactured gas plant
sites: Albert Lea, Austin, New Ulm and Owatonna. Potentially hazardous
wastes associated with former coal gasification operations have been
identified at each site. The Company incurred $0.2 million in
investigation cost for these sites in 1997 and $1.5 million since the
investigation process began.
The Company received accounting orders from the Minnesota Public Utilities
Commission (MPUC) which allows the deferral of investigation and
remediation costs applicable to the Minnesota sites and further allows the
Company to seek recovery in a rate case.
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 these sites. Little or no activity is expected at the Illinois sites in
1998. In 1997, $3.8 million was expensed for additional investigation and
remediation work expected at the Clinton site.
Previous actions by Iowa and Illinois regulators have permitted utilities
to recover prudently incurred unreimbursed investigation and remediation
costs.
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. Eight insurers paid the Company a total of $9.6
million in 1995 and 1996 in order to be discharged from the lawsuit. As of
December 31, 1997, $4.8 million is recorded as a deferred credit pending
regulatory disposition. Neither the Company nor its legal counsel is able
to predict the amount of any additional insurance recovery, and no
potential recovery has been recorded.
c. Planned Capital Expenditures
Plans for the construction and financing of future additions to utility
plant can be found elsewhere in this report in "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
NOTE 10. SEGMENT INFORMATION
The following table sets forth certain information relating to the
Company's operations:
1997 1996 1995
Operation information:
Customer revenues--
Electric $277.3 $276.6 $274.9
Gas 54.5 49.5 43.7
Operating income
Electric $52.8 $54.8 $57.3
Gas 2.7 4.1 9.5
Investment information:
Identifiable assets,
including allocated
common plant at
December 31--
Electric-utility $452.0 $455.4 $459.3
Gas-utility 42.6 42.3 39.3
Other information:
Construction expenditures--
Electric-utility $26.3 $25.7 $26.6
Gas-utility 2.6 5.3 2.0
Depreciation and amortization
expense
Electric $29.4 $28.9 $27.4
Gas 2.3 2.2 2.1
NOTE 11. QUARTERLY INFORMATION
(Unaudited)
The following table sets forth quarterly information relating to the
Company's operations:
(Thousands of Dollars)
(Except Earnings Per Share)
1997 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $88,873 $71,211 $88,857 $82,906
Operating income 12,916 7,383 14,143 6,343
Net income 9,332 4,119 10,948 4,769
Earnings per share of 0.90 0.36 1.05 0.42
common stock
1996 March 31 June 30 Sept. 30 Dec. 31
Operating revenues $87,049 $76,298 $83,482 $79,255
Operating income 13,140 7,649 12,762 10,196
Net income 9,541 3,927 9,821 5,034
Earnings per share of 0.93 0.34 0.95 0.45
common stock
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. Net income for the fourth
quarter of 1997 was $4.8 million, compared with $5.0 million in 1996.
Factors contributing to the lower net income included decreased gas sales,
increased operation and maintenance expense, and the recognition of
insurance proceeds to offset previously incurred legal expenses.
Total electric sales for the fourth quarter of 1997 decreased 3.8% over
the same period in 1996. Residential electric sales increased 0.3%, while
commercial and farm sales decreased 3.0% primarily due to decreased crop
drying. Large power and light sales increased 3.4%.
Total gas volumes decreased 3.6%, due primarily to warm weather. Gas
revenues were $16.1 million for the fourth quarter of 1997, compared to
$14.9 million for the fourth quarter of 1996. The increased revenues
reflect rate increases.
Maintenance expense for the fourth quarter of 1997 was $5.2 million
compared to $3.8 million for the fourth quarter of 1996. The variation for
the fourth quarter is primarily due to differences in the timing of
maintenance projects. For the calendar year, maintenance expense for 1997
was $17.8 million, compared to $16.2 million for 1996.
Other operating expense for the fourth quarter of 1997 reflects the
recognition of approximately $1.9 million received from insurance
companies in partial settlement of environmental litigation proceedings.
The proceeds offset environmental litigation expenses incurred by the
company in 1997. Other operating expense for the fourth quarter of 1997
also reflects a provision of $3.8 million related to anticipated future
environmental investigation expense.
Other operating expense includes expenses for the proposed merger of
Interstate Power Company, IES Industries and WPL Holdings were $0.7
million in the fourth quarter of 1997, compared to $1.2 million for the
fourth quarter of 1996.
Depreciation expense was $8.0 million for the fourth quarter of 1997,
compared to $7.9 million for the corresponding period of 1996. The small
increase is attributable to increased investment in plant.
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, 1997 and
1996 and the related statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1997.
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, 1997 and
1996 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Davenport, Iowa
January 29, 1998
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 included amounts based on informed judgments 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/ Michael R. Chase
Michael R. Chase
Executive Officer
President and Chief
Selected Financial Data
1997 1996 1995 1994 1993
Operating Revenues $331,847 $326,084 $318,542 $307,650 $309,468
-------- -------- -------- -------- --------
Operation 210,181 202,440 190,199 202,545 204,871
Maintenance 17,782 16,164 14,881 17,160 16,771
Depreciation and amortization 31,676 31,087 29,560 28,212 26,955
Income taxes 14,715 16,582 20,635 7,913 8,967
Property and other taxes 16,708 16,064 15,990 16,298 17,080
------- ------- ------- ------- -------
291,062 282,337 271,265 272,128 274,644
------- ------- ------- ------- -------
Operating income 40,785 43,747 47,277 35,522 34,824
Other income (deductions) - net 3,819 798 (2,826) 1,990 780
------- ------- ------- ------- -------
Income before interest charges 44,604 44,545 44,451 37,512 35,604
Interest charges 15,436 16,222 16,795 16,845 16,617
------- ------- ------- ------- -------
Net income 29,168 28,323 27,656 20,667 18,987
Preferred dividends 2,469 2,463 2,458 2,454 2,861
------- ------- ------- ------- -------
Earnings available for common
stock $26,699 $25,860 $25,198 $18,213 $16,126
========= ========= ========= ========= =========
Average number of common shares
outstanding 9,724,974 9,593,664 9,564,287 9,478,741 9,316,387
========= ========= ========= ========= =========
Earnings per common share $2.74 $2.69 $2.63 $1.92 $1.73
========= ========= ========= ========= =========
Common dividends declared per
share $2.08 $2.08 $2.08 $2.08 $2.08
========= ========= ========= ========= =========
Total assets $638,749 $639,200 $634,316 $628,845 $604,361
========= ========= ========= ========= =========
Long-term debt and mandatory
sinking fund preferred stock $189,997 $195,878 $212,916 $212,965 $227,007
========= ========= ========= ========= =========
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, 1997,
there were 12,446 holders of common stock and 138 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, 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
March 31, 1996 $0.52/Share 33 1/2 - 30 9,564,287
June 30, 1996 $0.52/Share 32 1/2 - 29 7/8 9,565,211
Sept. 30, 1996 $0.52/Share 32 1/2 - 28 7/8 9,574,607
Dec. 31, 1996 $0.52/Share 31 1/2 - 28 3/4 9,593,664
March 31, 1997 $0.52/Share 30 1/4 - 28 1/8 9,621,936
June 30, 1997 $0.52/Share 29 5/8 - 27 7/8 9,659,206
Sept. 30, 1997 $0.52/Share 32 1/8 - 29 1/8 9,696,735
Dec. 31, 1997 $0.52/Share 37 1/2 - 31 5/8 9,724,974