Annual Report (Form 10-K), fiscal year 1994




Item 2. Properties
Industries has no significant properties other than common stock of affiliates, temporary cash investments and cash surrender value of corporate life insurance policies.
Utilities' principal electric generating stations at December 31, 1994, are as follows:
Name and Location Major Fuel Net Kilowatts Accredited of Station Type Generating Capability
Duane Arnold Energy Center, Palo, Iowa Nuclear 360,500 (1) Ottumwa Generating Station, Ottumwa, Iowa Coal 343,440 (2) Prairie Creek Station, Cedar Rapids, Iowa Coal 234,000 Sutherland Station, Marshalltown, Iowa Coal 143,000 Sixth Street Station, Cedar Rapids, Iowa Coal 71,000 Burlington Generating Station, Burlington, Iowa Coal 211,800 George Neal Unit 3, Sioux City, Iowa Coal 144,200 (3) Total Coal 1,147,440
Peaking Turbines, Marshalltown, Iowa Oil 156,000 Centerville Combustion Turbines, Centerville, Iowa Oil 49,000 (4) Diesel Stations, all in Iowa Oil 12,200 Total Oil 217,200
Grinnell Station, Grinnell, Iowa Gas 47,200 Agency Street Combustion Turbines, West Burlington, Iowa Gas 65,000 (4) Burlington Combustion Turbines, Burlington, Iowa Gas 16,600 Total Gas 128,800
Total generating capability 1,853,940
(1) Represents Utilities' 70% ownership interest in this 515,000 Kw generating station. The plant is operated by Utilities.
(2) Represents Utilities' 48% ownership interest in this 715,500 Kw generating station. The plant is operated by Utilities.
(3) Represents Utilities' 28% ownership interest in this 515,000 Kw generating station which is operated by an unaffiliated utility.
(4) Effective December 31, 1994, all of the assets of Terra Comfort were sold to Utilities, including the Centerville and Agency Street Combustion Turbines.
At December 31, 1994, the transmission lines of Utilities, operating from 34,000 to 345,000 volts, approximated 4,390 circuit miles (all located in Iowa). Utilities owned 108 transmission substations (all located in Iowa) with a total installed capacity of 8,415.7 MVa and 466 distribution substations (all located in Iowa) with a total installed capacity of 2,545.8 MVa.
Subsidiaries other than Utilities also own property which primarily represents investments in transportation, oil and gas and real estate properties.
The Company's principal properties are suitable for their intended use. Utilities' principal properties are held subject to liens of indentures relating to its First Mortgage Bonds.
Item 3.

Item 3. Legal Proceedings
Industries, IES Energy, MicroFuel Corporation (the Corporation) now known as Ely, Inc. in which IES Energy has a 69.40% equity ownership, and other parties have been sued in Linn County District Court in Cedar Rapids, Iowa, by Allen C. Wiley. Mr. Wiley claims money damages on various tort and contract theories arising out of the 1992 sale of the assets of the Corporation, of which Mr. Wiley was a director and shareholder. All of the defendants in Mr. Wiley's suit have answered the complaint and denied liability. All of the defendants believe that the claims are without merit and are vigorously contesting them. The trial has been continued to an unspecified date, pending a decision in the appeal related to a separate suit discussed below.
The Corporation commenced a separate suit to determine the fair value of Mr. Wiley's shares under Iowa Code section 490. A decision was issued on August 31, 1994, by the Linn County District Court ruling that the value of Mr. Wiley's shares was $377,600 based on a 40 cent per share valuation. The Corporation contended that the value of Mr. Wiley's shares was 2.5 cents per share. The Decision has been appealed to the Iowa Supreme Court by the Corporation on a number of issues, including the Corporation's position that the trial court erred as a matter of law in discounting the testimony of the Corporation's expert witness. A decision on the appeal is not expected before the fourth quarter of 1995.
Reference is made to Notes 3 and 12 of the Notes to Consolidated Financial Statements for a discussion of Utilities' rate proceedings and environmental matters. Also see Item 1. "Business - Environmental Matters" and Item 7. "Management's Discussion and Analysis of the Results of Operations and Financial Condition."
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.

Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters
(a) Price Range of Common Stock and Dividends Declared
IES Industries Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol "IES." The table below sets forth, for the calendar quarters indicated, the reported high and low sales prices of IES Industries Common Stock as reported on the NYSE Composite Tape based on published financial sources, and the dividends declared per share on IES Industries Common Stock.
IES Industries Common Stock High Sale Low Sale Dividend (i) First Quarter $ 31 3/8 $ 27 $ .525 Second Quarter 29 25 1/2 .525 Third Quarter 28 3/8 24 7/8 .525 Fourth Quarter 26 5/8 24 3/4 .525
First Quarter 31 1/8 28 3/8 .525 Second Quarter 32 5/8 28 5/8 .525 Third Quarter 34 1/4 31 1/4 .525 Fourth Quarter 34 29 1/8 .525
(i) The Company has paid regular quarterly dividends on its common stock since April 1, 1950. Although the Company's practice has been to pay dividends quarterly, the time of payment and amount of future dividends are necessarily dependent upon earnings, financial requirements and other factors.
(b) Approximate Number of Equity Security Holders
Approximate Number of Record Title of Class Holders (as of December 31, 1994)
Common Stock, no par value 32,567
(c) Restriction on Payment of Dividends
Under terms of the Fifty-fifth and Fifty-sixth Supplemental Indentures relating to Utilities' Series W and Series X First Mortgage Bonds, Utilities agreed that no cash dividends shall be paid or declared, nor shall any distribution be made on any capital stock, nor shall any shares of such stock be purchased, redeemed or otherwise acquired for any consideration by Utilities or any subsidiary of Utilities, if after immediately giving effect to such payment, distribution or retirements, (A) the principal amount of all outstanding defined Unsecured Indebtedness of Utilities exceeds 20% of defined Total Capitalization, or (B) the aggregate amount of all such payments, distributions and retirements made since December 31, 1987, exceeds net income of Utilities since December 31, 1987, plus $50,000,000. Pursuant to these terms, at December 31, 1994, $18,209,000 of Utilities' retained earnings was restricted as to the payment of cash dividends. Utilities may periodically pay cash dividends on any shares of its preferred or preference stock at any time issued and outstanding, provided that all such payments shall be included in the above payments as determined since December 31, 1987.
The Series W and Series X First Mortgage Bonds both mature in 1995. Once such maturities are completed, there will no longer be any restrictions on Utilities' retained earnings.
Item 6.

Item 6. Selected Consolidated Financial Data
The following selected consolidated financial 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. See Item 7.

Item 7.
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 Industries Inc. (Industries) and its consolidated subsidiaries (the Company).
RESULTS OF OPERATIONS
Industries' wholly-owned subsidiaries are IES Utilities Inc. (Utilities) and IES Diversified Inc. (Diversified). The Company's net income decreased $1.1 million during 1994 and increased $19.2 million during 1993. Earnings per average common share declined from $2.45 in 1993 to $2.34 in 1994 because of the lower net income and the effect of increased average common shares outstanding. 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 1993 results also reflect the recording of certain property write-downs at Diversified and a $2.5 million contribution to the IES Industries Charitable Foundation. 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 $3.3 million during 1994 and increased $42.2 million during 1993. Reasons for the changes in the results of operations are explained in the following discussion.
ELECTRIC REVENUES
Electric revenues and Kwh sales for Utilities increased or (decreased) as compared with the prior year as follows:
1994 1993 ($ 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(k) 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
Gas revenues increased or (decreased) as compared with the prior year as follows:
1994 1993 (in millions)
Gas revenues: Utilities $ (15.3) $ 14.9 Industrial Energy Applications, Inc. (IEA) (1.1) (0.1) $ (16.4) $ 14.8
Utilities' 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, Utilities' 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(k) 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.
The decrease in IEA's gas revenues in 1994 also reflects the lower price of natural gas. Despite an increase of 16% in gas volumes, revenues decreased by $1.1 million.
OTHER REVENUES
Other revenues increased $14.1 million and $20.6 million during 1994 and 1993, respectively, largely because of increased revenues at Whiting Petroleum Company (Whiting) and Diversified's other subsidiaries, primarily in the energy and transportation industries. In addition, approximately $10 million of the 1993 increase related to the acquisition of certain resort properties in March 1993; Diversified previously held an equity interest in a company that owned the properties. Utilities' steam revenues also contributed to the 1993 increase.
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 12(b) of the Notes to Consolidated Financial Statements).
Gas purchased for resale decreased $15.0 million in 1994 because of lower gas costs and lower gas sales at Utilities. Gas purchased for resale increased $7.6 million during 1993 primarily because of increased per unit gas costs at Utilities and the increased sales.
Other operating expenses increased $14.2 million and $20.3 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, and increased operating activities at Whiting. The 1993 increase is primarily because of increased labor and benefits costs at Utilities and increased operating activities at several of Diversified's subsidiaries, including IEA and Whiting. In addition, $9 million of the 1993 increase is attributable to the resort properties acquired in March 1993.
Maintenance expenses increased $3.9 million and $7.5 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, increased amortization and depreciation of oil and gas properties 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 $1.9 million and $4.8 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 $1.6 million during 1994 primarily because of an increase in the average amount of debt outstanding. Interest expense decreased $1.0 million in 1993 because of a lower average interest rate, partially offset by an increase in the average amount of debt outstanding. 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.
Miscellaneous, net reflects income of $3.5 million and $7.5 million in 1994 and 1992, respectively, and expense of $2.9 million in 1993. The comparability of the years was significantly affected by the following 1993 transactions: (1) certain property write-downs at Diversified, (2) a contribution to the IES Industries Charitable Foundation, (3) a loss on the defeasance of Industries' debentures, and (4) gains on the sale of assets at Whiting and IEA aggregating $2.6 million. In 1994, a gain on the sale of an investment by one of Diversified's subsidiaries, net of lower interest income, also contributed to the increase in income over 1993.
Federal and state income taxes increased $4.5 million and $13.2 million in 1994 and 1993, respectively. The increase in 1994 is largely because of the effect of property related temporary differences for which deferred taxes had not been provided that are now becoming payable. 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 Utilities' construction programs, its debt maturities and sinking fund requirements and the level of Diversified's business opportunities. The Company's pre-tax ratio of earnings to fixed charges was 3.38, 3.38 and 2.63 in 1994-1992, respectively. In 1994, cash flows from operating activities were $216 million. These funds were primarily used for construction and acquisition expenditures and for energy efficiency program costs mandated by the Iowa Utilities Board (IUB).
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 12 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. The Company's debt ratings are as follows:
Moody's Standard & Poor's
Utilities - Long-term debt A1 A - Short-term debt P1 A1
Diversified - Short-term debt P2 A2
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 12 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 $202 million for 1995, of which approximately $163 million represents expenditures at Utilities and approximately $39 million represents expenditures at Diversified. Of the $163 million of Utilities' expenditures, 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. Diversified's anticipated expenditures include approximately $26 million at Whiting. 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 $230 million in 1996, $209 million in 1997, $235 million in 1998 and $227 million in 1999. It is estimated that approximately 70% 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, the following long-term debt will mature prior to December 31, 1999:
(in millions) Issue: Utilities $ 173.7 Diversified's variable rate credit facility 80.5 Other subsidiaries' debt 11.7 $ 265.9
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, among other things, the issuance of Collateral Trust Bonds upon the basis of 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.
Diversified has a variable rate credit facility that extends through November 9, 1997, with two one-year extensions available to Diversified. The facility also serves as a stand- by agreement for Diversified's commercial paper program. The agreement provides for a combined maximum of $150 million of borrowings under the agreement and commercial paper to be outstanding at any one time. Interest rates and maturities are set at the time of borrowing for direct borrowings under the agreement and for issuances of commercial paper. The interest rate options are based upon quoted market rates and the maturities are less than one year. At December 31, 1994, $12 million was borrowed under this facility, bearing an interest rate of 6.44%, maturing in January 1995. Diversified also had $68.5 million of commercial paper outstanding at December 31, 1994, with interest rates ranging from 6.27% to 6.38% and maturity dates in the first quarter of 1995, which was also supported by the facility. Diversified intends to continue borrowing under the renewal options of the facility and no conditions exist at December 31, 1994, that would prevent such borrowings. Accordingly, this debt is classified as long-term in the Consolidated Balance Sheets.
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. In addition, Industries had 5,000,000 shares of Cumulative Preferred Stock, no par value, authorized for issuance, none of which were outstanding at December 31, 1994.
The Company's capitalization ratios at year-end were as follows:
1994 1993
Long-term debt 48% 47% Preferred stock 2 2 Common equity 50 51 100% 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 $77.7 million (Industries - $1.5 million, Utilities - $67.7 million, Diversified - $7.5 million and Whiting - $1.0 million). Utilities was using $37 million of its lines to support commercial paper (weighted average interest rate of 6.13%) and $7.7 million 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.
Whiting is responsible for certain dismantlement and abandonment costs related to various off-shore oil and gas properties, the most significant of which is located off the coast of California. Whiting accrues these costs as reserves are extracted and such costs are included in "Depreciation and amortization" in the Consolidated Statements of Income. A corresponding environmental liability, $0.1 million at December 31, 1994, has been recognized in the Consolidated Balance Sheets for the cumulative amount expensed.
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. Utilities' results of operations are a significant portion of the consolidated results. The quarterly amounts were affected by seasonal weather conditions. The comparability of earnings per average common share is affected by the sale of 2.3 million shares to the public in the first quarter of 1993 as discussed in Note 8 of the Notes to Consolidated Financial Statements.
Quarter Ended March June September December 31 30 30 31 (in thousands, except per share amounts) Operating revenues $ 211,621 $ 171,117 $ 207,345 $ 195,781 Operating income 35,694 28,436 56,700 27,103 Net income 15,144 10,858 28,009 12,807 Earnings per average common share 0.53 0.38 0.98 0.45
Operating revenues $ 213,077 $ 170,470 $ 212,052 $ 205,667 Operating income 34,514 27,455 57,767 31,533 Net income 13,935 11,740 27,957 14,306 Earnings per average common share 0.53 0.42 0.99 0.51
Item 8.


Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 59.
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 Industries Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of IES INDUSTRIES 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 and the financial statement schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 Industries 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.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed in Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
As discussed in Note 7 to the consolidated financial statements, effective January 1, 1993, IES Industries 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, except per share amounts) Operating revenues: Electric $ 537,327 $ 550,521 $ 462,999 Gas 165,569 181,923 167,082 Other 82,968 68,822 48,215 785,864 801,266 678,296
Operating expenses: Fuel for production 85,952 87,702 73,368 Purchased power 68,794 93,449 74,794 Gas purchased for resale 120,795 135,830 128,259 Other operating expenses 176,863 162,642 142,348 Maintenance 52,841 48,913 41,415 Depreciation and amortization 86,378 77,012 69,392 Taxes other than income taxes 46,308 44,449 39,696 637,931 649,997 569,272
Operating income 147,933 151,269 109,024
Interest expense and other: Interest expense 46,010 44,440 45,426 Allowance for funds used during construction -3,910 -1,972 -3,177 Preferred dividend requirements of IES Utilities Inc. 914 914 1,729 Miscellaneous, net -3,472 2,908 -7,495 39,542 46,290 36,483
Income before income taxes 108,391 104,979 72,541
Federal and state income taxes 41,573 37,041 23,830
Net income $ 66,818 $ 67,938 $ 48,711
Average number of common shares outstanding 28,560 27,764 25,389
Earnings per average common share $ 2.34 $ 2.45 $ 1.92
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 $211,750 $ 202,919 $ 202,882 Add: Net income 66,818 67,938 48,711 Acquisition of Whiting Petroleum Corporation 0 0 5,233
Deduct: Cash dividends declared on common stock, at a per share rate of $2.10 for all years 60,065 59,107 53,350 Other 210 0 557
Balance at end of year ($18,209,000 restricted as to payment of cash dividends) $218,293 $ 211,750 $ 202,919
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, net of accumulated depreciation and amortization of $34,490,000 and $35,007,000, respectively 153,795 124,275 1,438,156 1,340,768
Current assets: Cash and temporary cash investments 4,993 7,465 Accounts receivable - Customer, less reserve 26,098 33,642 Other 10,388 10,421 Income tax refunds receivable 1,330 3,376 Production fuel, at average cost 13,988 14,338 Materials and supplies, at average cost 30,216 29,046 Adjustment clause balances 1,433 0 Regulatory assets 20,145 14,225 Prepayments and other 34,607 34,265 143,198 146,778
Investments: Nuclear decommissioning trust funds 33,779 28,059 Cash surrender value of life insurance policies 8,867 7,562 Investment in McLeod, Inc. 7,500 4,500 Other 5,609 4,349 55,755 44,470
Other assets: Regulatory assets 192,955 148,592 Deferred charges and other 13,925 19,211 206,880 167,803 $ 1,843,989 $ 1,699,819
December 31 CAPITALIZATION AND LIABILITIES 1994 1993 (in thousands) Capitalization (See Consolidated Statements of Capitalization):
Common stock $ 373,490 $ 360,301 Retained earnings 218,293 211,750 Total common equity 591,783 572,051 Cumulative preferred stock of IES Utilities Inc. 18,320 18,320 Long-term debt 473,206 522,343 1,083,309 1,112,714
Current liabilities: Short-term borrowings 37,000 24,000 Capital lease obligations 14,385 15,345 Maturities and sinking funds 100,422 464 Accounts payable 78,582 53,980 Accrued interest 9,494 9,471 Accrued taxes 44,897 42,368 Accumulated refueling outage provision 15,196 2,660 Dividends payable 15,839 15,519 Adjustment clause balances 0 5,149 Provision for rate refund liability 0 8,670 Environmental liabilities 5,428 4,871 Other 21,844 23,127 343,087 205,624
Long-term liabilities: Capital lease obligations 35,346 36,336 Environmental liabilities 38,288 21,324 Other 58,793 45,231 132,427 102,891
Deferred credits: Accumulated deferred income taxes 245,365 236,131 Accumulated deferred investment tax credits 39,801 42,459 285,166 278,590
Commitments and contingencies (Note 12)
$ 1,843,989 $ 1,699,819
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 - no par value - authorized 48,000,000 shares; outstanding 28,777,046 and 28,304,188 shares, respectively $ 373,490 $ 360,301 Retained earnings 218,293 211,750 591,783 572,051
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt: 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
Total IES Utilities Inc. 483,196 483,420
IES Diversified Inc. - Variable rate credit facility 80,500 32,000 Other subsidiaries' debt maturing through 2013 12,584 10,510 576,280 525,930 Unamortized debt premium and (discount), net -2,652 -3,123 573,628 522,807 Less - Amount due within one year 100,422 464 473,206 522,343 $ 1,083,309 $ 1,112,714
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 -
The Consolidated Financial Statements include the accounts of IES Industries Inc. (Industries) and its consolidated subsidiaries (collectively the Company). All subsidiaries for which Industries owns directly or indirectly more than 50% of the voting stock are included as consolidated subsidiaries. Industries' wholly-owned subsidiaries are IES Utilities Inc. (Utilities) and IES Diversified Inc. (Diversified). All significant intercompany balances and transactions, other than energy related transactions affecting Utilities, have been eliminated from the Consolidated Financial Statements. Such energy related transactions are made at prices that approximate market value and the associated costs are recoverable from Utilities' customers through the rate making process.
Investments for which the Company has at least a 20% interest are generally 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 -
Because of its ownership of Utilities, Industries is a holding company under the Public Utility Holding Company Act of 1935, but claims an exemption from all provisions thereof except Section 9(a)(2), which applies to the purchase of stock of other utility companies. Utilities is subject to regulation by the Iowa Utilities Board (IUB) and the Federal Energy Regulatory Commission (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 12(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 12(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) Oil and Gas Properties -
Whiting Petroleum Company (Whiting), a wholly-owned subsidiary of Diversified, uses the full cost method of accounting for its oil and gas properties. Accordingly, all costs of acquisition, exploration and development of properties are capitalized. Amortization of proved oil and gas properties is calculated using the units of production method. At December 31, 1994, capitalized costs less related accumulated amortization do not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves (calculated using current prices); plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. See Note 12(f) for a discussion of dismantlement and abandonment costs associated with certain oil and gas properties.
(j) Operating Revenues -
The Company accrues revenues for services rendered but unbilled at month-end in order to more properly match revenues with expenses.
(k) 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.
(l) 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 12(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 $11.1 million, $9.1 million and $7.7 million, respectively.
The Company's future minimum lease payments by year are as follows:
Capital Operating Year Lease Leases (in thousands)
1995 $ 15,634 $ 8,549 1996 15,653 8,479 1997 12,942 5,674 1998 6,394 4,245 1999 4,176 3,109 2000 - 2002 1,267 601 56,066 $ 30,657 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 $ 37.5 $ 27.8 $ 25.2 Deferred tax expense 6.7 14.1 1.4 Amortization and adjustment of investment tax credits (2.6) (4.9) (2.8) $ 41.6 $ 37.0 $ 23.8
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 5.9 5.5 5.8 Effect of property related temporary differences for which deferred taxes are not provided under rate making principles 3.0 1.5 0.4 Amortization of investment tax credits (2.5) (2.6) (3.9) Reversal through tariffs of deferred taxes provided at rates in excess of the current statutory Federal income tax rate (1.4) (1.7) (2.4) Adjustment of prior period taxes (1.6) (2.3) (1.6) Other items, net - (0.1) 0.6 Overall effective income tax rate 38.4% 35.3% 32.9%
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 $ 288 $ 280 Investment tax credit related (28) (30) Decommissioning related (13) (12) Other (2) (2) $ 245 $ 236
(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 $9.9 million.
The Company's policy is to fund the pension cost at an amount that is at least equal to the minimum funding requirements 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 $ 5,863 $ 4,342 $ 4,529 Interest cost on projected benefit obligation 11,431 11,314 10,219 Assumed return on plans' assets (12,593) (12,363) (11,872) Amortization of unrecognized gain (180) (767) (135) Amortization of prior service cost 1,354 1,213 956 Amortization of unrecognized plans' assets as of January 1, 1987 (333) (389) (389) Pension cost 5,542 3,350 3,308 Adjustment to funding level (5,431) (2,940) 294 Total pension costs paid to the Trustees $ 111 $ 410 $ 3,602
Actual return on plans'assets $ (97) $ 12,880 $ 8,949
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 $ 167,535 $ 176,935 Actuarial present value of benefits rendered to date - Accumulated benefits based on compensation to date, including vested benefits of $98,384,000 and $102,621,000, respectively 108,585 112,561 Additional benefits based on estimated future salary levels 40,146 43,673 Projected benefit obligation 148,731 156,234 Plans' assets in excess of projected benefit obligation 18,804 20,701 Remaining unrecognized net asset existing at January 1, 1987, being amortized over 20 years (3,844) (4,177) Unrecognized prior service cost 18,260 16,985 Unrecognized net gain (34,420) (29,278) Prepaid (accrued) pension cost recognized in the Consolidated Balance Sheets $ (1,200) $ 4,231
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 transition obligation for the non-regulated operations was expensed in 1993 and is reflected in other operating expenses.
The components of postretirement benefit costs for the years ended December 31, were as follows:
1994 1993 (in thousands)
Service cost $ 1,838 $ 1,744 Interest cost on accumulated postretirement benefit obligation 3,275 3,363 Actual return on plan assets (47) - Amortization of transition obligation existing at January 1, 1993, for regulated operations 2,024 2,024 Amortization of unrecognized asset loss (13) - Amortization of unrecognized gain (6) - Amortization of prior service cost 19 - Write-off of transition obligation existing at January 1, 1993, for non-regulated operations - 1,434 Postretirement benefit costs 7,090 8,565 Less: Deferred postretirement benefit costs 2,732 2,858 Net postretirement benefit costs $ 4,358 $ 5,707
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 18,896 19,092 Active employees eligible 5,306 4,294 Retirees 18,602 20,739 Total accumulated postretirement benefit obligation 42,804 44,125 Accumulated postretirement benefit obligation in excess of plans' assets (41,677) (42,954) Unrecognized transition obligation 36,439 38,463 Unrecognized net gain (5,703) (1,175) Unrecognized prior service cost 170 - Accrued postretirement benefit cost in in the Consolidated Balance Sheets $ (10,771) $ (5,666)
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 $6.8 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) COMMON STOCK:
The following table presents information relating to the issuance of common stock.
Common Stock Number of Shares Outstanding Amount (in thousands)
Balance, December 31, 1991 24,298,807 $ 260,414 Stock plan issuances* 404,324 11,473 Shares issued in connection with the Whiting merger 853,832 7,923 Balance, December 31, 1992 25,556,963 279,810 Public offering 2,300,000 66,555 Stock plan issuances* 447,225 13,936 Balance, December 31, 1993 28,304,188 360,301 Shares issued in connection with acquisition of Okie Companies 139,102 4,027 Purchases of treasury stock (213,300) (6,233) Stock plan issuances* 547,056 15,395 Balance, December 31, 1994 28,777,046 $ 373,490
Shares reserved for issuance pursuant to the Company's stock plans at December 31, 1994* 2,457,397
* Dividend Reinvestment and Stock Purchase Plan, Employee Stock Purchase Plan, Employee Savings Plan, Long-Term Incentive Plan of 1987, IES Bonus Stock Ownership Plan and Whiting Stock Option Plans
In 1994, Industries issued 139,102 shares of its common stock for the purchase of certain companies, collectively referred to as the Okie Companies, in a transaction that was accounted for as a purchase. The Okie Companies hold oil and gas properties in the United States and are now wholly-owned subsidiaries of Whiting.
During 1994, Industries reacquired 213,300 shares of its common stock on the open market, at an average price of $29.22 per share, which were subsequently issued to the Dividend Reinvestment Plan and certain of its benefit plans. At December 31, 1994, no shares remained held as treasury stock.
In the first quarter of 1993, Industries sold 2.3 million shares of its common stock in a public offering. The shares were priced at $30 per share. Net proceeds to Industries from this sale were approximately $67 million.
(9) 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.
There are 5,000,000 shares of Industries Cumulative Preferred Stock (no par value) and 700,000 shares of Utilities Cumulative Preference Stock ($100 par value) authorized for issuance, of which none were outstanding at December 31, 1994.
(10) 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.
Diversified has a variable rate credit facility that extends through November 9, 1997, with two one-year extensions available to Diversified. The facility also serves as a stand-by agreement for Diversified's commercial paper program. The agreement provides for a combined maximum of $150 million of borrowings under the agreement and commercial paper to be outstanding at any one time. Interest rates and maturities are set at the time of borrowing for direct borrowings under the agreement and for issuances of commercial paper. The interest rate options are based upon quoted market rates and the maturities are less than one year. At December 31, 1994, $12 million was borrowed under this facility, bearing an interest rate of 6.44%, maturing in January 1995. Diversified also had $68.5 million of commercial paper outstanding at December 31, 1994, with interest rates ranging from 6.27% to 6.38% and maturity dates in the first quarter of 1995, which was also supported by the facility. Diversified intends to continue borrowing under the renewal options of the facility and no conditions exist at December 31, 1994, that would prevent such borrowings. Accordingly, this debt is classified as long-term in the Consolidated Balance Sheets.
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 Utilities - 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
Diversified - Variable rate credit facility 80,500 - - - - Other subsidiaries' debt 282 305 331 357 10,393 Total $ 181,702 $ 16,075 $ 9,021 $ 1,047 $ 61,083
The Company intends to refinance the majority of the debt maturities with long-term securities.
(b) Long-Term Debt of McLeod, Inc. -
Diversified has a $7.5 million investment in Class B Common Stock of McLeod, Inc. (McLeod), which represents a voting interest of less than 20%. McLeod provides local and long-distance telecommunication services to business customers and other services related to fiber optics. In 1994, Diversified entered into an agreement whereby it will guarantee $6 million under a credit facility between McLeod and its bankers. Diversified is paid an annual commitment fee and receives options to purchase additional shares of Class B Common Stock for as long as the guarantee remains outstanding. At December 31, 1994, McLeod had $3.5 million outstanding under its facility.
(c) Short-Term Debt -
At December 31, 1994, the Company had bank lines of credit aggregating $77.7 million (Industries - $1.5 million, Utilities - $67.7 million, Diversified - $7.5 million and Whiting - $1.0 million). Utilities was using $37 million to support commercial paper (weighted average interest rate of 6.13%) and $7.7 million 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.
(11) 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 or earnings per average common share 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 $576 million compared to estimated fair value of $551 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 shareholders.
(12) COMMITMENTS AND CONTINGENCIES: (a) Construction Program -
The Company's construction and acquisition program anticipates expenditures of approximately $202 million for 1995, which includes $163 million at Utilities and $39 million at Diversified. In addition to the $163 million, Utilities anticipates expenditures of approximately $13 million for mandated energy efficiency programs. These 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 $9.5 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 $44 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.
Oil and Gas Properties Dismantlement and Abandonment Costs
Whiting is responsible for certain dismantlement and abandonment costs related to various off-shore oil and gas properties, the most significant of which is located off the coast of California. Whiting accrues these costs as reserves are extracted and such costs are included in "Depreciation and amortization" in the Consolidated Statements of Income. A corresponding environmental liability, $0.1 million at December 31, 1994, has been recognized in the Consolidated Balance Sheets for the cumulative amount expensed.
(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 $10 million. The ultimate level of costs to be billed to Utilities depends on the pipelines' filings with the FERC and other future events, including the market price of natural gas. However, Utilities believes any transition costs that the FERC would allow the pipelines to collect from Utilities would be recovered from its customers, based upon regulatory treatment of these costs currently and similar past costs by the IUB. Accordingly, regulatory assets, in amounts corresponding to the recorded liabilities, have been recorded to reflect the anticipated recovery.
(13) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities, Utilities has undivided ownership interests in jointly-owned electric generating stations and related transmission facilities. Each of the respective owners is responsible for the financing of its portion of the construction costs. Kilowatt-hour generation and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its Statements of Income. Information relative to Utilities' ownership interest in these facilities at December 31, 1994 is as follows:
Ottumwa Neal DAEC Unit 1 Unit 3 ($ 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
(14) SEGMENTS OF BUSINESS:
The principal business segments of Industries are the generation, transmission, distribution and sale of electric energy by Utilities and the purchase, distribution and sale of natural gas by Utilities and Industrial Energy Applications, Inc., a wholly-owned subsidiary of Diversified. Certain financial information relating to Industries' 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 165,569 181,923 167,082
Operating income - Electric 125,487 128,994 90,891 Gas 8,762 13,673 9,164
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 17,323
Assets - Identifiable assets - Electric 1,347,024 1,288,505 1,226,614 Gas 192,397 168,800 147,395 1,539,421 1,457,305 1,374,009 Other corporate assets 304,568 242,514 220,373
Total consolidated assets $ 1,843,989 $ 1,699,819 $ 1,594,382
Item 9.

Item 9. Changes and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.



Item 10. Directors, Executive Officers, Promoters and Control Persons of the Registrant
Information regarding the identification of directors of Industries and compliance with Section 16(a) reporting requirements of the Securities and Exchange Commission is included in Industries' definitive proxy statement prepared for the 1995 annual meeting of stockholders, which was filed on March 20, 1995, (Proxy Statement under the captions "Proposal Number 1 - Nomination and Election of Directors" and "Certain SEC Filings") and is incorporated herein by reference. The executive officers of the registrant are as follows:
Executive Officers of the Registrant (Effective February 7, 1995)
Lee Liu, 61, Chairman of the Board, President & Chief Executive Officer. First elected officer in 1975.
Blake O. Fisher, Jr., 50, Executive Vice President & Chief Financial Officer and Director. First elected officer in 1991. (i)
Larry D. Root, 58, Executive Vice President. First elected officer in 1979.
Dr. Robert J. Latham, 52, Senior Vice President, Finance. First elected officer in 1985.
Stephen W. Southwick, 48, Vice President, General Counsel & Secretary. First elected officer in 1982.
Thomas R. Seldon, 56, Vice President, Human Resources. First elected officer in 1987.
Dean E. Ekstrom, 47, Vice President, Management Systems. First elected officer in 1991.
Peter W. Dietrich, 55, Vice President, Corporate Development. First elected officer in 1988.
Richard A. Gabbianelli, 38, Controller & Chief Accounting Officer. First elected officer in 1994.
Dennis B. Vass, 45, Treasurer. First elected officer in 1995. (ii)
Officers are elected annually by the Board of Directors and each of the officers named above, except Blake O. Fisher, Jr. and Dennis B. Vass, have been employed by Industries or one of its significant subsidiaries as an officer or in other responsible positions at such companies for at least five years. There are no family relationships among these officers. There are no arrangements or understandings with respect to election of any person as an officer.
(i) Prior to the appointment of Blake O. Fisher, Jr. as Executive Vice President & Chief Financial Officer of the Company in January 1991, he was employed by Consumers Power Company as Vice President Finance and Treasurer.
(ii) Prior to the appointment of Dennis B. Vass as Treasurer of the Company in February, 1995, he was employed by Consumers Power Company as Financial Projects Director and by the Company in April, 1991, as Manager of Finance.
Item 11.

Item 11. Executive Compensation
Information regarding executive compensation and transactions is included in the Proxy Statement under the captions "Compensation of Directors", "Summary Compensation Table", "Compensation Committee Interlocks and Insider Participation" and "IES Industries Plans" and is incorporated herein by reference, except for the "Report of the Compensation Committee on Executive Compensation," the "Performance Graph" and "Proposal Number 2 - To Amend the IE Industries Inc. Long-Term Incentive Plan of 1987" included therein, which are not incorporated herein by reference.
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial owners and management is included in the Proxy Statement under the captions "Security Ownership of Beneficial Owners" and "Security Ownership of Management" and is incorporated herein by reference.
Item 13.

Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related transactions is included in the Proxy Statement under the captions "Other Transactions" and "Compensation of Directors" and is incorporated herein by reference.
PART IV
Item 14.

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page No.
(a) 1. Financial Statements -
Included in Part II of this report -
Report of Management. 56 - 57
Report of Independent Public Accountants. 58
Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992. 59
Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992. 60
Consolidated Balance Sheets at December 31, 1994 and 1993. 61 - 62
Consolidated Statements of Capitalization at December 31, 1994 and 1993. 63
Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992. 64
Notes to Consolidated Financial Statements. 65 - 97
(a) 2. Financial Statement Schedules -
Included in Part IV of this report -
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended December 31, 1994, 1993 and 1992. 103
Other schedules are omitted as not required under Rules of Regulation S-X.
(a) 3. Exhibits -
See Exhibit Index beginning on page 106.
(b) Reports on Form 8-K -
None.
IES INDUSTRIES INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
Column A Column B Column E
Balance Balance Description January 1 December 31 (in thousands) IES Industries Inc. and Non-utility Subsidiaries:
1994: Reserve for economic development loans $ 49 $ 49
Accumulated provision for uncollectible accounts and other $ 457 $ 323
1993: Reserve for economic development loans $ 247 $ 49
Accumulated provision for uncollectible accounts and other $ - $ 457
1992: Reserve for economic development loans $ 1,388 $ 247
Accumulated provision for uncollectible accounts and other $ 3,757 $ -
IES Utilities Inc.:
1994: Accumulated provision for uncollectible accounts $ 409 $ 650
Accumulated provision for rate refunds $ 8,670 $ -
1993: Accumulated provision for uncollectible accounts $ 567 $ 409
Accumulated provision for rate refunds $ 9,020 $ 8,670
1992: Accumulated provision for uncollectible accounts $ 804 $ 567
Accumulated provision for rate refunds $ 1,492 $ 9,020
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, on the 29th day of March 1995.
IES INDUSTRIES INC. (Registrant)
By /s/ Blake O. Fisher, Jr. Blake O. Fisher, Jr. Executive Vice President & Chief Financial Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 29, 1995:
/s/ Lee Liu Chairman of the Board, President & Lee Liu Chief Executive Officer (Principal Executive Officer)
/s/ Blake O. Fisher, Jr. Executive Vice President & Chief Blake O. Fisher, Jr. Financial Officer and Director (Principal Financial Officer)
/s/ Richard A. Gabbianelli Controller & Chief Accounting Officer Richard A. Gabbianelli (Principal Accounting Officer)
/s/ C.R.S. Anderson Director C.R.S. Anderson
/s/ J. Wayne Bevis Director J. Wayne Bevis
/s/ Dr. George Daly Director Dr. George Daly
/s/ G. Sharp Lannom, IV Director G. Sharp Lannom, IV
/s/ Jack R. Newman Director Jack R. Newman
/s/ Robert D. Ray Director Robert D. Ray
/s/ David Q. Reed Director David Q. Reed
/s/ Henry Royer Director Henry Royer
/s/ Robert W. Schlutz Director Robert W. Schlutz
/s/ Anthony R. Weiler Director Anthony R. Weiler
EXHIBIT INDEX
The Exhibits designated by an asterisk are filed herewith and all other Exhibits as stated to be filed are incorporated herein by reference.
Exhibit
3(a) Articles of Incorporation of Registrant, Amended and Restated as of May 4, 1993 (Filed as Exhibit 3(a) to Company's Form 10-K for the year 1993).
3(b) Bylaws of Registrant, as amended November 2, 1994 (Filed as Exhibit 3 to Company's Registration Statement, File No. 33-56981).
4(a) Indenture of Mortgage and Deed of Trust, dated as of September 1, 1993, between Utilities (formerly Iowa Electric Light and Power Company (IE)) and the First National Bank of Chicago, as Trustee (Mortgage) (Filed as Exhibit 4(c) to IE's Form 10-Q for the quarter ended September 30, 1993).
4(b) Supplemental Indentures to the Mortgage:
Number Dated as of IE File Reference Exhibit
First October 1, 1993 Form 10-Q, 11/12/93 4(d) Second November 1, 1993 Form 10-Q, 11/12/93 4(e)
4(c) Indenture of Mortgage and Deed of Trust, dated as of August 1, 1940, between Utilities (formerly IE) and the First National Bank of Chicago, Trustee (1940 Indenture) (Filed as Exhibit 2(a) to IE's Registration Statement, File No. 2-25347).
4(d) Supplemental Indentures to the 1940 Indenture:
Number Dated as of IE File Reference Exhibit
First March 1, 1941 2-25347 2(a) Second July 15, 1942 2-25347 2(a) Third August 2, 1943 2-25347 2(a) Fourth August 10, 1944 2-25347 2(a) Fifth November 10, 1944 2-25347 2(a) Sixth August 8, 1945 2-25347 2(a) Seventh July 1, 1946 2-25347 2(a) Eighth July 1, 1947 2-25347 2(a) Ninth December 15, 1948 2-25347 2(a) Tenth November 1, 1949 2-25347 2(a) Eleventh November 10, 1950 2-25347 2(a) Twelfth October 1, 1951 2-25347 2(a) Thirteenth March 1, 1952 2-25347 2(a) Fourteenth November 5, 1952 2-25347 2(a) Fifteenth February 1, 1953 2-25347 2(a) Sixteenth May 1, 1953 2-25347 2(a) Seventeenth November 3, 1953 2-25347 2(a) Eighteenth November 8, 1954 2-25347 2(a) Nineteenth January 1, 1955 2-25347 2(a) Twentieth November 1, 1955 2-25347 2(a) Twenty-first November 9, 1956 2-25347 2(a) Twenty-second November 6, 1957 2-25347 2(a) Twenty-third November 4, 1958 2-25347 2(a) Twenty-fourth November 3, 1959 2-25347 2(a) Twenty-fifth November 1, 1960 2-25347 2(a) Twenty-sixth January 1, 1961 2-25347 2(a) Twenty-seventh November 7, 1961 2-25347 2(a) Twenty-eighth November 6, 1962 2-25347 2(a) Twenty-ninth November 5, 1963 2-25347 2(a) Thirtieth November 4, 1964 2-25347 2(a) Thirty-first November 2, 1965 2-25347 2(a) Thirty-second September 1, 1966 Form 10-K, 1966 4.10 Thirty-third November 30, 1966 Form 10-K, 1966 4.10 Thirty-fourth November 7, 1967 Form 10-K, 1967 4.10 Thirty-fifth November 5, 1968 Form 10-K, 1968 4.10 Thirty-sixth November 1, 1969 Form 10-K, 1969 4.10 Thirty-seventh December 1, 1970 Form 8-K, 12/70 1 Thirty-eighth November 2, 1971 2-43131 2(g) Thirty-ninth May 1, 1972 Form 8-K, 5/72 1 Fortieth November 7, 1972 2-56078 2(i) Forty-first November 7, 1973 2-56078 2(j) Forty-second September 10,1974 2-56078 2(k) Forty-third November 5, 1975 2-56078 2(l) Forty-fourth July 1, 1976 Form 8-K, 7/76 1 Forty-fifth November 1, 1976 Form 8-K, 12/76 1 Forty-sixth December 1, 1977 2-60040 2(o) Forty-seventh November 1, 1978 Form 10-Q, 6/30/79 1 Forty-eighth December 1, 1979 Form S-16, 2-65996 2(q) Forty-ninth November 1, 1981 Form 10-Q, 3/31/82 2 Fiftieth December 1, 1980 Form 10-K, 1981 4(s) Fifty-first December 1, 1982 Form 10-K, 1982 4(t) Fifty-second December 1, 1983 Form 10-K, 1983 4(u) Fifty-third December 1, 1984 Form 10-K, 1984 4(v) Fifty-fourth March 1, 1985 Form 10-K, 1984 4(w) Fifty-fifth March 1, 1988 Form 10-Q, 5/12/88 4(b) Fifty-sixth October 1, 1988 Form 10-Q, 11/10/88 4(c) Fifty-seventh May 1, 1991 Form 10-Q, 8/13/91 4(d) Fifty-eighth March 1, 1992 Form 10-K, 1991 4(c) Fifty-ninth October 1, 1993 Form 10-Q, 11/12/93 4(a) Sixtieth November 1, 1993 Form 10-Q, 11/12/93 4(b)
4(e) Indenture or Deed of Trust dated as of February 1, 1923, between Utilities (successor to Iowa Southern Utilities Company (IS) as result of merger of IS and IE) and The Northern Trust Company (The First National Bank of Chicago, successor) and Harold H. Rockwell (Richard D. Manella, successor), as Trustees (1923 Indenture) (Filed as Exhibit B-1 to File No. 2- 1719).
4(f) Supplemental Indentures to the 1923 Indenture:
Dated as of File Reference Exhibit
May 1, 1940 2-4921 B-1-k May 2, 1940 2-4921 B-1-l October 1, 1945 2-8053 7(m) October 2, 1945 2-8053 7(n) January 1, 1948 2-8053 7(o) September 1, 1950 33-3995 4(e) February 1, 1953 2-10543 4(b) October 2, 1953 2-10543 4(q) August 1, 1957 2-13496 2(b) September 1, 1962 2-20667 2(b) June 1, 1967 2-26478 2(b) February 1, 1973 2-46530 2(b) February 1, 1975 2-53860 2(aa) July 1, 1975 2-54285 2(bb) September 2, 1975 2-57510 2(bb) March 10, 1976 2-57510 2(cc) February 1, 1977 2-60276 2(ee) January 1, 1978 0-849 2 March 1, 1979 0-849 2 March 1, 1980 0-849 2 May 31, 1986 33-3995 4(g) July 1, 1991 0-849 4(h) September 1, 1992 0-849 4(m) December 1, 1994 0-4117-1 4(f)
4(g) Credit Agreement dated as of March 5, 1992 among IES Diversified Inc. as Borrower, certain banks and Citibank, N.A., as Agent. (Filed as Exhibit 4(p) to Company's Form 10-K for the year 1991).
4(h) Amended and Restated Credit Agreement dated as of January 7, 1993 among IES Diversified Inc. as Borrower, certain banks and Citibank, N.A., as Agent. (Filed as Exhibit 4(v) to the Company's Form 10- K for the year 1992).
* 4(i) Second Amended and Restated Credit Agreement dated as of November 9, 1994 among IES Diversified Inc. as Borrower, certain banks and Citibank, N.A., as Agent.
10(a) Agreement dated December 15, 1971 between Central Iowa Power Cooperative and IE. (Filed as Exhibit 5(a) to IE's Registration Statement, File No. 2-43131).
10(b) Duane Arnold Energy Center Ownership Participation Agreement dated June 1, 1970 between Central Iowa Power Cooperative, Corn Belt Power Cooperative and IE. (Filed as Exhibit 5(kk) to IE's Registration Statement, File No. 2-38674).
10(c) Duane Arnold Energy Center Operating Agreement dated June 1, 1970 between Central Iowa Power Cooperative, Corn Belt Power Cooperative and IE. (Filed as Exhibit 5(ll) to IE's Registration Statement, File No. 2-38674).
10(d) Duane Arnold Energy Center Agreement for Transmission, Transformation, Switching, and Related Facilities dated June 1, 1970 between Central Iowa Power Cooperative, Corn Belt Power Cooperative and IE. (Filed as Exhibit 5(mm) to IE's Registration Statement, File No. 2-38674).
10(e) Basic Generating Agreement dated April 16, 1975 between Iowa Public Service Company, Iowa Power and Light Company, Iowa-Illinois Gas and Electric Company and IS for the joint ownership of Ottumwa Generating Station-Unit 1 (OGS-1). (Filed as Exhibit 1 to IE's Form 10-K for the year 1977).
10(f) Addendum Agreement to the Basic Generating Agreement for OGS-1 dated December 7, 1977 between Iowa Public Service Company, Iowa-Illinois Gas and Electric Company, Iowa Power and Light Company, IS and IE for the purchase of 15% ownership in OGS-1. (Filed as Exhibit 3 to IE's Form 10-K for the year 1977).
10(g) Fuel Lease dated August 21, 1973, as amended by Amendment No. 1 dated August 29, 1973, and by Amendment dated September 17, 1987, between Arnold Fuel, Inc. and IE for the procurement and financing of nuclear fuel. (Filed as Exhibit 10(l) to IE's Form 10-K for the year 1984).
10(h) Amendment dated as of September 17, 1987 to the Fuel Lease dated as of August 21, 1973 between Arnold Fuel, Inc. and IE. (Filed as Exhibit 10(i) to IE's Form 10-K for the year 1987).
10(i) Second Amended and Restated Credit Agreement dated as of September 17, 1987 between Arnold Fuel, Inc. and the First National Bank of Chicago and the Amended and Restated Consent and Agreement dated as of September 17, 1987 by IE. (Filed as Exhibit 10(j) to IE's Form 10-K for the year 1987).
Management Contracts and/or Compensatory Plans (Exhibits 10(j) through 10(t))
10(j) Service Contract between S. Levy, Incorporated and IE. (Filed as Exhibit 10(m) to IE's Form 10-K for the year 1985).
10(k) Supplemental Retirement Plan. (Filed as Exhibit 10(l) to the Company's Form 10-K for the year 1987).
10(l) Management Incentive Compensation Plan. (Filed as Exhibit 10(m) to the Company's Form 10-K for the year 1987).
10(m) Key Employee Deferred Compensation Plan. (Filed as Exhibit 10(n) to the Company's Form 10-K for the year 1987).
10(n) Long-Term Incentive Plan. (Filed as Exhibit 10(o) to the Company's Form 10-K for the year 1987).
10(o) Executive Guaranty Plan. (Filed as Exhibit 10(p) to the Company's Form 10-K for the year 1987).
10(p) Executive Change of Control Severance Agreement. (Filed as Exhibit 10(s) to the Company's Form 10-K for the year 1989).
10(q) Amendments to Key Employee Deferred Compensation Agreement for Directors. (Filed as Exhibit 10(u) to the Company's Form 10-Q for the quarter ended March 31, 1990).
10(r) Amendments to Key Employee Deferred Compensation Agreement for Key Employees. (Filed as Exhibit 10(v) to the Company's Form 10-Q for the quarter ended March 31, 1990).
10(s) Amendments to Management Incentive Compensation Plan. (Filed as Exhibit 10(y) to the Company's Form 10-Q for the quarter ended March 31, 1990).
10(t) Director Retirement Plan. (Filed as Exhibit 10(t) to the Company's Form 10-K for the year 1993).
10(u) Agreement and Plan of Merger, dated as of February 27, 1991, by and between IE Industries Inc. and Iowa Southern Inc. (Filed as Exhibit 2 to the Company's Form 8-K dated February 27, 1991).
10(v) IES Industries Inc. Shareholders' Rights Plan. (Filed as Exhibit I-2 to the Company's Registration Statement on Form 8-A filed November 13, 1991).
10(w) Restated Agreement and Plan of Merger among IES Industries Inc., WPC Acquisition Corp. and Whiting Petroleum Corporation dated November 15, 1991. (Filed as Annex A to the Company's Form S-4 Registration Statement No. 33-44495).
10(x) Agreement for Purchase and Sale of Certain Assets and Real Estate and Assignment of Easements, Leases and Licenses between Union Electric Company (Seller) and IE (Buyer). (Filed as exhibit 10(t) to IE's Form 10-K for the year 1991).
10(y) Lease and Security Agreement, dated October 1, 1993, between IES Diversified Inc., as lessee, and Sumitomo Bank Leasing and Finance, Inc., as lessor. (Filed as Exhibit 10(z) to the Company's Form 10-K for the year 1993).
10(z) Receivables Purchase and Sale Agreement dated as of June 30, 1989, as Amended and Restated as of April 15, 1994, among IES Utilities Inc. (as Seller) and CIESCO L.P. (as the Investor) and Citicorp North America, Inc. (as Agent). (Filed as Exhibit 10(a) to Utilities' Form 10-Q for the quarter ended March 31, 1994 (File No. 0-4117-1)).
10(aa) Agreement and Plan of Merger among IES Industries Inc., WOC Acquisition Company, Okie Crude Company, Elba Gas Company, Kimble Gas Gathering Company, Thomas M. Atkinson and Joan B. Atkinson, dated as of March 25, 1994. (Filed as Exhibit 10(b) to Company's Form 10-Q for the quarter ended March 31, 1994).
10(ab) IES Diversified Inc. Guaranty with McLeod, Inc., dated May 16, 1994 (Filed as Exhibit 10(c) to Company's Form 10-Q for the quarter ended June 30, 1994).
10(ac) Agreement Regarding Guarantee Between McLeod, Inc. and IES Diversified Inc., dated May 16, 1994 (Filed as Exhibit 10(d) to Company's Form 10-Q for the quarter ended June 30, 1994).
10(ad) Guaranty (IES Utilities Trust No. 1994-A) from IES Utilities Inc., dated as of June 29, 1994. (Filed as Exhibit 10(b) to Utilities' Form 10-Q for the quarter ended June 30, 1994 (File No. 0-4117-1)).
10(ae) Agreement and Plan of Merger between IE and IS dated as of June 4, 1993 (Agreement and Plan of Merger) (Filed as Exhibit 2 to the Company's Current Report on Form 8-K, dated June 4, 1993).
10(af) Amendment 1 dated June 16, 1993, to the Agreement and Plan of Merger (Filed as Exhibit 2(b) to the IE Registration Statement on Form S-3, dated September 14, 1993 (File No. 33-68796)).
10(ag) Amendment 2 dated September 8, 1993, to the Agreement and Plan of Merger (Filed as Exhibit 2(c) to the IE Registration Statement on Form S-3, dated September 14, 1993 (File No. 33-68796)).
10(ah) Amendment 3 dated September 27, 1993, to the Agreement and Plan of Merger (Filed as Exhibit 2(d) to the Company's Current Report on Form 8-K, dated December 9, 1993).
* 21 Subsidiaries of the Registrant.
* 23 Consent of Independent Public Accountants.
* 27 Financial Data Schedule
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Company has not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt that has not been registered if the total amount of securities authorized thereunder does not exceed 10% of total assets of the Company but hereby agrees to furnish to the Commission on request any such instruments.