Annual Report (Form 10-K), fiscal year 1993

Item 1. BUSINESS
GENERAL
Southern Indiana Gas and Electric Company (Company) is an operating public utility incorporated June 10, 1912, under the laws of the State of Indiana, engaged in the generation, transmission, distribution and sale of electric energy and the purchase of natural gas and its transportation, distribution and sale in a service area which covers ten counties in southwestern Indiana. The Company has a wholly-owned nonutility investment subsidiary, Southern Indiana Properties, Inc. (refer to Note 3 of the Notes To Consolidated Financial Statements, page 35, for further discussion).
Electric service is supplied directly to Evansville and 74 other cities, towns and communities, and adjacent rural areas. Wholesale electric service is supplied to an additional nine communities. At December 31, 1993, the Company served 118,163 electric customers, and was also obligated to provide for firm power commitments to the City of Jasper, Indiana, and to maintain spinning reserve margin requirements under an agreement with the East Central Area Reliability Group (ECAR).
At December 31, 1993, the Company supplied gas service to 100,398 customers in Evansville and 63 other nearby communities and their environs. Since 1986, the Company has purchased its natural gas supply requirements from numerous suppliers. During 1993, twenty-five suppliers were used; however, Texas Gas Transmission Corporation (TGTC) remained the Company's primary contract supplier. In November 1993, TGTC restructured its services so that its gas supplies are sold separately from its interstate transportation services. TGTC ceased to be a supplier of natural gas to the Company, and the Company assumed full responsibility for the purchase of all its natural gas supplies. (See subsequent reference under "Gas Business" to the restructuring of interstate pipelines.) During 1993, eighteen of the Company's major gas customers took advantage of the Company's gas transportation program to procure a portion of their gas supply needs from suppliers other than the Company.
The principal industries served by the Company include aluminum smelting and recycling, aluminum sheet products, polycarbonate resin (Lexan) and plastic products, appliance manufacturing, pharmacuetical and nutritional products, automotive glass, gasoline and oil products, and coal mining.
The only property the Company owns outside of Indiana is approximately eight miles of 138,000 volt electric transmission line which is located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky. The original cost of the property is less than $425,000. The Company does not distribute any electric energy in Kentucky.
LINES OF BUSINESS
The percentages of operating revenues and operating income before income taxes attributable to the electric and gas operations of the Company for five years ended December 31, 1993, were as follows:
ELECTRIC BUSINESS
The Company supplies electric service to 118,163 customers, including 103,318 residential, 14,645 commercial, 177 industrial, 19 public street and highway lighting and four municipal customers.
The Company's installed generating capacity as of December 31, 1993 was rated at 1,238,000 kilowatts (Kw). Coal-fired generating units provide 1,023,000 Kw of capacity and gas or oil-fired turbines used for peaking or emergency conditions provide 215,000 Kw.
In addition, the Company has interconnections with Louisville Gas and Electric Company, Public Service Company of Indiana, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, providing an ability to simultaneously interchange approximately 750,000 Kw.
Record-breaking peak conditions occurred on July 28, 1993, when the Company's system summer peak load of 1,012,700 Kw was 6.5% greater than the previous record system summer peak load of 951,200 Kw established August 17, 1988. The Company's total load obligation for each of the years 1989 through 1993 at the time of the system summer peak, and the related capacity margin, are presented below. The Company's other load obligations at the time of the peak included firm power commitments to Alcoa Generating Corporation (AGC) except as noted, the City of Jasper, Indiana, and the Company's reserve margin requirements under the ECAR agreement.
The all-time record system winter peak load of 771,900 Kw occurred during the 1989-1990 season on December 22, 1989, and was 10.8% greater than the 1992-1993 winter season system peak (the second highest winter peak) reached on February 18, 1993 at 696,800 Kw.
The Company, primarily as agent of AGC, operates the Warrick Generating Station, a coal-fired steam electric plant which interconnects with the Company's system and provides power for the Aluminum Company of America's Warrick Operations, which includes aluminum smelting and fabricating facilities. Of the four turbine generators at the plant, Warrick Units 1, 2 and 3, with a capacity of 144,000 Kw each, are owned by AGC. Warrick Unit 4, with a rated capacity of 270,000 Kw, is owned by the Company and AGC as tenants in common, each having shared equally in the cost of construction and sharing equally in the cost of operation and in the output.
The Company (a summer peaking utility) has an agreement with Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier Energy) for the sale of firm power to Hoosier Energy during the annual winter heating season (November 15- March 15). The contract made available 100 Mw during the 1993-1994 winter season, and allows for a possible increase to 250 Mw by November 15, 1998. The contract will terminate March 15, 2000.
Electric generation for 1993 was fueled by coal (99.8%) and natural gas (.2%). Oil was used only to light fires and stabilize flames in the coal-fired boilers and for testing of gas/oil fired peaking units.
Historically, coal for the Company's Culley Generating Station and Warrick Unit 4 has been purchased from operators of nearby Indiana strip mines pursuant to long-term contracts. During 1991, the Company pursued negotiations for new contracts with these mine operators and while doing so, purchased coal from the respective operators under interim agreements. In October 1992, the Company finalized a new supply agreement effective through 1995 and retroactive to 1991, with one of the operators under which coal is supplied to both locations. Included in the agreement was a provision whereby the contract could be
reopened by the Company for modification of certain coal specifications. In early 1993, the Company reopened the contract for such modifications. Effective July 1, 1993, the Company bought out the remainder of its contractual obligations with the supplier, enabling the Company to acquire lower priced spot market coal. The Company estimates the savings in coal costs during the 1991-1995 period, net of the total buyout costs, will approximate $56 million. The net savings are being passed back to the Company's electric customers through the fuel adjustment clause. The coal supplier retained the right of first refusal to supply Warrick Unit 4 and the Culley plant during the years 1996-2000. (See "Rate and Regulatory Matters" of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 15, for further discussion of the contract buyout.) The Indiana coal used in these plants is blended by the vendor and delivered to the plants to meet quality specifications set in conformance with the requirements of the Indiana State Implementation Plan for sulfur dioxide. Approximately 1,572,000 tons of coal were used during 1993 in the generation of electricity at the Culley Station and Warrick Unit 4. (See discussion under "Environmental Matters", page 7.) For supplying the A. B. Brown Generating Station, the Company has a contested agreement, possibly extending to 1998, with an area producer. (See Item 3, LEGAL PROCEEDINGS, page 10 for discussion of litigation with this producer regarding the coal supply agreement.) The amount of coal burned at A. B. Brown Generating Station during 1993 was approximately 862,000 tons. Both units at the generating station are equipped with flue gas desulfurization equipment so that coal with a higher sulfur content can be used. There are substantial coal reserves in the southern Indiana area. The average cost of coal consumed in generating electrical energy for the years 1989 through 1993 was as follows:
The Broadway Turbine Units 1 and 2, Northeast Gas Turbines and A. B. Brown Gas Turbine, when used for peaking, reserve or emergency purposes, use natural gas for fuel. Number 2 fuel oil can also be used in the Broadway Turbine Units and the Brown Gas Turbine.
All metered electric rates contain a provision for adjustment in charges for electric energy to reflect changes in the cost of fuel and the net energy cost of purchased power through the operation of a fuel adjustment clause unless certain criteria contained in the regulations are not met. The principal restriction to recovery of fuel cost increases is that such recovery is not allowed to the extent that operating income for the twelve month period provided in the fuel cost adjustment filing exceeds the operating income authorized by the Indiana Utility Regulatory Commission (IURC) in the latest general rate case of the Company. During 1991-1993, this restriction did not affect the Company. As prescribed by order of the IURC, the adjustment factor is calculated based on the estimated cost of fuel and the net energy cost of purchased power in a designated future quarter. The order also provides that any over- or underrecovery caused by variances between estimated and actual cost in a given quarter will be included in the second succeeding quarter's adjustment factor. This continuous reconciliation of estimated incremental fuel costs billed with actual incremental fuel costs incurred closely matches revenues to expenses.
The Company's primary goal in the area of research and development is cost savings through the use of new technologies. This is accomplished, in part, through the efforts of the Electric Power Research Institute (EPRI). In 1993, the Company paid $893,000 to EPRI to help fund research and development programs such as advanced clean coal burning technology.
The Company is participating with 14 other electric utility companies, through Ohio Valley Electric Corporation (OVEC) in arrangements with the United States Department of Energy (DOE), to supply the power requirements of the DOE plant near Portsmouth, Ohio. The sponsoring companies are entitled to receive from OVEC, and are obligated to pay for the right to receive, any available power in excess of the DOE contract demand. The proceeds from the sale of power by OVEC are designed to be sufficient to meet all of its costs and to provide for a return on its common stock. During 1993, the Company's participation in the OVEC arrangements was 1.5%.
The Company participates with 32 other utilities, located in eight states comprising the east central area of the United States, in the East Central Area Reliability Group, the purpose of which is to strengthen the area's electric power supply reliability.
GAS BUSINESS
The Company supplies natural gas service to 100,398 customers, including 91,476 residential, 8,682 commercial, 236 industrial and four public authority customers, through 2,520 miles of gas transmission and distribution lines.
The Company owns and operates three underground gas storage fields with an estimated ready delivery from storage of 3.9 million Dth of gas. Natural gas purchased from the Company's suppliers is injected into these storage fields during periods of light demand which are typically periods of lower prices. The injected gas is then available to supplement the normal contract volume from the pipeline during periods of peak requirements. It is estimated that approximately 119,000 Dth of gas per day can be withdrawn from the three storage fields during peak demand periods on the system.
The gas procurement practices of the Company and several of its major customers have been altered significantly during the past eight years as a result of changes in the natural gas industry. In 1985 and prior years, the Company purchased nearly its entire gas requirements from Texas Gas Transmission Corporation (TGTC) compared to 1993 when a total of 25 suppliers sold gas to the Company. In total, the Company purchased 17,270,415 Dth in 1993. Of this amount, 5,046,509 Dth, or 29%, was purchased from TGTC, which continued to be the Company's largest supplier and its major pipeline. In November 1993, TGTC restructured its services so that its gas supplies are sold separately from its interstate transportation services. TGTC ceased to be a supplier of natural gas to the Company, and the Company assumed full responsibility for the purchase of all its natural gas supplies. (See subsequent reference under "Gas Business" to the restructuring of interstate pipelines.) During 1993, eighteen of the Company's major gas customers took advantage of the Company's gas transportation program to procure a portion of their gas supply needs from suppliers other than the Company. A total of 11,370,542 Dth was transported for these major customers in 1993 compared to 9,497,059 Dth transported in 1992. The Company received fees for the use of its facilities in transporting such gas, allowing it to offset a portion of the loss of its customary sales margin with respect to these customers.
(See "Rate and Regulatory Matters" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 15 of this report, for discussion of the Company's general adjustment in gas rates and for discussion of the FERC Order No. 636 which requires interstate pipelines to restructure their services so that gas supplies will be sold separately from interstate transportation services.)
The all-time record send out occurred during the 1989- 1990 winter season on December 22, 1989, when 223,489 Dth of gas was delivered to the Company's customers. Of this amount, 89,614 Dth was purchased, 104,358 Dth was taken out of the Company's three underground storage fields, and 29,517 Dth was transported to customers under transportation agreements. The 1992-1993 winter season peak day send out was 189,717 Dth on February 17, 1993.
The average cost per Dth of gas purchased by the Company during the past five calendar years was as follows: 1989, $2.84; 1990, $2.84; 1991, $2.71; 1992, $2.77; and 1993 $2.85.
The State of Indiana has established procedures which result in the Company passing on to its customers the changes in the cost of gas sold unless certain criteria contained in the regulations are not met. The principal restriction to recovery of gas cost increases is that such recovery is not allowed to the extent that operating income for the twelve month period provided in the gas cost adjustment filing exceeds the operating income authorized by the IURC in the latest general rate case of the Company. During 1991-1993, this restriction did not affect the Company. Additionally, these procedures provide for scheduled quarterly filings and IURC hearings to establish the amount of price adjustments for a designated future quarter. The procedures also provide for inclusion in a later quarter of any variances between estimated and actual costs of gas sold in a given quarter. This reconciliation process with regard to changes in the cost of gas sold closely matches revenues to expenses. The Company's rate structure does not include a weather normalization-type clause whereby a utility would be authorized to recover the gross margin on sales established in its last general rate case, regardless of actual weather patterns.
Natural gas research is supported by the Company through the Gas Research Institute in cooperation with the American Gas Association. Since passage of the Natural Gas Act of 1978, a major effort has gone into promoting gas exploration by both conventional and unconventional sources. Efforts continue through various projects to extract gas from tight gas sands, shale and coal. Research is also directed toward the areas of conservation, safety and the environment.
On December 23, 1993, the Company entered into a definitive agreement to acquire Lincoln Natural Gas Company, Inc., a small gas distribution company of approximately 1,300 customers contiguous to the eastern boundary of the Company's gas service territory. The acquisition is expected to be completed by mid-1994, subject to necessary regulatory and shareholder approvals.
NONUTILITY SUBSIDIARY
During 1986, the Company formed a wholly-owned subsidiary, Southern Indiana Properties, Inc., which owns and/or operates certain nonutility assets. Currently included in the holdings of the subsidiary are an industrial park, investments in several leveraged-lease financing arrangements, investments in several tax oriented limited partnerships, a portfolio of financial investments (principally adjustable rate preferred stocks and municipal bonds), and other nonutility property. (See Note 3 of the Notes To Consolidated Financial Statements, page 35, for further discussion of Southern Indiana Properties, Inc.)
PERSONNEL
The Company's network of gas and electric operations directly involves 774 employees with an additional 190 employed at Alcoa's Warrick Power Plant. Alcoa reimburses the Company for the entire cost of the payroll and associated benefits at the Warrick Plant, with the exception of one-half of the payroll costs and benefits allocated to Warrick Unit 4, which is jointly owned by the Company and Alcoa. The total payroll and benefits for Company employees in 1993 (including all Warrick Plant employees) were $46.1 million, including $4.1 million of accrued postretirement benefits other than pensions which the Company is deferring as a regulatory asset until inclusion in rates. (See Note 1 of the Notes To Consolidated Financial Statements, page 29, for further discussion of the new financial accounting standard requiring recognition of these costs effective January 1, 1993 and related regulatory treatment.) In 1992, total payroll and benefits were $40.1 million.
On July 3, 1991, the Company signed a new three-year contract with Local 702 of the International Brotherhood of Electric Workers. The contract provided for a 4% general wage increase each of the three years of the contract. Certain cost-containment measures related to health care coverage were adopted. Improvements in productivity, work practices and the pension plan are also provided. Additionally, the Company's Hoosier Division signed a three- year labor contract with Local 135 of the Teamsters, Chauffeurs, Warehousemen and Helpers effective January 14, 1992. The contract provided for a 4% general wage increase each of the first and second years of the contract and a 3.75% general wage increase the third year of the contract. Also provided are improvements in health care coverage costs, pension benefits, sick pay, work practices and productivity.
CONSTRUCTION PROGRAM AND FINANCING
A total of $80,109,000 was spent in 1993 on the Company's construction program, of which $68,840,000 was for the electric system, $5,772,000 for the gas system, $967,000 for common utility plant facilities, and $4,530,000 for the Demand Side Management (DSM) Program. (See "Demand Side Management" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, page 19.) Major construction project expenditures in 1993 included $49.2 million of the originally projected $115 million (including Allowance for Funds Used During Construction) Culley Unit 2 and 3 scrubber project which is scheduled to be completed by 1995. (See "Clean Air Act" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, page 18.)
On May 11, 1993, the Company issued two series of adjustable rate first mortgage bonds totaling $45.0 million in connection with the sale of Warrick County, Indiana environmental improvement revenue bonds. The proceeds of the revenue bonds have been placed in trust are being used to finance a portion of the Culley scrubber project. (See "Liquidity and Capital Resources" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, page 20 for further discussion of this financing and discussion of the issuance of $110 million of first mortgage bonds used to refinance existing long-term debt.) No other securities were issued by the Company during 1993 for the purpose of funding its construction program.
For 1994, construction expenditures are presently estimated to be $92.2 million which includes $8.7 million for DSM programs. Expenditures in the power production area are expected to total $55.8 million and include $41.7 million for the construction of the Culley scrubber project. The balance of the 1994 construction program consists of $14.9 million for additions and improvements to other electric system facilities, $8.1 million of additions and improvements to the gas system and $4.7 million for the final phase of the $27 million Norman P. Wagner operations complex and miscellaneous common utility plant buildings, fixtures and equipment.
In keeping with the Company's objective to bring new facilities on line as needed, the construction program and amount of scheduled expenditures are reviewed periodically to factor in load growth projections, system balance requirements, environmental compliance and other considerations. As a result of this program of periodic review, construction expenditures may change in the future from the program as presented herein.
For the five-year period of 1994-1998, it is estimated that construction expenditures will total about $270 million as follows: 1994 - $92 million; 1995 - $41 million; 1996 - $44 million; 1997 - $48 million; and 1998 - $45 million. This construction program reflects approximately $51 million for the Company's DSM programs and $44 million to meet the Phase I requirements of the Clean Air Act Amendments of 1990. While the Company expects the majority of the construction requirements and an estimated $48 million in debt security redemptions and other long-term obligations to be provided by internally generated funds, external financing requirements of $50-70 million are anticipated.
The aforementioned amounts relating to the Company's construction program are in all cases inclusive of Allowance for Funds Used During Construction.
REGULATION
Operating as a public utility under the laws of Indiana, the Company is subject to regulation by the Indiana Utility Regulatory Commission as to its rates, services, accounts, depreciation, issuance of securities, acquisitions and sale of utility properties or securities, and in other respects as provided by the laws of Indiana.
In addition, the Company is subject to regulation by the Federal Energy Regulatory Commission with respect to the classification of accounts, rates for its sales for resale, interconnection agreements with other utilities, and acquisitions and sale of certain utility properties as provided by the laws of the United States.
See "Electric Business" and "Gas Business" for further discussion regarding regulatory matters.
The Company is subject to regulations issued pursuant to federal and state laws, pertaining to air and water pollution control. The economic impact of compliance with these laws and regulations is substantial, as discussed in detail under "Environmental Matters." The Company is also subject to multiple regulations issued by both federal and state commissions under the Federal Public Utility Regulatory Policies Act of 1978.
As a result of the Company's ownership of 33% of Community Natural Gas Company, the Company is a "Holding Company" as such term is defined under the Public Utility Holding Company Act of 1935 (the 1935 Act). The Company is exempt from all provisions of the 1935 Act except for the provisions of Section 9(A)(2), which pertains to acquisitions of other utilities.
COMPETITION
The Company does not presently compete for electric or gas customers with the other utilities within its assigned service areas. As a result of changes brought about by the National Energy Policy Act of 1992, the Company may be required to compete (or have the opportunity to compete) with other utilities and wholesale generators for sales of electricity to existing wholesale customers of the Company and other potential wholesale customers. (See subsequent reference to discussion of this recent legislation.) The Company currently competes with other utilities in connection with intersystem bulk power rates.
Some of the Company's customers have, or in the future could acquire, access to energy sources other than those available through the Company. (See "Gas Business", page 4, for discussion of gas transportation.) Although federal statute allows for bypass of a local distribution (gas utility) company, Indiana law disallows bypass in most cases
and the Company would likely litigate such an attempt in the Indiana courts. Additionally, the Company's geographical location in the corner of the state, surrounded on two sides by rivers, limits customers' ability to bypass the Company (by running long pipelines). There is also increasing interest in research on the development of sources of energy other than those in general use. Such competition from other energy sources has not been a material factor to the Company in the past. The Company is unable, however, to predict the extent of competition in the future or its potential effect on the Company's operations.
As part of its efforts to develop a National Energy Strategy, Congress has amended the Public Utility Holding Company Act and the Federal Power Act by enacting the National Energy Policy Act of 1992 (the Act), which will affect the traditional structure of the electric utility industry. (Refer to "National Energy Policy Act of 1992" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 18 of this report, for discussion of the major changes in the electric industry effected by the Act.)
ENVIRONMENTAL MATTERS
The Company is currently investigating the possible existence of facilities once owned and operated by the Company, its predecessors, previous landowners, or former affiliates of the Company utilized for the manufacture of gas. Refer to "Environmental Matters" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 17 of this report, for discussion of the Company's actions regarding the investigation.
The Company is subject to federal, state and local regulations with respect to environmental matters, principally air, solid waste and water quality. Pursuant to environmental regulations, the Company is required to obtain operating permits for the electric generating plants which it owns or operates and construction permits for any new plants which it might propose to build. Regulations concerning air quality establish standards with respect to both ambient air quality and emissions from the Company's facilities, including particulate matter, sulfur dioxide and nitrogen oxides. Regulations concerning water quality establish standards relating to intake and discharge of water from the Company's facilities, including water used for cooling purposes in electric generating facilities. Because of the scope and complexity of these regulations, the Company is unable to predict the ultimate effect of such regulations on its future operations, nor is it possible to predict what other regulations may be adopted in the future. The Company intends to comply with all applicable valid governmental regulations, but will contest any regulation it deems to be unreasonable or impossible to comply with or which is otherwise invalid.
The implementation of federal and state regulations designed to protect the environment, including those hereinafter referred to, involves or may involve review, certification or issuance of permits by federal and state agencies. Compliance with such regulations may limit or prevent certain operations or substantially increase the cost of operation of existing and future generating installations, as well as seriously delay or increase the cost of future construction. Such compliance may also require substantial investments above those amounts stated under "Construction Program and Financing", page 5.
All existing Company facilities have operating permits from the Indiana Air Board. In order to secure approval for these permits, the Company has installed electrostatic precipitators on all coal-fired units and is operating flue gas desulfurization (FGD) units to remove sulfur dioxide from the flue gas at its A. B. Brown Units 1 and 2 generating facilities. The FGD units at the Brown Station remove most of the sulfur dioxide from the flue gas emissions by way of a scrubbing process, thereby allowing the Company to burn high sulfur southern Indiana coal at the station.
Under the Federal Clean Air Act (the Act), states are authorized to adopt implementation plans to fulfill the requirements of the Act. These state plans are subject to approval by the U. S. Environmental Protection Agency (EPA). In 1972, Indiana adopted stringent regulations which comprise the State Implementation Plan (SIP) for attaining ambient air standards for particulates, sulfur dioxide and nitrogen oxides. The EPA approved that part of the SIP which sets forth emission standards, fixes time schedules for compliance with such standards and designates air quality regions for the State. The SIP was revised in 1979 to reflect revision of the Act and the State submitted the revised plan to the EPA for approval. On August 10, 1986, the Sierra Club filed a lawsuit against the EPA under Civil No. NA86-194-C seeking declaratory and injunctive relief to compel the EPA to take action pursuant to the Act to reduce sulfur dioxide emissions from power plants in Indiana including the Company's Warrick Unit 4 and Culley Generating Station. In settlement of this suit, the EPA agreed that there would be a SIP for the State by November 1988. The EPA gave final approval on December 16, 1988 to the Warrick County sulfur dioxide emission limits which had been
approved by the Indiana Air Pollution Control Board. The ruling provided for the reduction of sulfur dioxide emissions from the two Warrick County generating stations, Warrick and Culley, to take place in two phases. The first reduction, required by December 31, 1989, provided that sulfur dioxide emissions from all units at both stations be reduced to 5.41 lb/MMBTU from 6.00 lb/MMBTU. Under the second phase, which was effective August 1, 1991, sulfur dioxide emissions from Culley Units 1 and 2 had to be decreased to 2.79 lb/MMBTU, Culley Unit 3 was allowed to remain at 5.41 lb/MMBTU, and emissions from all units at the Warrick Generating Station had to be reduced to 5.11 lb/MMBTU. The Company is currently in compliance with these provisions.
In October 1990, the U.S. Congress adopted major revisions to the Act. The revisions impose significant restrictions on future emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) from coal-burning electric generating facilities, including those owned and operated by the Company. The legislation severely affects electric utilities, especially those in the Midwest. Two of the Company's principal coal-fired facilities (A. B. Brown Units 1 and 2, totaling 500 megawatts of capacity) are presently equipped with sulfur dioxide removal equipment (scrubbers) and are not expected to be severely affected by the new legislation. However, 523 megawatts of the Company's coal- fired generating capacity will be significantly impacted by the lower emission requirements. The Company will be required to reduce total emissions from Culley Unit 3 (250 megawatts), Warrick Unit 4 (135 megawatts) and Culley Unit 2 (92 megawatts) by approximately 50% to 2.5 lb/MMBTU by January 1995 (Phase I) and to 1.2 lb/MMBTU by January 2000 (Phase II). In addition, Unit 1 at Culley Station (46 megawatts) is also subject to the 1.2 lb/MMBTU restriction by January 2000. The legislation includes various incentives to promote the installation of scrubbers on units affected by the 1995 deadline. Current regulatory policy allows for the recovery through rates of all authorized and approved pollution control expenditures.
(Refer to "Clean Air Act" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 18 of this report, for discussion of the Company's Clean Air Act Compliance Plan, which was filed with the IURC on January 3, 1992 and approved October 14, 1992, and the associated estimated costs.)
In connection with the use of sulfur dioxide removal equipment at the A. B. Brown Generating Station, the Company operates a solid waste landfill for the disposal of approximately 200,000 tons of residue per year from the scrubbing process. Renewal of the landfill operating permit was granted in March 1992 by the Indiana Department of Environmental Management (IDEM). The permit expires in January 1997. Additionally, IDEM granted the Company's request for modification (expansion) of the landfill, issuing the construction permit in March 1992.
Under the Federal Water Pollution Control Act of 1972 and Indiana law and regulations, the Company is required to obtain permits to discharge effluents from its existing generating stations into the navigable waterways of the United States. The State of Indiana has received authorization from the EPA to administer the Federal discharge permits program in Indiana. Variances from effluent limitations may be granted by permit on a plant-by- plant basis where the utility can establish the limitations are not necessary to assure the protection of aquatic life and wildlife in and on the body of water into which the discharge is to be made. The Company has been granted National Pollution Discharge Elimination System (NPDES) permits covering miscellaneous waste water and thermal discharges for all its generating facilities to which the NPDES is applicable, namely the Culley Station, A. B. Brown Station and Warrick Unit 4. Such discharge permits are limited in time and must be renewed at five-year intervals. During 1989, the Company was granted renewed five-year permits for effluent discharge for such generating facilities, which are required to be renewed again in 1994. At present there are no known enforcement proceedings concerning water quality pending or threatened against the Company.
EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of the Company are elected at the annual organization meeting of the Board of Directors, held immediately after the annual meeting of stockholders, and serve until the next such organization meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted.
Item 2.



Item 2. PROPERTIES
The Company's installed generating capacity as of December 31, 1993 was rated at 1,238,000 Kw. The Company's coal-fired generating facilities are: the Brown Station with 500,000 Kw of capacity, located in Posey County about eight miles east of Mt. Vernon, Indiana; the Culley Station with 388,000 Kw of capacity, and Warrick Unit 4 with 135,000 Kw of capacity. Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana. The Company's gas-fired turbine peaking units are: the 80,000 Kw Brown Gas Turbine located at the Brown Station; two Broadway Gas Turbines located in Evansville, Vanderburgh County, Indiana, with a combined capacity of 115,000 Kw; and, two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20,000 Kw. The Brown and Broadway turbines are also equipped to burn oil. Total capacity of the Company's five gas turbines is 215,000 Kw and are generally used only for reserve, peaking or emergency purposes due to the higher per unit cost of generation. The Company's transmission system consists of 871 circuit miles of 138,000, 69,000 and 36,000 volt lines. The transmission system also includes 26 substations with an installed capacity of 3,874,724 kilovolt amperes (Kva). The electric distribution system includes 3,177 pole miles of lower voltage overhead lines and 180 trench miles of conduit containing 987 miles of underground distribution cable. The distribution system also includes 86 distribution substations with an installed capacity of 1,306,508 Kva and 45,057 distribution transformers with an installed capacity of 1,771,152 Kva.
The Company owns and operates three underground gas storage fields with an estimated ready delivery from storage capability of 3.9 million Dth of gas. The Oliver Field, in service since 1954, is located in Posey County, Indiana, about 13 miles west of Evansville. The Midway Field is located in Spencer County, Indiana, about 20 miles east
of Evansville near Richland, Indiana, and was placed in service in December 1966. The third field is the Monroe City Field, located in Knox County, about 10 miles east of Vincennes, Indiana. The field was placed in service in 1958.
The Company's gas transmission system includes 324 miles of transmission mains, and the gas distribution system includes 2,196 miles of distribution mains.
The Company's properties, but not those of its subsidiary, are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932 between the Company and Bankers Trust Company, New York, as Trustee, as supplemented by various supplemental indentures, all of which are exhibits to this report and collectively referred to as the "Mortgage".
Item 3.

Item 3. LEGAL PROCEEDINGS.
On January 27, 1993, a coal supplier filed a complaint in the Federal District Court for the Southern District of Indiana alleging that the Company breached a coal supply contract between the Company and that supplier. The Company had notified the supplier that it would not require any delivery of coal under the contract for at least some part of 1993. The supplier claims that this action violates certain minimum purchase requirements imposed by the contract, and asked the court to require specific performance of the contract by the Company and for unspecified monetary damages. The complaint alleges that the Company is obligated to purchase coal at a minimum rate of 50,000 tons per month under the contract and at any event to purchase all of the coal consumed at the Company's A. B. Brown generating plant below 1,000,000 tons per year. The contested contract may run until December 31, 1998. The Company filed counterclaims and disputes that its actions have violated the terms of the contract. On March 26, 1993, the Company and the coal supplier agreed to resume coal shipments but with the invoiced price per ton substantially lower than the contract price and subject to final outcome of the litigation. (Refer to "Rate and Regulatory Matters" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 15 of this report, for discussion of the pricing of this coal to inventory and the associated ratemaking treatment.) On June 6, 1993, the coal supplier won a summary judgement to require the Company to take a minimum of 600,000 tons annually, more or less in equal weekly shipments. The decision cannot be appealed until resolution of other contract provisions still before the court.
There are no other pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the registrant is a party.
No material legal proceedings were terminated during the fourth quarter of 1993.
Item 4.

Item 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
None
PART II
Item 5.

Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
The principal market on which the registrant's common stock (Common Stock) is traded is the New York Stock Exchange, Inc. where the Common Stock is listed. The high and low sales prices for the stock as reported in the consolidated transaction reporting system for each quarterly period during the two most recent fiscal years are:
As of February 4, 1994 there were 9,445 holders of record of Common Stock.
Dividends declared and paid per share of Common Stock during the past two years were:
Item 7.


Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS AND FINANCIAL CONDITION
Earnings per share of $2.45 in 1993 were the highest in Company history, following 1992 earnings of $2.26. The record 1993 earnings exceeded the previous all-time high of $2.37 in 1991 by 3%.
The 1993 earnings were favorably impacted by higher operating revenues due to weather-related increases in retail gas and electric sales. Greater maintenance and nonfuel-related operating expenses and fewer sales to wholesale electric customers partially offset the impact of the higher retail sales. Increased allowance for funds used during construction resulting from the Company's expanded construction program also contributed to the higher earnings.
For the thirty-fifth consecutive year, the Board of Directors declared a dividend increase to common shareholders at its January 1994 meeting. Payable in March 1994, the Company's new quarterly dividend is 41-1/4cents per share, increasing the indicated annual rate to $1.65 per share.
ELECTRIC OPERATIONS.
The table below compares changes in operating revenues, operating expenses, and electric sales between 1993 and 1992, and between 1992 and 1991, in summary form.
Higher weather-related sales to the Company's retail customers was the primary reason for the 6.3% ($15.3 million) rise in electric operating revenues. Effective October 1, 1993, the Company implemented the first step (about 1% overall) of a three-step increase in its base electric rates to recover the cost of complying with the Clean Air Act Amendments of 1990 (see "Rate and Regulatory Matters"), however, the rate increase had little impact on electric revenues during 1993. In 1992, operating revenues declined 7.9% ($20.8 million) due to fewer sales to retail and wholesale customers.
Cooler winter weather and much warmer summer temperatures, when cooling degree days were 30% greater than the prior year and about 17% above normal, were responsible for the 12.1% and 6.3% increases in residential and commercial sales, respectively. Following flat sales in 1992, industrial sales rose 5.7% during the current year due to increased manufacturing activity. Total system sales were up 7.6% over 1992. The Company experienced a 3.1% overall decline in system sales in 1992 when cooling degree days were down 30%.
During 1993, the Company's electric customer base grew by 1,276, or 1%, totaling 118,163 at year end.
In addition to greater system sales, 1993 system revenues increased approximately $2.7 million due to the recovery of higher unit fuel costs (see subsequent discussion of changes in the cost of fuel for electric generation), following a $4.7 million reduction in electric revenues in 1992 due to lower unit costs. Changes in the cost of fuel for electric generation and purchased power are reflected in customer rates through commission approved fuel cost adjustments.
Because of the current worldwide oversupply of primary aluminum and softening demand for rolled can sheet aluminum in the United States, the Aluminum Company of America (Alcoa) shut down several older potlines at various manufacturing facilities. Alcoa Generating Corporation (AGC), a wholly-owned subsidiary of Alcoa, provides the energy requirements for five potlines at Alcoa's Warrick County, Indiana facility from its Warrick Generating Station. Since 1987, the Company has provided electric energy to AGC (a wholesale customer) for a sixth potline. On July 20,1993, Alcoa shut down the oldest of the six potlines at the Warrick County manufacturing operation. The Company estimates that the decline in electric sales related to the potline for 1993 represented approximately $4.8 million in nonsystem revenues and approximately $.8 million in operating income compared to the prior year. Greater sales to other nonsystem customers, due in part to the region's warmer summer temperatures, partially offset the decline in sales to AGC. Total nonsystem sales by the Company declined 8.3% during the year. On an annual basis, the decline in revenue related to the reduced sales to AGC is estimated at $14.4 million with a corresponding $2.4 million decline in operating income. The Company anticipates that a portion of the decline in operating income will be offset in the future by increases in sales to other nonsystem customers made possible by the reduced commitment to AGC. Most sales to nonsystem customers, including AGC, are on an "as available" basis under interchange agreements which provide for significantly lower margins than sales to system customers.
Due to the much warmer summer temperatures, and to the increased demand by industrial customers, a new all-time peak load obligation of 1,100 megawatts was reached on July 28, 1993. The previous record peak, 1,054 megawatts, was set in 1988. The 1992 peak of 992 megawatts was held down by the unseasonably cool summer weather. The Company's total generating capacity at the time of the 1993 peak was 1,238 megawatts, representing an 11% capacity margin.
Fuel for electric generation, the most significant electric operating cost, was comparable to 1992. Slightly (2.8%) higher costs of coal per MMBtu consumed due to less favorable volume-related pricing, higher average per unit mine production costs, and the amortized cost of the buyout of one of the Company's long-term coal contracts (see "Rate and Regulatory Matters"), were offset by a decline in generation. The Company continues to pursue further reductions in coal prices as a key component of its strategy to remain a low-cost provider of electricity. The decline in 1992 fuel cost reflected a 6.2% decrease in generation and a lower average cost of coal consumed.
The greater energy requirements of the Company's customers and favorably priced power were the primary reasons for the increased purchases of electricity from other utilities, up substantially (220%) during 1993. Purchased electric energy costs decreased 48% in 1992 due to fewer purchases and lower average rates paid for such power.
After a 4.1% decrease in 1992, other operation expenditures rose 8.2% ($2.3 million) during the current year chiefly due to increased provisions for injuries and damages, consulting and legal expenditures related to a coal contract buyout (see "Rate and Regulatory Matters") and ongoing coal contract negotiations and litigation, and increases in various administrative and general costs.
Greater production plant maintenance activity was the primary reason for the 20% ($4 million) increase in electric maintenance expense. The Company performed a scheduled major turbine generator overhaul on A.B. Brown Unit 2 during the year and completed a major overhaul on the Culley Unit 1 turbine generator begun in late 1992. The Culley Unit 1 turbine generator overhaul was the only major maintenance project during 1992, when electric maintenance expenditures were down $4.5 million.
Depreciation and amortization expense increased slightly in 1993 reflecting normal additions to utility plant and the completion of the warehouse and operations building at the Company's new Norman P. Wagner Operations Center. A decline in depreciation and amortization occurred in 1992 when amortization provisions related to the deferred return on the phasein of A. B. Brown Unit 2 expired.
While inflation has a significant impact on the replacement cost of the Company's facilities, under the rate-making principles followed by the Indiana Utility Regulatory Commission (IURC), under whose regulatory jurisdiction the Company is subject, only the historical cost of electric and gas plant investment is recoverable in revenues as depreciation. With the exception of adjustments for changes in fuel and gas costs and margin on sales lost under the Company's demand side management programs (see "Demand Side Management"), the Company's electric and gas rates remain unchanged until a rate application is filed and a general rate order is issued by the IURC.
In addition to the impact of higher 1993 pretax income on income tax expense, the Company provided approximately $.5 million of additional federal income tax expense to reflect the higher tax rates enacted under the Omnibus Budget Reconciliation Act of 1993. (See Note1 of the Notes to Consolidated Financial Statements for further discussion.) Decreased income tax expense in 1992 was chiefly attributable to lower pretax income. The decrease in taxes other than income taxes during the current year resulted from a 1992 increase in property tax expense reflecting the general reassessment of the Company's property.
GAS OPERATIONS.
The following table compares changes in operating revenues, operating expenses, and gas sold and transported between 1993 and 1992, and between 1992 and 1991, in summary form.
Greater sales of natural gas and higher gas costs recovered through retail rates led to an 11.5% ($7.2 million) increase in gas operating revenues. Effective August 1, the Company implemented the first step (about 4% overall) of a two-step increase in its base gas rates (see "Rate and Regulatory Matters"), however, the impact on gas revenues during 1993 was not significant.
A 5.6% rise in the Company's gas sales in 1993 reflected increased sales to residential and commercial customers, up 12.8% and 10.2%, respectively. Although heating degree days during the period were about normal, they were 10% greater than those recorded in 1992. Deliveries to industrial customers under the Company's sales and transportation tariffs were up 7.6%, reflecting the increased manufacturing activity of several of the Company's largest industrial customers. In 1992, residential sales were flat and commercial sales were up only 3.1% due to milder winter weather; industrial sales and transportation volumes increased 6.7% during the same period.
During 1993, 1,402 new gas customers were added to the Company's system, raising the year end total 1.4% to 100,398.
On December 23, 1993, the Company entered into a definitive agreement to acquire Lincoln Natural Gas, a small gas distribution company of approximately 1,300 customers contiguous to the eastern boundary of the Company's gas
service territory. The acquisition is expected to be completed by mid-1994, subject to necessary regulatory and shareholder approvals.
The recovery of higher unit gas costs, up 6.1%, through retail rates in 1993 raised revenues $2.7 million following a $1.3 million increase in revenues related to the recovery of higher unit costs in the prior year. During the past two years, the market for purchase of natural gas supply has been very volatile with the average price ranging from a low of $1.34 per Dth in February 1992 to the peak of $2.58 per Dth in May 1993. Prices have declined somewhat since May but remain above the February low reflecting a general tightening of the balance between available supply and demand after several years of excess supply. Changes in the cost of gas sold are passed on to customers through IURC approved gas cost adjustments.
Cost of gas sold, the major component of gas operating expenses, was up 9.7% ($4.5 million) in 1993, following a 13.2% ($5.4 million) increase in 1992. The higher costs in both 1993 and 1992 reflected the increased deliveries to customers and higher unit costs.
Although the Company's primary pipeline supplier, Texas Gas Transmission Corporation (TGTC), implemented revised tariffs November 1, 1993 to reflect certain changes required by Federal Energy Regulatory Commission (FERC) Order 636, the Company's 1993 purchased gas costs were relatively unaffected by the new tariffs. As of November 1,1993, TGTC ceased to be a supplier of natural gas to the Company, and the Company assumed full responsibility for the purchase of all its natural gas supplies. (See "Rate and Regulatory Matters" for further discussion of FERC Order No. 636 and of the impact on future purchased gas costs and procurement practices of the Company.)
Other operation and maintenance expenses were 31% ($3.1 million) greater than the prior year due to increased provisions for injuries and damages (see "Environmental Matters" for discussion of the Company's investigation of the possible existence of facilities utilized for the manufacture of gas), abnormally low distribution maintenance expenses in 1992, and increases in various administrative and general costs.
Depreciation expense for 1993 and 1992 reflected increased gas plant additions during the past several years due to new business requirements and various improvements made to the distribution system. Partially offsetting the impact of increased gas plant additions were lower depreciation rates implemented during 1993 as a result of the Company's recent gas rate case.
Income tax expense for the current year was comparable to 1992, following a substantial decrease in income tax expense in 1992 resulting from lower pretax operating income.
OTHER INCOME AND INTEREST CHARGES.
Other income was $2.5million greater during 1993 due to increased allowance for equity funds used during construction, resulting primarily from the construction of the Company's new sulfur dioxide scrubber. (See "Clean Air Act" for further discussion.) Following a significant increase in nonutility income in 1991, nonutility income declined in 1992. The decline was largely due to lower fees from AGC for operation of its Warrick Generating Station.
Interest expense during the current year was relatively unchanged. The impact of an additional $45 million of long- term debt issued during the second quarter was offset by savings from refinancing $105 million of long-term debt in the second quarter, which reduced annual interest expense by $1 million, and by additional interest capitalized due to the increased construction program.
RATE AND REGULATORY MATTERS.
In November 1992, the Company petitioned the IURC requesting a general increase in gas rates, the first such adjustment since 1982. On July 21,1993, the IURC approved an overall increase of approximately 8%, or $5.5 million in revenues, in the Company's base gas rates. The increase is to be implemented in two equal steps. The first step of the rate adjustment, approximately 4%, took place August 1, 1993; the second step will become effective August 1, 1994.
In addition to seeking relief for rising operating and maintenance costs and substantial investment in utility plant over the past decade, the Company sought to restructure its tariffs, make available additional services, and "unbundle" existing services to better serve its gas customers and strategically position itself to address the changes brought about by the continued deregulation of the natural gas industry. (See subsequent discussion of FERC Order No. 636 in this section.)
On May 24, 1993, the Company petitioned the IURC for an adjustment in its base electric rates representing the first step in the recovery of the financing costs on its investment through March 31, 1993 in the Clean Air Act Compliance project presently being constructed at the Culley Generating Station. The majority of the costs are for the installation of a sulfur dioxide scrubber on Culley Units 2 and 3. (See "Clean Air Act" for further discussion of the project and previous approval of ratemaking treatment of the incurred costs.) On September 15,1993, the IURC granted the Company's request for a 1% revenue increase, approximately $1.8 million on an annual basis, which took effect October 1, 1993. The Company anticipates petitioning the IURC in February 1994 for a 2-3% increase for financing costs related to the project construction expenditures incurred since April 1,1993, with implementation of the new rates effective mid-1994.
On December 22, 1993, the Company filed a request with the IURC for the third of the three planned general electric rate increases. This final adjustment, expected to occur in early 1995, is estimated to be 6-9% and is necessary to recover financing costs related to the balance of the project construction expenditures, costs related to the operation of the scrubber, and certain nonscrubber-related costs such as additional costs incurred for postretirement benefits other than pensions beginning in 1993 and the recovery of demand side management program expenditures (see "Demand Side Management").
Over the past several years, the Company has been actively involved in intensive contract negotiations and legal actions to reduce its coal costs and thereby lower its electric rates. During 1992, the Company was successful in negotiating a new coal supply contract with one of its major coal suppliers. The new agreement, effective through 1995, was retroactive to 1991. Included in the agreement was a provision whereby the contract could be reopened by the Company for modification of certain coal specifications. In early 1993, the Company reopened the contract for such modifications. In response, the coal supplier elected to terminate the contract enabling the Company to buy out the remainder of its contractual obligations and acquire lower priced spot market coal. The cost of the contract buyout in 1993, which was based on estimated tons of coal to be consumed during the agreement period, and related legal and consulting services, totaled approximately $18 million. The Company anticipates that $2 million in additional buyout costs for actual tons of coal consumed above the previously estimated amount may be incurred during the 1994-1995 period. On September 22, 1993, the IURC approved the Company's request to amortize all buyout costs to coal inventory during the period July 1,1993 through December 31, 1995 and to recover such costs through the fuel adjustment clause beginning February 1994.
The Company estimates the savings in coal costs during the 1991-1995 period, net of the total buyout costs, will approximate $56 million. The net savings are being passed back to the Company's electric customers through the fuel adjustment clause.
The Company is currently in litigation with another coal supplier in an attempt to restructure an existing contract. Under the terms of the original contract, the Company was allegedly obligated to take 600,000 tons of coal annually. In early 1993, the Company informed the supplier that it would not require shipments under the contract until later in 1993. On March 26, 1993, the Company and the supplier agreed to resume coal shipments under the terms of their original contract except the invoiced price per ton would be substantially lower than the contract price. As approved by the IURC, the Company has charged the full contract price to coal inventory for subsequent recovery through the fuel adjustment clause. The difference between the contract price and the invoice price has been deposited in an escrow account with an offsetting accrued liability which will be paid either to the Company's ratepayers or its coal supplier upon settlement of the litigation. The escrowed amount was $8,749,000 at December 31, 1993. This litigation is scheduled for trial in June of 1994. Since the litigation arose due to the Company's efforts to reduce fuel costs, management believes that any related costs should be recoverable through the regulatory ratemaking process.
In late 1993, in a further effort to reduce coal costs, the Company and the supplier entered into a letter agreement, effective January 1, 1994, and until the litigation is settled, whereby the Company will purchase an additional 50,000 tons monthly above the alleged base requirements at a price lower than the original contract price for tons over 50,000 per month.
In April 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636 (the Order) which required interstate pipelines to restructure their services. In August 1992, the FERC issued Order No. 636-A which substantially reaffirmed the content of the original Order. Under the Order, the stated purpose of which is to improve the competitive structure of the natural gas pipeline industry, existing pipeline sales service was "unbundled" so that gas supplies are sold separately from interstate transportation services. This restructuring has occurred through tariff filings by pipelines after negotiations with their customers. Customers, such as the Company and ultimately its gas customers, could benefit from enhanced access to competitively priced gas supplies as well as from more flexible transportation services. Conversely, customer costs will rise because the Order requires pipelines to implement new rate design methods which shift additional demand-related costs to firm customers; additionally, the FERC has authorized the pipelines to seek recovery of certain "transition" costs associated with restructuring from their customers.
On November 2, 1992, the Company's major pipeline supplier, Texas Gas Transmission Corporation (TGTC), filed a recovery implementation plan with the FERC as part of its revised compliance filing regarding the Order. On October 1, 1993, the FERC accepted, subject to certain conditions, the TGTC recovery implementation plan (the Plan). The Plan, which addresses numerous issues related to the implementation of the requirements of the Order, became effective November 1, 1993. Under new TGTC transportation tariffs, which reflect the Plan's provisions, the Company will incur additional annual demand-related charges of approximately $1.9 million. Savings from lower volume-related transportation costs will partially offset the additional charges. TGTC has not yet determined the Company's allocation of transition costs, however, an estimate of such costs and implementation of revised TGTC tariffs to recover such costs are expected during the first quarter of 1994. Due to the anticipated regulatory treatment at the state level, the Company does not expect the Order to have a detrimental effect on its financial condition or results of operations.
ENVIRONMENTAL MATTERS.
The Company is currently investigating the possible existence of facilities once owned and operated by the Company, its predecessors, previous landowners, or former affiliates of the Company utilized for the manufacture of gas.
These facilities, if they existed, would have been operated from the 1850's through the early 1950's under industry standards then in effect. Operations at these facilities would have ceased many years ago. However, due to current environmental regulations, the Company and other responsible parties may be required to take remedial action if certain materials are found at the sites of these former facilities.
The Company has just recently initiated its investigation, and preliminary assessments have not yet been performed on any sites. However, based on its research, the Company has identified the existence and general location of four sites at which contamination may be present. The Company intends to perform preliminary assessments of all four sites during 1994 and, more than likely, will perform comprehensive investigations of some, or all, of these sites to determine if remedial action is required and to estimate the extent of such action and the associated costs.
The Company has notified all known insurance carriers providing coverage during the probable period of operation of these facilities of potential claims for coverage of environmental costs. The Company has not, however, recorded any receivables representing future recovery from insurance carriers. Additionally, the Company is attempting to identify all potentially responsible parties for each site. The Company has not been named a potentially responsible party by the Environmental Protection Agency for any of these sites.
While the Company intends to seek recovery from other responsible parties or insurance carriers, the Company does not presently anticipate seeking recovery of these investigation costs from its ratepayers. Therefore, the Company has expensed the $.5 million of anticipated cost of performing preliminary site assessments and the more comprehensive specific site investigations of all four sites. If, however, the specific site investigations indicate that significant remedial action is required, the Company will seek recovery of all related costs in excess of amounts recovered from other potentially responsible parties or insurance carriers through rates.
Although the IURC has not yet ruled on a pending request for rate recovery by another Indiana utility of such environmental costs, the IURC did grant that utility authority to utilize deferred accounting for such costs until the IURC rules on the request.
NATIONAL ENERGY POLICY ACT OF 1992.
In late 1992, the National Energy Policy Act of 1992 (the Act) was signed into law, enacting the first comprehensive energy legislation since the National Energy Act of 1978.
Key provisions contained in the Act, specifically Title VII (Electricity), are expected to cause some of the most significant changes in the history of the electric industry. The primary purpose of Title VII is to increase competition in electric generation by enabling virtually nonregulated entities, such as exempt wholesale generators, to develop power plants, and by providing the FERC authority to require a utility to provide transmission services, including the expansion of the utility's transmission facilities necessary to provide such services, to any entity generating electricity. Although the FERC may not order retail wheeling, the transmission of electricity directly to an ultimate consumer, it may order wheeling of electricity generated by an exempt wholesale generator or another utility to a wholesale customer of a regulated utility.
The changes brought about by the Act may require, or provide opportunities for, the Company to compete with other utilities and wholesale generators for sales to existing wholesale customers of the Company and other potential wholesale customers. The Company has long-term contracts with its five wholesale customers which mitigate the opportunity for other generators to provide service to them. Many observers of the electric utility industry, including major credit rating agencies, certain financial analysts, and some industry executives, have expressed an opinion that retail wheeling to large retail customers and other elements of a more competitive business environment will occur in the electric utility industry, similar to developments in the telecommunications and natural gas industries. The timing of these projected developments is uncertain. In addition, the FERC has adopted a position, generically and on a case- by-case basis, that it will pursue a more competitive, less regulated, electric utility industry. Although the Company is uncertain of the final outcome of these developments, it is committed to pursuing, and is moving rapidly to implement, its corporate strategy of positioning itself as a low-cost energy producer and the provider of high quality service to its retail as well as wholesale customers.
The Company already has some of the lowest per unit administrative, operation, and maintenance costs in the nation, and is continuing its efforts to further reduce its coal costs (see previous discussion of coal contract renegotiation in "Rates and Regulatory Matters").
CLEAN AIR ACT.
Revisions to federal clean air laws were enacted in 1990 which have a significant impact on all of American industry. Electric utilities, especially in the Midwest, were severely impacted by Title IV (acid rain provisions) of the Clean Air Act Amendments of 1990.
Title IV mandates utilities to significantly reduce emissions of sulfur dioxide (SO2) and nitrogen oxide (NOx) from coal-burning electric generating facilities in two steps. The Company is required to reduce annual emissions of SO2 on a Company-wide basis by approximately 50% by 1995 (Phase I). By the year 2000 (PhaseII), the Company must reduce emissions of SO2 by approximately 50% from the allowed 1995 level. Since the Company's two newest coal- fired generating units, A.B. Brown Units 1 and2 (500 MW total), are equipped with SO2 removal equipment (scrubbers), the impact of the law, although significant, is not as great for the Company as for some other midwestern utilities.
To meet the Phase I requirements and nearly all of the Phase II requirements, the Company's Clean Air Act Compliance Plan (the Compliance Plan), which was developed as a least-cost approach to compliance, proposed the installation of a single scrubber at the Culley Generating Station to serve both Culley Unit 2 (92MW) and Culley Unit 3 (250 MW) and the installation of state of the art low NOx burners on these two units.
In January 1992, the Company filed a petition with the IURC, requesting preapproval of the Compliance Plan and proposing recovery of financing costs to be incurred during the construction period. In October 1992, the IURC approved a stipulation and settlement agreement between the Company and intervenors pertaining to the petition, which essentially granted the request.
Construction of the facilities, originally projected to cost approximately $115 million including the related allowance for funds used during construction, began during 1992 with completion and testing expected to occur in late 1994. Construction costs are currently running under budget. Commercial operation will begin about January 1, 1995 to
comply with requirements of the Clean Air Act Amendments of 1990. Under the settlement agreement, the maximum capital cost of the compliance plan to be recovered from ratepayers is capped at approximately $107 million, plus any related allowance for funds used during construction. The estimated cost to operate and maintain the facilities, including the cost of chemicals to be used in the process, is $4-6 million per year, beginning in 1995.
By installing a scrubber, the Company was entitled to apply for extra allowances, called "extension allowances", to the federal EPA. However, because utilities applied for more extension allowances than the Act made available, the federal EPA established a lottery procedure to determine which utilities would actually receive the extension allowances. In order to ensure receipt of a majority of the extension allowances, the Company, and nearly all of the other applying utilities, formed an allowance pooling group. As a result, the Company will receive about 88,000 extension allowances, which it has sold to another party under a confidential agreement. The Company will credit the proceeds to customers over 1995-1999, reducing the rate impact of the Compliance Plan.
With the addition of the scrubber, the Company expects to exceed the minimum compliance requirements of Phase I of the Clean Air Act and have available unused allowances, called "overcompliance allowances", for sale to others. Proceeds from sales of overcompliance allowances will also be passed through to customers.
The scrubbing process utilized by the Culley scrubber produces a salable by-product, gypsum, a substance commonly used in wallboard and other products. In December 1993, the Company finalized negotiations for the sale of an estimated 150,000 to 200,000 tons annually of gypsum to a major manufacturer of wallboard. The agreement will enable the Company to reduce certain operating costs and to credit ratepayers with the proceeds from the sale of the gypsum, further mitigating the rate impact of the Compliance Plan.
The rate impact related to the Compliance Plan, estimated to be 7-10%, is being phased in over a three year period beginning in October 1993. (See "Rate and Regulatory Matters" for further discussion.)
DEMAND SIDE MANAGEMENT.
In October 1991, the IURC issued an order approving expenditures by the Company for development and implementation of demand side management (DSM) programs. The primary purpose of the DSM programs is to reduce the demand on the Company's generating capacity at the time of system peak requirements, thereby postponing or avoiding the addition of generating capacity. Thus, the order of the IURC provided that the accounting and ratemaking treatment of DSM program expenditures should generally parallel the treatment of construction of new generating facilities.
Most of the DSM program expenditures are being capitalized per the IURC order and will be amortized over a 15 year period beginning at the time the Company reflects such costs in its rates. The Company is requesting recovery of these costs in its general electric rate increase request filed December 22, 1993 (see "Rates and Regulatory Matters" for further discussion). In addition to the recovery of DSM program costs through base rate adjustments, the Company is collecting, through a quarterly rate adjustment mechanism, most of the margin on sales lost due to the implementation of DSM programs.
The Company expects to incur costs of approximately $51 million on DSM programs during the 1994-1998 period. By 1998, approximately 108 megawatts of capacity are expected to be postponed or eliminated due to these programs. Based on the latest projections, the expenditures for DSM programs, as approved by the IURC, will total an estimated $195 million through the year 2012 and result in overall savings of $160 million to ratepayers due to deferring the construction of about 156 megawatts of new generating capacity.
INTEGRATED RESOURCE PLAN.
In November 1993, the Company filed with the IURC a biannual update to its Integrated Resource Plan (IRP), including the DSM program expenditures referred to above. The IRP process is a least-cost approach to determining the combination of new generating facilities and conservation and load management options that will best meet customers' future energy needs.
The 1993 IRP update was the result of a nine month evaluation of detailed technology costs, customer energy use patterns, and market information, and includes natural gas conservation options not in the initial 1991 IRP. If the new IRP is approved by the IURC, the Company will implement several new DSM programs recommended by the IRP, including a residential weatherization pilot project. Supply side options recommended by the IRP include strategies to diversify the Company's natural gas suppliers, maximize the use of economical purchased power during peak usage periods, and expand the strategic use of the Company's gas storage fields.
While the Company intends to aggressively utilize various DSM programs to help delay the need for additional power sources, the 1993 IRP forecasts the need of a 125 megawatt base-load generating plant in the early 21st century to meet the future electricity needs of the Company's customers.
POSTEMPLOYMENT BENEFITS.
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits", effective for years beginning after December 15, 1993, which will require the Company to accrue the estimated cost of benefits provided to former or inactive employees after employment but before retirement age. Postemployment benefits include, but are not limited to, salary continuation, supplemental unemployment benefits, severance benefits, disability-related benefits (including workers' compensation), and continuation of benefits such as health care and life insurance coverage. The Company will adopt SFAS No. 112 on January 1, 1994. The impact of the new statement will not have a material impact on financial position or results of operations.
LIQUIDITY AND CAPITAL RESOURCES.
The Company experienced record earnings per share during 1993, and financial performance continued to be solid. Internally generated cash, bolstered by the increased retail sales, provided over 74% of the Company's construction and DSM program expenditures, despite the requirements of the Culley scrubber project. Earnings continued to be of high quality, of which 11.4% represented allowance for funds used during construction. The ratio of earnings to fixed charges (SEC method) was 3.8:1, the embedded cost of long-term debt is approximately 6.6%, and the Company's long-term debt continues to be rated AA by major credit rating agencies.
The Company has access to outside capital markets and to internal sources of funds that together should provide sufficient resources to meet capital requirements. The Company does not anticipate any changes that would materially alter its current liquidity.
On April 30, 1993, the Company called $84.5 million of its first mortgage bonds at a premium, plus accrued interest. The bonds called were the 8% due 2001, the 8% due 2002, the 8.35% due 2007, the 9-1/4% due 2016, and the 8-5/8% due 2017. The bonds called, having a weighted average interest rate of 8.5%, were refunded with two $45 million issues carrying interest rates of 6% and 7.6%, due 1999 and 2023, respectively.
On May 11, 1993, the Company issued two series of adjustable rate first mortgage bonds in connection with the sale of Warrick County, Indiana environmental improvement revenue bonds. The proceeds of the bonds have been placed in trust and are being used to finance a portion of the Culley scrubber project. The first series of bonds was for $22.2 million due 2028, the interest rate of which is fixed at 4.65% through April 30, 1998. The second series of bonds was for $22.8 million due 2023; the interest rate of this series is fixed at 6% through maturity.
On June 15, 1993, the Company retired $20 million of 8.50% first mortgage bonds maturing in June of 1993 with $20 million of 7-5/8% first mortgage bonds due 2025.
The only financing activity during 1992 was in December when the Company called 75,000 shares of 8.75% series cumulative preferred stock at $102 per share, plus accrued dividends, with the issuance of 75,000 shares of 6.50% series redeemable cumulative preferred stock, at $100 per share.
During the five year period 1994-1998, the Company anticipates that a total of $47.7 million of debt securities will be redeemed.
Construction expenditures, including $4.5 million for DSM programs, totaled $80.1 million during 1993, compared to the $52.1 million expended in 1992. As discussed in "Clean Air Act", construction of the new scrubber continued in 1993, requiring $49.2 million. The remainder of the 1993 construction expenditures consisted of the normal replacements and improvements to gas and electric facilities.
The Company expects that construction requirements for the years 1994-1998 will total approximately $270 million. Included in this amount is approximately $44 million to comply with the Clean Air Act amendments by 1995 and approximately $51 million of capitalized expenditures to develop and implement DSM programs. While the Company expects the majority of the construction program and debt redemption requirements to be provided by internally generated funds, external financing requirements of $50-70 million are anticipated.
At year end, the Company had $11 million in short-term borrowings, leaving unused lines of credit and trust demand note arrangements totaling $16 million.
The Company is confident that its long-term financial objectives, which include maintaining a capital structure near 45-50% long-term debt, 3-7% preferred stock, and 43-48% common equity, will continue to be met, while providing for future construction and other capital requirements.
Item 8.


Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No. 1. Financial Statements:
Report of Independent Public Accountants 23
Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991 24
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991 25
Consolidated Balance Sheets - December 31, 1993 and 1992 26 - 27
Consolidated Statements of Capitalization - December 31, 1993 and 1992 28
Consolidated Statements of Retained Earnings for the years ended December 31, 1993, 1992 and 1991 29
Notes to Consolidated Financial Statements 29 - 39
2. Supplementary Information:
Selected Quarterly Financial Data 40
3. Supplemental Schedules:
Schedule V - Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991 44 - 46
Schedule VI - Accumulated Provision for Depreciation and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991 47 - 49
Schedule VIII - Valuation and Qualifying Accounts and Reserves for the years ended December 31, 1993, 1992 and 1991 50
Schedule IX - Short-Term Borrowings 51
Schedule X - Supplementary Income Statement Information 52
Schedule XIII - Other Investments 53
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Consolidated Financial Statements or the accompanying Notes to Consolidated Financial Statements.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Southern Indiana Gas and Electric Company:
We have audited the consolidated balance sheets and consolidated statements of capitalization of SOUTHERN INDIANA GAS AND ELECTRIC COMPANY (an Indiana corporation) AND SUBSIDIARY as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the supplemental schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and supplemental schedules 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas and Electric Company and Subsidiary as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed in Note 1, effective January 1, 1993, the Company changed its methods of accounting for income taxes and postretirement benefits other than pensions.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules listed under Item 8 (3) are presented for the purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These supplemental schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO. Chicago, Illinois January 24, 1994
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary Southern Indiana Properties, Inc. All significant intercompany transactions and balances have been eliminated.
CUSTOMER RECEIVABLES, SALES, AND TRANSPORTATION REVENUES
The Company's customer receivables, gas and electric sales, and gas transportation revenues are primarily derived from supplying electricity and natural gas to a broadly diversified base of residential, commercial, and industrial customers located in a southwestern region of Indiana. The Company serves 118,163 electric customers in the city of Evansville and 74 other communities and serves 100,398 gas customers in the city of Evansville and 63 other communities.
UTILITY PLANT
Utility plant is stated at the historical original cost of construction. Such cost includes payroll-related costs such as taxes, pensions, and other fringe benefits, general and administrative costs, and an allowance for the cost of funds used during construction (AFUDC), which represents the estimated debt and equity cost of funds capitalized as a cost of construction. While capitalized AFUDC does not represent a current source of cash, it does represent a basis for future cash revenues through depreciation and return allowances. The weighted average AFUDC rate (before income tax) used by the Company was 10.5% in 1993, 11.5% in 1992, and 11.2% in 1991.
DEPRECIATION
Depreciation of utility plant is provided using the straight-line method over the estimated service lives of the depreciable plant. Provisions for depreciation, expressed as an annual percentage of the cost of average depreciable plant in service, were 4.0% for electric and 3.7 % for gas in 1993, 4.0% for electric and 3.9% for gas in 1992, and 4.0% for both electric and gas in 1991.
INCOME TAXES
The Company utilizes a comprehensive interperiod income tax allocation policy, providing deferred taxes on temporary timing differences. Investment tax credits recorded have been deferred and are amortized through credits to income over the lives of the related property. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes". SFAS No. 109 requires an asset and liability approach for financial accounting and reporting for income taxes rather than the deferred method. The new standard requires the Company to establish deferred tax assets and liabilities, as appropriate, for all temporary differences and to adjust deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse. In the first quarter of 1993, because of the effects of rate regulation, the Company recorded an increase of $4,987,000 in deferred tax assets and a decrease of $8,551,000 in deferred tax liabilities, and established a corresponding regulatory liability of $13,538,000, primarily to recognize the probable future reduction in rates to flow back to customers deferred taxes previously collected in excess of current tax rates. The adoption of this standard did not have a material impact on results of operations, cash flow, or financial position. The components of the net deferred income tax liability at January 1, 1993 and December 31, 1993 are as follows:
Of the $17,668,000 increase in the net deferred income tax liability from January 1, 1993 to December 31, 1993, $11,263,000 is due to current year deferred federal and state income tax expense and the remaining $6,405,000 increase is primarily a result of the decrease in the net regulatory liability. The components of current and deferred income tax expense for the years ended December 31 are as follows:
The components of deferred federal and state income tax expense for the years ended December 31 are as follows:
As a result of the Omnibus Budget Reconciliation Act of 1993, signed into law on August 10, 1993, the Company provided additional income tax expense of $524,000 in 1993 to recognize the impact of the 1% increase in federal income tax rates. A reconciliation of the statutory tax rates to the Company's effective income tax rate for the years ended December 31 is as follows:
PENSION PLANS
The Company has trusteed, noncontributory defined benefit plans which cover eligible full-time regular employees. The plans provide retirement benefits based on years of service and the employee's highest 60 consecutive months' base compensation during the last 120 months of employment. The funding policy of the Company is to contribute amounts to the plans equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) but not in excess of the maximum deductible for federal income tax purposes. The plans' assets as of December 31, 1993 consist of investments in interest bearing obligations and common stocks of 51% and 49%, respectively. The components of net pension cost for the years ended December 31 are as follows:
Part of the pension cost is charged to construction and other accounts.
The funded status of the retirement plans at December 31 is as follows:
The projected benefit obligation at December 31, 1992 was determined using an assumed discount rate of 8%. Due to the decline in yields on high quality fixed income investments, a discount rate of 7% was used to determine the projected benefit obligation at December 31, 1993. For both periods, the long-term rate of compensation increases was assumed to be 5%, and the long-term rate of return on plan assets was assumed to be 8%. The transitional asset is being recognized over approximately 15, 18, and 14 years for the Salaried, Hourly, and Hoosier plans, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company provides certain postretirement health care and life insurance benefits for retired employees and their dependents through fully insured plans. Retired employees are eligible for lifetime medical and life insurance coverage if they retire on or after attainment of age 55, regardless of length of service. Their spouses are eligible for medical coverage until age 65. Prior to age 65, retirees are covered by the same insured health care plans provided to active employees. After attaining age 65, the retirees are covered by insured Medicare supplement plans. Additionally, the Company reimburses the retirees for Medicare Part B premiums incurred. The health care plans pay stated percentages of covered medical expenses incurred, after subtracting payments by Medicare or other providers and after a stated deductible has been met. Prior to 1993, the cost of retiree health care and life insurance benefits was recognized as insurance premiums were paid, which was consistent with current ratemaking practices. The costs for retirees totaled $670,000 and $598,000 in 1992 and 1991, respectively. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" which requires the expected cost of these benefits be recognized during the employees' years of service. The actuarial assumptions and calculations involved in determining the recognized costs closely parallel pension accounting requirements. As authorized by the Indiana Utility Regulatory Commission in a December 30, 1992 generic ruling, the Company is deferring as a regulatory asset the additional SFAS No. 106 costs accrued over the costs of benefits actually paid after date of adoption, but prior to inclusion in rates. As required by the generic order, the Company anticipates including the additional costs of the benefits in rates within four years after date of adoption of SFAS No. 106. The components of the net periodic other postretirement benefit cost for the year ended December 31, 1993, is as follows:
The 1993 cost determined under the new standard includes the amortization of the discounted present value of the obligation at the adoption date, $29,400,000, over a 20 year period. Reconciliation of the accumulated postretirement benefit obligation to the accrued liability for postretirement benefits as of January 1, 1993 and December 31, 1993, is as follows:
The assumptions used to develop the accumulated postretirement benefit obligation at January 1, 1993 included a discount rate of 8.5% and a health care cost trend rate applicable to gross eligible charges of 14% in 1993 declining to 6% in 2008, and remaining level thereafter. Due to the decline in yields on high quality fixed income investments and general inflation, a discount rate of 7.25% and a health care cost trend rate of 13.5% in 1994 declining to 5.5% in 2008 were used to determine the accumulated postretirement benefit obligation at December 31, 1993. The estimated cost of these future benefits could
be significantly impacted by future changes in health care costs, work force demographics, interest rates, or plan changes. A 1% increase in the assumed health care cost trend rate each year would increase the aggregate service and interest costs for 1993 by $900,000 and the accumulated postretirement benefit obligation by $4,700,000. The Company currently anticipates continuing its policy of funding postretirement benefits costs other than pensions as incurred.
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits", which will require the Company to accrue the estimated cost of benefits provided to former or inactive employees after employment but before retirement. The Company will adopt SFAS No. 112 on January 1, 1994. The impact of the new statement will not have a material impact on financial position or results of operations.
CASH FLOW INFORMATION
For the purposes of the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company, during 1993, 1992, and 1991, paid interest (net of amounts capitalized) of $18,359,000, $17,890,000, and $18,502,000, respectively, and income taxes of $10,248,000, $14,291,000, and $18,289,000, respectively. The Company is involved in several partnerships which are partially financed by partnership obligations amounting to $16,730,000 and $16,114,000 at December 31, 1993 and 1992, respectively.
INVENTORIES
The Company accounts for its inventories under the average cost method except for gas in underground storage which is accounted for under two inventory methods: the average cost method for the Company's Hoosier Division (formerly Hoosier Gas Corporation) and the last-in, first- out (LIFO) method for all other gas in storage. Inventories at December 31 are as follows:
Based on the December 1993 price of gas purchased, the cost of replacing the current portion of gas in underground storage exceeded the amount stated on a LIFO basis by approximately $12,400,000 at December 31, 1993.
OPERATING REVENUES AND FUEL COSTS
Revenues include all gas and electric service billed during the year except as discussed below. All metered gas rates contain a gas cost adjustment clause which allows for adjustment in charges for changes in the cost of purchased gas. As ordered by the IURC, the calculation of the adjustment factor is based on the estimated cost of gas in a future quarter. The order also provides that any under- or overrecovery caused by variances between estimated and actual cost in a given quarter, as well as refunds from its pipeline suppliers, will be included in adjustment factors of four future quarters beginning with the second succeeding quarter's adjustment factor. All metered electric rates contain a fuel adjustment clause which allows for adjustment in charges for electric energy to reflect changes in the cost of fuel and the net energy cost of purchased power. As ordered by the IURC, the calculation of the adjustment factor is based on the estimated cost of fuel and the net energy cost of purchased power in a future quarter. The order also provides that any under- or overrecovery caused by variances between estimated and actual cost in a given quarter will be included in the second succeeding quarter's adjustment factor. The Company also collects through a quarterly rate adjustment mechanism, the margin on electric sales lost due to the implementation of demand side management programs. Reference is made to "Demand Side Management" in Management's Discussion and Analysis of Operations and Financial Condition for further discussion. The Company records monthly any under- or overrecovery as an asset or liability, respectively, until such time as it is billed or refunded to its customers. The IURC reviews for approval the adjustment clauses on a quarterly basis.
The cost of gas sold is charged to operating expense as delivered to customers and the cost of fuel for electric generation is charged to operating expense when consumed.
2. REGULATORY AND OTHER MATTERS
The IURC has jurisdiction over all investor-owned gas and electric utilities in Indiana. The FERC has jurisdiction over those investor-owned utilities that make wholesale energy sales. These agencies regulate the Company's utility business operations, rates, accounts, depreciation allowances, services, security issues, and the sale and acquisition of properties. On July 21, 1993, the IURC approved an overall increase of approximately 8%, or $5.5 million in revenues, in the Company's base gas rates. The increase is to be implemented in two equal steps. The first step of the rate adjustment, approximately 4%, took place August 1, 1993; the second step will become effective August 1, 1994. On May 24, 1993, the Company petitioned the IURC for an adjustment in its base electric rates representing the first step in the recovery of the financing costs on its investment through March 31, 1993 in the Clean Air Act Compliance project presently being constructed at the Culley Generating Station. The majority of the costs are for the installation of a sulfur dioxide scrubber on Culley Units 2 and 3. On September 15, 1993, the IURC granted the Company's request for a 1% revenue increase (approximately $1,800,000 on an annual basis), which took effect October 1, 1993. The Company anticipates petitioning the IURC in February 1994 for a 2-3% increase for financing costs related to project construction expenditures incurred since April 1, 1993, with implementation of the new rates effective mid-1994. On December 22, 1993, the Company filed a request with the IURC for a general electric rate increase. This adjustment, expected to occur in early 1995, is estimated to be 6-9% and is necessary to recover financing costs related to the balance of the scrubber project construction expenditures, costs related to the operation of the scrubber, and certain nonscrubber-related costs such as additional costs incurred for postretirement benefits other than pensions beginning in 1993 and the recovery of demand side management program expenditures. In April 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636 (the Order) which required interstate pipelines to restructure their services. In August 1992, the FERC issued Order No. 636-A which substantially reaffirmed the content of the original Order. On November 2, 1992, the Company's major pipeline , Texas Gas Transmission Corporation (TGTC), filed a recovery implementation plan with the FERC as part of its revised compliance filing regarding the Order. On October 1, 1993, the FERC accepted, subject to certain conditions, the TGTC recovery implementation plan. Under the new TGTC transportation tariffs, which became effective November 1, 1993, the Company will incur additional annual demand-related charges of approximately $1.9 million. Savings from lower volume-related transportation costs will partially offset the additional charges. TGTC has not yet determined the Company's allocation of transition costs, however, an estimate of such costs and implementation of revised TGTC tariffs to recover such costs, are expected during the first quarter of 1994. Due to the anticipated regulatory treatment at the state level, the Company does not expect the Order to have a detrimental effect on its financial condition or results of operations. Over the past several years, the Company has been involved in contract negotiations and legal actions to reduce its coal costs. During 1992, the Company successfully negotiated a new coal supply contract with a major supplier which was retroactive to 1991 and effective through 1995. In 1993, the Company exercised a provision of the agreement which allowed the Company to reopen the contract for the modification of certain coal specifications. In response, the coal supplier elected to terminate the contract enabling the Company to buy out the remainder of its contractual obligations and acquire lower priced spot market coal. The cost of the contract buyout in 1993, which was based on estimated tons of coal to be consumed during the agreement period, and related legal and consulting services, totaled approximately $18 million. The Company anticipates that $2 million in additional buyout costs for actual tons of coal consumed above the previously estimated amount may be incurred during the 1994-1995 period. On September 22, 1993, the IURC approved the Company's request to amortize all buyout costs to coal inventory during the period July 1, 1993 through December 31, 1995 and to recover such costs through the fuel adjustment clause beginning February 1994. As of December 31, 1993, $13,295,000 of settlement costs paid to date had not yet been amortized to coal inventory. The Company is currently in litigation with another coal supplier in an attempt to restructure an existing contract. Under the terms of the contract, the Company was allegedly obligated to take 600,000 tons of coal annually. In early 1993, the Company informed the supplier that it would not require shipments under the contract until later in 1993. On March 26, 1993, the Company and the supplier agreed to resume coal shipments under the terms of their original contract except the invoiced price per ton would be substantially lower than the contract price. As approved by the IURC, the Company has charged the full contract price to coal inventory for subsequent recovery through the fuel adjustment clause. The difference between the contract price and the invoice price has been deposited in an escrow account with an offsetting accrued liability which will be paid to either the Company's ratepayers or its coal supplier upon resolution of the litigation. The escrowed amount was $8,749,000 at December 31, 1993. This litigation is scheduled for trial in June of 1994. Since the litigation arose due to the Company's efforts to reduce fuel costs, management believes that any related costs should be recoverable through the regulatory ratemaking process. In late 1993, in a further effort to reduce coal costs, the Company and the supplier entered into a letter agreement, effective January 1, 1994, and until the litigation is settled, whereby the Company will purchase an additional 50,000 tons monthly above the alleged base requirements at a price lower than the original contract price for tons over 50,000 per month. Reference is made to
"Rate and Regulatory Matters" in Management's Discussion and Analysis of Operations and Financial Condition for further discussion.
3. SOUTHERN INDIANA PROPERTIES, INC.
Southern Indiana Properties, Inc. (SIPI), a wholly- owned subsidiary, was formed to conduct nonutility investment activities while segregating such activities from the Company's regulated utility business. Net income for the years 1993, 1992, and 1991 was $2,525,000, $2,321,000, and $1,936,000, respectively, and is included in "Other, net" in the Consolidated Statements of Income. SIPI investment activities consist principally of investments in partnerships (primarily in real estate), leveraged leases, and marketable securities. SIPI is a lessor in four leveraged lease agreements under which an office building, a part of a reservoir, an interest in a paper mill, and passenger railroad cars are leased to third parties. The economic lives and lease terms vary with the leases. The total equipment and facilities cost was approximately $101,200,000 and $83,400,000 at December 31, 1993 and 1992, respectively. The cost of the equipment and facilities was partially financed by nonrecourse debt provided by lenders, who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accept as their sole remedy in the event of default by the lessee. Such debt amounted to approximately $78,700,000 and $63,700,000 at December 31, 1993 and 1992, respectively. The Company's net investment in leveraged leases at those dates was $8,184,000 and $7,191,000, respectively, as shown:
4. SHORT-TERM FINANCING
The Company has trust demand note arrangements totaling $17,000,000 with several banks, of which $11,000,000 was utilized at December 31, 1993. Funds are also borrowed from time to time from banks on a short-term basis, made available through lines of credit. These available lines of credit totaled $10,000,000 at December 31, 1993 of which none was utilized at that date.
5. LONG-TERM DEBT
The annual sinking fund requirement of the Company's first mortgage bonds is 1% of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. The Company intends to meet the 1994 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 1994 is excluded from current liabilities on the balance sheet. At December 31, 1993, $106,887,000 of the Company's utility plant remained unfunded under the Company's Mortgage Indenture. Several of the Company's partnership investments have been financed through obligations with such partnerships. Additionally, the Company's investments in leveraged leases have been partially financed through notes payable to banks. Of the amount of first mortgage bonds, notes payable, and partnership obligations outstanding at December 31, 1993, the following amounts mature in the five years subsequent to 1993: 1994 - $4,612,000; 1995 - $11,143,000; 1996 - $12,394,000; 1997 - $2,672,000; and 1998 - $16,577,000. In addition, $41,475,000 of adjustable rate pollution control series first mortgage bonds could, at the election of the bondholder, be tendered to the Company in 1994 on certain interest payment dates. If the Company's agent is unable to remarket any bonds tendered at that time, the Company would be required to obtain additional funds for payment to bondholders. For financial statement presentation purposes those bonds subject to tender in 1994 are shown as current liabilities. First mortgage bonds, notes payable, and partnership obligations outstanding and classified as long-term at December 31 are as follows:
6. CUMULATIVE PREFERRED STOCK
The amount payable in the event of involuntary liquidation of each series of the $100 par value preferred stock is $100 per share, plus accrued dividends. The nonredeemable preferred stock is callable at the option of the Company as follows: 4.8% Series at $110 per share, plus accrued dividends; and 4.75% Series at $101 per share, plus accrued dividends.
7. CUMULATIVE REDEEMABLE PREFERRED STOCK
On December 8, 1992, the Company issued $7,500,000 of its Cumulative Redeemable Preferred Stock to replace a like amount of 8.75% of Cumulative Preferred Stock. The new series has an interest rate of 6.50% and is redeemable at $100 per share on December 1, 2002. In the event of involuntary liquidation of this series of $100 par value preferred stock, the amount payable is $100 per share, plus accrued dividends.
8. CUMULATIVE SPECIAL PREFERRED STOCK
The Cumulative Special Preferred Stock contains a provision which allows the stock to be tendered on any of its dividend payment dates. On April 1, 1992, the Company repurchased 850 shares of the Cumulative Special Preferred Stock at a cost of $85,000 as a result of a tender within the provision of the issuance. On March 8, 1991, the Company repurchased 100 shares at a cost of $10,000 as a result of the same provision.
9. COMMITMENTS AND CONTINGENCIES
The Company presently estimates that approximately $90,000,000 will be expended for construction purposes in 1994, including those amounts applicable to the Company's Clean Air Act Compliance Plan and demand side management (DSM) programs. Commitments for the 1994 construction program are approximately $44,000,000 at December 31, 1993. Reference is made to "Clean Air Act" and "Demand Side Management" in Management's Discussion and Analysis of Operations and Financial Condition for discussion of the impact of the Federal Clean Air Act and implementation of the Company's DSM programs. The Company is currently investigating the possible existence of facilities once owned and operated by the Company, its predecessors, previous landowners, or former affiliates of the Company utilized for the manufacture of gas. Based on its investigations, the Company has identified the existence and general location of four sites at which contamination may be present. The Company is attempting to identify all potentially responsible parties for each site. The Company has not been named a potentially responsible party by the Environmental Protection Agency for any of these sites. While the Company intends to seek recovery from other responsible parties or insurance carriers, the Company does not presently anticipate seeking recovery of these investigation costs from its ratepayers. Therefore, the Company has expensed the $500,000 anticipated cost of performing preliminary and comprehensive specific site investigations of all four sites. If the specific site investigations indicate that significant remedial action is required, the Company will seek recovery of all related costs in excess of amounts recovered from other potentially responsible parties or insurance carriers through rates. Although the IURC has not yet ruled on a pending request for rate recovery by another Indiana utility of such environmental costs, the IURC did grant that utility authority to utilize deferred accounting for such costs until the IURC rules on the request.
10. COMMON STOCK
Since 1986, the Board of Directors of the Company authorized the repurchase of up to $25,000,000 of the Corporation's common stock. As of December 31, 1993, the Company had accumulated 1,110,177 common shares with an associated cost of $24,540,000 under this plan.
On January 21, 1992, the Board of Directors of the Company approved a four-for-three common stock split effective March 30, 1992. The stock split was authorized by the IURC on March 18, 1992. Average common shares outstanding, earnings per share of common stock and dividends per share of common stock as shown in the accompanying financial statements have been adjusted to reflect the split. Shares issued during 1992 as a result of the stock split were 3,923,706. No shares of common stock were issued during 1993 and 1991. Each outstanding share of the Company's stock contains a right which entitles registered holders to purchase from the Company one one-hundredth of a share of a new series of the Company's Redeemable Preferred Stock, no par value, designated as Series 1986 Preferred Stock, at an initial price of $120.00 (Purchase Price) subject to adjustment. The rights will not be exercisable until a party acquires beneficial ownership of 20% of the Company's common shares or makes a tender offer for at least 30% of its common shares. The rights expire October 15, 1996. If not exercisable, the rights in whole may be redeemed by the Company at a price of $.01 per right at any time prior to their expiration. If at any time after the rights become exercisable and are not redeemed and the Company is involved in a merger or other business combination transaction, proper provision shall be made to entitle a holder of a right to buy common stock of the acquiring company having a value of two times such Purchase Price.
11. OWNERSHIP OF WARRICK UNIT 4
The Company and Alcoa Generating Corporation (AGC), a subsidiary of Aluminum Company of America, own the 270 MW Unit 4 at the Warrick Power Plant as tenants in common. Construction of the unit was completed in 1970. The cost of constructing this unit was shared equally by AGC and the Company, with each providing its own financing for its share of the cost. The Company's share of the cost of this unit at December 31, 1993 is $30,733,000 with accumulated depreciation totaling $17,846,000. AGC and the Company also share equally in the cost of operation and output of the unit. The Company's share of operating costs is included in operating expenses in the Consolidated Statements of Income.
12. SEGMENTS OF BUSINESS
The Company is primarily a public utility operating company engaged in distributing electricity and natural gas.
The reportable items for electric and gas departments for the years ended December 31 are as follows:
13. TAXES OTHER THAN INCOME TAXES
The items comprising property and other taxes for the years ended December 31 are as follows:
14. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
CASH AND TEMPORARY INVESTMENTS
The carrying amount approximates fair value because of the short maturity of those investments. The fair value of temporary investments were based on current market values.
LONG-TERM DEBT
The fair value of the Company's long-term debt was estimated based on the current quoted market rate of utilities with a comparable debt rating. Nonutility long- term debt was valued based upon the most recent debt financing.
PARTNERSHIP OBLIGATIONS
The fair value of the Company's partnership obligations was estimated based on the current quoted market rate of comparable debt.
REDEEMABLE PREFERRED STOCK
Fair value of the Company's redeemable preferred stock was estimated based on the current quoted market of utilities with a comparable debt rating. The carrying amount and estimated fair values of the Company's financial instruments at December 31 are as follows:
At December 31, 1993 and 1992, approximately $19,100,000 and $11,200,000, respectively, represent the excess of fair value over carrying amounts of the Company's long-term debt relating to utility operations. Anticipated regulatory treatment of the excess of fair value over carrying amounts of the Company's long-term debt, if in fact settled at amounts approximating those above, would dictate that these amounts be used to reduce the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations.
Item 9.

Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Item 10.



Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Identification of Directors
The information required by this item is 			 included in the Company's Proxy Statement, definitive copies of which were filed with the Commission pursuant to Regulation 14A.
(b) Identification of Executive Officers
The information required by this item is included in Part I, Item 1. - BUSINESS on page 9, to which reference is hereby made.
Item 11.

Item 11. EXECUTIVE COMPENSATION AND TRANSACTIONS
The information required by this item is included in the Company's Proxy Statement, definitive copies of which were filed with the Commission pursuant to Regulation 14A.
Item 12.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is included in the Company's Proxy Statement, definitive copies of which were filed with the Commission pursuant to Regulation 14A.
Item 13.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is included in the Company's Proxy Statement, definitive copies of which were filed with the Commission pursuant to Regulation 14A.
PART IV
Item 14.

Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1) The financial statements, including supporting schedules, are listed in the Index to Financial Statements, page 22, (a) 2) filed as part of this report.
(a) 3) Exhibits:
EX-2(a) Merger Agreement - Plan of Reorganization and Agreement of Merger, by and among: Southern Indiana Gas and Electric Company; Southern Indiana Group, Inc.; Horizon Investments, Inc.; and MPM Investment Corporation, dated August 27, 1987. (Physically filed and designated as Exhibit A in Form S-4 Registration Statement filed November 12, 1987, File No. 33-18475.)
EX-3(a) Amended Articles of Incorporation as amended March 26, 1985. (Physically filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 3-A.) Articles of Amendment of the Amended Articles of Incorporation, dated March 24, 1987. (Physically filed and designated in Form 10-K for the fiscal year 1987, File No. 1-3553, as Exhibit 3-A.) Articles of Amendment of the Amended Articles of Incorporation, dated November 27, 1992. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 3-A).
EX-3(b) By-Laws as amended through December 18, 1990. (Physically filed in Form 10-K for the fiscal year 1990, File No. 1-3553, as Exhibit 3-B.) By-Laws as amended through September 22, 1993. (Physically filed herewith as EX-3(b).)
EX-4(a)*Mortgage and Deed of Trust dated as of April 1, 1932 between the Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Physically filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Physically filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Physically filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Physically filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Physically filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Physically filed and designated in Form 8-K, dated April 13, 1993, File 1-3553, as Exhibit 4.) June 1, 1993 (Physically filed and designated in Form 8-K, dated June 14, 1993, File 1-3553, as Exhibit 4.) May 1, 1993. (Physically filed herewith as EX-4(a).)
EX-10.1 Agreement, dated, January 30, 1968, for Unit
No. 4 at the Warrick Power Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and the Company. (Physically filed and designated in Registration No. 2-29653 as Exhibit 4(d)-A.)
EX-10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June 26, 1969, between Alcoa and the Company. (Physically filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.)
*Pursuant to paragraph (b)(4)(iii)(a) of Item 601 of Regulation S-K, the Company agrees to furnish to the Commission on request any instrument with respect to long- term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company, and has therefore not filed such documents as exhibits to this Form 10-K.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (Continued)
EX-10.3 Letter Agreement, dated April 9, 1973, and agreement dated April 30, 1973, between Alcoa and the Company. (Physically filed and designated in Registration No. 2-53005 as Exhibit 4(e)-4.)
EX-10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971, between Alcoa and the Company. (Physically filed and designated in Registration No. 2-41209 as Exhibit 4(e)-1.)
EX-10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and Letter Agreement dated April 30, 1973 - First Supplement. (Physically filed and designated in Form 12-K for the fiscal year 1975, File No. 1-3553, as Exhibit 1(e).)
EX-10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Physically filed and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.)
EX-10.7 Letter Agreement dated August 22, 1978 between the Company and Alcoa, which amends Agreement for Sale in an Emergency of Electrical Power and Energy Generation by Alcoa and the Company dated June 26, 1979. (Physically filed and designated in Form 10-K for the fiscal year 1978, File No. 1- 3553, as Exhibit A-2.)
EX-10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement. (Physically filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-3.)
EX-10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Physically filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-5.)
EX-10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement. (Physically filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-6.)
EX-10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power Agreement, dated May 28, 1971, between Alcoa and the Company. (Physically filed and designated in Form 10- K for the fiscal year 1980, File No. 1-3553, as Exhibit (20)-1.)
EX-10.12* Agreement dated May 6, 1991 between the Company and Ronald G. Reherman for consulting services and supplemental pension and disability benefits. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A- 12.)
EX-10.13* Agreement dated July 22, 1986 between the Company and A. E. Goebel regarding continuation of employment. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-13.)
EX-10.14* Agreement dated July 25, 1986 between the Company and Ronald G. Reherman regarding continuation of employment. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-14.)
EX-10.15* Agreement dated July 22, 1986 between the Company and James A. Van Meter regarding continuation of employment. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-15.)
EX-10.16* Agreement dated February 22, 1989 between the Company and J. Gordon Hurst regarding continuation of employment. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553 as Exhibit 10-A-16.)
EX-10.17* Summary description of the Company's nonqualified Supplemental Retirement Plan (Physically filed and designated in Form 10- K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.)
* Filed pursuant to paragraph (b)(10)(iii)(A) of Item 601 of Regulation S-K.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (Continued)
EX-10.18* Supplemental Post Retirement Death Benefits Plan, dated October 10, 1984. (Physically filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-18.)
EX-10.19* Summary description of the Company's Corporate Performance Incentive Plan. (Physically filed and designated in Form 10- K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-19.)
EX-10.20* Company's Corporate Performance Incentive Plan as amended for the plan year beginning January 1, 1994. (Physically filed herewith as Exhibit 10-A-20.)
* Filed pursuant to paragraph (b)(10)(iii)(A) of Item 601 of Regulation S-K.
(b) Reports on Form 8-K
No Form 8-K reports were filed by the Company during the fourth quarter of 1993.
SCHEDULE V Page 1 of 3 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY PROPERTY, PLANT AND EQUIPMENT Year 1993
SCHEDULE IX
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
SHORT-TERM BORROWINGS
Reference is made to Note 4 of the Notes to Consolidated Financial Statements, page 35, regarding short- term borrowings.
SCHEDULE X
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
SUPPLEMENTARY INCOME STATEMENT INFORMATION
Reference is made to Note 13 of the Notes to Consolidated Financial Statements, page 39, regarding taxes other than income taxes.
Maintenance and depreciation, other than set forth in the "Consolidated Statements of Income," rents, advertising costs, research and development and royalties during the periods were not significant.
SCHEDULE XIII
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
OTHER INVESTMENTS December 31, 1993
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.
Date: March 28, 1994 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY By R. G. Reherman, Chairman, President and Chief Executive Officer
BY (R. G. Reherman) R. G. Reherman
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 and on the dates indicated.
Signatures Title Date
R. G. Reherman Chairman, President, Chief Executive Officer (Principal Executive Officer) March 28, 1994
A. E. Goebel* Senior Vice President, Chief Financial Officer, Secretary and Treasurer (Principal Financial Officer) March 28, 1994
S. M. Kerney* Controller (Principal Accounting Officer) March 28, 1994
Melvin H. Dodson* ) ) Walter B. Emge* ) ) Robert L. Koch II* ) ) Jerry A. Lamb* ) ) Donald A. Rausch* ) Directors March 28, 1994 ) John H. Schroeder* ) ) Richard W. Shymanski*) ) Donald E. Smith* ) ) James S. Vinson* ) ) N. P. Wagner* )
*By (R. G. Reherman, Attorney-in-fact)
SIGECO 10-K
EXHIBIT INDEX
Sequential Page Number
Exhibits incorporated by reference are found on 42-44
EX-3(b) By-Laws as amended through September 22, 1993 63-79
EX-4(a) Supplemental Indentures dated May 1, 1993 81-108
EX-10.20 Company's Corporate Performance Incentive Plan as amended for the plan year beginning January 1, 1994 110-114
EX-12 Computation of ratio of earnings to fixed charges 55
EX-21 Subsidiary of the Registrant 56
EX-24 Power-of-Attorney 60-61