EX-13
INTERSTATE POWER COMPANY
Annual Report to Stockholders
1996
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 several
federal and state regulatory agencies. The companies expect to receive
regulatory approvals by the end of the third 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 886,000 electric customers and 375,000
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 IPC'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 22, 1997, the Board of Directors of WPLH declared a
quarterly dividend of 50 cents per share. This represents an equivalent
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 385,000 and 150,000 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.
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 336,000 and 176,000 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 IPC, 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 $63 million in 1996, versus $61
million in 1995. 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 $31, $29 and $41 million in 1996, 1995 and
1994, respectively. For the five year period from 1997 through 2001,
construction expenditures are estimated to be $218 million. The company
anticipates that approximately 75% of the construction funds for years
1997 and 1998 will be generated internally. The 1997 and 1998 construction
programs are estimated to be $36 and $45 million, respectively. Budgeted
construction expenditures for 1997 and 1998 include approximately $10
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 $75 million in short-term debt. At year
end 1996, a $42.5 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 1996, the company had $28.7
million of commercial paper payable. The company anticipates that short-
term debt will increase to $52 million at year end 1997 due to
construction outlays and the retirement of $17 million of 6 1/8% First
Mortgage Bonds which mature on May 1, 1997.
At December 31, 1996, 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 3.8 times for 1996, 3.7 times for 1995 and 2.7 times for 1994.
The company's stock price decreased from $33.125 at year end 1995 to $29
at year end 1996. 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
anticipates that it will resume open market purchases to satisfy the
Dividend Reinvestment and Stock Purchase Plan requirements in mid 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.
NEW ACCOUNTING GUIDANCE
Statements of Position (SOP) 96-1 on environmental liabilities was issued
by the American Institute of Certified Public Accountants in 1996. The
company has reviewed the requirements of the SOP and is in compliance with
its provisions.
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
annual capacity payments of $24.6 million in 1996, 1995 and 1994. Over the
remaining life of the contracts, total capacity payments will be
approximately $111 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 approximately $2.5 million
of the purchased power payments in the Illinois and FERC jurisdictions.
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 switched to low sulfur coal and installed low nitrogen oxide
burners. 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.
COAL TAR DEPOSITS
Early this century, various utilities including the company operated
plants which 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.
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 1996, remediation of the site is
almost complete. The company's total share of cost from 1984 to 1996 at
this site was $3.7 million.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post-remediation
groundwater monitoring is underway. From 1991 through 1996, the company
incurred costs aggregating $6.8 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
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 1996, and $1.2 million since the
investigation process began.
In 1995 and 1996, the company received accounting orders from the MPUC
which allow 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
1997. In 1996, $0.4 million was expensed for investigation work expected
at the Clinton site in 1997.
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. Seven insurers paid the company a total of $8.6
million in 1995 and 1996 in order to be discharged from the lawsuit. As of
December 31, 1996, $5.8 million is recorded as a deferred credit pending
regulatory disposition. 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 additional insurance
recovery, and no potential recovery has been recorded.
LARGE ELECTRIC CUSTOMERS
The company's six largest electric customers consumed a total of 1,744,557
MWH of electricity in 1996, which accounts for over 31 percent of total
MWH sales. These customers are involved in the production of agricultural,
chemical and cement products and their usage is generally not affected by
weather variations. Electric consumption by these customers decreased 0.4
percent from 1995, while 1995 consumption was 4.9 percent over 1994. The
aggregate 1996 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 reviews.
The company's Minnesota rates recover jurisdictional demand side
management expenditures and lost revenues. Other operating expenses for
1996, 1995 and 1994 include $1.0, $0.6 and $0.5 million, respectively, for
the amortization of Minnesota costs. A 1994 Iowa Utilities Board (IUB)
order allows recovery over a four year period of $6.7 million of deferred
Iowa costs incurred through 1992; such recovery began October 1994. Other
operating expenses for 1996 and 1995 include $1.2 million for the
amortization of Iowa costs. As of December 31, 1996 and 1995, the total
demand side management costs deferred were $29.9 and $23.1 million,
respectively. Of the $29.9 million deferred, approximately $7.9 million
relates to costs incurred in 1996. The company filed in Iowa in 1996 for
recovery of $18.5 million of costs incurred from 1993 through 1995.
Management believes that the amounts deferred meet the criteria
established for recovery.
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
paid $1.1 million of transition costs in 1996 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 $2.2 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 to the company
applicable to taking ownership of the gas. Twenty-four large customers
currently purchase a majority of their gas requirements from producers or
gas marketers. Consumption for the three largest gas customers was up 0.6%
over 1995 and currently accounts for approximately 66% of system
throughput. The company's largest gas customer, which represents 32% of
the company's total gas throughput, is committed by contract for the next
five years.
RATE MATTERS
The company filed for rate increases in 1995 in the Iowa electric, Iowa
gas, Minnesota electric, and Minnesota gas jurisdictions. Revenues from
those jurisdictions comprise over 87% of total revenues. Such applications
sought to recover the costs associated with the purchased power contracts,
the environmental clean-up of former manufactured gas plant sites, 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. 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 refunded to customers approximately $250,000 collected in 1995 in
excess of the final order.
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. An IUB order granting an increase of $1.1 million was received
in August 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. 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 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 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.
As discussed under Demand Side Management Costs, the company filed in 1996
for recovery of Iowa costs incurred in 1995, 1994 and 1993.
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.
Current initiatives at the federal level propose to allow customers to
purchase energy from alternative power suppliers and then pay the local
utility a fee for delivery of the energy.
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.
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 $2.69 for 1996, compared with
$2.63 for 1995 and $1.92 for 1994. Increased sales, electric and gas rate
increases and continuing efforts to control costs contributed to the
increased earnings. The 1996 return on common equity was 12.9%, compared
with 13.0% for 1995 and 9.5% in 1994.
Electric residential sales for 1995 were unusually high primarily because
of warm and humid weather during the air conditioning season. The 1996
summer returned to a more normal weather pattern. KWH use per residential
customer was 7,972 for 1996, 8,280 for 1995, and 7,799 for 1994.
Electric "margin" represents electric revenue less certain other costs
(primarily fuel and purchased power). Electric margins for years 1996,
1995 and 1994 were $153.5, $151.8 and $138.9 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" represents gas revenue less
certain other costs (primarily purchased gas). The gas margins for 1996,
1995 and 1994 were $17.2, $17.3 and $14.5 million, respectively. An
increase in residential and commercial gas sales of 7.3% and 10.8%,
respectively, contributed to a higher gas margin, as did rate increases in
the states of Minnesota and Iowa. The gas margin for 1996 was depressed
due to a sharp increase in gas costs in December. Under existing purchased
gas adjustment clauses, there is a delay of at least a month in collecting
(or refunding) any variations in gas costs.
Other operating expenses were $53.1, $51.1 and $51.9 million for 1996,
1995 and 1994, respectively (excluding deferral of environmental costs as
ordered by the MPUC). Other operating expenses include $2.7 million for
1996 and $1.3 million for 1995 of merger related expenses. Other operating
expenses for the years 1996, 1995 and 1994, include $0.4, $1.0 and $1.7
million, respectively, for environmental investigation, remediation and
litigation costs.
Maintenance expense for 1996 was $16.2 million, compared to $14.9 million
in 1995 and $17.2 million in 1994. Several maintenance projects postponed
in 1995 were completed in 1996.
Depreciation expense was $30.6, $29.3 and $27.8 million, for 1996, 1995
and 1994, respectively. The increase is primarily due to additional
investment and the implementation of higher depreciation rates approved by
the MPUC.
The company and the Internal Revenue Service reached a settlement of
income tax audits in 1996, for tax years through 1994. To reflect the
settlement, the company recorded additional interest expense of $0.1
million.
Interest on long-term debt was $14.6, $14.8 and $15.4 million for 1996,
1995 and 1994, respectively. On May 1, 1997, $17 million of 6 1/8% First
Mortgage Bonds will be retired, and as of December 31, 1996, have been
classified as a current liability. As a result, the percentage of total
capitalization attributable to long-term debt has declined from 44.8% at
year end 1995 to 41.6% at year end 1996.
Other interest charges for 1996 were $1.9 million, compared with $2.3
million for 1995 and $1.8 million for 1994. Interest on commercial paper
payable was $1.6, $2.1 and $0.7 million for 1996, 1995 and 1994,
respectively. The decreased commercial paper interest expense is primarily
attributable to a lower average balance outstanding. At year end 1996, the
company had $28.7 million of short-term commercial paper payable, compared
with $39.3 million at year end 1995.
The company's investment in coal stockpiles was $13.3 million at December
31, 1996 and $15.8 million at December 31, 1995. 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 $2.3, $2.4 and $3.7 million at December 31,
1996, 1995 and 1994, respectively.
Statements of Income
For the years ended December 31 1996 1995 1994
(Thousands of Dollars)
OPERATING REVENUES:
Electric $276,620 $274,873 $261,730
Gas 49,464 43,669 45,920
Total operating revenues 326,084 318,542 307,650
OPERATING EXPENSES:
Operation:
Fuel for electric generation 57,560 62,164 61,384
Power purchased 61,556 57,566 58,339
Cost of gas sold 31,617 25,888 30,905
Other operating expenses 53,134 45,717 51,917
Maintenance 16,164 14,881 17,160
Depreciation and amortization 31,087 29,560 28,212
Income taxes:
Federal current 11,389 11,608 1,395
State current 3,434 3,549 454
Deferred taxes - net 2,787 6,506 7,092
Investment tax credit amortization (1,028) (1,028) (1,028)
Property and other taxes 16,064 15,990 16,298
Total operating expenses 283,764 272,401 272,128
OPERATING INCOME 42,320 46,141 35,522
OTHER INCOME AND DEDUCTIONS 2,225 (1,690) 1,990
INCOME BEFORE INTEREST CHARGES 44,545 44,451 37,512
INTEREST CHARGES:
Long-term debt 14,587 14,811 15,405
Other interest charges 1,885 2,325 1,772
Borrowed funds used during construction (250) (341) (332)
Total interest charges 16,222 16,795 16,845
NET INCOME 28,323 27,656 20,667
PREFERRED STOCK DIVIDENDS (2,463) (2,458) (2,454)
INCOME AVAILABLE FOR COMMON STOCK $ 25,860 $ 25,198 $ 18,213
EARNINGS PER AVERAGE COMMON SHARE
OUTSTANDING based on 9,593,664;
9,564,287 and 9,478,741 shares,
respectively $ 2.69 $ 2.63 $ 1.92
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
1996 1995
(Thousands of Dollars)
UTILITY PLANT:
In Service:
Electric:
Production $376,338 $374,489
Transmission 187,911 183,858
Distribution 234,320 221,645
General 53,847 54,232
Total Electric 852,416 834,224
Gas 68,047 63,303
920,463 897,527
Less - accumulated depreciation 426,471 402,685
493,992 494,842
Held for future use 591 590
Construction work in progress 3,129 3,095
Net utility plant 497,712 498,527
OTHER PROPERTY AND INVESTMENTS 453 555
CURRENT ASSETS:
Cash and cash equivalents 3,072 1,537
Accounts receivable, less reserves of $200 28,227 27,797
Inventories - at average cost:
Fuel 16,623 19,332
Materials and supplies 6,214 5,509
Prepaid pension cost 3,331 3,870
Prepaid income tax 9,483 6,690
Other prepayments and current assets 683 614
Total current assets 67,633 65,349
DEFERRED DEBITS:
Regulatory assets 66,786 62,841
Unamortized debt expense 5,710 5,915
Other 906 1,129
Total deferred debits 73,402 69,885
TOTAL $639,200 $634,316
The accompanying notes are an integral part of these financial statements.
Balance Sheets
CAPITALIZATION AND LIABILITIES
As of December 31
1996 1995
(Thousands of Dollars)
CAPITALIZATION, per accompanying statements:
Common stock, par value $3.50 per share;
authorized - 30,000,000 shares; issued and
outstanding - 9,670,866 in 1996 and
9,564,287 in 1995 $ 33,848 $ 33,475
Additional paid-in capital 105,959 103,145
Retained earnings 66,251 61,150
Total common equity 206,058 197,770
Preferred stock (optional sinking fund) 10,819 10,819
Preferred stock (mandatory sinking fund) 24,147 24,036
Long-term debt 171,731 188,880
Total capitalization 412,755 421,505
CURRENT LIABILITIES:
Commercial paper 28,700 39,300
Long-term debt maturing within one year 17,000 -
Accounts payable 14,013 11,868
Dividends payable - preferred stock 599 599
Payrolls accrued 3,291 2,846
Taxes accrued 16,953 16,758
Interest accrued 2,817 2,819
FERC Order 636 transition costs 2,200 3,200
Other 2,878 4,756
Total current liabilities 88,451 82,146
DEFERRED CREDITS AND OTHER NON-CURRENT
LIABILITIES:
Accumulated deferred income taxes 99,303 95,518
Accumulated deferred investment tax credits 17,013 18,041
Deferred pension cost 4,999 4,900
Accrued postretirement benefit cost 1,311 2,792
Environmental clean-up costs 7,234 6,860
Other 8,134 2,554
Total deferred credits and other non-current
liabilities 137,994 130,665
COMMITMENTS AND CONTINGENCIES (Notes 2, 8, 10,
11, 12 and 14)
TOTAL $639,200 $634,316
Statements of Cash Flows
For the years ended December 31
1996 1995 1994
(Thousands of Dollars)
RECONCILIATION OF NET INCOME TO CASH FLOWS
FROM OPERATING ACTIVITIES:
Net Income $28,323 $27,656 $20,667
Adjustment for non-cash items:
Depreciation and amortization 31,087 29,560 28,212
Deferred income taxes 4,916 6,912 5,488
Investment tax credit amortization (1,028) (1,028) (1,028)
Equity funds used during construction (AFUDC) (13) - (166)
Prepaid pension cost 99 74 9
Changes in assets and liabilities:
Accounts receivable - net (430) (5,447) 3,710
Inventories 2,016 4,599 (1,536)
Accounts payable and other current liabilities 73 (2,946) 4,324
Accrued and prepaid taxes (2,500) 2,379 (1,011)
Interest accrued (2) (111) (160)
Other prepayments and current assets 470 1,469 (656)
Rate refund payable (256) 256 -
Regulatory assets - deferred demand side
management costs (6,718) (6,177) (7,295)
Regulatory assets - other 2,648 794 (8,267)
Other operating activities 4,018 3,275 721
Cash flows from operating activities 62,703 61,265 43,012
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (30,734) (28,238) (40,600)
Borrowed funds used during construction (AFUDC) (250) (341) (332)
Other (243) 127 (670)
Cash flows from investing activities (31,227) (28,452) (41,602)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock 3,228 - 4,237
Issuance of long-term debt - - 13,250
Retirement of long-term debt (225) (14,225) (13,475)
Debt and stock discount and financing expenses - - (357)
Dividends on common and preferred stock (22,344) (22,288) (22,111)
Commercial paper - net (10,600) 3,700 15,500
Cash flows from financing activities (29,941) (32,813) (2,956)
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS $ 1,535 $ - $(1,546)
CASH AND CASH EQUIVALENTS:
Beginning of year $ 1,537 $ 1,537 $ 3,083
End of year $ 3,072 $ 1,537 $ 1,537
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of interest capitalized) $15,678 $16,655 $16,773
Income taxes $16,330 $11,134 $ 8,066
The accompanying notes are an integral part of these financial statements.
Statements of Capitalization
As of December 31 1996 1995
(Thousands of Dollars)
COMMON EQUITY $206,058 49.9% $197,770 46.9%
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% 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 (1,921) (1,990)
Unamortized Issuance Expense on 6.40%
Preferred Stock (101) (104)
Unamortized Call Premiums on Preferred Stock (1,081) (1,120)
24,147 5.9% 24,036 5.7%
LONG-TERM DEBT:
First Mortgage Bonds:
6 1/8% Series due 1997 - 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
144,000 161,000
Pollution Control Revenue Bonds:
5.95% due 1996 to 1998 6,075 6,300
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
30,725 30,950
Other Long-Term Debt 95 104
Unamortized Discount on Long-Term Debt (3,089) (3,174)
Total Long-Term Debt - net 171,731 41.6% 188,880 44.8%
TOTAL CAPITALIZATION $412,755 100.0% $421,505 100.0%
(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 1996 1995 1994
(Thousands of Dollars)
Retained Earnings, Beginning of Year $61,150 $55,893 $57,397
Net Income 28,323 27,656 20,667
Dividends on Common Stock (19,950) (19,941) (19,717)
Dividends on Preferred Stock (2,463) (2,458) (2,454)
Additional Minimum Liability for
Non-Qualified Pension Plan at
December 31 - net of taxes (809) - -
Retained Earnings, End of Year $66,251 $61,150 $55,893
NOTES TO FINANCIAL STATEMENTS
1. Summary of Accounting Policies
GENERAL
Interstate Power Company (company) is a 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
weather 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.
RECLASSIFICATIONS
Certain reclassifications have been made to the prior years financial
statements to conform with the presentation for 1996. Such
reclassifications had no impact on net income or stockholders' equity.
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. Actual results could differ from those estimates.
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 3.6% in 1996 and 3.5% in 1995 and
1994.
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.
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
5.8% for 1996, 6.0% for 1995 and 6.3% for 1994. 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.
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 an energy 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 energy adjustment clauses, but rather must be
addressed in base rates in a formal rate proceeding.
DEBT REACQUISITION PREMIUM
In accordance with normal regulatory practices, the company defers debt
redemption premiums and amortizes such costs over the life of the
replacement bonds.
REGULATORY ASSETS
Regulatory assets represent probable future revenue associated with
certain incurred costs. The company is subject to the provisions of SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation". In the
event that the Company's operations are no longer subject to the
provisions of SFAS 71, as a result of market-based pricing due to
regulatory or other charges, existing regulatory assets and liabilities
would have to be written off unless provisions are made to ensure their
recovery or refund.
Regulatory assets of $66.8 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) 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, 1996 and 1995, regulatory assets were as follows:
1996 1995
(Millions of Dollars)
Deferred income taxes (Note 9) $26.6 $27.8
Deferred demand side management (Note 12) 29.9 23.1
Environmental clean-up (Note 2) 6.4 6.2
FERC order No. 636 transition costs (Note 8) 2.2 3.2
Employee/retiree benefits (Note 7) 1.7 2.5
Total $66.8 $62.8
CONCENTRATION OF SALES
The company provides service to six large electric customers which account
for over 31% of total 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.
In addition, the company provides electric service to 165,000 electric
customers in 234 communities and 49,000 gas customers in 39 communities.
Credit risk for these customers is spread over a diversified base of
residential, commercial and small industrial customers.
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 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. Additional 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 1996, remediation of the site is
almost complete. The company's total share of cost from 1984 to 1996 at
this site is $3.7 million.
The company formerly operated a manufactured gas plant in Rochester,
Minnesota. Soil remediation was completed in 1995 and post-remediation
groundwater monitoring is underway. From 1991 through 1996, the company
incurred costs aggregating $6.8 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 1996 and $1.2 million since the
investigation process began.
In 1995 and 1996, 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
1997. In 1996, $0.4 million was expensed for investigation work expected
at the Clinton site in 1997.
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. Seven insurers paid the company a total of $8.6
million in 1995 and 1996 in order to be discharged from the lawsuit. As of
December 31, 1996, $5.8 million is recorded as a deferred credit pending
regulatory disposition. 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 additional insurance
recovery, and no potential recovery has been recorded.
3. Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments at year
end 1996 and 1995 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 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 $2.0 million as of year end 1996 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 1996 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.
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 39,326; 176,971
and 44,868 shares of common stock on the open market during 1996, 1995 and
1994, respectively. The company received $3.2 million for 106,579 shares
of new common stock issued in 1996 and $4.2 million for 174,446 shares of
new common stock issued in 1994. 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, 1997, $17 million of 6 1/8% First Mortgage Bonds will mature and
are classified as a current liability on the December 31, 1996, balance
sheet. Total debt maturities for the years 1997 through 2001 are $17.2,
$6.3, $0.4, $0.4 and $0.4 million, respectively.
Annual sinking fund requirements are $1.8 million for the years 1997
through 2001. 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 1996 were met by property
additions.
6. Short-Term Borrowings
The company had bank lines of credit aggregating $42.5 million at December
31, 1996. 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 1996, 1995 and 1994 was
$32.8, $46.8 and $35.6 million, respectively, all in commercial paper,
with the average outstanding borrowing during the year of $27.0, $36.2 and
$15.6 million, respectively. The average interest rate on borrowings was
5.48%, 5.96% and 4.73% for the years 1996, 1995 and 1994, respectively. At
December 31, 1996, the interest rate was 5.48%.
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,
1996, 1995 and 1994 were $3.7, $3.4 and $3.4 million, respectively. In
addition to the pension plan, the company has an unfunded non-qualified
supplemental retirement plan (SRP) which, as amended in 1995, provides a
retirement benefit for officers of the company. Although the SRP has no
assets, the company purchases corporate owned life insurance to provide
funding for future cash requirements. The cash value of such insurance was
$0.9 million, $0.6 million and $0.4 million as of December 31, 1996, 1995
and 1994 respectively. The total accumulated benefit obligation for the
SRP at December 31, 1996, was $2.9 million.
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. The company recognized an
additional minimum liability on the balance sheet in 1996 for the plan in
which the accumulated benefit obligation exceeded the fair value of plan
assets.
Qualified Pension Plan
Cost Components 1996 1995 1994
(Thousands of Dollars)
Service cost $ 2,312 $ 2,302 $ 2,599
Return on plan assets (3,631) (3,513) (1,646)
Interest cost on projected benefit
obligation 3,680 3,629 3,569
Net amortization and deferral 126 146 (1,259)
Net pension cost $ 2,487 $ 2,564 $ 3,263
The assumptions used for measurement purposes are as follows:
Discount rate for obligation 7.5% 7.5% 7.5%
Discount rate for expense 7.5% 7.5% 7.0%
Assumed rate of compensation increase 5.0% 5.0% 5.0%
Expected long-term rate of return 8.0% 8.0% 7.0%
Reconciliation of Funded Status of Qualified Pension Plan as of
November 1:
Plan assets at fair value $51,343 $48,698 $48,685
Vested benefit obligation $34,670 $33,058 $35,057
Nonvested benefit obligation 1,296 1,825 2,365
Accumulated benefit obligation 35,966 34,883 37,422
Additional benefits based on
estimated future salary levels 15,662 16,624 13,130
Projected benefit obligation $51,628 $51,507 $50,552
Plan assets greater or (less) than
the projected benefit obligation $ (285) $(2,809) $(1,867)
Unrecognized net obligation at
October 31, 1986, being amortized
over 16.1 years 2,071 2,412 2,753
Unrecognized prior service cost 2,125 904 3,316
Unrecognized net (gain)loss 1,812 4,604 473
Net prepaid pension cost $ 5,723 $ 5,111 $ 4,675
In addition to providing pension benefits, the company provides life
insurance for retired employees and health care benefits for 921 retirees
and spouses. Substantially all of the company's 882 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 $4.3, $4.1 and $4.9 million for 1996, 1995 and 1994,
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 1996 cost of postretirement benefits would increase by
$0.6 million and the accumulated benefit obligation would increase by $5.0
million.
The table below sets forth the postretirement health care plan's
accumulated benefit obligation (in thousands):
1996 December 31, 1996 January 1, 1996
Retirees $25,954 $21,168
Active plan participants 14,014 13,141
Total accumulated benefit obligation 39,968 34,309
Less fair value of plan assets 11,066 6,640
Accumulated postretirement benefit
obligation in excess of plan assets 28,902 27,669
Unrecognized net gain or (loss) (3,412) 812
Unrecognized transition obligation (22,728) (23,991)
Accrued postretirement benefit cost $ 2,762 $ 4,490
The components of the estimated cost of postretirement benefits other than
pensions for the twelve months ended December 31, 1996 and 1995, are as
follows (in thousands):
1996 1995
Service cost $1,198 $1,097
Return on plan assets (507) (440)
Interest cost on accrued postretirement
benefit obligation 2,486 2,291
Amortization of transition obligation 1,543 1,543
Net amortization and deferral (388) (377)
Net cost $4,332 $4,114
The assumptions used for measurement purposes are as follows:
1997 1996
Discount rate for obligations 7.5% 7.5%
Discount rate for expense 7.5% 7.5%
Initial medical cost trend rate 8.0% 8.0%
Ultimate medical cost trend rate 6.0% 6.0%
Year that the medical cost trend rate
is assumed to decrease to the ultimate rate 1998 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. A December 1995 Iowa Utilities Board (IUB) order allowed an
annual increase of $6.6 million.
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. An IUB order granting an increase of $1.1 million was received
in August 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. On April 10, 1996, the Commission issued an order allowing an
increase in electric rates of $2.3 million. Rates reflecting the increase
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. 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.
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 $2.2
million payable in declining annual installments from 1997 to 2006. 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, 1996, includes regulatory
assets and deferred tax liabilities in an equal amount of $26.6 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, 1996 and 1995, balance sheet
are shown below:
Item: Thousands of Dollars
1996 1995
Property $86,737 $84,865
Energy Conservation Costs 10,262 7,589
Call Premiums on Reacquired Bonds 1,889 1,948
Environmental Costs - Net (2,626) (188)
Unbilled Revenue (3,474) (3,348)
Other (2,968) (2,038)
Total $89,820 $88,828
Gross deferred assets $(9,483) $(6,690)
Gross deferred liabilities 99,303 95,518
Total $89,820 $88,828
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.
1996 1995 1994
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 5.2% 5.7% 4.0%
Investment tax credit amortization (2.2%) (2.2%) (3.4%)
Excess book over tax depreciation 1.3% 1.5% 2.0%
Other (0.3%) 1.3% (6.8%)
Overall effective income tax rate 39.0% 41.3% 30.8%
The current and deferred tax expense is comprised of (in thousands):
1996 1995 1994
Federal and state currently payable $14,823 $15,157 $ 1,849
Deferred income tax - federal and state:
Additional tax depreciation - net 3,004 3,673 3,270
Energy efficiency costs 2,674 2,394 2,413
Environmental costs - net (2,437) 166 2,010
Other (455) 273 (601)
Investment tax credit amortization (1,028) (1,028) (1,028)
Federal and state currently payable -
other income and deductions 1,551 (1,182) 1,276
Total $18,132 $19,453 $ 9,189
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, 1996 and 1995,
included in utility plant were $82.4 and $82.0 million, respectively, and
the accumulated provision for depreciation was $43.3 and $40.8 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 purchased
power agreement are approximately $13.7 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, 1996
and 1995, was $24.7 and $24.8 million, respectively, and the accumulated
provision for depreciation was $10.2 and $9.6 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.
11. Purchased Power Contracts
The company has three long-term purchased power 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 purchased power contracts required annual capacity payments of
$24.6 million in 1996, 1995 and 1994. Over the remaining period of the
contracts, total capacity payments will be approximately $111 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. 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.
Increased margins from sales growth in Illinois have largely offset the
revenue deficiency.
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 $1.0 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 costs over a four year period. The company filed in 1996 for recovery
of $18.5 million of costs incurred from 1993 through 1995. As of December
31, 1996 and 1995, the amounts deferred were $29.9 and $23.1 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
reflect seasonal and timing variations which are common in the utility
industry.
(Thousands of Dollars)
(Except Earnings Per Share)
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 8,769
Net income 9,541 3,927 9,821 5,034
Earnings per share of common stock .93 .34 .95 .45
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
Net income for the fourth quarter of 1996 was $5.0 million, compared with
$4.3 million in 1995. Factors contributing to the higher net income
included increased electric and gas sales, decreased maintenance expense,
and the recognition of insurance proceeds to offset previously incurred
legal expenses.
Total electric sales for the fourth quarter of 1996 increased 3.9% over
the same period in 1995. Residential electric sales increased 1.2%, while
commercial and farm sales increased 7.1% primarily due to increased crop
drying. Large power and light sales increased 2.7%.
Total gas volumes increased 6.0%, due primarily to a 7.2% increase in
transportation gas volumes. Gas revenues were $14.9 million for the fourth
quarter of 1996, compared to $13.6 million for the fourth quarter of 1995.
The increased revenues reflect increased residential and commercial sales
due to colder temperatures.
Maintenance expense for the fourth quarter of 1996 was $3.8 million
compared to $4.1 million for the fourth quarter of 1995. The variation for
the fourth quarter is primarily due to differences in the timing of
maintenance projects. For the calendar year, maintenance expense for 1996
was $16.2 million, compared to $14.9 million for 1995.
Other operating expense for the fourth quarter of 1996 reflects the
recognition of approximately $2.5 million received from insurance
companies in partial settlement of environmental litigation proceedings.
The proceeds offset environmental litigation expenses incurred by the
company in 1996. Other operating expense for the fourth quarter of 1996
also reflects a provision of $0.4 million related to anticipated future
environmental investigation expense.
Other operating expense for the proposed merger of Interstate Power
Company, IES Industries and WPL Holdings were $1.2 million in the fourth
quarter of 1996, compared to $1.3 million for the fourth quarter of 1995.
Depreciation expense was $7.9 million for the fourth quarter of 1996,
compared to $7.5 million for the corresponding period of 1995. The
increase is attributable to increased investment in plant and the
implementation of higher depreciation rates.
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 $78.8 million.
The company has three natural gas supply contracts, three natural gas
transportation contracts, and three natural gas storage contracts, which
collectively obligate the company for a minimum annual commitment of
approximately $11.1 million. Such agreements individually expire from 1998
through 2002.
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, 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 several
federal and state regulatory agencies. The companies expect to receive
regulatory approvals by the end of the third quarter of 1997.
The summary below contains selected unaudited pro forma financial data for
the year ended December 31, 1996. The financial data should be read in
conjunction with the historical consolidated financial statements and
related notes of the Company, WPLH and IES and in conjunction with the
unaudited pro forma combined financial statements and related notes of
Interstate Energy included in the Form 10-K Annual Report of Interstate
Power Company.
PRO FORMA
COMBINED
IES WPLH IPC (Unaudited)
(in thousands)
Operating Revenues $ 973,912 $ 932,844 $326,084 $2,232,840
Income from Continuing
Operations $ 60,907 $ 73,205 $ 25,860 $ 159,972
Earnings per share from
Continuing Operations $ 2.04 $ 2.38 $ 2.69 $ 2.12
Assets at December 31,
1996 $2,125,562 $1,900,531 $639,200 $4,665,293
Long-term debt, net at
December 31, 1996 $ 744,298 $ 430,190 $188,731 $1,363,219
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 IPC'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 22, 1997, the Board of Directors of WPLH declared a
quarterly dividend of 50 cents per share. This represents an equivalent
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 385,000 and 150,000 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.
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 336,000 and 176,000 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 IPC, 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.
16. Segments of Business
Information about the company's operations in different segments of
business for 1996, 1995 and 1994 are shown in the table below.
Electric Gas Total
(Thousands of Dollars)
1996
Revenue $276,620 $49,464 $326,084
Operating income (Before income taxes) $ 54,835 $ 4,066 $ 58,901
Depreciation and amortization expense $ 28,919 $ 2,168 $ 31,087
Capital expenditures $ 25,738 $ 5,259 $ 30,997
Utility plant - net $455,368 $42,344 $497,712
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 $ 1,996 $ 28,579
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
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, 1996 and
1995 and the related statements of income, retained earnings and of cash
flows for each of the three years in the period ended December 31, 1996.
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, 1996 and
1995 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Davenport, Iowa
January 30, 1997
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/ Michael R. Chase
Michael R. Chase
President and Chief
Executive Officer
Selected Financial Data
1996 1995 1994 1993 1992
(Thousands of Dollars)
Operating revenues $326,084 $318,542 $307,650 $309,468 $285,298
Operation 203,867 191,335 202,545 204,871 181,391
Maintenance 16,164 14,881 17,160 16,771 16,966
Depreciation and
amortization 31,087 29,560 28,212 26,955 25,887
Income taxes 16,582 20,635 7,913 8,967 9,337
Property and other taxes 16,064 15,990 16,298 17,080 16,533
283,764 272,401 272,128 274,644 250,114
Operating income 42,320 46,141 35,522 34,824 35,184
Other income (deductions)
- net 2,225 (1,690) 1,990 780 724
Income before interest
charges 44,545 44,451 37,512 35,604 35,908
Interest charges 16,222 16,795 16,845 16,617 16,691
Net income 28,323 27,656 20,667 18,987 19,217
Preferred dividends 2,463 2,458 2,454 2,861 2,975
Earnings available for
common stock $ 25,860 $ 25,198 $ 18,213 $ 16,126 $ 16,242
Average number of common
shares outstanding 9,593,664 9,564,287 9,478,741 9,316,387 9,297,748
Earnings per common
share $ 2.69 $ 2.63 $ 1.92 $ 1.73 $ 1.74
Common dividends
declared per share $ 2.08 $ 2.08 $ 2.08 $ 2.08 $ 2.08
Total assets $639,200 $634,316 $628,845 $604,361 $558,100
Long-term debt and
mandatory sinking fund
preferred stock $195,878 $212,916 $212,965 $227,007 $207,958
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, 1996,
there were 13,904 holders of common stock and 152 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, 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
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 1/4 - 28 3/4 9,593,664