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, 1995, are as follows:
Name and Location Major Fuel Net Kilowatts Accredited of Station Type Generating Capability
Duane Arnold Energy Center, Palo, Iowa Nuclear 364,000 (1)
Ottumwa Generating Station, Ottumwa, Iowa Coal 343,440 (2) Prairie Creek Station, Cedar Rapids, Iowa Coal 212,500 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 1,125,940
Peaking Turbines, Marshalltown, Iowa Oil 162,500 Centerville Combustion Turbines, Centerville, Iowa Oil 48,000 Diesel Stations, all in Iowa Oil 12,200 Total Oil 222,700
Grinnell Station, Grinnell, Iowa Gas 47,200 Agency Street Combustion Turbines, West Burlington, Iowa Gas 63,750 Burlington Combustion Turbines, Burlington, Iowa Gas 47,400 Total Gas 158,350
Total generating capability 1,870,990
(1) Represents Utilities' 70% ownership interest in this 520,000 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.
At December 31, 1995, the transmission lines of Utilities, operating from 34,000 to 345,000 volts, approximated 4,409 circuit miles (all located in Iowa). Utilities owned 108 transmission substations (all located in Iowa) with a total installed capacity of 8,597.1 MVa and 468 distribution substations (all located in Iowa) with a total installed capacity of 2,593.1 MVa.
Subsidiaries other than Utilities also own property which primarily represents investments in transportation, energy-related 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 Bonds.
Item 3.
Item 3. Legal Proceedings
Industries, Diversified, 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 answered the complaint and denied liability. Industries and Diversified were dismissed from the suit in a motion for summary judgment. In addition a motion for summary judgement has reduced Mr. Wiley's claims against the remaining parties to breach of fiduciary duty. All of the defendants believe that the claims are without merit and are vigorously contesting them. The trial has been continued to April 8, 1996, but will likely be continued again given the 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 was 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. The Iowa Supreme Court assigned the case to the Iowa Court of Appeals. On February 2, 1996, the Iowa Court of Appeals reversed the District Court ruling after determining the District Court erred in discounting the expert testimony. Mr. Wiley has a limited time period to make application to the Supreme Court for further review of the Court of Appeals ruling, otherwise the case is remanded back to the District Court for consideration of the expert testimony, but with no additional evidence being taken. Neither Mr. Wiley or his counsel have indicated whether they will ask for further review.
Reference is made to Notes 3 and 12 of the Notes to Consolidated Financial Statements for a discussion of Utilities' rate proceedings and the Company's environmental matters, respectively. 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 $ 27 5/8 $ 24 5/8 $ .525 Second Quarter 26 3/8 20 3/8 .525 Third Quarter 26 3/4 21 3/8 .525 Fourth Quarter 28 1/2 25 7/8 .525
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
(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 timing 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, 1995)
Common Stock, no par value 29,731
(c) Restriction on Payment of Dividends
Under provisions of the Merger Agreement, Industries' annual dividend payment cannot exceed $2.10 per share, the current annual payment level, pending the Proposed Merger.
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 Consolidated Financial Statements include the accounts of IES Industries Inc. (Industries) and its consolidated subsidiaries (collectively the Company). Industries' wholly-owned subsidiaries are IES Utilities Inc. (Utilities) and IES Diversified Inc. (Diversified).
PROPOSED MERGER OF THE COMPANY
The Company, WPL Holdings, Inc. (WPLH) and Interstate Power Company (IPC) have entered into an Agreement and Plan of Merger (Merger Agreement), dated November 10, 1995 (the Proposed Merger). The new holding company will be named Interstate Energy Corporation (Interstate Energy) and Industries will cease to exist. The Proposed Merger, which will be accounted for as a pooling of interests, has been approved by the respective Boards of Directors. It is still subject to approval by the shareholders of each company as well as several federal and state regulatory agencies. The companies expect to receive the shareholder approvals in the second quarter of 1996 and the regulatory approvals by the second quarter of 1997.
The business of Interstate Energy will consist of utility operations and various non-utility enterprises, and it is expected that its utility subsidiaries will serve more than 870,000 electric customers and 360,000 natural gas customers in Iowa, Illinois, Minnesota and Wisconsin.
The operating revenues, net income from continuing operations and total assets of the companies were as follows: PRO FORMA IES COMBINED INDUSTRIES WPLH IPC (Unaudited) (in thousands)
1995 operating revenues $ 851,010 $ 807,255 $ 318,542 $ 1,976,807
1995 net income from continuing operations 64,176 71,618 25,198 160,992
Assets at December 31, 1995 $ 1,985,591 $ 1,872,414 $ 634,316 $ 4,492,321
Under the terms of the Merger Agreement, the outstanding shares of WPLH's common stock will remain unchanged and outstanding as shares of Interstate Energy. Each outstanding share of the Company's common stock will be converted to .98 shares of Interstate Energy's common stock. Each share of IPC's common stock will be converted to 1.11 shares of Interstate Energy's common stock. It is anticipated that Interstate Energy will retain WPLH's common share dividend payment level as of the effective time of the merger. On January 24, 1996, the Board of Directors of WPLH declared a quarterly dividend of 49.25 cents per share. This represents an equivalent annual rate of $1.97 per share. Under provisions of the Merger Agreement, Industries' annual dividend payment cannot exceed $2.10 per share, the current annual payment level, pending the Proposed Merger.
Interstate Energy will be the parent company of Utilities, Wisconsin Power and Light Company and IPC and will be registered under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The Merger Agreement provides that these operating utility companies will continue to operate as separate entities for a minimum of three years beyond the effective date of the merger. In addition, the non-utility operations of the Company and WPLH will be combined shortly after the effective date of the merger under one entity to manage the diversified operations of Interstate Energy.
The SEC historically has interpreted the 1935 Act to preclude registered holding companies, with limited exceptions, from owning both electric and gas utility systems. Although the SEC has recently recommended that registered holding companies be allowed to hold both gas and electric utility operations if the affected states agree, it remains possible that the SEC may require as a condition to its approval of the Proposed Merger that the Company, WPLH and IPC divest their gas utility properties, and possibly certain non-utility ventures of the Company and WPLH, within a reasonable time after the effective date of the Proposed Merger.
Legislation to repeal the 1935 Act was introduced in Congress in 1995 and is pending. No assurance can be given as to when or if such legislation will be considered or enacted. The Staff of the SEC has also recommended that the SEC "permit combination systems by registered holding companies if the affected states concur," and the SEC has proposed rules that would relax current restrictions on investment by registered holding companies in certain "energy related," non-utility businesses. No prediction can be made as to the outcome of these legislative and regulatory proposals.
See Note 2 of the Notes to Consolidated Financial Statements for a further discussion of the Proposed Merger.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the components of net income and financial condition from the prior periods for the Company:
The Company's net income decreased ($2.6) million and ($1.1) million during 1995 and 1994, respectively. Earnings per average common share declined to $2.20 in 1995 from $2.34 in 1994. The 1995 results reflect the impact of the Iowa Utilities Board (IUB) price reduction order in Utilities' recent electric rate case. The effect of the lower electric prices, including the required refund, reduced the 1995 net income by approximately $9.7 million ($0.33 per share). (See Note 3(b) of the Notes to Consolidated Financial Statements for a further discussion of the electric rate case). Warmer than normal weather conditions during the summer months, which added $0.18 to earnings, and an aggressive cost containment program partially offset the negative effects of the IUB order. The 1994 results were affected by milder than normal weather, particularly during the summer months. The 1993 results reflect the recording of certain property write-downs at Diversified and a $2.5 million contribution to the IES Industries Charitable Foundation.
The Company's operating income increased or (decreased) $3.8 million and ($3.3) million during 1995 and 1994, respectively. Reasons for the changes in the results of operations are explained in the following discussion.
Electric Revenues Electric revenues and Kwh sales for Utilities increased or (decreased) as compared with the prior year as follows:
1995 1994 ($ in millions)
Total electric revenues $ 23.1 $ (13.2) Change in off-system sales revenues (0.3) (11.3) Electric revenues (excluding off-system sales) $ 23.4 $ (1.9)
Electric sales (excluding off-system sales): Residential and Rural 7.9% (1.4%) General Service 6.1 0.4 Large General Service 5.9 8.9 Total 5.3 4.3
Warmer than normal weather during the summer of 1995 significantly increased sales. Utilities set new usage records several times, culminated by a new energy peak demand record of 1,824 megawatts on July 12, 1995. The 1994 Kwh sales were adversely affected by milder than normal weather, particularly during the summer months. The largest effect of weather each year was on sales to residential and rural customers. Under historically normal weather conditions, total sales (excluding off-system sales) during 1995 and 1994 would have increased 3.6% and 4.8%, respectively. Sales during 1995 also benefited from the effects of Utilities' annual true-up adjustment to unbilled sales. The growth in general service and large general service sales continues to reflect the underlying strength of the economy as industrial expansions in Utilities' service territory continued during 1995.
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 increase in the 1995 electric revenues was primarily due to the increased sales (excluding off-system sales), higher fuel costs collected through the EAC, the unbilled revenue adjustment and the recovery of expenditures for energy efficiency programs pursuant to an IUB order. The effect of the warmer than normal weather increased 1995 electric revenues by approximately $9 million. These items were partially offset by a reduction in revenues of approximately $17 million during 1995 as the result of the IUB price reduction order. Approximately $3.5 million, $0.07 per share, of the price reduction decrease related to revenues collected in the fourth quarter of 1994. See Notes 3(b) and 3(c) of the Notes to Consolidated Financial Statements for a further discussion of the electric rate case and the energy efficiency cost recovery case, respectively.
The decrease in the 1994 electric revenues was 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 1994 sales (excluding off-system sales) partially offset the effects of the above items.
Gas Revenues Gas revenues increased or (decreased) as compared with the prior year as follows:
1995 1994 (in millions)
Gas revenues: Utilities $ (1.7) $ (15.3) Industrial Energy Applications, Inc. (IEA) 26.5 (1.1) $ 24.8 $ (16.4)
Utilities' gas sales and transported volumes in therms increased or (decreased) as compared with the prior period as follows:
1995 1994
Residential 3.4% (7.1%) Commercial 2.5 (8.2) Industrial (22.7) (13.2)
Sales to consumers (0.5) (8.3)
Transported volumes 22.1 22.2
Total 4.8 (2.7)
Under historically normal weather conditions, Utilities' gas sales and transported volumes would have increased 3.5% and 0.7% in 1995 and 1994, 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.
On August 4, 1995, Utilities applied to the IUB for an annual increase in gas rates of $8.8 million, or 6.2%. An interim increase of $7.1 million became effective October 11, 1995, subject to refund. Utilities, the Office of Consumer Advocate and all three industrial intervenor groups have entered into a settlement agreement, subject to IUB approval, which allows Utilities a $6.3 million annual increase. Utilities expects that the IUB will rule on the settlement agreement no later than the second quarter of 1996.
Utilities' gas revenues decreased in 1995 primarily because of lower gas costs recovered through the PGA, and was substantially offset by the effects of the interim rate increase, recovery of expenditures for the energy efficiency programs and increased revenues from transported gas volumes. The 1994 revenue decrease was primarily due to lower gas costs recovered through the PGA and, to a lesser extent, the effect of the lower sales.
IEA's gas revenues increased in 1995 primarily due to an increase of 121% in gas volumes, partially offset by lower unit gas costs. The significant increase in gas volumes was due to heightened marketing efforts as well as expanding into additional regional markets. IEA, which is based in Cedar Rapids, IA, opened branch offices in Phoenix, Denver, St. Louis and Atlanta in 1995. The decrease in IEA's 1994 gas revenues was due to lower gas costs, partially offset by a 16% increase in gas volumes.
Other Revenues Other revenues increased $17.2 million and $14.1 million during 1995 and 1994, respectively, primarily because of increased revenues at Whiting Petroleum Company (Whiting). Whiting's operations have expanded significantly the last several years as a result of continued acquisitions of oil and gas properties. These increases were partially offset as the result of the sale of several of Diversified's subsidiaries during 1994 and 1995. The operations of the subsidiaries that were sold were not significant to the results of operations or financial position of the Company. An increase in Utilities' steam revenues also contributed to the 1995 increase.
Operating Expenses Fuel for production increased $10.3 million during 1995 due to higher fuel cost recoveries through the EAC, which are included in fuel for production, and a higher average fuel cost. Total 1995 Kwh generation at Utilities' generating stations was flat compared to 1994. The Duane Arnold Energy Center (DAEC), Utilities' nuclear generating facility, generated less Kwh in 1995 because it was down from late February 1995 to late April 1995 for a scheduled refueling outage. There was no refueling outage in 1994. Increased generation at Utilities' fossil-fueled generating stations, due to the increased sales and the DAEC outage, virtually offset the decreased DAEC generation. 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. Generation at Utilities' generating stations increased during 1994 primarily because of increased sales and the increased availability of DAEC as there was a scheduled refueling outage in 1993 also.
Purchased power decreased ($1.9) million and ($24.7) million in 1995 and 1994, respectively. The 1995 decrease was primarily due to lower capacity costs of ($6.6) million, partially offset by higher energy purchases of $4.7 million due to the increased sales to customers and flat generation, as discussed above. The 1994 decrease was caused by 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.
Gas purchased for resale increased $20.9 million in 1995 due to the increased gas sales at IEA and the timing of the recovery of gas costs through the PGA at Utilities, partially offset by lower natural gas prices. Gas purchased for resale decreased ($15.0) million in 1994 because of lower gas costs and lower gas sales at Utilities.
Other operating expenses increased $24.5 million and $14.2 million in 1995 and 1994, respectively. Increased labor and benefits costs and increased operating activities at Whiting contributed to both increases. The 1995 increase was also due to costs associated with a project to review and redesign Utilities' major business processes, the amortization of previously deferred energy efficiency expenditures at Utilities (which are currently being recovered through rates), increased operating activities at IEA and costs relating to the Proposed Merger. These increases were partially offset by decreased nuclear operating costs, lower insurance costs at Utilities and decreased costs resulting from the sale of the Diversified subsidiaries. In addition, following the receipt of the IUB price reduction order, Utilities took action and successfully reduced 1995 operating and maintenance costs by about $8 million from budgeted levels. The 1994 increase was also attributable to higher nuclear operating costs, former manufactured gas plant (FMGP) clean-up costs and increased information technology costs at Utilities.
Maintenance expenses increased or (decreased) ($6.7) million and $3.9 million during 1995 and 1994, respectively. The 1995 decrease was due to less required maintenance activities at the DAEC and at Utilities' fossil-fueled generating stations and the cost containment actions discussed above. The 1994 increase was primarily because of increased labor costs and maintenance at the DAEC, partially offset by lower maintenance at Utilities' fossil-fueled generating stations.
Depreciation and amortization increased during both years because of increases in utility plant in service and the acquisition of oil and gas operating properties. The 1995 increase was partially offset by lower depreciation rates implemented at Utilities as a result of the IUB electric price reduction order. Depreciation and amortization expenses for all periods include a provision for decommissioning the DAEC, which is collected through rates. The annual recovery level was increased to $6.0 million in 1995 from $5.5 million, as a result of Utilities' recent electric rate case.
During the first quarter of 1996, the Financial Accounting Standards Board (FASB) issued an Exposure Draft on Accounting for Liabilities Related to Closure and Removal of Long-Lived Assets which deals with, among other issues, the accounting for decommissioning costs. If current electric utility industry accounting practices for such decommissioning are changed: (1) annual provisions for decommissioning could increase relative to 1995 and, (2) the estimated cost for decommissioning could be recorded as a liability, rather than as accumulated depreciation, with recognition of an increase in the recorded amount of the related DAEC plant. 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 the recovery of decommissioning costs allowed in Utilities' most recent rate case).
Taxes other than income taxes increased $2.7 million and $1.9 million during 1995 and 1994, respectively, largely because of increased property taxes at Utilities caused by increases in assessed property values.
Interest Expense and Other Interest expense increased $4.7 million during 1995 primarily because of an increase in the average amount of short-term debt outstanding and interest related to Utilities' electric rate refund. Lower average interest rates, attributable to refinancing $100 million of long-term debt at lower rates and the mix of long-term and short-term debt, partially offset the increase.
Miscellaneous, net reflected a decrease in income of ($0.3) million during 1995 and an increase in income of $6.4 million during 1994. The 1995 decrease was primarily due to an increase in fees related to the sale of utility accounts receivable as the average amount of receivables sold during the year increased. Gains on the sale of several investments by Diversified's subsidiaries partially offset these fees. The 1994 increase was primarily due to the effect of transactions recorded in 1993 for certain property write-downs at Diversified, a contribution to the IES Charitable Foundation and a loss on the defeasance of Industries' debentures.
Federal and state income taxes increased $0.9 million and $4.5 million in 1995 and 1994, respectively. The increases for both years are due to the effect of property related temporary differences for which deferred taxes had not been provided, pursuant to rate making principles, that are now becoming payable. Adjustments to tax reserves also contributed to the increased taxes in 1995.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to Utilities' construction programs, its debt maturities and the level of Diversified's business opportunities. The Company's pretax ratio of times interest earned was 3.12, 3.38 and 3.38 in 1995-1993, respectively. In 1995, cash flows from operating activities were $196 million versus $216 million in 1994. The decrease was primarily due to expenditures related to the effect of the 1995 DAEC refueling outage and other changes in working capital.
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 A2 A - Short-term debt P1 A1
Diversified - Short-term debt P2 A2
The Company's liquidity and capital resources will be affected by environmental and legislative issues, including the ultimate disposition of remediation issues surrounding the Company's environmental liabilities and the Clean Air Act as amended, as discussed in Note 12 of the Notes to Consolidated Financial Statements, and the National Energy Policy Act of 1992 as discussed in the Other Matters section. 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. It is not certain if, and how, the Proposed Merger may affect the Company's debt ratings.
The IUB has current 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, 1995, Utilities had approximately $50 million of such costs recorded as regulatory assets. On June 1, 1995, Utilities began recovery of those costs incurred through 1993. See Note 3(c) of the Notes to Consolidated Financial Statements for a discussion of the timing of the filings for the recovery of these costs under IUB rules.
Under provisions of the Merger Agreement, there are restrictions on the amount of common stock and long-term debt the Company can issue pending the merger. The Company does not expect the restrictions to have a material effect on its ability to meet its future capital requirements.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program anticipates expenditures of approximately $245 million for 1996, of which approximately $164 million represents expenditures at Utilities and approximately $81 million represents expenditures at Diversified. Of the $164 million of Utilities' expenditures, 55% represents expenditures for electric, gas and steam transmission and distribution facilities, 19% represents fossil-fueled generation expenditures, 13% represents information technology expenditures and 5% represents nuclear generation expenditures. The remaining 8% represents miscellaneous electric and general expenditures. In addition to the $164 million, Utilities anticipates expenditures of $13 million in connection with mandated energy efficiency programs. Diversified's anticipated expenditures include approximately $75 million for domestic and international energy-related construction and acquisition expenditures.
The Company's levels of construction and acquisition expenditures are projected to be $283 million in 1997, $255 million in 1998, $247 million in 1999 and $215 million in 2000. It is estimated that approximately 80% of Utilities' construction and acquisition expenditures will be provided by cash from operating activities (after payment of dividends) for the five-year period 1996-2000. Financing plans for Diversified's construction and acquisition program will vary, depending primarily on the level of energy- related acquisitions.
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.
Under provisions of the Merger Agreement, there are restrictions on the amount of construction and acquisition expenditures the Company can make pending the merger. The Company does not expect the restrictions to have a material effect on its ability to implement its anticipated construction and acquisition program.
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, 2000:
(in millions) Utilities $ 140.3 Diversified's variable rate credit facility 124.2 Other subsidiaries' debt 11.4 $ 275.9
The Company intends to refinance the majority of the debt maturities with long-term securities.
In December 1995, Utilities issued $50 million of Subordinated Deferrable Interest Debentures, 7-7/8%, due 2025. The proceeds from the issuance of the debentures were used to retire short-term borrowings which were incurred in October 1995 to repay at maturity, $50 million of Series X, 9.42% First Mortgage Bonds.
In March 1995, Utilities repaid at maturity $50 million of Series W, 9.75% First Mortgage Bonds and, in a separate transaction, issued $50 million of Collateral Trust Bonds, 7.65%, due 2000.
Utilities has entered into an Indenture of Mortgage and Deed of Trust dated September 1, 1993 (New Mortgage). 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. 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. 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, 1995, such restrictions would have allowed Utilities to issue at least $258 million of additional First Mortgage Bonds.
In order to provide an instrument for the issuance of unsecured subordinated debt securities, Utilities entered into an Indenture dated December 1, 1995 (Subordinated Indenture). The Subordinated Indenture provides for, among other things, the issuance of unsecured subordinated debt securities. Any debt securities issued under the Subordinated Indenture are subordinate to all senior indebtedness of Utilities, including First Mortgage Bonds and Collateral Trust Bonds.
Utilities has received authority from the Federal Energy Regulation Commission (FERC) and the SEC to issue up to $250 million of long-term debt, and has $150 million of remaining authority under the current FERC docket and $200 million of remaining authority under the current SEC shelf registration. Utilities expects to replace one series of First Mortgage Bonds that mature in 1996 with other long- term securities.
Diversified has a variable rate credit facility that extends through November 9, 1998, with a one-year extension 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, 1995, there were no borrowings outstanding under this facility. Diversified had $124.2 million of commercial paper outstanding at December 31, 1995, with interest rates ranging from 5.85% to 6.50% and maturity dates in the first quarter of 1996. Diversified intends to continue borrowing under the renewal options of the facility and no conditions exist at December 31, 1995, that would prevent such borrowings. Accordingly, this debt is classified as long-term in the Consolidated Balance Sheets. The facility contains covenants that could restrict the amount of borrowings available under the facility.
Refer to Note 6(b) of the Notes to Consolidated Financial Statements for a discussion of a guarantee associated with debt issued by McLeod, Inc.
The Articles of Incorporation of Utilities authorize and limit the aggregate amount of additional shares of Cumulative Preference Stock and Cumulative Preferred Stock that may be issued. At December 31, 1995, 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, 1995.
The Company's capitalization ratios at year-end were as follows:
1995 1994
Long-term debt 49% 48% Preferred stock 2 2 Common equity 49 50 100% 100%
The 1995 and 1994 ratios include $15 million and $100 million, respectively, of long-term debt due in less than one year because it was the Company's intention to refinance the debt with long-term securities.
Under provisions of the Merger Agreement, there are restrictions on the amount of common stock and long-term debt the Company can issue pending the merger. The Company does not expect the restrictions to have a material effect on its ability to meet its future capital requirements.
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, 1995, Utilities had outstanding short-term borrowings of $109.9 million, including $8.9 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, 1995, Utilities had sold $58 million under the agreement.
At December 31, 1995, the Company had bank lines of credit aggregating $131.1 million (Industries - $1.5 million, Utilities - $121.1 million, Diversified - $7.5 million and Whiting - $1.0 million). Utilities was using $101 million to support commercial paper (weighted average interest rate of 5.81%) and $11.1 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, 1995, there were no borrowings under this facility.
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible Party (PRP) by various federal and state environmental agencies for 28 FMGP sites, but believes it is not responsible for two of these sites. There are also six other sites for which it may be designated as a PRP in the future. Utilities is working pursuant to the requirements of the various agencies to investigate, mitigate, prevent and remediate, where necessary, damage to property, including damage to natural resources, at and around the sites in order to protect public health and the environment. Utilities believes it has completed the remediation of five sites although it is in the process of obtaining final approval from the applicable environmental agencies on this issue for each site. Utilities is in various stages of the investigation and/or remediation processes for 19 sites and expects to begin the investigation process in 1996 for the other two sites. Utilities estimates the range of costs to be incurred for investigation and/or remediation of the sites to be approximately $22 million to $55 million.
Utilities has recorded environmental liabilities related to the FMGP sites of approximately $35 million (including $4.6 million as current liabilities) at December 31, 1995. 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, and the minimum of the estimated cost range for those sites where the investigation is in its earlier stages or has not started. 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 may be required to monitor these sites for a number of years upon completion of remediation, as is the case with several of the sites for which remediation has been completed.
Utilities has begun pursuing claims under its prior 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, 1995. Regulatory assets of approximately $35 million, which reflect the future recovery that is being provided through Utilities' rates, have been recorded in the Consolidated Balance Sheets. Considering the current 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 (NOx) to achieve reductions of atmospheric chemicals believed to cause acid rain. The provisions of the Act are being 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 has completed the modifications necessary to meet the Phase I requirements and has installed continuous emission monitors on all affected units as required by the Act. Utilities expects to meet the requirements of Phase II by switching to lower sulfur fuels, capital expenditures primarily related to fuel burning equipment and boiler modifications and the possible purchase of sulfur dioxide allowances. Utilities estimates capital expenditures at approximately $20 million, including $4 million in 1996, in order to meet the acid rain requirements of the Act.
The acid rain program under the Act also creates sulfur dioxide allowances. An allowance is defined as an authorization for an owner to emit one ton of sulfur dioxide into the atmosphere. Currently, Utilities receives a sufficient number of allowances annually to offset its emissions of sulfur dioxide from its Phase I units. It is anticipated that in the year 2000, when the Phase II units participate in the allowance program, Utilities may have an insufficient number of allowances annually to offset its estimated emissions and may have to purchase additional allowances, or make modifications to the plants or limit operations to reduce emissions. Utilities is reviewing its options to ensure that it will have sufficient allowances to offset its emissions in the year 2000 and thereafter. Utilities believes that the potential cost of ensuring sufficient allowances will not have a material adverse effect on its financial position or results of operations.
The Act also requires the United States Environmental Protection Agency (EPA) to study and regulate, if necessary, additional issues that potentially affect the electric utility industry, including emissions relating to nitrogen oxides (NOx), ozone transport and mercury. Currently, the impacts of these potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-case modeling methods, suggests that the Cedar Rapids area could be classified as "nonattainment" for the National Ambient Air Quality Standard (NAAQS) established for sulfur dioxide. The worst- case modeling study suggests that two of Utilities' generating facilities contribute to the modeled exceedences and recommends that additional monitors be located near Utilities' sources to assess actual ambient air quality. In the event that Utilities' facilities contribute excessive emissions, Utilities would be required to reduce emissions, which would primarily entail capital expenditures for modifications to the facilities. Utilities is currently reviewing EPA's assumptions and modeling results and is proposing a strategy to voluntarily reduce the excessive emissions through modification of its facilities at a potential capital cost of up to $10 million over the next four years.
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, $10.9 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 with the possibility of further delay being likely. 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 and supporting legislation currently before the U.S. Congress, 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, 1995, Utilities has prepaid costs of approximately $1.1 million to the Compact for the building of such a facility. A Compact disposal facility is anticipated to be in operation in approximately ten years after approval of new enabling legislation by the member states. Such legislation is expected to be considered by the member states in 1996. 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. In addition, the Barnwell, South Carolina disposal facility has reopened for an indefinite time period and Utilities is in the process of shipping to Barnwell the majority of the low-level radioactive waste it has accumulated on-site, and intends to ship the waste it produces in the future as long as the Barnwell site remains open, thereby minimizing the amount of waste stored on-site.
The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects has been the subject of increased public, governmental, industry 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, $1.7 million at December 31, 1995, has been recognized in the Consolidated Balance Sheets for the cumulative amount expensed.
OTHER MATTERS
Competition As legislative, regulatory, economic and technological changes occur, electric utilities are faced with increasing pressure to become more competitive. Such competitive pressures could result in loss of customers and an incurrence of stranded costs (i.e. the cost of assets which could be rendered otherwise unrecoverable as the result of competitive pricing). To the extent stranded costs cannot be recovered from customers, they would be borne by security holders.
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. In March 1995, the FERC issued a Notice of Proposed Rulemaking pursuant to which FERC proposes to promote competition in the electric utility industry by requiring that each transmission owning utility must 1) implement non- discriminatory tariffs allowing open access to that utility's transmission facilities by wholesale buyers and sellers of electricity and 2) charge itself the same price for transmission and ancillary services as it charges third parties under the tariffs. Utilities filed conforming pro- forma open access transmission tariffs with the FERC on July 24, 1995. The tariffs were accepted by the FERC and became effective October 1, 1995. The geographic position of Utilities' transmission system could provide revenue opportunities in the open access environment. FERC's proposal would allow for recovery of certain wholesale stranded costs in connection with wholesale transmission. IEA received approval in the same FERC proceeding to market electric power at market based rates. The Company cannot predict the final regulations that may be adopted.
The IUB initiated a Notice of Inquiry (Docket No. NOI- 95-1) in early 1995 on the subject of "Emerging Competition in the Electric Utility Industry." A one-day roundtable discussion was held to address all forms of competition in the electric utility industry and to assist the IUB in gathering information and perspectives on electric competition from all persons or entities with an interest or stake in the issues. Additional discussions were held in December 1995. The IUB is expected to release a status report on the inquiry in the first quarter of 1996.
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). If a portion of Utilities' operations become no longer subject to the provisions of SFAS 71, a write-down of related regulatory assets would be required, unless some form of transition cost recovery is established by the appropriate regulatory body. Utilities believes that it still meets the requirements of SFAS 71. Refer to Note 1(c) of the Notes to Consolidated Financial Statements for a further discussion.
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, ongoing cost reductions and productivity enhancements. In 1995, the Company initiated a program called Process Redesign to examine all of the major business processes of Utilities. The goals of Process Redesign include improving customer service and commitment and significantly reducing Utilities' cost structure. In 1995, Process Redesign identified many of the changes that Utilities should pursue and Utilities has begun implementing many of those actions. Implementation will be substantially completed in 1996.
Accounting Pronouncements SFAS 121, issued in March 1995 by the Financial Accounting Standards Board (FASB) and effective for 1996, establishes accounting standards for the impairment of long-lived assets. SFAS 121 also requires that regulatory assets that are no longer probable of recovery through future revenues be charged to earnings. SFAS 121 is not expected to have an impact on the financial position or results of operations of the Company upon adoption.
Financial Derivatives The Company has a policy that financial derivatives are to be used only to mitigate business risks and not for speculative purposes. Derivatives have been used by the Company on a very limited basis. At December 31, 1995, the Company had no financial derivatives outstanding.
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 financial position or 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 Utilities' rate activities and seasonal weather conditions. The first quarter net income in 1995 was significantly lower than 1994 as Utilities recorded a $8.0 million pre-tax reserve for electric rate refund in the first quarter of 1995. Approximately $3.5 million of the reserve related to revenues collected in the fourth quarter of 1994. Milder weather in 1995 also contributed to the decrease. Utilities' rate activities are discussed in Note 3 of the Notes to Consolidated Financial Statements. Refer to Management's Discussion and Analysis for a discussion of the impacts of weather.
Quarter Ended March June September December 31 30 30 31 (in thousands, except per share amounts) Operating revenues $ 206,392 $ 189,447 $ 238,467 $ 216,704 Operating income 22,115 33,456 63,710 32,431 Net income 6,740 12,508 31,120 13,808 Earnings per average common share 0.23 0.43 1.06 0.48
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
Item 8.
Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 70.
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, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, 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 are 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 8 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.
/s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Chicago, Illinois February 2, 1996
CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31 1995 1994 1993 (in thousands, except per share amounts) Operating revenues: Electric $ 560,471 $ 537,327 $ 550,521 Gas 190,339 165,569 181,923 Other 100,200 82,968 68,822 851,010 785,864 801,266
Operating expenses: Fuel for production 96,256 85,952 87,702 Purchased power 66,874 68,794 93,449 Gas purchased for resale 141,716 120,795 135,830 Other operating expenses 201,390 176,863 162,642 Maintenance 46,093 52,841 48,913 Depreciation and amortization 97,958 86,378 77,012 Taxes other than income taxes 49,011 46,308 44,449 699,298 637,931 649,997
Operating income 151,712 147,933 151,269
Interest expense and other: Interest expense 50,727 46,010 44,440 Allowance for funds used during construction -3,424 -3,910 -1,972 Preferred dividend requirements of IES Utilities Inc. 914 914 914 Miscellaneous, net -3,170 -3,472 2,908 45,047 39,542 46,290
Income before income taxes 106,665 108,391 104,979
Federal and state income taxes 42,489 41,573 37,041
Net income $ 64,176 $ 66,818 $ 67,938
Average number of common shares outstanding 29,202 28,560 27,764
Earnings per average common share $ 2.20 $ 2.34 $ 2.45
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31 1995 1994 1993 (in thousands)
Balance at beginning of year $ 218,293 $ 211,750 $ 202,919 Add: Net income 64,176 66,818 67,938
Deduct: Cash dividends declared on common stock, at a per share rate of $2.10 for all years 61,392 60,065 59,107 Other 0 210 0 Balance at end of year $ 221,077 $ 218,293 $ 211,750
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS December 31 ASSETS 1995 1994 (in thousands) Property, plant and equipment: Utility - Plant in service - Electric $ 1,900,157 $ 1,798,059 Gas 165,825 158,115 Other 106,396 86,005 2,172,378 2,042,179 Less - Accumulated depreciation 950,324 880,888 1,222,054 1,161,291 Leased nuclear fuel, net of amortization 36,935 49,731 Construction work in progress 52,772 73,339 1,311,761 1,284,361 Other, net of accumulated depreciation and amortization of $53,026,000 and $35,767,000, respectively 193,215 154,657 1,504,976 1,439,018
Current assets: Cash and temporary cash investments 6,942 4,993 Accounts receivable - Customer, less reserve 37,214 26,098 Other 10,493 10,388 Income tax refunds receivable 982 6,434 Production fuel, at average cost 12,155 13,988 Materials and supplies, at average cost 28,354 30,216 Adjustment clause balances 0 1,433 Regulatory assets 22,791 20,145 Oil and gas properties held for resale 9,843 0 Prepayments and other 23,099 24,692 151,873 138,387
Investments: Nuclear decommissioning trust funds 47,028 33,779 Investment in foreign entities 24,770 473 Cash surrender value of life insurance policies 9,838 8,867 Investment in McLeod, Inc. 9,200 7,500 Other 3,897 4,274 94,733 54,893
Other assets: Regulatory assets 207,202 192,955 Deferred charges and other 26,807 23,840 234,009 216,795 $ 1,985,591 $ 1,849,093
December 31 CAPITALIZATION AND LIABILITIES 1995 1994 (in thousands) Capitalization (See Consolidated Statements of Capitalization): Common stock $ 391,269 $ 373,490 Retained earnings 221,077 218,293 Total common equity 612,346 591,783 Cumulative preferred stock of IES Utilities Inc. 18,320 18,320 Long-term debt (excluding current portion) 601,708 473,206 1,232,374 1,083,309
Current liabilities: Short-term borrowings 101,000 37,000 Capital lease obligations 15,717 14,385 Maturities and sinking funds 15,447 100,422 Accounts payable 80,089 78,582 Dividends payable 16,244 15,839 Accrued interest 8,051 9,494 Accrued taxes 53,983 50,001 Accumulated refueling outage provision 7,690 15,196 Adjustment clause balances 3,148 0 Environmental liabilities 5,634 5,428 Other 21,800 21,680 328,803 348,027
Long-term liabilities: Pension and other benefit obligations 44,619 38,643 Capital lease obligations 21,218 35,346 Environmental liabilities 43,087 38,288 Other 21,097 20,314 130,021 132,591
Deferred credits: Accumulated deferred income taxes 257,278 245,365 Accumulated deferred investment tax credits 37,115 39,801 294,393 285,166
Commitments and contingencies (Note 12)
$ 1,985,591 $ 1,849,093
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31 1995 1994 (in thousands) Common equity: Common stock - no par value - authorized 48,000,000 shares; outstanding 29,508,415 and 28,777,046 shares, respectively $ 391,269 $ 373,490 Retained earnings 221,077 218,293 612,346 591,783
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt: IES Utilities Inc. - Collateral Trust Bonds - 7.65% series, due 2000 50,000 0 6% series, due 2008 50,000 50,000 7% series, due 2023 50,000 50,000 5.5% series, due 2023 19,400 19,400 169,400 119,400
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%, retired in 1995 0 50,000 Series X, 9.42%, retired in 1995 0 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 30,000 239,000 339,000
Pollution control obligations - 5.75%, due serially 1996 to 2003 3,556 3,696 5.95%, due 2007, secured by First Mortgage Bonds 10,000 10,000 Variable rate (5.10% - 5.95% at December 31, 1995) due 2000 to 2010 11,100 11,100 24,656 24,796
Subordinated Deferrable Interest Debentures, 7-7/8%, due 2025 50,000 0
Total IES Utilities Inc. 483,056 483,196
IES Diversified Inc. - Variable rate credit facility 124,245 80,500 Other subsidiaries' debt maturing through 2013 12,307 12,584 619,608 576,280 Unamortized debt premium and (discount), net -2,453 -2,652 617,155 573,628 Less - Amount due within one year 15,447 100,422 601,708 473,206 $ 1,232,374 $ 1,083,309
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). Industries is an investor-owned holding company whose primary operating company, IES Utilities Inc. (Utilities), is engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas. The Company's principal markets are located in the state of Iowa. The Company also has various non-utility subsidiaries which are primarily engaged in the energy-related, transportation and real estate development businesses.
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 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 "Miscellaneous, net" in the Consolidated Statements of Income. Investments that do not meet the criteria for the consolidating or equity methods of accounting are accounted for under the cost method.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect: 1) the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and 2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain prior period amounts have been reclassified on a basis consistent with the 1995 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).
Refer to Note 2 for a discussion of the proposed merger of the Company.
(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:
1995 1994 (in millions)
Deferred income taxes (Note 1(d)) $ 91.1 $ 90.1 Energy efficiency program costs (Note 3(c)) - . Currently being recovered through rates 18.3 20.3 . Recovery has not yet been requested 31.4 14.4 Environmental liabilities (Note 12(f)) 46.9 43.8 Employee pension and benefit costs (Note 8) 27.5 25.0 Unamortized loss on reacquired debt 5.7 6.1 FERC Order No. 636 transition costs (Note 12(h)) 5.0 8.0 Other 4.1 5.4 230.0 213.1 Classified as "Current assets - regulatory assets" 22.8 20.1 Classified as "Other assets - regulatory assets" $ 207.2 $ 193.0
Refer to the individual footnotes referenced above for a further discussion of certain items reflected in regulatory assets.
If a portion of Utilities' operations become no longer subject to the provisions of SFAS 71, a write-off of related regulatory assets would be required, unless some form of transition cost recovery is established by the appropriate regulatory body.
SFAS 121, issued in March 1995 by the Financial Accounting Standards Board (FASB) and effective for 1996, establishes accounting standards for the impairment of long- lived assets. SFAS 121 also requires that regulatory assets that are no longer probable of recovery through future revenues be charged to earnings. SFAS 121 is not expected to have an impact on the financial position or results of operations of the Company upon adoption.
(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). As the deferred taxes become payable, over periods exceeding 30 years for some generating plant differences, they are recovered through rates. 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 that have maturities of less than 90 days from the date of acquisition.
(f) Depreciation of Utility Property, Plant and Equipment -
The depreciation life of Utilities' nuclear generating station, the Duane Arnold Energy Center (DAEC), was increased from 36 years to 40 years based on an extension of the Nuclear Regulatory Commission (NRC) license life to 2014, using the remaining life method, as part of Utilities' most recent rate case as discussed in note 3(b). The average rates of depreciation for electric and gas properties of Utilities, consistent with current rate making practices, were as follows:
1995 1994 1993
Electric 3.4% 3.6% 3.5% Gas 3.5% 3.8% 3.5%
The electric and gas depreciation rates declined in 1995 from 1994 because of revised depreciation rates approved in Utilities' most recent electric and gas rate proceedings.
(g) Decommissioning of the DAEC -
Pursuant to the recent electric rate case order, the IUB allowed Utilities to increase the recovery of anticipated costs to decommission the DAEC from $5.5 million to $6.0 million annually. 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 current recovery figures are based on the following assumptions: 1) cost to decommission the DAEC of $252.8 million in 1993 dollars, based on the NRC minimum formula (which exceeds the amount in the current site-specific study completed in 1994); 2) inflation of 4.91% annually through 1997; 3) the prompt dismantling and removal method of decommissioning, which is assumed to begin in the year 2014; 4) monthly funding of all future collections into external trust funds and funded on a tax-qualified basis to the extent possible; and 5) an average after-tax return of 6.82% for all external investments. All of these assumptions are subject to change in future regulatory proceedings. At December 31, 1995, Utilities had $47.0 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 1995, 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 the Exposure Draft on Accounting for Liabilities Related to Closure and Removal of Long-Lived Assets, issued by the FASB in the first quarter of 1996, which deals with, among other issues, the accounting for decommissioning costs.
(h) Property, Plant and Equipment -
Utility plant (excluding acquisition adjustments of $30.6 million, net of accumulated amortization, recorded at cost) is recorded at original cost. 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 1995-1993 were 6.5%, 9.3% and 5.7%, respectively. These capitalized costs are recovered by Utilities in rates as the cost of the utility plant is depreciated.
Other property, plant and equipment is recorded at cost. Upon retirement or sale of other property and equipment, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is included in "Miscellaneous, net" in the Consolidated Statements of Income.
Normal repairs, maintenance and minor items of utility plant and other property, plant and equipment are expensed. Ordinary retirements of utility plant, including removal costs less salvage value, are charged to accumulated depreciation upon removal from utility plant accounts, and no gain or loss is recognized.
(i) Oil and Gas Properties -
Whiting Petroleum Corporation (Whiting), a wholly-owned subsidiary under 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, 1995, capitalized costs less related accumulated amortization did 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. The Company has $9.8 million on its Consolidated Balance Sheet at December 31, 1995, relating to specific oil and gas properties purchased by Whiting in the fourth quarter of 1995 that it intends to sell during 1996.
(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) PROPOSED MERGER OF THE COMPANY:
The Company, WPL Holdings, Inc. (WPLH) and Interstate Power Company (IPC) have entered into an Agreement and Plan of Merger (Merger Agreement), dated November 10, 1995, providing for: a) IPC becoming a wholly-owned subsidiary of WPLH, and b) the merger of the Company with and into WPLH, which merger will result in the combination of the Company and WPLH as a single holding company (collectively, the Proposed Merger). The new holding company will be named Interstate Energy Corporation (Interstate Energy) and Industries will cease to exist. The Proposed Merger, which will be accounted for as a pooling of interests, has been approved by the respective Boards of Directors. It is still subject to approval by the shareholders of each company as well as several federal and state regulatory agencies. The companies expect to receive the shareholder approvals in the second quarter of 1996 and the regulatory approvals by the second quarter of 1997.
The operating revenues, net income from continuing operations and total assets of the companies were as follows:
PRO FORMA IES COMBINED INDUSTRIES WPLH IPC (Unaudited) (in thousands)
1995 operating revenues $ 851,010 $ 807,255 $ 318,542 $ 1,976,807
1995 net income from continuing operations 64,176 71,618 25,198 160,992
Assets at December 31, 1995 1,985,591 1,872,414 634,316 4,492,321
Under the terms of the Merger Agreement, the outstanding shares of WPLH's common stock will remain unchanged and outstanding as shares of Interstate Energy. Each outstanding share of the Company's common stock will be converted to .98 shares of Interstate Energy's common stock. Each share of IPC's common stock will be converted to 1.11 shares of Interstate Energy's common stock. It is anticipated that Interstate Energy will retain WPLH's common share dividend payment level as of the effective time of the merger. On January 24, 1996, the Board of Directors of WPLH declared a quarterly dividend of 49.25 cents per share. This represents an equivalent annual rate of $1.97 per share.
WPLH is a holding company headquartered in Madison, Wisconsin, and is the parent company of Wisconsin Power and Light Company (WP&L) and Heartland Development Corporation (HDC). WP&L supplies electric and gas service to approximately 377,000 and 146,000 customers, respectively, in south and central Wisconsin. HDC and its principal subsidiaries are engaged in businesses in three major areas: environmental engineering and consulting, affordable housing and energy services. IPC, an operating public utility headquartered in Dubuque, Iowa, supplies electric and gas service to approximately 163,000 and 49,000 customers, respectively, in northeast Iowa, northwest Illinois and southern Minnesota.
Interstate Energy will be the parent company of Utilities, WP&L and IPC and will be registered under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The Merger Agreement provides that these operating utility companies will continue to operate as separate entities for a minimum of three years beyond the effective date of the merger. In addition, the non-utility operations of the Company and WPLH will be combined shortly after the effective date of the merger under one entity to manage the diversified operations of Interstate Energy. The corporate headquarters of Interstate Energy will be in Madison.
The SEC historically has interpreted the 1935 Act to preclude registered holding companies, with limited exceptions, from owning both electric and gas utility systems. Although the SEC has recently recommended that registered holding companies be allowed to hold both gas and electric utility operations if the affected states agree, it remains possible that the SEC may require as a condition to its approval of the Proposed Merger that the Company, WPLH and IPC divest their gas utility properties, and possibly certain non-utility ventures of the Company and WPLH, within a reasonable time after the effective date of the Proposed Merger.
(3) RATE MATTERS: (a) 1995 Gas Rate Case -
On August 4, 1995, Utilities applied to the IUB for an annual increase in gas rates of $8.8 million, or 6.2%. An interim increase of $8.6 million was requested and the IUB, subsequently, approved an interim increase of $7.1 million annually, effective October 11, 1995, subject to refund. Utilities, the Office of Consumer Advocate and all three industrial intervenor groups have entered into a settlement agreement, subject to IUB approval, which allows Utilities a $6.3 million annual increase. Utilities expects that the IUB will rule on the settlement agreement no later than the second quarter of 1996.
(b) 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%. The IUB issued its final order on June 30, 1995, which resulted in an annual retail rate reduction of approximately $14.4 million. The Board ruled against Utilities on issues of increased recovery levels of nuclear depreciation expense and nuclear decommissioning expense, and recovery of the full purchase price of Union Electric Company's (UE) Iowa service territory.
On August 16, 1995, Utilities received approval from the IUB to implement final prices. Northern and Southeastern zone price changes became effective on that date. A price design change was implemented in the Southern zone effective January 1, 1996. As a result of the IUB order, Utilities refunded approximately $12.8 million, including interest, in the fourth quarter of 1995.
(c) Energy Efficiency Cost Recovery -
The IUB has current 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, Utilities applied in 1994 to the IUB for recovery of costs incurred through 1993 for such programs. In April 1995, the IUB issued its Final Decision and Order concerning Utilities' energy efficiency expenditures, which allows Utilities to recover its direct expenditures, carrying costs, and a return on its expenditures, as well as a reward of approximately $4 million for a total allowed recovery of approximately $32 million. Recovery of energy efficiency costs will be over a four-year period and began on June 1, 1995. In 1996, under provisions of the IUB rules, the Company will file for recovery of the costs incurred after December 31, 1993 ($31.4 million as of December 31, 1995).
(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 a $65 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 1995-1993 were $18.0 million, $17.8 million and $12.4 million, respectively.
The Company's operating lease rental expenses for 1995-1993 were $10.4 million, $11.1 million and $9.1 million, respectively.
The Company's future minimum lease payments by year are as follows:
Capital Operating Year Lease Leases (in thousands)
1996 $ 15,515 $ 8,083 1997 13,787 7,241 1998 6,389 6,932 1999 3,865 5,220 2000 824 2,403 2001 149 178 40,529 $ 30,057 Less: Amount representing interest 3,594 Present value of net minimum capital lease payments $ 36,935
(5) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled revenues, arise primarily from the sale of electricity and natural gas. At December 31, 1995, Utilities was serving a diversified base of residential, commercial and industrial customers consisting of approximately 333,000 electric and 174,000 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, 1995, $58 million was sold under the agreement.
(6) INVESTMENTS: (a) Foreign Entities -
At December 31, 1995, the Company had $24.8 million of investments in foreign entities on its Consolidated Balance Sheet that included 1) investments in two New Zealand electric distribution entities, 2) a loan to a New Zealand company, and 3) an investment in an international venture capital fund. The Company accounts for these investments under the cost method.
(b) McLeod, Inc. -
At December 31, 1995, Diversified had a $9.2 million investment in Class B Common Stock of McLeod, Inc. (McLeod), which is accounted for under the cost method. 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, 1995, McLeod had $3.6 million of borrowings outstanding under its facility.
(7) INCOME TAXES:
The components of federal and state income taxes for the years ended December 31, were as follows:
1995 1994 1993 (in millions)
Current tax expense $ 34.7 $ 37.5 $ 27.8 Deferred tax expense 10.5 6.7 14.1 Amortization and adjustment of investment tax credits (2.7) (2.6) (4.9) $ 42.5 $ 41.6 $ 37.0
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.
1995 1994 1993
Statutory federal income tax rate 35.0% 35.0% 35.0% Add (deduct): State income taxes, net of federal benefits 5.5 5.9 5.5 Effect of rate making on property related differences 2.6 1.6 (0.2) Amortization of investment tax credits (2.5) (2.5) (2.6) Adjustment of prior period taxes (0.4) (1.6) (2.3) Other items, net (0.4) - (0.1) Overall effective income tax rate 39.8% 38.4% 35.3%
The accumulated deferred income taxes as set forth below in the Consolidated Balance Sheets at December 31, arise from the following temporary differences:
1995 1994 (in millions)
Property related $ 296 $ 288 Investment tax credit related (26) (28) Decommissioning related (14) (13) Other 1 (2) $ 257 $ 245
(8) BENEFIT PLANS: (a) Pension Plans -
The Company has two non-contributory pension 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 1995 totaled $9.2 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. The Company has an investment policy governing asset allocation guidelines for its pension plans. The target ranges are as follows: 1) 37%- 43% in large and mid-sized domestic company equity securities, 2) 7%-13% in foreign equity securities, 3) 7%- 13% in small domestic company equity securities, 4) 0-5% in real estate, and 5) the remainder in fixed income securities. As of December 31, 1995, the plan's investment mix was consistent with the policy guidelines.
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:
1995 1994 1993 (in thousands)
Service cost $ 5,215 $ 5,863 $ 4,342 Interest cost on projected benefit obligation 11,811 11,431 11,314 Assumed return on plans' assets (12,567) (12,593) (12,363) Amortization of unrecognized gain (754) (180) (767) Amortization of prior service cost 1,355 1,354 1,213 Amortization of unrecognized plans' assets as of January 1, 1987 (333) (333) (389) Pension cost 4,727 5,542 3,350 Adjustment to funding level (4,727) (5,431) (2,940) Total pension costs paid to the Trustee $ - $ 111 $ 410
Actual return on plans' assets $ 36,614 $ (97) $ 12,880
The reduction in the service cost for 1995 was primarily due to an increase in the discount rate at December 31, 1994.
A reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets at December 31, is presented below: 1995 1994 (in thousands)
Fair market value of plans' assets $ 195,329 $ 167,535 Actuarial present value of benefits rendered to date - Accumulated benefits based on compensation to date, including vested benefits of $119,996,000 and $98,384,000, respectively 131,274 108,585 Additional benefits based on estimated future salary levels 41,581 40,146 Projected benefit obligation 172,855 148,731 Plans' assets in excess of projected benefit obligation 22,474 18,804 Remaining unrecognized net asset existing at January 1, 1987, being amortized over 20 years (3,511) (3,844) Unrecognized prior service cost 16,905 18,260 Unrecognized net gain (41,795) (34,420) Accrued pension cost recognized in the Consolidated Balance Sheets $ (5,927) $ (1,200)
Assumed rate of return, all plans 8.00% 8.00% Weighted average discount rate of projected benefit obligation, all plans 7.50% 8.25% Range of assumed rates of increase in future compensation levels for the plans 4.75% 4.00-5.75%
The increase in the projected benefit obligation was primarily due to changes in the mortality rate assumptions and a reduction in the discount rate at December 31, 1995.
(b) Other Postemployment Benefit Plans -
The Company provides certain benefits to retirees (primarily health care benefits). 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 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. The gas and electric portions of these costs are being recovered through rates beginning in 1993 and 1995, respectively, including amounts that were deferred by the Company between when SFAS 106 was adopted and when recovery through rates began. The amounts deferred are being amortized as they are collected through rates over a three-year period. Utilities' unamortized balance of these deferred costs was $3.4 million at December 31, 1995.
The transition obligation for the non-regulated operations was expensed in 1993 and is reflected in other operating expenses.
Pursuant to the provisions of SFAS 71, certain adjustments to Utilities' other postretirement benefit provisions are necessary to reflect the accounting for other postretirement benefit costs allowed in its most recent rate cases.
The components of postretirement benefit costs for the years ended December 31, were as follows:
1995 1994 1993 (in thousands)
Service cost $ 1,387 $ 1,838 $ 1,744 Interest cost on accumulated postretirement benefit obligation 3,175 3,275 3,363 Assumed return on plans' assets (56) (60) - Amortization of transition obligation existing at January 1, 1993, for regulated operations 2,024 2,024 2,024 Amortization of unrecognized gain (230) (6) - Amortization of prior service cost 19 19 - Write-off of transition obligation existing at January 1, 1993, for non-regulated operations - - 1,434 Postretirement benefit costs 6,319 7,090 8,565 Amortized/(deferred) postretirement benefit costs 2,220 (2,732) (2,858) Adjustment to funding level 1,162 - - Net postretirement benefit costs $ 9,701 $ 4,358 $ 5,707
Actual return on plans' assets $ 273 $ 47 $ -
The reduction in the service cost for 1995 was primarily due to an increase in the discount rate at December 31, 1994.
A reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets at December 31, is presented below:
1995 1994 (in thousands)
Fair market value of plans' assets $ 6,515 $ 1,127 Accumulated postretirement benefit obligation - Active employees not yet eligible 22,254 18,896 Active employees eligible 6,282 5,306 Retirees 22,575 18,602 Total accumulated postretirement benefit obligation 51,111 42,804 Accumulated postretirement benefit obligation in excess of plans' assets (44,596) (41,677) Unrecognized transition obligation 34,415 36,439 Unrecognized net (gain)/loss 349 (5,703) Unrecognized prior service cost 151 170 Accrued postretirement benefit cost in the Consolidated Balance Sheets $ (9,681) $ (10,771)
Assumed rate of return 8.00% 8.00% Weighted average discount rate of accumulated postretirement benefit obligation 7.50% 8.25% Medical trend on paid charges: Initial trend rate 10.00% 11.00% Ultimate trend rate 6.50% 6.50%
The increase in the accumulated postretirement benefit obligation was primarily due to a reduction in the discount rate at December 31, 1995, as well as changes made for mortality, turnover and age assumptions. The assumed medical trend rates are critical assumptions in determining the service and interest 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 1995 service and interest cost by $0.9 million (21%) and the accumulated postretirement benefit obligation at December 31, 1995, by $8.7 million (17%).
(9) COMMON, PREFERRED AND PREFERENCE STOCK: (a) Common Stock -
The following table presents information relating to the changes in common stock.
Common Stock Number of Shares Amount Outstanding (in thousands)
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 oil and gas 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 issued in connection with acquisition of oil and gas companies 75,638 1,925 Stock plan issuances* 655,731 15,854 Balance, December 31, 1995 29,508,415 $ 391,269
Shares reserved for issuance pursuant to the Company's stock plans at December 31, 1995* 2,201,666
* Dividend Reinvestment and Stock Purchase Plan, Employee Stock Purchase Plan, Employee Savings Plan, Long-Term Incentive Plan, IES Bonus Stock Ownership Plan and Whiting Stock Option Plans
In March 1995, Industries issued 75,638 shares of its common stock for the purchase of oil and gas companies, which 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, 1995, no shares remained held as treasury stock.
(b) Preferred and Preference Stock:
Utilities has 466,406 shares of Cumulative Preferred Stock, $50 par value, authorized for issuance at December 31, 1995, 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, 1995 and 1994. 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, 1995.
(10) DEBT: (a) Long-Term Debt -
In December 1995, Utilities issued $50 million of Subordinated Deferrable Interest Debentures, 7-7/8%, due 2025. The proceeds from the issuance of the debentures were used to retire short-term borrowings which were incurred in October 1995 to repay at maturity, $50 million of Series X, 9.42% First Mortgage Bonds.
In March 1995, Utilities repaid at maturity $50 million of Series W, 9.75% First Mortgage Bonds and, in a separate transaction, issued $50 million of Collateral Trust Bonds, 7.65%, due 2000.
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, 1998, with a one-year extension 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, 1995, there were no borrowings outstanding under this facility. Diversified had $124.2 million of commercial paper outstanding at December 31, 1995, with interest rates ranging from 5.85% to 6.50% and maturity dates in the first quarter of 1996. Diversified intends to continue borrowing under the renewal options of the facility and no conditions exist at December 31, 1995, that would prevent such borrowings. Accordingly, this debt is classified as long-term in the Consolidated Balance Sheets.
Refer to Note 6 (b) for a discussion of a guarantee associated with debt issued by McLeod.
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 1996-2000 are as follows:
Debt Maturities (in thousands)
Debt Issue 1996 1997 1998 1999 2000 Utilities - Sinking fund requirements $ 630 $ 550 $ 550 $ 550 $ 550 Pollution control 140 140 140 140 1,696 Series J 15,000 - - - - 6-1/8% Series - 8,000 - - - Series Z - - - 50,000 - Series L - - - - 15,000 7.65% Series - - - - 50,000
Diversified - Variable rate credit facility - - - 124,245 - Other subsidiaries' debt 307 333 360 10,366 35 Total $ 16,077 $ 9,023 $ 1,050 $ 185,301 $ 67,281
The Company intends to refinance the majority of the debt maturities with long-term securities.
(b) Short-Term Debt -
At December 31, 1995, the Company had bank lines of credit aggregating $131.1 million (Industries - $1.5 million, Utilities - $121.1 million, Diversified - $7.5 million and Whiting - $1.0 million). Utilities was using $101 million to support commercial paper (weighted average interest rate of 5.81%) and $11.1 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, 1995, there were no borrowings outstanding under this facility.
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair values of financial instruments at December 31, 1995, and 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. The balance of the "Nuclear decommissioning trust funds" as shown in the Consolidated Balance Sheets included $5.3 million of unrealized gains at December 31, 1995, and $0.8 million of unrealized losses at December 31, 1994, on the investments held in the trust funds. The accumulated reserve for decommissioning costs was adjusted by a corresponding amount.
(c) Cumulative Preferred Stock of Utilities -
The estimated fair value of this stock of $11.3 million and $10.2 million at December 31, 1995, and December 31, 1994, respectively, is based upon the market yield of similar securities and quoted market prices.
(d) Long-Term Debt -
At December 31, 1995, and December 31, 1994, the carrying amount of long-term debt was $620 million and $576 million, respectively, compared to estimated fair values of $644 million and $551 million, respectively. The estimated fair value of long-term debt is based upon the market yield of similar securities and 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 $245 million for 1996, which includes $164 million at Utilities and $81 million at Diversified. In addition to the $164 million, Utilities anticipates expenditures of approximately $13 million for mandated energy efficiency programs, which expenditures will be deferred pursuant to IUB rules as discussed in Note 3(c). Substantial commitments have been made in connection with these expenditures.
(b) Purchase Power Contracts -
Utilities is purchasing power from UE under a firm capacity contract with 1996 and 1997 requirements of 80 Mw and 60 Mw of delivered capacity, respectively. Utilities will also purchase an additional annual maximum interruptible capacity of up to 54 Mw of 25 Hz power, which extends through 1998. The costs of capacity purchases for these contracts are reflected in "Purchased power" in the Consolidated Statements of Income.
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 expected to be incurred under all existing contracts will approximate $14.1 million, $11.1 million, $3.3 million, $3.4 million and $0.4 million for the years 1996-2000, 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, 1995, the contracts cover approximately $158 million of coal over the life of the contracts, which includes $55 million expected to be incurred in 1996. 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 operating and capital expenditures under the agreement for 1996 are estimated to total approximately $13 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 -
Public liability for nuclear accidents is governed by the Price Anderson Act of 1988 which sets a statutory limit of $8.9 billion for liability to the public for a single nuclear power plant incident and requires nuclear power plant operators to provide financial protection for this amount. As required, Utilities provides this financial protection for a nuclear incident at the DAEC through a combination of liability insurance ($200 million) and industry-wide retrospective payment plans ($8.7 billion). Under the industry-wide plan, each operating licensed nuclear reactor in the United States is subject to an assessment in the event of a nuclear incident at any nuclear plant in the United States. Based on its ownership of the DAEC, Utilities could be assessed a maximum of $79.3 million per nuclear incident, with a maximum of $10 million per incident per year (of which Utilities' 70% ownership portion would be approximately $55 million and $7 million, respectively) if losses relating to the incident exceeded $200 million. These limits are subject to adjustments for changes in the number of participants and inflation in future years.
Utilities is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). These companies provide $1.9 billion of insurance coverage on certain property losses at DAEC for property damage, decontamination and premature decommissioning. The proceeds from such insurance, however, must first be used for reactor stabilization and site decontamination before they can be used for plant repair and premature decommissioning. NEIL also provides separate coverage for the cost of replacement power during certain outages. Owners of nuclear generating stations insured through NML and NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. NML and NEIL's accumulated reserve funds are currently sufficient to more than cover its exposure in the event of a single incident under the primary and excess property damage or replacement power coverages. However, Utilities could be assessed annually a maximum of $3.1 million under NML, $9.8 million for NEIL property and $0.7 million for NEIL replacement power if losses exceed the accumulated reserves funds. Utilities is not aware of any losses that it believes are likely to result in an assessment.
In the unlikely event of a catastrophic loss at DAEC, the amount of insurance available may not be adequate to cover property damage, decontamination and premature decommissioning. Uninsured losses, to the extent not recovered through rates, would be borne by Utilities and could have a material adverse effect on Utilities' financial position and results of operations.
(f) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately $48.7 million in its Consolidated Balance Sheets at December 31, 1995. The significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible Party (PRP) by various federal and state environmental agencies for 28 FMGP sites, but believes it is not responsible for two of these sites. There are also six other sites for which it may be designated as a PRP in the future. Utilities is working pursuant to the requirements of the various agencies to investigate, mitigate, prevent and remediate, where necessary, damage to property, including damage to natural resources, at and around the sites in order to protect public health and the environment. Utilities believes it has completed the remediation of five sites although it is in the process of obtaining final approval from the applicable environmental agencies on this issue for each site. Utilities is in various stages of the investigation and/or remediation processes for 19 sites and expects to begin the investigation process in 1996 for the two other sites. Utilities estimates the range of costs to be incurred for investigation and/or remediation of the sites to be approximately $22 million to $55 million.
Utilities has recorded environmental liabilities related to the FMGP sites of approximately $35 million (including $4.6 million as current liabilities) at December 31, 1995. 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, and the minimum of the estimated cost range for those sites where the investigation is in its earlier stages or has not started. 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 may be required to monitor these sites for a number of years upon completion of remediation, as is the case with several of the sites for which remediation has been completed.
Utilities has begun pursuing claims under its prior 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, 1995. Regulatory assets of approximately $35 million, which reflect the future recovery that is being provided through Utilities' rates, have been recorded in the Consolidated Balance Sheets. Considering the current 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, $10.9 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, $1.7 million at December 31, 1995, has been recognized in the Consolidated Balance Sheets for the cumulative amount expensed.
(g) Air Quality Issues -
The Clean Air Act Amendments Act of 1990 (Act) requires emission reductions of sulfur dioxide and nitrogen oxides (NOx) to achieve reductions of atmospheric chemicals believed to cause acid rain. The provisions of the Act are being 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 has completed the modifications necessary to meet the Phase I requirements and has installed continuous emission monitors on all affected units as required by the Act. Utilities expects to meet the requirements of Phase II by switching to lower sulfur fuels, capital expenditures primarily related to fuel burning equipment and boiler modifications and the possible purchase of sulfur dioxide allowances. Utilities estimates capital expenditures at approximately $20 million, including $4 million in 1996, in order to meet the acid rain requirements of the Act.
The acid rain program under the Act also creates sulfur dioxide allowances. An allowance is defined as an authorization for an owner to emit one ton of sulfur dioxide into the atmosphere. Currently, Utilities receives a sufficient number of allowances annually to offset its emissions of sulfur dioxide from its Phase I units. It is anticipated that in the year 2000, when the Phase II units participate in the allowance program, Utilities may have an insufficient number of allowances annually to offset its estimated emissions and may have to purchase additional allowances, or make modifications to the plants or limit operations to reduce emissions. Utilities is reviewing its options to ensure that it will have sufficient allowances to offset its emissions in the year 2000 and thereafter. Utilities believes that the potential cost of ensuring sufficient allowances will not have a material adverse effect on its financial position or results of operations.
The Act also requires the United States Environmental Protection Agency (EPA) to study and regulate, if necessary, additional issues that potentially affect the electric utility industry, including emissions relating to nitrogen oxides (NOx), ozone transport and mercury. Currently, the impacts of these potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-case modeling methods, suggests that the Cedar Rapids area could be classified as "nonattainment" for the National Ambient Air Quality Standard (NAAQS) established for sulfur dioxide. The worst- case modeling study suggests that two of Utilities' generating facilities contribute to the modeled exceedences and recommends that additional monitors be located near Utilities' sources to assess actual ambient air quality. In the event that Utilities' facilities contribute excessive emissions, Utilities would be required to reduce emissions, which would primarily entail capital expenditures for modifications to the facilities. Utilities is currently reviewing EPA's assumptions and modeling results and is proposing a strategy to voluntarily reduce the excessive emissions through modification of its facilities at a potential capital cost of up to $10 million over the next four years.
(h) FERC Order No. 636 -
Pursuant to FERC Order No. 636 (Order 636), which transitions the natural gas supply business to a less regulated environment, Utilities has enhanced access to competitively priced gas supply and more flexible transportation services. However, under Order 636, Utilities is required to pay certain transition costs incurred and billed by its pipeline suppliers.
Utilities began paying the transition costs in 1993 and at December 31, 1995, has recorded a liability of $5.0 million for those transition costs that have been incurred, but not yet billed, by the pipelines to date, including $1.9 million expected to be billed through 1996. 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 $7.0 million. The ultimate level of costs to be billed to Utilities depends on the pipelines' future filings with the FERC and other future events, including the market price of natural gas. However, Utilities believes any transition costs that the FERC would allow the pipelines to collect from Utilities would be recovered from its customers, based upon regulatory treatment of these costs currently and similar past costs by the IUB. Accordingly, regulatory assets, in amounts corresponding to the recorded liabilities, have been recorded to reflect the anticipated recovery.
(13) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities, Utilities has undivided ownership interests in jointly-owned electric generating stations and related transmission facilities. Each of the respective owners is responsible for the financing of its portion of the construction costs. Kilowatt-hour generation and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its Statements of Income. Information relative to Utilities' ownership interest in these facilities at December 31, 1995 is as follows:
Ottumwa Neal DAEC Unit 1 Unit 3 ($ in millions)
Utility plant in service $ 498.0 $ 189.3 $ 56.2 Accumulated depreciation $ 201.2 $ 86.0 $ 27.1 Construction work in progress $ 2.7 $ 1.7 $ 0.7 Plant capacity - Mw 520 716 515 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, transportation and sale of natural gas by Utilities and Industrial Energy Applications, Inc., a wholly-owned subsidiary under Diversified. Certain financial information relating to Industries' significant segments of business is presented below:
Year Ended December 31 1995 1994 1993 (in thousands) Operating results: Revenues - Electric $ 560,471 $ 537,327 $ 550,521 Gas 190,339 165,569 181,923
Operating income - Electric 130,390 125,487 128,994 Gas 11,056 8,762 13,673
Other information: Depreciation and amortization - Electric 72,487 68,640 63,832 Gas 6,176 6,214 5,186
Construction and acquisition expenditures - Electric * 108,356 112,773 96,736 Gas 9,368 10,066 15,428
Assets - Identifiable assets - Electric 1,395,666 1,347,024 1,288,505 Gas 199,050 192,397 168,800 1,594,716 1,539,421 1,457,305 Other corporate assets 390,875 309,672 242,514 Total consolidated assets $ 1,985,591 $ 1,849,093 $ 1,699,819
* Excludes intercompany acquisitions which are eliminated for consolidated financial statement purposes.
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 1996 annual meeting of stockholders, which will be filed within 120 days of December 31, 1995, (Proxy Statement under the captions "Election of IES 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 6, 1996)
Lee Liu, 62, Chairman of the Board, President & Chief Executive Officer. First elected officer in 1975.
Blake O. Fisher, Jr., 51, Executive Vice President & Chief Financial Officer and Director. First elected officer in 1991. (i)
Stephen W. Southwick, 49, Vice President, General Counsel & Secretary. First elected officer in 1982.
Dean E. Ekstrom, 48, Vice President, Administration. First elected officer in 1991.
Peter W. Dietrich, 56, Vice President, Corporate Development. First elected officer in 1988.
Richard A. Gabbianelli, 39, Controller & Chief Accounting Officer. First elected officer in 1994.
Dennis B. Vass, 46, Treasurer. First elected officer in 1995. (ii)
Officers are elected annually by the Board of Directors and each of the officers named above, except Dennis B. Vass, has 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) Blake O. Fisher, Jr. resigned as Executive Vice President & Chief Financial Officer and Director of IES Industries Inc. effective February 21,1996.
(ii) Dennis B. Vass was elected as Treasurer & Principal Financial Officer effective February 21, 1996. Prior to the appointment of Mr. 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.
Larry D. Root, Executive Vice President, retired effective December 31, 1995.
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" and "IES Plans" and is incorporated herein by reference, except for the "Report of the Compensation Committee on Executive Compensation" and the "Performance Graph", 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. 67 - 68
Report of Independent Public Accountants. 69
Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993. 70
Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993. 71
Consolidated Balance Sheets at December 31, 1995 and 1994. 72 - 73
Consolidated Statements of Capitalization at December 31, 1995 and 1994. 74
Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993. 75
Notes to Consolidated Financial Statements. 76 - 110
(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, 1995, 1994 and 1993. 116
Other schedules are omitted as not required under Rules of Regulation S-X.
(a) 3. Exhibits -
See Exhibit Index beginning on page 119.
(b) Reports on Form 8-K -
Items Reported Financial Statements Date of Report
5,7 None February 9, 1996 (1) 5,7 None November 10, 1995 (2)
(1) The Form 8-K report was filed on February 20, 1996 with the earliest event reported occurring on February 9, 1996.
(2) The Form 8-K report was filed on November 17, 1995 with the earliest event reported occurring on November 10, 1995.
IES INDUSTRIES INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
Column A Column B Column E
Balance Balance Description January 1 December 31 (in thousands) IES Utilities Inc.:
1995: Accumulated provision for uncollectible accounts $ 650 $ 676
Accumulated provision for rate refunds $ - $ 106
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
Non-utility Subsidiaries:
1995: Accumulated provision for uncollectible accounts and other $ 372 $ 685
1994: Accumulated provision for uncollectible accounts and other $ 506 $ 372
1993: Accumulated provision for uncollectible accounts and other $ 247 $ 506
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 7th day of March 1996.
IES INDUSTRIES INC. (Registrant)
By /s/ Lee Liu Lee Liu Chairman of the Board, President & Chief Executive Officer
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 7, 1996:
/s/ Lee Liu Chairman of the Board, President & Lee Liu Chief Executive Officer (Principal Executive Officer)
/s/ Dennis B. Vass Treasurer & Principal Financial Officer Dennis B. Vass (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
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) Third March 1, 1995 Form 10-Q, 5/12/95 4(b)
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) Sixty-first March 1, 1995 Form 10-Q, 5/12/95 4(a)
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) 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. (Filed as Exhibit 4(i) to the Company's Form 10-K for the year 1994).
4(h) Indenture (For Unsecured Subordinated Debt Securities), dated as of December 1, 1995, between Utilities and The First National Bank of Chicago, as Trustee (Subordinated Indenture) (Filed as Exhibit 4(i) to Utilities' Amendment No. 1 to Registration Statement, File No. 33-62259).
4(i) Officer's Certificate establishing the terms of new Series of Subordinated Debentures (Filed as Exhibit 4 to Utilities' Current Report on Form 8-K, dated December 8, 1995).
10(a) Operating and Transmission Agreement between Central Iowa Power Cooperative and IE (Filed as Exhibit 10(q) to IE's Form 10-K for the year 1990).
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) 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(h) through 10(q))
10(h) Supplemental Retirement Plan. (Filed as Exhibit 10(l) to the Company's Form 10-K for the year 1987).
10(i) Management Incentive Compensation Plan. (Filed as Exhibit 10(m) to the Company's Form 10-K for the year 1987).
10(j) Key Employee Deferred Compensation Plan. (Filed as Exhibit 10(n) to the Company's Form 10-K for the year 1987).
10(k) Long-Term Incentive Plan. (Filed as Exhibit A to the Company's Proxy Statement dated March 20, 1995).
10(l) Executive Guaranty Plan. (Filed as Exhibit 10(p) to the Company's Form 10-K for the year 1987).
10(m) Executive Change of Control Severance Agreement. (Filed as Exhibit 10(s) to the Company's Form 10-K for the year 1989).
10(n) 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(o) 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(p) 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(q) Director Retirement Plan. (Filed as Exhibit 10(t) to the Company's Form 10-K for the year 1993).
10(r) 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(s) 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(t) 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(u) 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(v) 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(w) 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(x) 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(y) 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(z) Agreement Regarding Guaranty 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(aa) 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(ab) 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(ac) 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(ad) 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(ae) 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).
10(af) Agreement and Plan of Merger among IES Industries Inc., WOK Acquisition Company, Okie Energy Company, Keener Energy Company, Thomas M. Atkinson and Joan B. Atkinson, dated as of March 15, 1995 (Filed as Exhibit 10(a) to the Company's Form 10-Q for the quarter ended March 31, 1995).
10(ag) Agreement and Plan of Merger, dated as of November 10, 1995, by and among WPL Holdings, Inc., IES Industries Inc., Interstate Power Company and AMW Acquisition, Inc. (Filed as Exhibit 2.1 to the Company's Form 8-K, dated November 10, 1995).
10(ah) Copy of Coal Supply Agreement, dated July 27, 1977, between IS and Sunoco Energy Development Co. (former parent of Cordero Mining Co.), and letter memorandum thereto, dated October 29, 1984, relating to the purchase of coal supplies for the fuel requirements at the Ottumwa Generating Station. (Filed as Exhibit 10-A-4 to File No. 33-3995).
* 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.