SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): March 15, 1995
IES UTILITIES INC.
(Exact name of registrant as specified in its charter)
Iowa 0-4117-1 42-0331370
(State or other jurisdiction (Commission (I.R.S. Employer
of incorporation) File No.) Identification No.)
IES Tower, Cedar Rapids, Iowa 52401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 319-398-4411
The purpose of this Current Report is to file certain
consolidated financial information regarding the Registrant (IES
Utilities Inc.). Such financial information is set forth in the
Financial Statements and Exhibits to this Current Report.
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits.
Page
(a) Financial Statements
Report of Management 4 - 5
Report of Independent Public Accountants 6
Consolidated Statements of Income for the years ended
December 31, 1994, 1993 and 1992 7
Consolidated Statements of Retained Earnings for the
years ended December 31, 1994, 1993 and 1992 8
Consolidated Balance Sheets as of December 31, 1994
and 1993 9 - 10
Consolidated Statements of Capitalization as of
December 31, 1994 and 1993 11
Consolidated Statements of Cash Flows for the years
ended December 31, 1994, 1993 and 1992 12
Notes to Consolidated Financial Statements 13 - 39
Management's Discussion and Analysis of the
Results of Operations and Financial Condition 40 - 56
Selected Consolidated Quarterly Financial
Data (Unaudited) 57
(b) Pro Forma Financial Information
None.
(c) Exhibits
3 Bylaws of Registrant, as amended February 7, 1995
12 Ratio of Earnings to Fixed Charges
23 Consent of Independent Public Accountants
27 Financial Data Schedule
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
IES UTILITIES INC.
(Registrant)
By /s/ Richard A. Gabbianelli
(Signature)
Richard A. Gabbianelli
Controller & Chief Accounting Officer
Date March 15, 1995
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits.
REPORT OF MANAGEMENT
The Company's management has prepared and is responsible
for the presentation, integrity and objectivity of the
consolidated financial statements and related information
included in this report. The consolidated financial
statements have been prepared in conformity with generally
accepted accounting principles applied on a consistent basis
and, in some cases, include estimates that are based upon
management's judgment and the best available information,
giving due consideration to materiality. Financial information
contained elsewhere in this report is consistent with that in
the consolidated financial statements.
The Company maintains a system of internal accounting
controls which it believes is adequate to provide reasonable
assurance that assets are safeguarded, transactions are
executed in accordance with management authorization and the
financial records are reliable for preparing the consolidated
financial statements. The system of internal accounting
controls is supported by written policies and procedures, by a
staff of internal auditors and by the selection and training
of qualified personnel. The internal audit staff conducts
comprehensive audits of the Company's system of internal
accounting controls. Management strives to maintain an
adequate system of internal controls, recognizing that the
cost of such a system should not exceed the benefits derived.
In accordance with generally accepted auditing standards, the
independent public accountants (Arthur Andersen LLP) obtained
a sufficient understanding of the Company's internal controls
to plan their audit and determine the nature, timing and
extent of other tests to be performed. Management is not
aware of any material internal control weaknesses.
The Board of Directors, through its Audit Committee
comprised entirely of outside directors, meets periodically
with management, the internal auditor and Arthur Andersen LLP
to discuss financial reporting matters, internal control and
auditing. To ensure their independence, both the internal
auditor and Arthur Andersen LLP have full and free access to
the Audit Committee.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Utilities Inc.:
We have audited the accompanying consolidated balance sheets
and statements of capitalization of IES UTILITIES INC. (an
Iowa corporation) AND SUBSIDIARY COMPANIES as of
December 31, 1994 and 1993, and the related consolidated
statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1994.
These financial statements are the responsibility of the
Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management,
as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial
position of IES Utilities Inc. and subsidiary companies as of
December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 1994, in conformity with
generally accepted accounting principles.
As discussed in Note 7 to the consolidated financial
statements, effective January 1, 1993, IES Utilities Inc. and
subsidiary companies changed their method of accounting for
postretirement benefits other than pensions.
ARTHUR ANDERSEN LLP
Chicago, Illinois,
February 3, 1995
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1994 1993 1992
(in thousands)
Operating revenues:
Electric $ 537,327 $ 550,521 $ 462,999
Gas 139,033 154,318 139,455
Other 9,006 8,911 7,808
685,366 713,750 610,262
Operating expenses:
Fuel for production 85,952 87,702 73,368
Purchased power 68,794 93,449 74,794
Gas purchased for resale 95,340 109,122 101,605
Other operating expenses 132,281 123,210 119,607
Maintenance 49,542 46,219 39,573
Depreciation and amortization 75,316 69,407 64,107
Taxes other than income taxes 42,550 41,312 36,847
549,775 570,421 509,901
Operating income 135,591 143,329 100,361
Interest expense and other:
Interest expense 41,572 40,169 39,628
Allowance for funds used during
construction -3,910 -1,972 -3,177
Miscellaneous, net -1,247 -801 -2,104
36,415 37,396 34,347
Income before income taxes 99,176 105,933 66,014
Federal and state income taxes 37,966 37,963 20,723
Net income 61,210 67,970 45,291
Preferred dividend requirements 914 914 1,729
Net income available for common stock $ 60,296 $ 67,056 $ 43,562
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1994 1993 1992
(in thousands)
Balance at beginning of year $ 188,862 $ 153,106 $ 134,822
Add:
Net income 61,210 67,970 45,291
Deduct:
Cash dividends declared -
Common stock 52,000 31,300 24,721
Preferred stock, at stated rates 914 914 1,729
Other 0 0 557
Balance at end of year
($18,209,000 restricted as to
payment of cash dividends) $ 197,158 $ 188,862 $ 153,106
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS 1994 1993
(in thousands)
Property, plant and equipment, at original cost:
Utility -
Plant in service -
Electric $ 1,798,059 $ 1,708,757
Gas 158,115 147,956
Other 86,005 75,845
2,042,179 1,932,558
Less - Accumulated depreciation 880,888 813,312
1,161,291 1,119,246
Leased nuclear fuel, net of amortization 49,731 51,681
Construction work in progress 73,339 45,566
1,284,361 1,216,493
Other 1,824 0
1,286,185 1,216,493
Current assets:
Cash and temporary cash investments 2,135 18,313
Accounts receivable -
Customer, less reserve 12,051 22,679
Other 9,763 10,330
Income tax refunds receivable 3,450 3,082
Production fuel, at average cost 13,988 14,338
Materials and supplies, at average cost 26,699 26,861
Adjustment clause balances 1,433 0
Regulatory assets 20,145 14,225
Prepayments and other 29,546 30,985
119,210 140,813
Investments:
Nuclear decommissioning trust funds 33,779 28,059
Cash surrender value of life insurance policies 2,915 2,380
Other 1,085 1,258
37,779 31,697
Other assets:
Regulatory assets 192,955 148,592
Deferred charges and other 9,239 9,383
202,194 157,975
1,645,368 1,546,978
December 31
CAPITALIZATION AND LIABILITIES 1994 1993
(in thousands)
Capitalization (See Consolidated Statements of
Capitalization):
Common stock $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 197,158 188,862
Total common equity 509,627 501,331
Cumulative preferred stock 18,320 18,320
Long-term debt 380,404 480,074
908,351 999,725
Current liabilities:
Notes payable to associated companies 18,495 0
Short-term borrowings 37,000 24,000
Capital lease obligations 14,385 15,345
Maturities and sinking funds 100,140 224
Accounts payable 70,354 47,179
Accrued interest 9,438 9,438
Accrued taxes 47,188 39,763
Accumulated refueling outage provision 15,196 2,660
Dividends payable 229 5,229
Adjustment clause balances 0 5,149
Provision for rate refund liability 0 8,670
Environmental liabilities 5,428 4,721
Other 18,095 17,648
335,948 180,026
Long-term liabilities:
Capital lease obligations 35,346 36,336
Environmental liabilities 37,853 21,114
Other 46,724 29,866
119,923 87,316
Deferred credits:
Accumulated deferred income taxes 241,345 237,464
Accumulated deferred investment tax credits 39,801 42,447
281,146 279,911
Commitments and contingencies (Note 11)
$ 1,645,368 $ 1,546,978
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1994 1993
(in thousands)
Common equity:
Common stock - par value $2.50 per share -
authorized 24,000,000 shares;
outstanding 13,370,788 shares $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 197,158 188,862
509,627 501,331
Cumulative preferred stock 18,320 18,320
Long-term debt of IES Utilities Inc.:
Collateral Trust Bonds -
6% series, due 2008 50,000 50,000
7% series, due 2023 50,000 50,000
5.5% series, due 2023 19,400 19,400
119,400 119,400
First Mortgage Bonds -
Series J, 6-1/4%, due 1996 15,000 15,000
Series L, 7-7/8%, due 2000 15,000 15,000
Series M, 7-5/8%, due 2002 30,000 30,000
Series W, 9-3/4%, due 1995 50,000 50,000
Series X, 9.42%, due 1995 50,000 50,000
Series Y, 8-5/8%, due 2001 60,000 60,000
Series Z, 7.60%, due 1999 50,000 50,000
6-1/8% series, due 1997 8,000 8,000
9-1/8% series, due 2001 21,000 21,000
7-3/8% series, due 2003 10,000 10,000
7-1/4% series, due 2007 30,000 30,000
339,000 339,000
Pollution control obligations -
5.75%, due serially 1995 to 2003 3,696 3,920
5.95%, due 2007, secured by
First Mortgage Bonds 10,000 10,000
Variable rate (5.45% - 5.60% at
December 31, 1994), due 2000 to 2010 11,100 11,100
24,796 25,020
Unamortized debt premium and (discount), net -2,652 -3,122
480,544 480,298
Less - Amount due within one year 100,140 224
380,404 480,074
908,351 999,725
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
1994 1993 1992
(in thousands)
Cash flows from operating activities:
Net income $ 61,210 $ 67,970 $ 45,291
Adjustments to reconcile net income to net cash
flows from operating activities -
Depreciation and amortization 75,316 69,407 64,107
Principal payments under capital lease obligations 16,246 11,429 11,725
Deferred taxes and investment tax credits -410 10,531 -2,406
Refueling outage provision 12,536 -4,889 -5,503
Allowance for equity funds used during construction -2,299 -824 -1,831
Other 3,240 1,613 1,134
Other changes in assets and liabilities -
Accounts receivable 10,395 -8,553 -571
Production fuel, materials and supplies 404 5,909 1,579
Accounts payable 20,444 5,620 345
Accrued taxes 7,057 -10,991 6,118
Provision for rate refunds -8,670 -350 7,528
Adjustment clause balances -6,582 6,366 -4,122
Gas in storage 1,919 -2,309 -7,867
Other 4,082 183 2,441
Net cash flows from operating activities 194,888 151,112 117,968
Cash flows from financing activities:
Dividends declared on common stock -52,000 -31,300 -24,721
Dividends declared on preferred stock -914 -914 -1,729
Equity infusion from parent company 0 50,000 0
Proceeds from issuance of long-term debt 0 119,400 83,400
Reductions in long-term debt and preferred stock -224 -79,624 -39,429
Net change in short-term borrowings 31,495 -68,560 51,660
Principal payments under capital lease obligations -16,304 -11,276 -12,337
Sale of utility accounts receivable 800 10,490 7,710
Other -5,000 5,010 231
Net cash flows from financing activities -42,147 -6,774 64,785
Cash flows from investing activities:
Construction and acquisition expenditures -148,062 -113,212 -171,013
Nuclear decommissioning trust funds -5,532 -5,532 -5,532
Deferred energy efficiency costs -16,157 -9,747 -6,877
Other 832 723 -3,009
Net cash flows from investing activities -168,919 -127,768 -186,431
Net increase (decrease) in cash and temporary cash investments -16,178 16,570 -3,678
Cash and temporary cash investments at beginning of year 18,313 1,743 5,421
Cash and temporary cash investments at end of year $ 2,135 $ 18,313 $ 1,743
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 42,678 $ 39,291 $ 35,770
Income taxes $ 34,479 $ 40,130 $ 23,640
Noncash investing and financing activities -
Capital lease obligations incurred $ 14,297 $ 14,605 $ 1,973
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation -
IES Utilities Inc. (Utilities) is a wholly-owned
subsidiary of IES Industries Inc. (Industries). The
Consolidated Financial Statements include the accounts of
Utilities and its consolidated subsidiaries (collectively the
Company). All subsidiaries for which Utilities owns directly
or indirectly more than 50% of the voting stock, which are IES
Ventures Inc. and IES Midland Development Inc., are included
as consolidated subsidiaries. Both of these subsidiaries were
formed in December 1994 and had no operations in 1994. All
significant intercompany balances and transactions have been
eliminated from the Consolidated Financial Statements.
Investments for which the Company has at least a 20%
interest are accounted for under the equity method of
accounting. These investments are stated at acquisition cost,
increased or decreased for the Company's equity in
undistributed net income or loss, which is included in
"Interest expense and other - Miscellaneous, net" in the
Consolidated Statements of Income.
Certain prior period amounts have been reclassified on a
basis consistent with the 1994 presentation.
(b) Regulation -
Utilities is subject to regulation by the Iowa Utilities
Board (IUB) and the Federal Energy Regulatory Commission
(FERC). Utilities' consolidated subsidiaries are not subject
to regulation by the IUB or the FERC.
(c) Regulatory Assets -
Utilities is subject to the provisions of Statement of
Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71). The
regulatory assets represent probable future revenue to
Utilities associated with certain incurred costs as these
costs are recovered through the rate making process. At
December 31, regulatory assets as reflected in the
Consolidated Balance Sheets were comprised of the following
items:
1994 1993
(in millions)
Deferred income taxes (Note 1(d)) $ 90.1 $ 88.6
Environmental liabilities (Note 11(f)) 43.8 25.4
Energy efficiency programs (Note 3(b)) 34.7 18.5
Employee pension and benefit costs (Note 7) 25.0 14.1
FERC Order No. 636 transition costs (Note 11(h)) 8.0 5.0
Unamortized loss on reacquired debt 6.1 6.4
Cancelled plant costs 2.4 3.3
Other 3.0 1.5
213.1 162.8
Classified as "Current assets - regulatory assets" 20.1 14.2
Classified as "Other assets - regulatory assets" $ 193.0 $ 148.6
Refer to the individual footnotes referenced above for a
further discussion of certain items reflected in regulatory
assets.
(d) 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. Deferred taxes are recorded using currently
enacted tax rates.
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 temporary differences reverse, the
related accumulated deferred income taxes are reversed to
income. Investment tax credits for Utilities have been
deferred and are subsequently credited to income over the
average lives of the related property.
Consistent with rate making practices for Utilities,
deferred tax expense is not recorded for certain temporary
differences (primarily related to utility property, plant and
equipment). Accordingly, Utilities has recorded deferred tax
liabilities and regulatory assets, as identified in Note 1(c).
(e) Temporary Cash Investments -
Temporary cash investments are stated at cost, which
approximates market value, and are considered cash equivalents
for the Consolidated Statements of Cash Flows. These
investments consist of short-term liquid investments which
have maturities of less than 90 days from the date of
acquisition.
(f) Depreciation of Utility Property, Plant and
Equipment -
The average rates of depreciation for electric and gas
properties of Utilities, including Utilities' nuclear
generating station, the Duane Arnold Energy Center (DAEC),
which is being depreciated over a 36-year life using a
remaining life method, consistent with current rate making
practices, were as follows:
1994 1993 1992
Electric 3.6% 3.5% 3.5%
Gas 3.8% 3.5% 3.0%
(g) Decommissioning of the DAEC -
Included in Utilities' proposed electric rate increase
discussed in Note 3(a) is a proposal to increase the annual
recovery of anticipated costs to decommission the DAEC to
approximately $9 million annually from the current level of
$5.5 million. Decommissioning expense is included in
"Depreciation and amortization" in the Consolidated Statements
of Income and the cumulative amount is included in
"Accumulated depreciation" in the Consolidated Balance Sheets
to the extent recovered through rates. The proposal is based
on the following assumptions: 1) cost to decommission the DAEC
of $252.7 million in 1993 dollars, based on the Nuclear
Regulatory Commission (NRC) minimum formula (which exceeds the
amount in the current site-specific study completed in 1994);
2) inflation of 4.91% annually to the year 2014, when
decommissioning is expected to begin; 3) the prompt
dismantling and removal method of decommissioning; 4) monthly
funding of all future collections into external trust funds
and funded on a tax-qualified basis to the extent possible; 5)
an average after-tax return of 6.82% for all external
investments; and 6) collection of the costs on a straight-line
basis, in real terms, through 2014. Current
levels of rate recovery: 1) do not recognize estimated future
inflation for the entire period prior to commencement of the
decommissioning process; 2) assume that decommissioning begins
in 2010; and 3) provide recovery on a straight-line basis
without considering the effects of inflation. At December 31,
1994, Utilities had $33.8 million invested in external
decommissioning trust funds as indicated in the Consolidated
Balance Sheets, and also had an internal decommissioning
reserve of $21.7 million recorded as accumulated depreciation.
Earnings on the external trust funds, which were $1.0 million
in 1994, are recorded as interest income and a corresponding
interest expense payable to the funds is recorded. The
earnings accumulate in the external trust fund balances and in
accumulated depreciation on utility plant.
See "Management's Discussion and Analysis of the Results
of Operations and Financial Condition" for a discussion of
industry issues raised by the staff of the SEC and a Financial
Accounting Standards Board review regarding the electric
utility industry method of accounting for decommissioning
costs.
(h) Allowance for Funds Used During Construction -
The allowance for funds used during construction (AFC),
which represents the cost during the construction period of
funds used for construction purposes, is capitalized by
Utilities as a component of the cost of utility plant. The
amount of AFC applicable to debt funds and to other (equity)
funds, a non-cash item, is computed in accordance with the
prescribed FERC formula. The aggregate gross rates used by
Utilities for 1994-1992 were 9.3%, 5.7% and 9.2%,
respectively.
(i) Operating Revenues -
The Company accrues revenues for services rendered but
unbilled at month-end in order to more properly match revenues
with expenses.
(j) Adjustment Clauses -
Utilities' tariffs provide for subsequent adjustments 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 Consolidated Statements of
Income. The cumulative effects are reflected in the
Consolidated Balance Sheets as a current asset or current
liability, pending automatic reflection in future billings to
customers.
(k) Accumulated Refueling Outage Provision -
The IUB allows Utilities to collect, as part of its base
revenues, funds to offset other operating and maintenance
expenditures incurred during refueling outages at the DAEC.
As these revenues are collected, an equivalent amount is
charged to other operating and maintenance expenses with a
corresponding credit to a reserve. During a refueling outage,
the reserve is reversed to offset the refueling outage
expenditures.
(2) ACQUISITION OF IOWA SERVICE TERRITORY OF UNION
ELECTRIC COMPANY:
Effective December 31, 1992, Utilities purchased the Iowa
distribution system and a portion of the Iowa transmission
facilities of Union Electric Company (UE) for approximately
$65 million in cash. The net book value of the acquired
assets was approximately $35 million and the amount of the
purchase price in excess of the book value (approximately $30
million) has been recorded as an acquisition adjustment. The
acquisition adjustment is being amortized over the life of the
property and the amortization is included in "Interest expense
and other - Miscellaneous, net" in the Consolidated Statements
of Income. Recovery of the acquisition adjustment through
rates has been requested in Utilities' current electric rate
filing, which is discussed in Note 3(a). See Note 11(b) for a
discussion of the purchase power contracts between Utilities
and UE associated with this acquisition.
(3) RATE MATTERS:
(a) 1994 Electric Rate Case -
In 1994, Utilities applied to the IUB for an increase in
retail electric rates of approximately $26 million annually,
or 5.2%. Utilities' proposal includes approximately
$12 million in annual revenue requirement related to increased
recovery levels of depreciation expense and nuclear
decommissioning expense. To the extent these proposals are
approved by the IUB, corresponding increases in expense would
be recorded and there would be no effect on net income. No
interim increase was requested.
The Office of Consumer Advocate (OCA) filed a petition in
connection with this proceeding to reduce the rates for retail
electric service by approximately $27 million or 5.5%. The
primary differences between the amount of the increase
requested by Utilities and the decrease proposed by the OCA
are: 1) a 13.9% return on common equity requested by Utilities
compared to 11.1% proposed by the OCA; 2) OCA's rejection of
Utilities' proposal to increase collections for
decommissioning the DAEC; 3) OCA's rejection of Utilities'
proposal to increase depreciation rates; 4) OCA's proposal to
reject most of Utilities' request to recover an acquisition
adjustment associated with its acquisition of the Iowa service
territory of UE; and 5) an adjustment to test year sales
levels proposed by the OCA. If a rate reduction is ultimately
ordered by the IUB, the reduction would be effective from
October 22, 1994, and revenues collected beyond that date
would be subject to refund to the extent of the reduction
approved by the IUB, if any. As of December 31, 1994,
Utilities' revenues collected subject to refund were
approximately $5 million.
Intervenors in the proceeding also submitted filings in
October 1994. These parties, which primarily represent
individual or groups of customers, generally object to
particular elements of the price increase and Utilities' price
design proposals. Those intervenors that quantified their
positions have generally argued for a price decrease, but none
as large as that proposed by the OCA.
Utilities expects to receive an order from the IUB in May
1995.
(b) 1994 Energy Efficiency Cost Recovery Filing -
The IUB has adopted rules that mandate Utilities to spend
2% of electric and 1.5% of gas gross retail operating revenues
for energy efficiency programs. Under provisions of the IUB
rules, in August 1994, Utilities applied to the IUB for
recovery of approximately $23 million and $13 million for the
electric and gas programs, respectively, related to costs
incurred through 1993 for such programs. The $36 million
total for the electric and gas programs is comprised of
$21 million of direct expenditures and carrying costs
(recorded as a "Regulatory asset" in the Consolidated Balance
Sheets, including $3.6 million as current), $7 million for a
return on the expenditures over the recovery period and
$8 million for a reward based on a sharing of the benefits of
such programs.
In October 1994, the OCA and an intervenor in the
proceeding filed their direct testimony. The principal
difference between Utilities and the other parties is
approximately $7 million in the reward calculation. Hearings
in the proceeding were held in January 1995. Any increase
approved by the IUB is not expected to be effective before
April 1995, and recovery will be over a four-year period with
a return allowed on the unrecovered portion over the recovery
period.
(4) LEASES:
Utilities has a capital lease covering its 70% undivided
interest in nuclear fuel purchased for the DAEC. Future
purchases of fuel may also be added to the fuel lease. This
lease provides for annual one-year extensions and Utilities
intends to exercise such extensions through the DAEC's
operating life. Interest costs under the lease are based on
commercial paper costs incurred by the lessor. Utilities is
responsible for the payment of taxes, maintenance, operating
cost, risk of loss and insurance relating to the leased fuel.
The lessor has an $80 million credit agreement with a
bank supporting the nuclear fuel lease. The agreement
continues on a year-to-year basis, unless either party
provides at least a three-year notice of termination; no such
notice of termination has been provided by either party.
Annual nuclear fuel lease expenses include the cost of
fuel, based on the quantity of heat produced for the
generation of electric energy, plus the lessor's interest
costs related to fuel in the reactor and administrative
expenses. These expenses (included in "Fuel for production"
in the Consolidated Statements of Income) for 1994-1992 were
$17.8 million, $12.4 million and $12.9 million, respectively.
The Company's operating lease rental expenses for
1994-1992 were $9.8 million, $8.4 million and $6.8 million,
respectively.
The Company's future minimum lease payments by year are
as follows:
Capital Operating
Year Lease Leases
(in thousands)
1995 $ 15,634 $ 7,023
1996 15,653 6,987
1997 12,942 4,591
1998 6,394 3,317
1999 4,176 2,544
2000 - 2002 1,267 -
56,066 $ 24,462
Less: Amount representing interest 6,335
Present value of net minimum
capital lease payments $ 49,731
(5) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled
revenues, arise primarily from the sale of electricity and
natural gas. At December 31, 1994, Utilities was serving a
diversified base of residential, commercial and industrial
customers consisting of approximately 330,000 electric and
173,000 gas customers.
Utilities has entered into an agreement, which expires in
1999, with a financial institution to sell, with limited
recourse, an undivided fractional interest of up to
$65 million in its pool of utility accounts receivable. At
December 31, 1994, $54 million was sold under the agreement.
(6) INCOME TAXES:
The components of Federal and state income taxes for the
years ended December 31, were as follows:
1994 1993 1992
(in millions)
Current tax expense $ 38.4 $ 27.5 $ 23.2
Deferred tax expense 2.2 15.4 0.3
Amortization and adjustment
of investment tax credits (2.6) (4.9) (2.8)
$ 38.0 $ 38.0 $ 20.7
The overall effective income tax rates shown below for
the years ended December 31, were computed by dividing total
income tax expense by income before income taxes.
1994 1993 1992
Statutory Federal income tax rate 35.0% 35.0% 34.0%
Add (deduct):
State income taxes, net of Federal benefits 6.1 5.8 5.6
Effect of property related temporary
differences for which deferred taxes
are not provided under rate making
principles 3.2 1.5 0.5
Amortization of investment tax credits (2.7) (2.5) (4.2)
Reversal through tariffs of deferred
taxes provided at rates in excess of
the current statutory Federal income
tax rate (1.5) (1.7) (2.7)
Adjustment of prior period taxes (1.9) (2.0) (2.0)
Other items, net 0.1 (0.3) 0.2
Overall effective income tax rate 38.3% 35.8% 31.4%
The accumulated deferred income taxes as set forth below
in the Consolidated Balance Sheets at December 31, arise from
the following temporary differences:
1994 1993
(in millions)
Property related $ 276 $ 272
Investment tax credit related (28) (30)
Decommissioning related (13) (12)
Other 6 7
$ 241 $ 237
(7) BENEFIT PLANS:
(a) Pension Plans -
The Company has one contributory and two non-contributory
retirement plans that, collectively, cover substantially all
of its employees. Plan benefits are generally based on years
of service and compensation during the employees' latter years
of employment. Payments made from the pension funds to
retired employees and beneficiaries during 1994 totaled
$9.7 million.
The Company's policy is to fund the pension cost at an
amount that is at least equal to the minimum funding require-
ments mandated by the Employee Retirement Income Security Act
(ERISA) and that does not exceed the maximum tax deductible
amount for the year.
Pursuant to the provisions of SFAS 71, certain
adjustments to Utilities' pension provision are necessary to
reflect the accounting for pension costs allowed in its most
recent rate cases.
The components of the pension provision for the years
ended December 31, were as follows:
1994 1993 1992
(in thousands)
Service cost $ 5,786 $ 4,275 $ 4,439
Interest cost on projected
benefit obligation 11,265 11,131 9,999
Assumed return on plans' assets (12,426) (12,177) (11,640)
Amortization of unrecognized gain (180) (763) (135)
Amortization of prior service cost 1,335 1,195 938
Amortization of unrecognized plans'
assets as of January 1, 1987 (329) (384) (382)
Pension cost 5,451 3,277 3,219
Adjustment to funding level (5,340) (2,867) 301
Total pension costs paid to the Trustees $ 111 $ 410 $ 3,520
Actual return on plans' assets $ (101) $ 12,718 $ 8,861
A reconciliation of the funded status of the plans to the
amounts recognized in the Consolidated Balance Sheets at
December 31, is presented below:
1994 1993
(in thousands)
Fair market value of plans' assets $ 165,267 $ 174,133
Actuarial present value of benefits rendered to date -
Accumulated benefits based on compensation to
date, including vested benefits of $96,968,000
and $100,905,000, respectively 107,017 110,676
Additional benefits based on estimated
future salary levels 39,565 42,938
Projected benefit obligation 146,582 153,614
Plans' assets in excess of projected benefit obligation 18,685 20,519
Remaining unrecognized net asset existing at
January 1, 1987, being amortized over 20 years (3,792) (4,109)
Unrecognized prior service cost 17,991 16,708
Unrecognized net gain (33,942) (28,830)
Prepaid (accrued) pension cost recognized in the
Consolidated Balance Sheets $ (1,058) $ 4,288
Assumed rate of return, all plans 8.00% 8.00%
Weighted average discount rate of projected benefit
obligation, all plans 8.25% 7.50%
Range of assumed rates of increase in future
compensation levels for the plans 4.00-5.75% 4.00-5.75%
(b) Other Postemployment Benefit Plans -
The Company provides certain benefits to retirees
(primarily health care benefits). Through 1992, the Company
expensed such costs as benefits were paid ($2.2 million for
1992), which was consistent with rate making practices at that
time.
Effective January 1, 1993, the Company adopted SFAS 106,
which requires the accrual of the expected cost of
postretirement benefits other than pensions during the
employees' years of service. The IUB has adopted rules
stating that postretirement benefits other than pensions will
be included in Utilities' rates pursuant to the provisions of
SFAS 106. The rules permit Utilities to amortize the
transition obligation as of January 1, 1993, over 20 years and
require that all amounts collected are to be funded into an
external trust to pay benefits as they become due. Beginning
in 1993, the gas portion of these costs is being recovered in
Utilities' gas rates, and is funded in external trust funds.
The IUB has adopted a rule that permits a deferral of the
incremental electric SFAS 106 costs until the earlier of: 1)
an order in an electric rate case, or 2) December 31, 1995.
Accordingly, pursuant to the provisions of SFAS 71, Utilities
had deferred $5.6 million of such costs at December 31, 1994.
Utilities has requested recovery of these costs in the
electric rate case discussed in Note 3(a).
The components of postretirement benefit costs for the
years ended December 31, were as follows:
1994 1993
(in thousands)
Service cost $ 1,785 $ 1,685
Interest cost on accumulated postretirement
benefit obligation 3,175 3,247
Actual return on plan assets (47) -
Amortization of transition obligation
existing at January 1, 1993 2,024 2,024
Amortization of unrecognized asset loss (13) -
Amortization of unrecognized gain (4) -
Amortization of prior service cost 19 -
Postretirement benefit costs 6,939 6,956
Less: Deferred postretirement benefit costs 2,732 2,858
Net postretirement benefit costs $ 4,207 $ 4,098
A reconciliation of the funded status of the plans to the
amounts recognized in the Consolidated Balance Sheets at
December 31, is presented below:
1994 1993
(in thousands)
Fair market value of plans' assets $ 1,127 $ 1,171
Accumulated postretirement benefit obligation -
Active employees not yet eligible 18,216 18,325
Active employees eligible 5,119 4,130
Retirees 18,161 20,140
Total accumulated postretirement benefit
obligation 41,496 42,595
Accumulated postretirement benefit obligation
in excess of plans' assets (40,369) (41,424)
Unrecognized transition obligation 36,439 38,463
Unrecognized net gain (5,358) (1,167)
Unrecognized prior service cost 170 -
Accrued postretirement benefit cost in the
Consolidated Balance Sheets $ (9,118) $ (4,128)
Assumed rate of return 8.00% 8.00%
Weighted average discount rate of
accumulated postretirement benefit
obligation 8.25% 7.50%
Medical trend on paid charges:
Initial trend rate 11.00% 12.00%
Ultimate trend rate 6.50% 6.50%
The assumed medical trend rates are critical assumptions
in determining the service cost and accumulated postretirement
benefit obligation related to postretirement benefit costs. A
1% change in the medical trend rates, holding all other
assumptions constant, would have changed the 1994 service cost
by $1.0 million (20%) and the accumulated postretirement
benefit obligation at December 31, 1994, by $6.6 million
(16%).
On January 1, 1994, the Company adopted the provisions of
SFAS 112, "Employers' Accounting for Postemployment Benefits,"
and its adoption did not have a material effect on the
Company's financial position or results of operations.
(8) PREFERRED AND PREFERENCE STOCK:
Utilities has 466,406 shares of Cumulative Preferred
Stock, $50 par value, authorized for issuance at
December 31, 1994, of which the 6.10%, 4.80% and 4.30% Series
had 100,000, 146,406 and 120,000 shares, respectively,
outstanding at both December 31, 1994 and 1993. These shares
are redeemable at the option of Utilities upon 30 days notice
at $51.00, $50.25 and $51.00 per share, respectively, plus
accrued dividends. In addition, there are 700,000 shares of
Utilities Cumulative Preference Stock ($100 par value)
authorized for issuance, of which none were outstanding at
December 31, 1994.
(9) DEBT:
(a) Long-Term Debt -
Utilities' Indentures and Deeds of Trust securing its
First Mortgage Bonds constitute direct first mortgage liens
upon substantially all tangible public utility property.
Utilities' Indenture and Deed of Trust securing its Collateral
Trust Bonds constitutes a second lien on substantially all
tangible public utility property while First Mortgage Bonds
remain outstanding.
Total sinking fund requirements, which Utilities intends
to meet by pledging additional property under the terms of
Utilities' Indentures and Deeds of Trust, and debt maturities
for 1995-1999 are as follows:
Debt Maturities
(in thousands)
Debt Issue 1995 1996 1997 1998 1999
Sinking fund
requirements $ 780 $ 630 $ 550 $ 550 $ 550
Pollution control 140 140 140 140 140
Series W 50,000 - - - -
Series X 50,000 - - - -
Series J - 15,000 - - -
6-1/8% Series - - 8,000 - -
Series Z - - - - 50,000
Total $ 100,920 $ 15,770 $ 8,690 $ 690 $ 50,690
The Company intends to refinance the majority of the debt
maturities with long-term securities.
(b) Short-Term Debt -
At December 31, 1994, the Company had bank lines of
credit aggregating $67.7 million, of which $37 million was
being used to support commercial paper (weighted average
interest rate of 6.13%) and $7.7 million was being used to
support certain pollution control obligations. Commitment
fees are paid to maintain these lines and there are no
conditions which restrict the unused lines of credit. In
addition to the above, Utilities has an uncommitted credit
facility with a financial institution whereby it can borrow up
to $40 million. Rates are set at the time of borrowing and no
fees are paid to maintain this facility. At
December 31, 1994, there were no borrowings under this
facility. Utilities also has a letter of credit in the amount
of $3.4 million supporting two of its variable rate pollution
control obligations.
(10) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair values of financial instruments at
December 31, 1994, and the basis upon which they were
estimated are as follows:
(a) Current Assets and Current Liabilities -
The carrying amount approximates fair value because of
the short maturity of such financial instruments.
(b) Nuclear Decommissioning Trust Funds -
The carrying amount represents the fair value of these
trust funds, as reported by the trustee. On January 1, 1994,
the Company adopted SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities." This standard,
which applies to Utilities' nuclear decommissioning trust
funds, requires that unrealized gains and losses on such
investments be included in the reported balance of such
investments. At December 31, 1994, the balance of the "Nuclear
decommissioning trust funds" as shown in the Consolidated
Balance Sheets included $0.8 million of unrealized losses on
the investments held in the trust funds. The accumulated
reserve for decommissioning costs was adjusted by a
corresponding amount and there was no effect on net income
from adopting this standard.
(c) Cumulative Preferred Stock of Utilities -
The estimated fair value of this stock of $10.2 million
is based upon the market yield of similar securities.
(d) Long-Term Debt -
The carrying amount of long-term debt was $483 million
compared to estimated fair value of $459 million. The
estimated fair value of long-term debt is based upon quoted
market prices.
Since Utilities is subject to regulation, any gains or
losses related to the difference between the carrying amount
and the fair value of financial instruments may not be
realized by the Company's parent.
(11) COMMITMENTS AND CONTINGENCIES:
(a) Construction Program -
The Company's construction and acquisition program
anticipates expenditures of approximately $163 million for
1995, and additional expenditures of approximately $13 million
for mandated energy efficiency programs. The energy efficiency
expenditures will be deferred pursuant to IUB rules as
discussed in Note 3(b). Substantial commitments have been made
in connection with all such expenditures.
(b) Purchase Power Contracts -
In connection with the acquisition of the UE properties
discussed in Note 2, Utilities is purchasing power from UE
under a firm capacity contract with a 1995 requirement of
100 Mw of delivered capacity declining to 60 Mw in 1997.
Utilities will also purchase an additional annual maximum
interruptible capacity of up to 54 Mw of 25 Hz power, which
extends through 1998 and will continue thereafter unless
either party gives a three-year notice of cancellation. The
costs of capacity purchases for these contracts are reflected
in "Purchased power" in the Consolidated Statements of Income.
Utilities has a contract to purchase capacity of 50 Mw
from the City of Muscatine for the period May 1, 1995, through
October 31, 1995. Utilities has also entered into an
agreement with Basin Electric Power Cooperative to purchase
capacity of 50 Mw, 75 Mw, 100 Mw and 100 Mw during the annual
six-month summer season for the years 1996 through 1999,
respectively.
Total capacity charges under all existing contracts will
approximate $16.3 million, $14.3 million, $12.3 million,
$4.7 million and $3.4 million for the years 1995-1999,
respectively.
(c) Coal Contract Commitments -
Utilities has entered into coal supply contracts which
expire between 1996 and 2001 for its fossil-fueled generating
stations. At December 31, 1994, the contracts cover
approximately $199 million of coal over the life of the
contracts, which includes $50 million expected to be incurred
in 1995. Utilities expects to supplement these coal contracts
with spot market purchases to fulfill its future fossil fuel
needs.
(d) Information Technology Services -
The Company entered into an agreement, expiring in 2004,
with Electronic Data Systems Corporation (EDS) for information
technology services. The contract is subject to declining
termination fees. The Company's anticipated expenditures
under the agreement for 1995 are estimated to be approximately
$9.1 million. Future costs under the agreement are variable
and are dependent upon the Company's level of usage of
technological services from EDS.
(e) Nuclear Insurance Programs -
The Price-Anderson Amendments Act of 1988 (1988 Act)
provides Utilities with the benefit of $8.9 billion of public
liability coverage consisting of $200 million of insurance and
$8.7 billion of potential retroactive assessments from the
owners of nuclear power plants. Based upon its ownership of
the DAEC, under the 1988 Act, Utilities could be assessed a
maximum of $79.3 million per nuclear incident, with a maximum
of $10 million per year (of which Utilities' 70% ownership
portion would be approximately $55 million and $7 million,
respectively) if losses relating to the incidents exceeded
$200 million. These limits are subject to adjustments for
inflation in future years.
Utilities is a member of Nuclear Electric Insurance
Limited (NEIL), which provides insurance coverage for the cost
of certain property losses at nuclear generating stations and
for the cost of replacement power during certain outages.
Companies insured through NEIL are subject to retroactive
premium adjustments if losses exceed accumulated reserve
funds. NEIL's accumulated reserve funds are currently
sufficient to more than cover its exposure in the event of a
single incident under the property damage or replacement power
coverages. However, Utilities could be assessed annually a
maximum of $8.5 million for certain property losses and
$0.7 million for replacement power if NEIL's losses relating
to accidents exceeded its accumulated reserve funds.
Utilities is not aware of any losses that it believes are
likely to result in an assessment.
(f) Environmental Liabilities -
The Company has recorded environmental liabilities of
approximately $43 million, including $5.4 million as current
liabilities, in its Consolidated Balance Sheets at December
31, 1994. The significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible
Party (PRP) by either the Iowa Department of Natural Resources
(IDNR), the Minnesota Pollution Control Agency (MPCA) or the
United States Environmental Protection Agency (EPA) for 28
FMGP sites. Utilities believes that it is not responsible for
two of the sites for which it has been designated a PRP.
Utilities has another FMGP site for which it has not yet been
formally designated as a PRP. Utilities is working pursuant
to the requirements of the IDNR, MPCA and EPA to investigate,
mitigate, prevent and remediate, where necessary, damage to
property, including damage to natural resources, at and around
the remaining 27 sites in order to protect public health and
the environment. In addition, Utilities has recently become
aware that two additional sites may exist, but it has not yet
been able to determine if any liability may exist.
Utilities has completed the remediation of three sites
and is in various stages of the investigation and/or
remediation processes for 22 sites. The investigation process
is scheduled to begin in 1995 or 1996 for the two other sites.
In 1994, Utilities received updated investigation reports on a
number of sites, which, at some sites, indicated a greater
volume of contaminated soil, surface and ground water needing
treatment, and a greater volume of substances requiring higher
cost incineration, than was anticipated in prior estimates.
It is possible that future cost estimates will be greater than
the current estimates as the investigation process proceeds
and as additional facts become known.
Utilities has recorded environmental liabilities related
to the FMGP sites of $31 million (including $4.3 million as
current liabilities) at December 31, 1994. These amounts are
based upon Utilities' best current estimate of the amount to
be incurred for investigation and remediation costs for those
sites where the investigation process has been or is
substantially completed. For those sites where the
investigation is in its earlier stages or has not started, the
liability represents the minimum of the estimated cost range.
All investigations are expected to be completed by 1999 and
site-specific remediations, based on recommendations from the
IDNR, MPCA and EPA, are anticipated to be completed within
three years after the completion of the investigations of each
site. Utilities may be required to monitor these sites for a
number of years upon completion of remediation, as is the case
with the three sites for which remediation has been completed.
Utilities has begun pursuing coverage for investigation,
mitigation, prevention, remediation and monitoring costs from
its insurance carriers and is investigating the potential for
third party cost sharing for FMGP investigation and clean-up
costs. The amount of shared costs, if any, cannot be
reasonably determined and, accordingly, no potential sharing
has been recorded at December 31, 1994. Regulatory assets of
$31.0 million have been recorded in the Consolidated Balance
Sheets, which reflect the future recovery that is being
provided through Utilities' rates. Considering the rate
treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will
not have a material adverse effect on its financial position
or results of operations.
National Energy Policy Act of 1992
The National Energy Policy Act of 1992 requires owners of
nuclear power plants to pay a special assessment into a
"Uranium Enrichment Decontamination and Decommissioning Fund."
The assessment is based upon prior nuclear fuel purchases and,
for the DAEC, averages $1.4 million annually through 2007, of
which Utilities' 70% share is $1.0 million. Utilities is
recovering the costs associated with this assessment through
its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment,
$12.0 million payable through 2007, has been recorded as a
liability in the Consolidated Balance Sheets, including
$0.8 million included in "Current liabilities - Environmental
liabilities," with a related regulatory asset for the
unrecovered amount.
(g) Clean Air Act -
The Clean Air Act Amendments Act of 1990 (Act) requires
emission reductions of sulfur dioxide and nitrogen oxides to
achieve reductions of atmospheric chemicals believed to cause
acid rain. The provisions of the Act will be implemented in
two phases with Phase I affecting two of Utilities' units
beginning in 1995 and Phase II affecting all units beginning
in the year 2000. Utilities is in the process of completing
the modifications necessary to meet the Phase I requirements.
Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels and through capital
expenditures primarily related to fuel burning equipment and
boiler modifications. Utilities estimates capital
expenditures at approximately $22.5 million, including
$4.4 million in 1995, in order to meet the requirements of the
Act.
(h) FERC Order No. 636 -
The FERC issued Order No. 636 (Order 636) in 1992. Order
636, as modified on rehearing: 1) requires Utilities' pipeline
suppliers to unbundle their services so that gas supplies are
obtained separately from transportation service, and
transportation and storage services are operated and billed as
separate and distinct services; 2) requires the pipeline
suppliers to offer "no notice" transportation service under
which firm transporters (such as Utilities) can receive
delivery of gas up to their contractual capacity level on any
day without prior scheduling; 3) allows pipelines to abandon
long-term (one year or more) transportation service provided
to a customer under an expiring contract whenever the customer
fails to match the highest rate and longest term (up to 20
years) offered to the pipeline by other customers for the
particular capacity; and 4) provides for a mechanism under
which pipelines can recover prudently incurred transition
costs associated with the restructuring process. Utilities
has enhanced access to competitively priced gas supply and
more flexible transportation services as a result of
Order 636. However, under Order 636, Utilities is required to
pay certain transition costs incurred and billed by its
pipeline suppliers.
Utilities' three pipeline suppliers have made filings
with the FERC to begin collecting their respective transition
costs, and additional filings are expected. Utilities began
paying the transition costs in 1993, and, at December 31,
1994, has recorded a liability of $8.0 million for those
transition costs that have been incurred by the pipelines to
date, including $3.0 million expected to be billed through
1995. Utilities is currently recovering the transition costs
from its customers through its Purchased Gas Adjustment
Clauses as such costs are billed by the pipelines. Transition
costs, in addition to the recorded liability, that may
ultimately be charged to Utilities could approximate
$10 million. The ultimate level of costs to be billed to
Utilities depends on the pipelines' filings with the FERC and
other future events, including the market price of natural
gas. However, Utilities believes any transition costs that
the FERC would allow the pipelines to collect from Utilities
would be recovered from its customers, based upon regulatory
treatment of these costs currently and similar past costs by
the IUB. Accordingly, regulatory assets, in amounts
corresponding to the recorded liabilities, have been recorded
to reflect the anticipated recovery.
(12) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa
utilities, Utilities has undivided ownership interests in
jointly-owned electric generating stations and related
transmission facilities. Each of the respective owners is
responsible for the financing of its portion of the
construction costs. Kilowatt-hour generation and operating
expenses are divided on the same basis as ownership with each
owner reflecting its respective costs in its Statements of
Income. Information relative to Utilities' ownership interest
in these facilities at December 31, 1994 is as follows:
Ottumwa Neal
DAEC Unit 1 Unit 3
($ in millions)
Utility plant in service $ 490.8 $ 187.9 $ 55.5
Accumulated depreciation $ 242.4 $ 80.6 $ 25.7
Construction work in progress $ 5.3 $ - $ 1.3
Plant capacity - Mw 515 716 515
Percent ownership 70% 48% 28%
In-service date 1974 1981 1975
(13) SEGMENTS OF BUSINESS:
The principal business segments of the Company are the
generation, transmission, distribution and sale of electric
energy and the purchase, distribution and sale of natural gas
by Utilities. Certain financial information relating to the
Company's significant segments of business is presented below:
Year Ended December 31
1994 1993 1992
(in thousands)
Operating results:
Revenues -
Electric $ 537,327 $ 550,521 $ 462,999
Gas 139,033 154,318 139,455
Operating income -
Electric 125,487 128,994 90,891
Gas 8,135 13,750 8,367
Other information:
Depreciation and amortization -
Electric 68,640 63,832 59,707
Gas 6,214 5,186 4,024
Construction and acquisition
expenditures -
Electric 99,543 84,720 154,902
Gas 12,719 12,582 17,308
Assets -
Identifiable assets -
Electric 1,347,024 1,288,505 1,226,614
Gas 186,911 164,773 141,801
1,533,935 1,453,278 1,368,415
Other corporate assets 111,433 93,700 72,476
Total consolidated assets $ 1,645,368 $ 1,546,978 $ 1,440,891
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The following discussion analyzes significant changes in
the components of net income and financial condition from the
prior periods for IES Utilities Inc. (Utilities) and its
consolidated subsidiaries (the Company). Utilities'
consolidated subsidiaries, IES Ventures Inc. and IES Midland
Development Inc., were formed in December 1994 and had no
operations in 1994.
RESULTS OF OPERATIONS
The Company's net income available for common stock
decreased $6.8 million during 1994 and increased $23.5 million
during 1993. The 1994 results were affected by milder than
normal weather, particularly during the summer months. The
1993 results reflect Utilities' acquisition of the Iowa
service territory of Union Electric Company (UE) (as discussed
in Note 2 of the Notes to Consolidated Financial Statements)
and a return to more normal weather conditions in Utilities'
service territory from that experienced in 1992. The 1992
results were adversely affected by extremely cool summer
weather and a mild winter in Utilities' service territory.
The Company's operating income decreased $7.7 million
during 1994 and increased $43.0 million during 1993. Reasons
for the changes in the results of operations are explained in
the following discussion.
ELECTRIC REVENUES
Electric revenues and Kwh sales for Utilities increased
or (decreased) as compared with the prior year as follows:
1994 1993
($ in millions)
Electric revenues $ (13.2) $ 87.5
Electric sales (excluding off-system sales):
Residential and Rural (1.4%) 17.1%
Commercial 3.4% 17.4%
Industrial 9.3% 40.6%
Total 4.3% 24.9%
The 1994 Kwh sales were adversely affected by milder than
normal weather, particularly during the summer months. The
largest effect of weather was on sales to residential and
rural customers. Under normal weather conditions, 1994 sales
would have been flat and total sales (excluding off-system
sales) would have increased 4.8%, compared to 1993 actual
sales. The growth in commercial and industrial sales
continues to reflect the underlying strength of the economy as
several major industrial expansions in Utilities' service
territory were announced in 1994.
The 1993 sales increases are attributable to the
acquisition of the UE territory and a return to more normal
weather conditions. After adjusting for these items,
underlying total electric sales (excluding off-system sales)
increased 6% in 1993, which reflects the economic growth in
the industrial and commercial customer base.
Utilities' electric tariffs include energy adjustment
clauses (EAC) that are designed to currently recover the costs
of fuel and the energy portion of purchased power billings to
customers. See Note 1(j) of the Notes to Consolidated
Financial Statements for discussion of the EAC.
The decrease in the 1994 electric revenues is
attributable to lower fuel costs collected through the EAC,
lower off-system sales to other utilities and the effect of
the mix of sales between lower margin industrial customers and
higher margin residential and rural customers. Increased
total sales (excluding off-system sales) partially offset the
effects of the above items. The increase in electric revenues
for 1993 is primarily because of the higher sales and
increased recovery of fuel costs through the EAC.
See Note 3(a) of the Notes to Consolidated Financial
Statements for a discussion of Utilities' 1994 electric rate
case.
GAS REVENUES
Utilities' gas revenues decreased $15.3 million during
1994 and increased $14.9 million during 1993. Gas sales in
therms (including transported volumes), which also reflect the
effects of weather, decreased 2.7% in 1994 and increased 5.3%
in 1993. Adjusting for the effects of weather, gas sales
decreased 1.8% and 1.5% in 1994 and 1993, respectively.
Utilities' gas tariffs include purchased gas adjustment
clauses (PGA) that are designed to currently recover the cost
of gas sold. See Note 1(j) of the Notes to Consolidated
Financial Statements for discussion of the PGA.
Utilities' gas revenues decreased in 1994 primarily
because of lower gas costs recovered through the PGA and, to a
lesser extent, the effect of the lower sales. Gas revenues
increased in 1993 substantially because of increased costs of
gas recovered through the PGA, the effect of gas rate
increases that became effective in September 1992 and the
sales increase.
OTHER REVENUES
Other revenues increased $0.1 million and $1.1 million
during 1994 and 1993, respectively, primarily due to increased
steam sales.
OPERATING EXPENSES
Despite an increase in the amount of Kwh generation from
a year ago, fuel for production decreased $1.8 million in 1994
largely because of lower average fuel prices and the effect of
lower fuel cost recoveries through the EAC, which are included
in fuel for production. Generation at Utilities' generating
stations increased because of the increase in electric Kwh
sales and because of increased availability of Utilities'
nuclear generating station, the Duane Arnold Energy Center
(DAEC), which was down for part of 1993 because of a scheduled
refueling outage. There were refueling outages in 1993 and
1992, but no such outage in 1994. Fuel for production
increased $14.3 million in 1993 because of increased
availability of Utilities' fossil-fueled generating stations,
which experienced extended maintenance outages in 1992, and
because of increased sales.
Purchased power decreased $24.7 million in 1994 because
of lower off-system sales to other utilities, increased
generation at Utilities' generating stations and the
expiration, in April 1993, of a purchase power agreement with
the City of Muscatine. Purchased power increased $18.7
million in 1993, of which approximately $14.7 million
represents increased energy purchases and approximately
$4.0 million is a net increase in capacity charges. The
increase in energy purchases is because of the increased Kwh
sales. The increased capacity costs reflect the contracts
associated with the acquisition of the UE service territory,
partially offset by the expiration of the purchase power
agreement with the City of Muscatine. (See Note 11(b) of the
Notes to Consolidated Financial Statements).
Gas purchased for resale decreased $13.8 million in 1994
because of lower gas costs and lower gas sales at Utilities.
Gas purchased for resale increased $7.5 million during 1993
primarily because of increased per unit gas costs at Utilities
and the increased sales.
Other operating expenses increased $9.1 million and $3.6
million in 1994 and 1993, respectively. The 1994 increase is
primarily attributable to increases in labor and benefits
costs, nuclear operating costs, former manufactured gas plant
(FMGP) clean-up costs and information technology costs at
Utilities. The 1993 increase is primarily because of
increased labor and benefits costs and higher electric and gas
transmission and distribution costs, partially offset by lower
non-labor costs at the DAEC.
Maintenance expenses increased $3.3 million and $6.6
million during 1994 and 1993, respectively. The 1994 increase
is primarily because of increased labor costs and maintenance
at the DAEC, partially offset by lower maintenance at
Utilities' fossil-fueled generating stations. The 1993
increase is primarily because of increased maintenance at
Utilities' fossil-fueled generating stations and the DAEC.
Depreciation and amortization increased during both years
because of increases in utility plant in service and, in 1993,
the acquisition of the UE territory on December 31, 1992. An
increase in the average gas utility property depreciation
rate, resulting from an updated depreciation study, also
contributed to the 1993 increase. Depreciation and
amortization expenses for all years include $5.5 million for
the DAEC decommissioning provision, which is collected through
rates.
The staff of the Securities and Exchange Commission (SEC)
has questioned certain of the current accounting practices of
the electric utility industry regarding the recognition,
measurement and classification of decommissioning costs for
nuclear generating stations in the financial statements of
electric utilities. In response to these questions, the
Financial Accounting Standards Board has agreed to review the
accounting for removal costs, including decommissioning. If
current electric utility industry accounting practices for
such decommissioning are changed: (1) annual provisions for
decommissioning could increase, (2) the estimated cost for
decommissioning could be recorded as a liability rather than
as accumulated depreciation, and (3) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction to
decommissioning expense. If such changes are required,
Utilities believes that there would not be an adverse effect
on its financial position or results of operations based on
current rate making practices. (See Note 1(g) of the Notes to
Consolidated Financial Statements for a discussion of
Utilities' proposal for collection of decommissioning costs
included in its current rate filing).
Taxes other than income taxes increased $1.2 million and
$4.5 million during 1994 and 1993, respectively, largely
because of increased property taxes. The 1993 increase is
related, in part, to the acquisition of the UE service
territory.
INTEREST EXPENSE AND OTHER
Interest expense increased $1.4 million and $0.5 million
during 1994 and 1993, respectively, primarily because of an
increase in the average amount of debt outstanding. A
reduction in the average interest rate in 1993 substantially
offset the effect of the higher average outstanding debt. The
lower average interest rate reflects the refinancing of
certain long-term debt issues at lower rates and lower cost
short-term borrowings outstanding for interim periods between
the redemption of certain long-term debt series and the
issuance of their long-term replacements.
Federal and state income taxes were constant in 1994 and
increased $17.2 million in 1993. A decrease in income before
income taxes in 1994 was offset by a higher effective income
tax rate (see Note 6 of the Notes to Consolidated Financial
Statements). The 1993 increase results from an increase in
taxable income and an increase of 1% in the Federal statutory
income tax rate. Adjustments of $1.5 million, recorded in the
second quarter of 1992, to previously recorded tax reserves also
affected the comparability of 1993 with the prior period.
OTHER MATTERS
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 and greater
encouragement of independent power production and
cogeneration. Although various states throughout the country
are currently exploring the possibility of expanded
competition in the retail electric energy market, there is no
significant activity underway in Iowa.
The Company cannot predict the long-term consequences of
these competitive issues on its results of operations or
financial condition. The Company's strategy for dealing with
these emerging issues includes seeking growth opportunities,
continuing to offer quality customer service, on-going cost
reductions and productivity enhancements. The Company
recently initiated a major project to review and redesign its
business processes with the primary goals being reduced
operating costs, increased efficiency and enhanced customer
service.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily
attributable to its construction programs, debt maturities and
sinking fund requirements. The Company's pre-tax ratio of
earnings to fixed charges was 3.39, 3.64 and 2.71 in 1994-
1992, respectively. In 1994, cash flows from operating
activities were $195 million. These funds were primarily used
for construction and acquisition expenditures, for energy
efficiency program costs mandated by the Iowa Utilities Board
(IUB) and to pay dividends.
The Company anticipates that future capital requirements
will be met by cash generated from operations and external
financing. The level of cash generated from operations is
partially dependent upon economic conditions, legislative
activities, environmental matters and timely rate relief for
Utilities. (See Notes 3 and 11 of the Notes to Consolidated
Financial Statements).
Access to the long-term and short-term capital and credit
markets is necessary for obtaining funds externally.
Utilities' debt ratings are as follows:
Moody's Standard & Poor's
Long-term debt A1 A
Short-term debt P1 A1
Utilities' liquidity and capital resources will be
affected by environmental and legislative issues, including
the ultimate disposition of remediation issues surrounding the
FMGP issue, the Clean Air Act as amended, the National Energy
Policy Act of 1992 and Federal Energy Regulatory Commission
(FERC) Order 636, as discussed in Note 11 of the Notes to
Consolidated Financial Statements. Consistent with rate
making principles of the IUB, management believes that the
costs incurred for the above matters will not have a material
adverse effect on the financial position or results of
operations of the Company.
The IUB has adopted rules which require Utilities to
spend 2% of electric and 1.5% of gas gross retail operating
revenues annually for energy efficiency programs. Energy
efficiency costs in excess of the amount in the most recent
electric and gas rate cases are being recorded as regulatory
assets by Utilities. At December 31, 1994, Utilities had
$35 million of such costs recorded as regulatory assets.
Under provisions of the IUB rules, Utilities made its initial
filing for recovery of the costs in August 1994. See Note
3(b) of the Notes to Consolidated Financial Statements for a
discussion of the filing.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program
anticipates expenditures of approximately $163 million for
1995, of which approximately 32% represents expenditures for
electric transmission and distribution facilities, 23%
represents fossil-fueled generation expenditures, 15%
represents expenditures for steam distribution plant and 9%
represents nuclear generation expenditures. The remaining 21%
represents miscellaneous electric, gas and general
expenditures. In addition to the $163 million, Utilities
anticipates expenditures of $13 million in connection with
mandated energy efficiency programs. Substantial commitments
have been made in connection with all such expenditures.
The Company's levels of construction and acquisition
expenditures are projected to be $167 million in 1996, $146
million in 1997, $170 million in 1998 and $182 million in
1999. It is estimated that approximately 80% of construction
expenditures will be provided by cash from operating
activities (after payment of dividends) for the five-year
period 1995-1999.
Capital expenditure and investment and financing plans
are subject to continual review and change. The capital
expenditure and investment programs may be revised
significantly as a result of many considerations including
changes in economic conditions, variations in actual sales and
load growth compared to forecasts, requirements of
environmental, nuclear and other regulatory authorities,
acquisition opportunities, the availability of alternate
energy and purchased power sources, the ability to obtain
adequate and timely rate relief, escalations in construction
costs and conservation and energy efficiency programs.
LONG-TERM FINANCING
Other than Utilities' periodic sinking fund requirements,
which Utilities intends to meet by pledging additional
property, approximately $174 million of long-term debt will
mature prior to December 31, 1999. The Company intends to
refinance the majority of the debt maturities with long-term
securities.
In order to provide an up-to-date instrument for the
issuance of bonds, notes or other evidence of indebtedness,
Utilities has entered into an Indenture of Mortgage and Deed
of Trust dated September 1, 1993 (New Mortgage). The lien of
the New Mortgage is subordinate to the lien of Utilities'
first mortgages until such time as all bonds issued under the
first mortgages have been retired and such mortgages
satisfied. The New Mortgage provides for the issuance of
Collateral Trust Bonds upon the basis of, among other things,
First Mortgage Bonds being issued by Utilities. Accordingly,
to the extent that Utilities issues Collateral Trust Bonds on
the basis of First Mortgage Bonds, it must comply with the
requirements for the issuance of First Mortgage Bonds under
Utilities' first mortgages. Under the terms of the New
Mortgage, Utilities has covenanted not to issue any additional
First Mortgage Bonds under its first mortgages except to
provide the basis for issuance of Collateral Trust Bonds.
The Indentures pursuant to which Utilities issues First
Mortgage Bonds constitute direct first mortgage liens upon
substantially all tangible public utility property and contain
covenants which restrict the amount of additional bonds which
may be issued. At December 31, 1994, such restrictions would
have allowed Utilities to issue $320 million of additional
First Mortgage Bonds. Utilities has received authority from
the FERC to issue $250 million of long-term debt and is
currently authorized by the SEC to issue $50 million of
long-term debt under an existing registration statement.
Utilities expects to replace two series of First Mortgage
Bonds that mature in 1995 with other long-term securities.
The Articles of Incorporation of Utilities authorize and
limit the aggregate amount of additional shares of Cumulative
Preferred Stock and Cumulative Preference Stock which may be
issued. At December 31, 1994, Utilities could have issued an
additional 700,000 shares of Cumulative Preference Stock and
100,000 additional shares of Cumulative Preferred Stock.
The Company's capitalization ratios at December 31, 1994
and 1993, were as follows:
Long-term debt 48%
Preferred stock 2
Common equity 50
100%
The 1994 ratios include $100 million of
Utilities' First Mortgage Bonds maturing in 1995
that are classified as a current liability in
the Consolidated Balance Sheets, but which are
expected to be refinanced with long-term
securities.
SHORT-TERM FINANCING
For interim financing, Utilities is authorized by the
FERC to issue, through 1996, up to $200 million of short-term
notes. In addition to providing for ongoing working capital
needs, this availability of short-term financing provides
Utilities flexibility in the issuance of long-term securities.
At December 31, 1994, Utilities had outstanding short-term
borrowings of $55.5 million, including $18.5 million of notes
payable to associated companies.
Utilities has an agreement, which expires in 1999, with a
financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool
of utility accounts receivable. At December 31, 1994,
Utilities had sold $54 million under the agreement.
At December 31, 1994, the Company had bank lines of
credit aggregating $67.7 million, of which $37 million was
being used to support commercial paper (weighted average
interest rate of 6.13%) and $7.7 million was being used to
support certain pollution control obligations. Commitment
fees are paid to maintain these lines and there are no
conditions which restrict the unused lines of credit. In
addition to the above, Utilities has an uncommitted credit
facility with a financial institution whereby it can borrow up
to $40 million. Rates are set at the time of borrowing and no
fees are paid to maintain this facility. At
December 31, 1994, there were no borrowings under this
facility. Utilities also has a letter of credit in the amount
of $3.4 million supporting two of its variable rate pollution
control obligations.
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible
Party (PRP) by either the Iowa Department of Natural Resources
(IDNR), the Minnesota Pollution Control Agency (MPCA) or the
United States Environmental Protection Agency (EPA) for 28
FMGP sites. Utilities believes that it is not responsible for
two of the sites for which it has been designated a PRP.
Utilities has another FMGP site for which it has not yet been
formally designated as a PRP. Utilities is working pursuant
to the requirements of the IDNR, MPCA and EPA to investigate,
mitigate, prevent and remediate, where necessary, damage to
property, including damage to natural resources, at and around
the remaining 27 sites in order to protect public health and
the environment. In addition, Utilities has recently become
aware that two additional sites may exist, but it has not yet
been able to determine if any liability may exist.
Utilities has completed the remediation of three sites
and is in various stages of the investigation and/or
remediation processes for 22 sites. The investigation process
is scheduled to begin in 1995 or 1996 for the two other sites.
In 1994, Utilities received updated investigation reports on a
number of sites, which, at some sites, indicated a greater
volume of contaminated soil, surface and ground water needing
treatment, and a greater volume of substances requiring higher
cost incineration, than was anticipated in prior estimates.
It is possible that future cost estimates will be greater than
the current estimates as the investigation process proceeds
and as additional facts become known.
Utilities has recorded environmental liabilities related
to the FMGP sites of $31 million (including $4.3 million as
current liabilities) at December 31, 1994. These amounts are
based upon Utilities' best current estimate of the amount to
be incurred for investigation and remediation costs for those
sites where the investigation process has been or is
substantially completed. For those sites where the
investigation is in its earlier stages or has not started, the
liability represents the minimum of the estimated cost range.
All investigations are expected to be completed by 1999 and
site-specific remediations, based on recommendations from the
IDNR, MPCA and EPA, are anticipated to be completed within
three years after the completion of the investigations of each
site. Utilities may be required to monitor these sites for a
number of years upon completion of remediation, as is the case
with the three sites for which remediation has been completed.
Utilities has begun pursuing coverage for investigation,
mitigation, prevention, remediation and monitoring costs from
its insurance carriers and is investigating the potential for
third party cost sharing for FMGP investigation and clean-up
costs. The amount of shared costs, if any, can not be
reasonably determined and, accordingly, no potential sharing
has been recorded at December 31, 1994. Regulatory assets of
$31.0 million have been recorded in the Consolidated Balance
Sheets, which reflect the future recovery that is being
provided through Utilities' rates. Considering the rate
treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will
not have a material adverse effect on its financial position
or results of operations.
The Clean Air Act Amendments Act of 1990 (Act) requires
emission reductions of sulfur dioxide and nitrogen oxides to
achieve reductions of atmospheric chemicals believed to cause
acid rain. The provisions of the Act will be implemented in
two phases with Phase I affecting two of Utilities' units
beginning in 1995 and Phase II affecting all units beginning
in the year 2000. Utilities is in the process of completing
the modifications necessary to meet the Phase I requirements.
Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels and through capital
expenditures primarily related to fuel burning equipment and
boiler modifications. Utilities estimates capital
expenditures at approximately $22.5 million, including $4.4
million in 1995, in order to meet the requirements of the Act.
The National Energy Policy Act of 1992 requires owners of
nuclear power plants to pay a special assessment into a
"Uranium Enrichment Decontamination and Decommissioning Fund."
The assessment is based upon prior nuclear fuel purchases and,
for the DAEC, averages $1.4 million annually through 2007, of
which Utilities' 70% share is $1.0 million. Utilities is
recovering the costs associated with this assessment through
its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment,
$12.0 million payable through 2007, has been recorded as a
liability in the Consolidated Balance Sheets, including
$0.8 million included in "Current liabilities - Environmental
liabilities," with a related regulatory asset for the
unrecovered amount.
The Nuclear Waste Policy Act of 1982 assigned
responsibility to the U.S. Department of Energy (DOE) to
establish a facility for the ultimate disposition of high
level waste and spent nuclear fuel and authorized the DOE to
enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into
such a contract and has made the agreed payments to DOE. The
DOE, however, has experienced significant delays in its
efforts and material acceptance is now expected to occur no
earlier than 2010. Utilities has been storing spent nuclear
fuel on-site since plant operations began in 1974 and has
current on-site capability to store spent fuel until 2002.
Utilities is aggressively reviewing options for additional
spent nuclear fuel storage capability, including expanding on-
site storage, pursuing other off-site storage and supporting
legislation to resolve the lack of progress by the DOE.
The Low-Level Radioactive Waste Policy Amendments Act of
1985 mandated that each state must take responsibility for the
storage of low-level radioactive waste produced within its
borders. The State of Iowa has joined the Midwest Interstate
Low-Level Radioactive Waste Compact Commission (Compact),
which is planning a storage facility to be located in Ohio to
store waste generated by the Compact's six member states. At
December 31, 1994, Utilities has prepaid costs of
approximately $1 million to the Compact for the building of
such a facility. Currently, Utilities is storing its low-
level radioactive waste generated at the DAEC on-site until
new disposal arrangements are finalized among the Compact
members. A Compact disposal facility is anticipated to be in
operation in approximately ten years. On-site storage
capability currently exists for low-level radioactive waste
expected to be generated until the Compact facility is able to
accept waste materials.
The possibility that exposure to electric and magnetic
fields emanating from power lines, household appliances and
other electric sources may result in adverse health effects
has been the subject of increased public, governmental and
media attention. A considerable amount of scientific research
has been conducted on this topic without definitive results.
Research is continuing in order to resolve scientific
uncertainties.
EFFECTS OF INFLATION
Under the rate making principles prescribed by the
regulatory commissions to which Utilities is subject, only the
historical cost of plant is recoverable in revenues as
depreciation. As a result, Utilities has experienced economic
losses equivalent to the current year's impact of inflation on
utility plant.
In addition, the regulatory process imposes a substantial
time lag between the time when operating and capital costs are
incurred and when they are recovered. Utilities does not
expect the effects of inflation at current levels to have a
significant effect on its results of operations.
Selected Consolidated Quarterly Financial Data (unaudited)
The following unaudited consolidated quarterly data, in
the opinion of the Company, includes adjustments, which are
normal and recurring in nature, necessary for the fair
presentation of the results of operations and financial
position. The quarterly amounts were affected by seasonal
weather conditions. In addition, increased operating expenses
in the fourth quarter of 1994 affected the comparability of
the fourth quarter amounts.
Quarter Ended
March June September December
31 30 30 31
(in thousands)
1994
Operating revenues $ 192,013 $ 148,019 $ 179,477 $ 165,857
Operating income 34,248 24,777 51,777 24,789
Net income 14,944 9,255 25,733 11,278
Net income available
for common stock 14,715 9,026 25,504 11,051
1993
Operating revenues $ 193,785 $ 148,919 $ 187,392 $ 183,654
Operating income 32,974 24,523 54,497 31,335
Net income 14,423 10,491 26,214 16,842
Net income available
for common stock 14,194 10,262 25,985 16,615
Prior period operating income figures have been restated
on a basis consistent with the current presentation as the
income statement format was revised as a result of the
formation in December 1994 of Utilities' non-utility
subsidiaries, IES Ventures Inc. and IES Midland Development
Inc.