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 three active wholly-owned nonutility subsidiaries, Southern Indiana Properties, Inc., Southern Indiana Minerals, Inc., and Energy Systems Group, Inc., and one wholly-owned utility subsidiary, Lincoln Natural Gas Company, Inc. (See Note 1 (a) of the Notes To Consolidated Financial Statements, page 31, 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, 1994, the Company served 118,992 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, 1994, the Company supplied gas service to 102,929 customers in Evansville and 64 other nearby communities and their environs. Since 1986, the Company has purchased its natural gas supply requirements from numerous suppliers. During 1994, twenty-one suppliers were used. Until November 1993, Texas Gas Transmission Corporation (TGTC) was 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. 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 1994, twenty-two 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 polycarbonate resin (Lexan) and plastic products, aluminum smelting and recycling, aluminum sheet products, appliance manufacturing, pharmaceutical 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 the five years ended December 31, 1994, were as follows:
Reference is made to Note 12 of the Notes To Consolidated Financial Statements, page 41, for Segments of Business Data.
ELECTRIC BUSINESS
The Company supplies electric service to 118,996 customers, including 104,049 residential, 14,741 commercial, 179 industrial, 23 public street and highway lighting and four municipal customers.
The Company's installed generating capacity as of December 31, 1994 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, CINergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power Association, 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 reached 1,012,700 Kw . The 1993 peak was 2.2% greater than the 1994 system summer peak load of 990,800 Kw (the second highest summer peak in Company history) established July 20, 1994. The Company's total load obligation for each of the years 1990 through 1994 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 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 772,000 Kw occurred during the 1993-1994 season on January 19, 1994, and was slightly greater than the previous record winter season system peak reached on December 22, 1989 of 771,900 Kw.
The Company, primarily as agent of Alcoa Generating Corporation (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 peaking power to Hoosier Energy during the annual winter heating season (November 15-March 15). The contract made available 100 Mw during the 1994-1995 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 1994 was fueled by coal (99.5%) and natural gas (0.5%). 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 buy out costs, will approximate $58 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 16, for further discussion of the contract buy out.) The Indiana coal used in these plants is blended by the vendor and delivered to the plants to meet specifications set in conformance with the requirements of the Indiana State Implementation Plan for sulfur dioxide issued under Federal laws regulating air quality (Clean Air Act). Approximately 1,372,000 tons of coal were used during 1994 in the generation of electricity at the Culley Station and Warrick Unit 4. Culley Units 2 and 3 were recently equipped with flue gas desulfurization equipment as part of the Company's Clean Air Act Compliance Plan. (See "Environmental Matters", page 7, for further discussion.) 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 1994 was approximately 1,160,000 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 1990 through 1994 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 1992-1994, 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.
(See "Rate and Regulatory Matters" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 16, for discussion of the Company's general adjustments in electric rates.) The Company participates in research and development in which the primary goal 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 1994,
the Company paid $829,000 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 1994, the Company's participation in the OVEC arrangements was 1.5%.
The Company participates with 32 other utilities and other affiliated groups 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 102,929 customers, including 93,719 residential, 8,980 commercial, 226 industrial and four public authority customers, through 2,644 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 contracted volumes 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 1994 when a total of 24 suppliers sold gas to the Company. In total, the Company purchased 15,554,557 Dth in 1994. In November 1993, TGTC restructured its services so that its gas supplies are sold separately from its interstate transportation services. 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 1994, twenty-two 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 11,584,538 Dth was transported for these major customers in 1994 compared to 11,370,542 Dth transported in 1993. 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 16, 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 were 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 1993-1994 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: 1990, $2.84; 1991, $2.71; 1992, $2.77; 1993, $2.85; and 1994, $2.54.
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 the gas cost adjustment filing exceeds the operating income authorized by the IURC in the latest general rate case of the Company. During 1992-1994, 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. (LNG), a small gas distribution company serving approximately 1,300 customers contiguous to the eastern boundary of the Company's gas service territory. On June 30, 1994, the Company completed its acquisition of LNG after receiving the necessary regulatory and shareholder approvals. The applicable financial data in this filing has been restated to reflect this acquisition, except where noted. (See Note 1, of the Notes to Consolidated Financial Statements, page 31, for further discussion of this acquisition.)
NONUTILITY SUBSIDIARIES
In addition to its wholly-owned utility subsidiary, LNG, the Company has three active wholly-owned nonutility subsidiaries. Southern Indiana Properties, Inc., formed in 1986, invests principally in partnerships (primarily real estate), leveraged leases and marketable securities. Energy Systems Group, Inc., incorporated in April 1994, provides equipment and related design services to industrial and commercial customers. Southern Indiana Minerals, Inc., incorporated in May 1994, processes and markets coal combustion by-products. (See Note 1 of the Notes to Consolidated Financial Statements, page 31, for further discussion.)
PERSONNEL
The Company's network of gas and electric operations directly involves 780 employees with an additional 182 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 1994 (including all Warrick Plant employees) were $47.5 million, including $5 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, pages 31- 36, for further discussion of the new financial accounting standard requiring recognition of these costs effective January 1, 1993 and related regulatory treatment.) In 1993, total payroll and benefits were $46.1 million.
On July 1, 1994, the Company signed a new four-year contract with Local 702 of the International Brotherhood of Electrical Workers. The contract provides for annual wage increases of 3.5%, 3.5%, 3.75% and 4.0%. Improvements in productivity, work practices and the pension plan are also included, along with initiatives to increase labor/management cooperation. Additionally, the Company's Hoosier Division signed a five-year labor contract with Local 135 of the Teamsters, Chauffeurs, Warehousemen and Helpers. The contract provides for annual wage increases of 3.5%, 3.5%, 3.75%, 4.0% and 4.0%. Also included are improvements in health care coverage costs and pension benefits.
CONSTRUCTION PROGRAM AND FINANCING
A total of $84,751,000 was spent in 1994 on the Company's construction program, of which $65,949,000 was for the electric system, $9,315,000 for the gas system, $5,368,000 for common utility plant facilities, and $4,119,000 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 21.) Major construction project expenditures in 1994 included $36.4 million to substantially complete the estimated $103 million (including Allowance for Funds It Used During Construction) Culley Unit 2 and 3 scrubber project. (See "Clean Air Act" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, page 20.) The Culley scrubber project was completed and declared commercially in service on February 1, 1995.
Other than an $11 million increase in short-term debt, no financing activity occurred during 1994.
For 1995, construction expenditures are presently estimated to be $40.3 million which includes $6.8 million for DSM programs. Expenditures in the power production area are expected to total $8.4 million. The balance of the 1995 construction program consists of $14.3 million for additions and improvements to other electric system facilities, $7.9 million of additions and improvements to the gas system and $2.9 million for 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 planning 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.
Currently it is estimated that construction expenditures will total about $230 million for the years 1995-1999 as follows: 1995 - $40 million; 1996 - $49 million; 1997 - $58 million; 1998 - $44 million; and 1999 - $39 million. This construction program reflects approximately $47 million for the Company's DSM programs; however, as discussed in "Demand Side Management" of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 21, the anticipated changes in the electric industry may require changes to the level of future DSM expenditures. While the Company expects the majority of the construction requirements and an estimated $90 million of required debt redemptions to be provided by internally generated funds, external financing requirements of $55-70 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 LNG and 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.
On December 20, 1994, the Company's Board of Directors authorized the steps required for a corporate reorganization
in which a holding company would become the parent of the Company. (See "Holding Company" of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION, page 18, for further discussion of the proposed reorganization.)
COMPETITION
The Company does not presently compete for retail 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. 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 19, 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 19 , 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 electric generation facilities have operating permits from the Indiana Air Board or other agencies having jurisdiction. 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.
In October 1990, the U.S. Congress adopted major revisions to the Federal Clean Air 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 were not severely affected by the new legislation. However, 523 megawatts of the Company's coal- fired generating capacity were significantly impacted by the lower emission requirements. The Company was 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). The Company met the Phase I emission requirements by January 1995 with the implemention of its Clean Air Act Compliance Plan which includes equipping Culley Units 2 and 3 with a sulfur dioxide scrubber, among other provisions. Unit 1 at Culley Station (46 megawatts) is also subject to the 1.2 lb/MMBTU restriction by January 2000. The legislation included 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 20, 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. Refer also to "Construction Program and Financing", page 5, for further discussion of the Company's Culley scrubber project.)
On April 1, 1994 , the EPA (Region V) issued the Company a Notice of Violation regarding the exceedance of quarterly opacity limitations at the Company's Culley Generating Station for six quarterly periods during 1992- 1993. The Company met with the EPA in May 1994 to present the Company's voluntary opacity limitation compliance plan (Compliance Plan), which is designed to eliminate future exceedances, and which had already been implemented by the Company. The EPA has since contacted the Company and accepted the Compliance Plan. The EPA is developing an Agreed Order based on the accepted Compliance Plan and subsequent operational performance of the units. A civil penalty may be levied on the Company by the EPA, but the amount, if any, of such penalty is not known at this time.
Under the Federal Clean Air Act (the Act), states are authorized to adopt implementation plans to fulfill the requirements of the Act. The Indiana Department of Environmental Management (IDEM), which administers the Indiana State Implementation Plan, issued to the Company on October 11, 1994 a Notice of Violation (NOV) regarding exceedance of quarterly opacity limitations for the first quarter of 1994 at the Company's Culley Generating Station. The Company subsequently consented to an Agreed Order and a civil penalty of $30,000. As previously discussed, actions had already been taken by the Company to correct compliance deficiencies with the opacity limitations before the NOV was issued.
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, Broadway Station (gas turbines) and Warrick Unit 4. Such discharge permits are limited in time and must be renewed at five-year intervals. During 1994, the Company submitted renewal applications for
these permits. The existing permits will remain in effect until action is taken by IDEM on the renewal applications. 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, 1994 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 798 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 26 substations with an installed capacity of 3,870,349 kilovolt amperes (Kva). The electric distribution system includes 3,175 pole miles of lower voltage overhead lines and 186 trench miles of conduit containing 1,046 miles of
underground distribution cable. The distribution system also includes 87 distribution substations with an installed capacity of 1,493,422 Kva and 45,644 distribution transformers with an installed capacity of 1,805,318 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 2,320 miles of distribution mains.
The Company's properties, excluding those of its subsidiaries, 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 in 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 16 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 Company maintains that shipments from the supplier do not conform to the agreed upon coal specifications in the contract. This litigation came to trial conclusion based upon summary judgment motions in June 1994. The U. S. District Court found in favor of the Company regarding required coal quality specification and, in the earlier summary judgment, found in favor of the coal supplier regarding alleged minimum annual tonnage requirements. Damages of $1,442,000 were awarded to the coal supplier. Both parties have initiated appeal procedures and expect the case to be heard by the Court of Appeals in mid-1995 with a decision from that court later in 1995. The parties are also considering mediation. 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.
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 1994.
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 10, 1995 there were 9,332 holders of record of Common Stock.
Dividends declared and paid per share of Common Stock during the past two years were:
The quarterly dividend on Common Stock was increased to 42-1/4 cents per share in January 1995, payable March 20, 1995.
The payment of cash dividends on Common Stock is, in effect, restricted by the Mortgage to accumulated surplus, available for distribution to the Common Stock, earned subsequent to December 31, 1947, subject to reduction if amounts deducted from earnings for current repairs and maintenance and provisions for renewals, replacements and depreciation of all the property of the Company are less than amounts specified in the Mortgage. See Section 1.02 of the Supplemental Indenture dated as of July 1, 1948, as supplemented. No amount was restricted against cash dividends on Common Stock as of December 31, 1994, under this restriction.
The payment of cash dividends on Common Stock is, in effect, restricted by the Amended Articles of Incorporation to accumulated surplus, available for distribution to the Common Stock, earned subsequent to December 31, 1935. The Amended Articles of Incorporation require that, immediately after such dividends, there shall remain to the credit of earned surplus an amount at least equal to two times the annual dividend requirements on all then outstanding Preferred Stock, No Par Value. See Art. VI, Terms of Capital Stock, General Provisions (B). The amount restricted against cash dividends on Common Stock at December 31, 1994 under this restriction was $2,209,642, leaving $215,823,713 unrestricted for the payment of dividends. In addition, the Amended Articles of Incorporation provide that surplus otherwise available for the payment of dividends on Common Stock shall be restricted to the extent that such surplus is included in a calculation required to permit the Company to issue, sell or dispose of preferred stock or other stock senior to the Common Stock (Art. VI, Terms of Capital Stock, General Provisions (E)).
An order of the Securities and Exchange Commission dated October 12, 1944 under the Public Utility Holding Company Act of 1935 in effect restricts the payment of cash dividends on Common Stock to 75% of net income available for distribution to the Common Stock, earned subsequent to December 31, 1943, if the percentage of Common Stock equity to total capitalization and surplus, as defined, is less than 25%. At December 31, 1994, such ratio amounted to approximately 48%.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS AND FINANCIAL CONDITION.
Earnings per share of $2.53 in 1994 were the highest in Company history, exceeding 1993 earnings of $2.44, the previous all-time high. Earnings in 1992 were $2.25.
The record earnings reflected improved gas and electric margins resulting from recent rate adjustments, greater sales to the Company's commercial and industrial electric customers, and increased allowance for funds used during construction resulting from the Company's expanded construction program. Expected increases in maintenance and nonfuel-related operating expenses and a decline in sales to gas customers partially offset the impact of the higher margins.
At its December 1994 meeting, the Board of Directors authorized the actions necessary for a corporate reorganization in which a yet to be formed holding company would become the parent of the Company. Assuming the Company obtains shareholder approval at its March 1995 annual meeting and receives the required authorizations from federal regulatory agencies, the reorganization should be completed by late 1995 (see "Holding Company").
At its January 1995 meeting, the Board of Directors declared a dividend increase to common shareholders, marking the thirty-sixth consecutive year of dividend growth. Payable in March 1995, the Company's new quarterly dividend is 42-1/4 cents per share, increasing the indicated annual rate to $1.69 per share.
ELECTRIC OPERATIONS. The table below compares changes in operating revenues, operating expenses and electric sales between 1994 and 1993, and between 1993 and 1992, in summary form.
The Company's implementation of the first and second steps of a three-step increase in its base electric rates (see "Rate and Regulatory Matters"), effective October 1, 1993 and June 29, 1994, respectively, and greater sales to the Company's commercial and industrial customers were the primary reasons for the 1% ($2.5 million) increase in electric operating revenues. Lower per unit fuel costs recovered in customer rates and lower average unit revenues from sales to nonsystem electric customers partially offset the impact of increased base rates and greater sales. In 1993, operating revenues rose 6.3% ($15.3 million) on higher weather-related sales to retail customers.
System revenues rose an estimated $3.7 million due to the effect of two increases in base electric rates. Effective October 1, 1993, the Company implemented the first step (about 1% of retail revenues, or $1.8 million on an annual basis) 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"). Effective June 29, 1994, the second step (about 2.3% of retail revenues, or $4.2 million on an annual basis) of the increase was implemented.
Despite milder winter and summer temperatures, when heating and cooling degree days were lower than in 1993 by 10% and 8%, respectively, commercial sales rose 2.4% on increased local economic activity. Residential sales declined about 1%. Due to continued growth in manufacturing activity, sales to the Company's industrial customers rose 3.2% following a 5.7% increase in 1993. Total system sales were up 1.8% over 1993. System sales in 1993 exceeded 1992 sales by 7.6% due to much warmer summer temperatures.
During 1994, the Company's electric customer base grew by 829, totaling 118,992 at year end.
System revenues declined approximately $2.3 million in 1994 due to recovery of lower unit fuel costs following a $2.7 million increase in 1993 from the recovery of higher unit fuel costs. Changes in the cost of fuel for electric generation and purchased power are reflected in customer rates through commission-approved fuel cost adjustments.
Since 1987, the Company has provided electric energy to Alcoa Generating Corporation (AGC), a wholly-owned subsidiary of Alcoa (a wholesale customer), for one of its six potlines. Due to market conditions in the aluminum industry, Alcoa shut down the oldest of the six potlines at the Warrick County manufacturing operation in July 1993. 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. During 1994, revenue related to the reduced sales to AGC declined an additional $8.2 million with a corresponding $1.4 million additional decline in operating income. A portion of the decline in operating income was offset by increased sales to other nonsystem customers made possible by the reduced commitment to AGC. Total nonsystem sales were 3.2% higher than 1993, due primarily to the requirements of one nonassociated utility during the first quarter of 1994. 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.
Milder summer temperatures and the peak-shaving effect of the Company's demand side management programs resulted in a 1994 peak load obligation of 1,068 megawatts, 2.9% lower than the all-time peak of 1,100 megawatts reached on July 28, 1993, despite the increased demand by industrial customers. The Company's total generating capacity at the time of the 1994 peak was 1,238 megawatts, representing a 14% capacity margin.
Although electric generation increased 7.2% as a result of the increased sales and fewer purchases of electricity from other utilities, fuel for electric generation, the most significant electric operating cost, rose only 2.8% due to lower coal costs and improved plant efficiencies. In 1994, the Company experienced more favorable volume-related pricing with its remaining long-term contract supplier and took advantage of generally lower spot market coal prices. 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 (see "Rate and Regulatory Matters"). The 1993 fuel costs were comparable to 1992; in each year, a decline in generation offset slightly higher costs of coal consumed.
The Company reduced its purchases of electricity from other utilities by 41% compared to the previous year due to lower energy requirements and internally generated electricity being more favorably priced compared to that available from other utilities. Purchased electric energy costs in 1993 were 220% higher than in 1992 due to greater energy requirements of the Company and the availability of lower- priced power from other utilities.
Because the Company is undecided whether it will seek recovery of 1993 and 1994 demand side management expenditures and postretirement benefits other than pensions allocable to firm wholesale customers, about $2.5 million of these costs were expensed. As a result of these expenses, increased employee benefit costs, higher operating costs at the A. B. Brown scrubber due to increased generation at that plant and consulting and legal expenditures related to on- going coal contract negotiations and litigation (see "Rate and Regulatory Matters"), other operation expenditures increased 23.6% ($7.1 million) during the current year, after an 8.2% rise in 1993.
Expected increases in production plant maintenance activity were the primary reason for the 14.9% ($3.6 million) rise in electric maintenance expense. In addition to normal maintenance project expenditures, the Company performed a scheduled major turbine generator overhaul on Culley Unit 2, performed significant repairs to one of the Company's gas turbine peaking units and incurred greater maintenance costs on the A. B. Brown scrubber facilities due to the plant's significantly greater generation. Electric maintenance expenditures in 1993 rose 20% over 1992, when such costs were down $4.5 million. Depreciation and amortization expense increased about 3% in 1994, following a 2% increase in 1993, reflecting normal additions to utility plant.
While inflation has a significant impact on the replacement cost of the Company's facilities, only the historical cost of electric and gas plant investment is recoverable in revenues as depreciation under the ratemaking principles followed by the Indiana Utility Regulatory Commission (IURC), under whose regulatory jurisdiction the Company is subject. 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.
Federal and state income tax expense was lower during 1994 due to the decrease in pretax income. Income tax expense rose $1.9 million in 1993, the result of higher pretax income and the provision of additional federal income tax expense to reflect higher tax rates enacted under the Omnibus Budget Reconciliation Act of 1993. The $3.2 million decrease in taxes other than income taxes during the current year reflects adjustments to prior years' provisions for property taxes related to the favorable outcome of a property tax appeal.
GAS OPERATIONS. The following table compares changes in operating revenues, operating expenses and gas sold and transported between 1994 and 1993, and between 1993 and 1992, in summary form.
Fewer sales of natural gas and lower gas costs recovered through retail rates more than offset the impact on gas operating revenues of the second step (about 4% of gas revenues, or $2.75 million on an annual basis) of the Company's two-step increase in its base gas rates, effective August 1, 1994 (see "Rate and Regulatory Matters"). The overall decline in 1994 gas revenues was 2.8%.
A 32% decline in industrial sales during 1994 was the primary reason for an 8.5% drop in the Company's gas sales. Residential and commercial customer sales also declined, 4.7% and 4.8%, respectively, due to the milder winter temperatures. Industrial sales were down due to increased transportation activity of certain large customers; total deliveries to industrial customers under the Company's sales and transportation tariffs declined 3.9% primarily due to the lower production levels of Alcoa, one of the Company's largest industrial customers (see "Electric Operations"). In 1993, residential and commercial sales were up 12.8% and 10.3%, respectively, due to colder winter weather, and industrial sales and transportation volumes increased 6.4% on greater manufacturing activity of several of the Company's largest customers.
On June 30, 1994, the Company completed its acquisition of Lincoln Natural Gas Company, Inc. (LNG), a small gas distribution company serving approximately 1,300 customers contiguous to the eastern boundary of the Company's gas service territory. (See Note 1 of the Notes to Consolidated Financial Statements for further discussion.) In addition to the LNG customers, 1,200 new gas customers were added to the Company's system, raising the year end total to 102,929.
The recovery of lower unit gas costs through retail rates in 1994 lowered revenues approximately $1 million following a $2.7 million increase in revenues related to the recovery of higher unit costs in the prior year. During the past several years, the market for purchase of natural gas supply has been very volatile with the average price ranging from the low of $1.34 per Dth in February 1992 to the peak of $2.58 per Dth in May 1993 and then declining to $1.38 per Dth in October 1994. The volatility of the market reflects the general tightening of the balance between available supply and demand after several years of excess supply, and more recently, the effect of the further deregulation of the gas pipeline industry (see "Rate and Regulatory Matters"). 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, declined 17.5% ($9 million) in 1994 to $42.3 million, following a 9.9% ($4.6 million) increase in 1993. The lower costs in 1994 reflected a 10.6% decrease in deliveries to customers and a 7.9% decline in the average unit cost of gas delivered to customers. The higher cost of gas sold in 1993 was due to increased deliveries to customers and higher unit costs.
Although the Company's former 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 No. 636, the Company's 1994 and 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.)
Following a 31% increase in 1993, other operation and maintenance expenses were 8.1% ($1.1 million) greater than the prior year due primarily to expenses associated with an accelerated program of relocating gas customer meters outside of customer premises to aid in future operating efficiencies, greater employee-related benefit costs and increases in various other operating expenses.
Although the Company has continued to invest in gas plant due to new business requirements and improvements to the distribution system, depreciation expense in 1994 declined, reflecting the impact of a full year of lower depreciation rates implemented during 1993 as a result of the Company's gas rate case. Depreciation expense in 1993 was relatively unchanged from 1992 because lower depreciation rates were only in effect during five months of 1993.
The significant increase in income tax expense resulted from higher pretax gas income in 1994; income tax expense in 1993 was comparable to 1992.
OTHER INCOME AND INTEREST CHARGES.
Other income was $1.1 million greater during 1994 due to increased allowance for equity funds used during construction, resulting primarily from the continued construction of the Company's new sulfur dioxide scrubber (see "Clean Air Act" ). Higher other income in 1993, up $2.5 million, also resulted from increased allowance for equity funds used during construction related to the scrubber project.
Interest expense during the current year and during 1993 was relatively unchanged. Increased interest expense on short- term debt during 1994 was offset by additional interest capitalized due to the increased construction program.
RATE AND REGULATORY MATTERS.
As described in Note 1 of the Notes to Consolidated Financial Statements, the Company complies with the provisions of Financial Accounting Standard (FAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows certain costs incurred by the Company that have been, or are expected to be, approved by regulatory authorities for recovery through rates, to be deferred as regulatory assets until recovered by the Company. In the event the Company determines that it no longer meets the criteria for following FAS 71, the accounting impact to the Company would be an extraordinary noncash charge to operations of an amount that could be material. Criteria that could give rise to the discontinuance of FAS 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs, and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of FAS 71 is appropriate.
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 was implemented in two equal steps of approximately 4% on August 1, 1993 and 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.
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 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 petitioned the IURC on March 1, 1994 for recovery of financing costs related to the scrubber construction costs incurred from April 1, 1993 through January 31, 1994, and was granted a 2.3% increase, approximately $4.2 million on an annual basis, in base electric retail rates. This second step of the increase was effective June 29, 1994. On December 22, 1993, the Company petitioned the IURC for the third of the three planned general electric rate increases related to its Clean Air Act Compliance project. The final adjustment is necessary to cover financing costs related to the balance of the project construction expenditures, costs related to the operation of the scrubber, certain nonscrubber-related operating 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"). The Company filed its case-in- chief on May 16, 1994 supporting a $12.4 million, 5.7% retail rate increase. On October 1, 1994, the Office of the Utility Consumer Counselor (UCC) filed its case-in-chief. On rebuttal, the Company reduced its request to $10.5 million reflecting a stipulated agreement with the UCC on depreciation rates and a reduction in the final estimated cost of the Clean Air Act Compliance project. The estimated impact of the UCC's recommendation is a $1.7 million, .7%, decrease in retail revenues. The major differences between the Company's request and the UCC's proposal are the requested rate of return on equity, the recovery of the additional cost of postretirement benefits other than pensions, the "fair value" of rate base investment and the appropriate level of operation and maintenance expenses to be included in cost of service. All hearings have been completed and the Company is awaiting the final rate order, anticipated in early 1995. The Company cannot predict what action the IURC may take with respect to this proposed rate increase.
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. In 1994, the Company incurred additional buyout costs of $.8 million. No additional buyout costs are anticipated for the remainder of the agreement 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 total savings in coal costs during the 1991-1995 period resulting from the renegotiation and subsequent buyout, net of the total buyout costs, will approximate $58 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. 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 a letter agreement which is effective until final resolution of the current litigation. Under the letter agreement, 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 recovery through the fuel adjustment clause. The difference between the contract price and the invoice price , $22 million at December 31, 1994, has been deposited in an escrow account and will be paid to either the Company's ratepayers or its coal supplier upon resolution of the litigation. The Company also maintains that shipments from the supplier do not conform to the agreed upon coal specifications in the contract. This litigation came to trial conclusion based upon summary judgment motions in June 1994. The U.S. District Court found in favor of the Company regarding required coal quality specifications and, in an earlier summary judgment, found in favor of the coal supplier regarding alleged minimum annual tonnage requirements. Both parties have initiated appeal procedures and expect the case to be heard by the Court of Appeals in mid-1995 with a decision from that court later in 1995. The parties are also considering mediation. 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 an additional letter agreement, effective January 1, 1994, and continuing until the litigation is resolved, whereby the Company will purchase an additional 50,000 tons monthly above the alleged base requirements at a market-competitive price. The price under this agreement is not subject to revision regardless of the outcome of the litigation.
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. 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 could 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 which will be partially offset by lower volume-related transportation costs. TGTC has estimated that the Company's allocation of transition costs will total approximately $5.2 million, to be incurred over a three-year period ending the first quarter of 1997, and has filed and received approval for recovery of $3 million of these costs. During 1994, the Company was billed $1.3 million of these transition costs, $.4 million of which it deferred pending authorization by the IURC of recovery of such costs. The Company has also recognized an additional $1.7 million of these costs which have not yet been billed. Since authorization for recovery of transition costs was recently granted by the IURC to other Indiana utilities, the Company does not expect the Order to have a detrimental effect on its financial condition or results of operations.
HOLDING COMPANY.
On December 20, 1994, the Company's Board of Directors authorized the steps required for a corporate reorganization in which a yet to be formed holding company would become the parent of the Company. Three of the Company's four subsidiaries are expected to also become subsidiaries of the new holding company. The Company will seek shareholder approval at the Company's March 28, 1995 annual meeting. In addition to shareholder approval, approval by the Federal Energy Regulatory Commission and the Securities and Exchange Commission is required.
The reorganization is in response to the changes created in the electric industry by the Energy Policy Act of 1992 and the need to respond quickly to the more competitive business environment. The new structure will enable the Company to better define and separate its regulated and nonregulated businesses.
If the Company receives the required shareholder and regulatory approvals, the outstanding shares of Company common stock would be exchanged on a one-for-one basis for shares of common stock of the new holding company. All of the Company's debt securities and all of its outstanding shares of preferred stock would remain securities of the Company and be unaffected.
If the necessary approvals are received when expected, the Company anticipates the reorganization could be completed by late 1995. ENVIRONMENTAL MATTERS.
In 1993, the Company expensed $.5 million of anticipated cost of performing preliminary and comprehensive investigations of 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 would have been operated from the 1850's through the early 1950's under industry standards then in effect. 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 completed its initial investigation in early 1994 and identified the existence and general location of four sites. Although the results of preliminary assessments of the sites indicated no contamination was present, the Company elected to conduct more comprehensive testing of the sites to provide conclusive evidence that no such contamination exists. Comprehensive testing of three of the sites was initiated in late 1994; the Company expects to initiate testing of the fourth site in 1995. Testing of one site has been completed with no evidence of contamination present, and testing of the remaining sites should be completed in 1995. No additional costs for testing are anticipated at this time.
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 (EPA) for any of these sites.
The Company does not presently anticipate seeking recovery of these investigation costs from its ratepayers. 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.
Key provisions of the National Energy Policy Act of 1992 (the Act) are expected to cause some of the most significant changes in the history of the electric industry. The primary purpose of the electric provisions 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 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. Although there has been much discussion of the subject during the past year, most notably in California where the state regulatory commission staff proposed a plan to implement retail wheeling, 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 industry, and is continuing its efforts to further reduce its coal costs.
CLEAN AIR ACT.
To meet the Phase I requirements of the Clean Air Act Amendments of 1990 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 (92 MW) and Culley Unit 3 (250 MW) and the installation of state of the art low NOx burners on these two units. In October 1992, the IURC approved a stipulation and settlement agreement between the Company and intervenors essentially approving the Compliance Plan.
Construction of the facilities, originally projected to cost approximately $115 million including the related allowance for funds used during construction, began during 1992. This project, which is on schedule and under budget, will total approximately $103 million. 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 annual cost to operate and maintain the facilities, including the cost of chemicals to be used in the process, is approximately $4.3 million.
By installing a scrubber, the Company was entitled to apply to the federal EPA for extra allowances, called "extension allowances". The Company will receive about 88,500 extension allowances, which it has sold to another party under a confidential agreement. As part of the IURC- approved stipulation and agreement, the Company agreed to credit approximately $2.5 million per year for the period 1995 through 1999 to retail customers to reduce 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. This scrubber has been operating in a start-up "test" mode for several months, and by early January 1995, the Company had shipped several barge loads of gypsum to the manufacturer. The agreement will enable the Company to reduce certain operating costs 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 7-8%, 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 "Rate and Regulatory Matters"). 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.
According to projections included in the Company's latest update of its Integrated Resource Plan (IRP), approved by the IURC on September 7, 1994, the Company expects to incur costs of approximately $54 million on DSM programs during the 1995-1999 period. The projections indicate that by 1999, approximately 118 megawatts of capacity are expected to have been postponed or eliminated due to these programs. While the latest projections of DSM expenditures are an estimated $201 million through the year 2012, they are estimated to result in incremental savings of approximately $160 million to ratepayers by deferring the need for approximately 166 megawatts of new generating capacity. However, due to the anticipated changes in the electric industry precipitated by the National Energy Policy Act of 1992, the projected DSM programs, related costs and associated results are subject to change.
In addition to the utilization of DSM programs, the 1993 IRP forecasts the need for 125 megawatts of base-load generating capacity in the early 21st century to meet the future electricity needs of the Company's customers.
LIQUIDITY AND CAPITAL RESOURCES.
The Company experienced record earnings per share during 1994, and financial performance continued to be solid. Internally generated cash provided 58.8% 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 12.8% represented allowance for funds used during construction. The ratio of earnings to fixed charges (SEC method) was 3.7:1, 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.
Other than an $11 million increase in short-term debt, no financing activity occurred during 1994, in contrast to 1993 when the Company called $84.5 million of its first mortgage bonds, at a premium, and refunded them with two $45 million issues. In addition, the Company retired $20 million of its maturing first mortgage bonds with a $20 million issue due 2025. To provide financing for a portion of the Culley scrubber project, the Company issued two series of adjustable rate first mortgage bonds totaling $45 million in May 1993 in connection with the sale of Warrick County, Indiana environmental improvement bonds.
During the five-year period 1995-1999, the Company anticipates that a total of $90 million of debt securities will be redeemed.
Construction expenditures, including $4.1 million for DSM programs, totaled $84.8 million during 1994, compared to the $80.2 million expended in 1993. As discussed in "Clean Air Act", construction of the new scrubber continued in 1994, requiring $36.4 million. The remainder of the 1994 construction expenditures consisted of the normal replacements and improvements to gas and electric facilities and of the construction of a $3.7 million vehicle maintenance facility located at the Company's Norman P. Wagner Operations Center.
At this time, the Company expects that construction requirements for the years 1995-1999 will total approximately $230 million, including approximately $47 million of capitalized expenditures to develop and implement DSM programs; however, as discussed previously in "Demand Side Management", the anticipated changes in the electric industry may require changes to the level of future DSM expenditures. 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 $55-70 million are anticipated.
At year end, the Company had $22.1 million in short-term borrowings, leaving unused lines of credit and trust demand note arrangements totaling $13 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
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 SUBSIDIARIES as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the 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 schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas and Electric Company and Subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 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 schedule listed under Item 8 (3) is presented for the purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This supplemental schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois January 23, 1995
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries Southern Indiana Properties, Inc., Southern Indiana Minerals, Inc., Energy Systems Group, Inc. and Lincoln Natural Gas Company, Inc. All significant intercompany transactions and balances have been eliminated. Southern Indiana Properties, Inc. invests principally in partnerships (primarily in real estate), leveraged leases and marketable securities. Energy Systems Group, Inc., incorporated in April 1994, provides equipment and related design services to industrial and commercial customers. Southern Indiana Minerals, Inc., incorporated in May 1994, processes and markets coal combustion by-products. The operating results of these subsidiaries are included in "Other, net" in the Consolidated Statements of Income. On June 30, 1994, the Company completed the acquisition of Lincoln Natural Gas Company, Inc. (LNG), a small gas distribution company with approximately 1,300 customers contiguous to the eastern boundary of the Company's gas service territory. The Company issued 49,399 shares of its common stock for all common stock of LNG. This transaction was accounted for as a pooling of interests. Prior period financial statements have been restated to reflect this merger and to conform to current period presentation.
(b) REGULATION
The Indiana Utility Regulatory Commission (IURC) has jurisdiction over all investor-owned gas and electric utilities in Indiana. The Federal Energy Regulatory Commission (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. The financial statements of the Company are based on generally accepted accounting principles, which give recognition to the ratemaking and accounting practices of these agencies.
(c) REGULATORY ASSETS
The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues to the Company associated with certain incurred costs which will be recovered from customers through the ratemaking process. Because of the expected favorable regulatory treatment, the following regulatory assets are reflected in the Consolidated Balance Sheets as of December 31:
(d) CONCENTRATION OF CREDIT RISK
The Company's customer receivables from gas and electric sales and gas transportation services are primarily derived from a broadly diversified base of residential, commercial and industrial customers located in a southwestern region of Indiana. The Company serves 118,992 electric customers in the city of Evansville and 74 other communities and serves 102,929 gas customers in the city of Evansville and 64 other communities. The Company continually reviews customers' creditworthiness and requests deposits or refunds deposits based on that review. See Note 3 of Notes to Consolidated Financial Statements for a discussion of receivables related to its leveraged lease investments.
(e) 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 9.5% in 1994, 10.5% in 1993 and 11.5% in 1992.
(f) 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 as follows:
(g) INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes." The standard did not have a material impact on results of operations, cash flow or financial position. The Company utilizes the liability method of accounting for income taxes, providing deferred taxes on temporary differences. Investment tax credits have been deferred and are amortized through credits to income over the lives of the related property. The components of the net deferred income tax liability at December 31 are as follows:
Of the $3,309,000 increase in the net deferred income tax liability from December 31, 1993 to December 31, 1994, $234,000 is due to current year deferred federal and state income tax expense and the remaining $3,075,000 increase is primarily a result of the change in the net regulatory assets and liabilities. 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:
A reconciliation of the statutory tax rates to the Company's effective income tax rate for the years ended December 31 is as follows:
(h) PENSION BENEFITS
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' 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, 1994 consist of investments in interest-bearing obligations and common stocks of 52% and 48%, respectively. The components of net pension cost related to these plans 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 trusteed retirement plans at December 31 is as follows:
The projected benefit obligation at December 31, 1993 was determined using an assumed discount rate of 7%. Due to the increase in yields on high quality fixed income investments, a discount rate of 8% was used to determine the projected benefit obligation at December 31, 1994. 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. In addition to the trusteed pension plans discussed above, the Company provides supplemental pension benefits to certain current and former officers under nonqualified and nonfunded plans. In 1994, the Company charged $1,978,000 to pension expense representing the projected value of these future benefits earned as of December 31, 1994, but not yet recognized. Future annual service cost related to these benefits will be approximately $150,000.
(i) 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 1993, the cost of retiree health care and life insurance benefits was recognized as insurance premiums were paid, which was consistent with ratemaking practices. The costs for retirees totaled $670,000 in 1992. 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. 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. The components of the net periodic other postretirement benefit cost for the years ended December 31 are as follows:
The net periodic 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. Because the Company is undecided whether it will seek recovery of 1993 and 1994 postretirement benefits other than pensions allocable to firm wholesale customers, $372,000 of these costs, which had previously been deferred as regulatory assets, were expensed in 1994. Reconciliation of the accumulated postretirement benefit obligation to the accrued liability for postretirement benefits as of December 31 is as follows:
The assumptions used to develop the accumulated postretirement benefit obligation at December 31, 1993 included a discount rate of 7.25% and a health care cost trend rate of 13.5% in 1994 declining to 5.5% in 2008. Due to the increase in yields on high quality fixed income investments, a discount rate of 8.25% was used to determine the accumulated postretirement benefit obligation at December 31, 1994. All other actuarial assumptions remained unchanged at year end. The estimated cost of these future benefits could be significantly affected 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 1994 by $750,000 and the accumulated postretirement benefit obligation by $5,800,000. The Company anticipates that beginning in 1995, postretirement benefits costs other than pensions will be funded as recognized, through a Voluntary Employee Benefit Association (VEBA) trust.
(j) POSTEMPLOYMENT BENEFITS
In November 1992, the Financial Accounting Standards Board issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits," which requires the Company to accrue the estimated cost of benefits provided to former or inactive employees after employment but before retirement. The Company adopted SFAS No. 112 on January 1, 1994. The adoption of the new standard did not affect financial position or results of operations.
(k) 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 1994, 1993 and 1992, paid interest (net of amounts capitalized) of $18,053,000, $18,359,000 and $17,890,000, respectively, and income taxes of $15,447,000, $10,248,000 and $14,291,000, respectively. The Company is involved in several partnerships which are partially financed by partnership obligations amounting to $12,881,000 and $16,730,000 at December 31, 1994 and 1993, respectively.
(l) 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 1994 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 $11,000,000 at December 31, 1994. (m) 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) RATE AND REGULATORY MATTERS
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 was implemented in two equal steps. The first step of the rate adjustment, approximately 4%, took place August 1, 1993; the second step of the rate adjustment took place on 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 (CAAC) 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 $1.8 million on an annual basis, which took effect October 1, 1993. The Company petitioned the IURC on March 1, 1994 for recovery of financing costs related to scrubber construction expenditures incurred from April 1, 1993 through January 31, 1994, and was granted a 2.3% increase, approximately $4.2 million on an annual basis, in base electric retail rates effective June 29, 1994. On December 22, 1993, the Company petitioned the IURC for the third of three planned general electric rate increases related to its CAAC project. The final adjustment is necessary to cover financing costs related to the balance of the project construction expenditures, costs related to the operation of the scrubber, certain nonscrubber-related operating costs such as additional costs incurred for postretirement benefits other than pensions beginning in 1993, and the recovery of demand side management program expenditures. The Company filed its case-in-chief on May 16, 1994 supporting a $12.4 million, 5.7% retail rate increase. On October 1, 1994, the Office of the Utility Consumer Counselor (UCC) filed its case-in-chief. On rebuttal, the Company reduced its request to $10.5 million reflecting a stipulated agreement with the UCC on depreciation rates and a reduction in the final estimated cost of the Clean Air Compliance project. The estimated impact of the UCC's recommendation is a $1.7 million, .7%, decrease in retail revenues. The major differences between the Company's request and the UCC's proposal are the requested rate of return on equity, the recovery of the additional cost of postretirement benefits other than pensions, the fair value of ratebase investment, and the appropriate level of operation and maintenance expenses to be included in cost of service. All hearings have been completed and the Company is awaiting the final rate order, anticipated in early 1995. The Company cannot predict what action the IURC may take with respect to this proposed rate increase. 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 which will be partially offset by lower volume-related transportation costs. TGTC has estimated that the Company's allocation of transition costs will total approximately $5.2 million, to be incurred over a three-year period ending the first quarter of 1997, and has filed and received approval for recovery of $3 million of these costs. During 1994, the Company was billed $1,285,000 of these transition costs, $445,000 of which it deferred pending authorization by the IURC of recovery of such costs. The Company has also recognized an additional $1.7 million of these costs, which have not yet been billed. Since authorization for the recovery of transition costs was recently granted by the IURC to other Indiana utilities, 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. In 1994, the Company incurred additional buyout costs of $.8 million. No additional buyout costs are anticipated for the remainder of the agreement 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, 1994, $7,685,000 of settlement costs paid to date had not yet been amortized to coal inventory. The Company is currently in litigation with another coal supplier. 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 a letter agreement which is effective until final resolution of the current litigation. Under the letter agreement 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 recovery through the fuel adjustment clause. The difference between the contract price and the invoice price, $22,018,000 at December 31, 1994, 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 Company also maintains that shipments from the supplier do not conform to the agreed upon coal specifications in the contract. This litigation came to trial conclusion based upon summary judgment motions in June 1994. The U.S. District Court found in favor of the Company regarding required coal quality specifications and, in an earlier summary judgement, found in favor of the coal supplier regarding alleged minimum annual tonnage requirements. Both parties have initiated appeal procedures and expect the case to be heard by the Court of Appeals in mid-1995 with a decision from that court later in 1995. The parties are also considering mediation. 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 an additional letter agreement, effective January 1, 1994, and continuing until the litigation is resolved, whereby the Company will purchase an additional 50,000 tons monthly above the alleged base requirements at a market-competitive price. The price under this agreement is not subject to revision regardless of the outcome of the litigation. Reference is made to "Rate and Regulatory Matters" in Management's Discussion and Analysis of Operations and Financial Condition for further discussion of these matters.
(3) LEVERAGED LEASES
Southern Indiana Properties, Inc. 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 at December 31, 1994 and 1993, 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 accepted as their sole remedy in the event of default by the lessee. Such debt amounted to approximately $77,900,000 and $78,700,000 at December 31, 1994 and 1993, respectively. The Company's net investment in leveraged leases at those dates was $6,169,000 and $8,184,000, respectively, as shown:
(4) SHORT-TERM FINANCING
The Company has trust demand note arrangements totaling $17,000,000 with several banks, of which $13,000,000 was utilized at December 31, 1994. Funds are also borrowed periodically from banks on a short-term basis, made available through lines of credit. These available lines of credit totaled $18,000,000 at December 31, 1994 of which $9,000,000 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 1995 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 1995 is excluded from current liabilities on the balance sheet. At December 31, 1994, $163,063,000 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, 1994, the following amounts mature in the five years subsequent to 1994: 1995 - $11,178,000; 1996 - $12,340,000; 1997 - $2,712,000; 1998 - $16,617,000; and 1999 - $47,074,000. In addition, $31,500,000 of adjustable rate pollution control series first mortgage bonds could, at the election of the bondholder, be tendered to the Company in May 1995. 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 1995 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.
(9) COMMITMENTS AND CONTINGENCIES
The Company presently estimates that approximately $40,000,000 will be expended for construction purposes in 1995, including those amounts applicable to the Company's demand side management (DSM) programs. Commitments for the 1995 construction program are approximately $21,000,000 at December 31, 1994. Reference is made to "Demand Side Management" in Management's Discussion and Analysis of Operations and Financial Condition for discussion of the implementation of the Company's DSM programs. In 1993, the Company expensed $500,000 for the anticipated cost of performing preliminary and comprehensive investigations of 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. The Company completed its initial investigations in early 1994 and identified the existence and general location of four sites at which contamination may be present. The Company completed its preliminary assessments of all four sites in 1994. Although the results of the preliminary assessments of the sites indicated no contamination was present, the Company elected to conduct more comprehensive testing to provide conclusive evidence that no such contamination exists. Comprehensive testing of three of the sites was initiated in late 1994; the Company expects to initiate testing of the fourth site in 1995. Testing of one site has been completed with no evidence of contamination present, and testing of the remaining sites should be completed in 1995. No additional costs for testing are anticipated at this time. 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. The Company does not presently anticipate seeking recovery of these investigation costs from its ratepayers. 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, 1994, 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. On June 30, 1994, the Company completed its acquisition of Lincoln Natural Gas Company, Inc. (LNG). The Company issued 49,399 shares of common stock for all common stock of LNG. 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 restated to reflect the issued shares. No shares of common stock were issued during 1993. After obtaining stockholder approval at the Company's 1994 Annual Stockholders Meeting, the Company established a common stock option plan for key management employees of the Company. During 1994, 153,666 options were granted to participants, of which 76,996 options are exercisable one year after the grant date. Since the impact of the outstanding options on earnings per share is antidilutive, only primary earnings per share have been presented. 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, 1994 is $30,914,000 with accumulated depreciation totaling $19,045,000. 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) DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The company adopted in 1994 SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," which requires accounting for certain investment in debt or equity securities at either amortized cost or fair value. Of the $5,444,000 of temporary investments, $2,990,000 are available-for-sale securities and $200,000 are held-to- maturity securities. Nonutility property and other includes of held-to-maturity securities, which are valued at amortized cost. The unrealized loss, net of tax, of $106,000 on these investments is recorded as a separate component of shareholders' equity. The carrying amount and estimated fair values of the Company's financial instruments at December 31 are as follows:
At December 31, 1994, the carrying amounts of the Company's debt relating to utility operations exceeded fair market value by $14,000,000. Fair value of long-term debt at December 31, 1993 exceeded carrying amounts by $20,400,000. Anticipated regulatory treatment of the excess or deficiency 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 or increase 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. 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 is based on fair value or amortized cost. The fair value was determined based on current market values.
NONUTILITY PROPERTY AND OTHER
Included in Nonutility property are held-to-maturity debt securities. Held-to-maturity debt securities are valued at amortized cost, which approximates fair value.
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.
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 23, (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 and designated in Form 10-K for the fiscal year 1993, File No. 1-3553, 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 and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 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 and designated in Form 10-K for the fiscal year 1993, File No. 1-3553, as Exhibit 10-A-20.)
EX-12 Computation of Ratio of Earnings to Fixed Charges
EX-21 Subsidiaries of the Registrant
EX-24 Power of Attorney
* 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 1994.
SCHEDULE II
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 30, 1995 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY By R. G. Reherman, Chairman, President and Chief Executive Officer
BY /s/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.
SIGECO 10-K