SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________________________
to ________________________________
Commission File Number 1-3553
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Indiana 35-0672570
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47741-0001
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code: (812)
465-5300
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Common Stock, Without Par Value New York Stock Exchange
Rights to Purchase Preferred Stock,
No Par Value, Series 1986 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock, $100 Par Value
(Title of Class)
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of
registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes [X] No [ ]
State the aggregate market value of the voting stock held by
non-affiliates of the registrant: $471,341,191 at February
28, 1994, including 185,895 shares of Preferred Stock, $100
Par Value.
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date:
Outstanding as of
Class February 28, 1994
Common Stock, Without Par Value 15,705,427
Documents incorporated by reference (to the extent indicated
herein):
Part of Form 10-K into which
Document document is incorporated
Proxy Statement dated February 22, 1994 relating to the
1994 Annual Meeting of Stockholders Part III
1
PART 1
Item 1. BUSINESS
GENERAL
Southern Indiana Gas and Electric Company (Company) is
an operating public utility incorporated June 10, 1912,
under the laws of the State of Indiana, engaged in the
generation, transmission, distribution and sale of electric
energy and the purchase of natural gas and its
transportation, distribution and sale in a service area
which covers ten counties in southwestern Indiana. The
Company has a wholly-owned nonutility investment subsidiary,
Southern Indiana Properties, Inc. (refer to Note 3 of the
Notes To Consolidated Financial Statements, page 35, for
further discussion).
Electric service is supplied directly to Evansville and
74 other cities, towns and communities, and adjacent rural
areas. Wholesale electric service is supplied to an
additional nine communities. At December 31, 1993, the
Company served 118,163 electric customers, and was also
obligated to provide for firm power commitments to the City
of Jasper, Indiana, and to maintain spinning reserve margin
requirements under an agreement with the East Central Area
Reliability Group (ECAR).
At December 31, 1993, the Company supplied gas service
to 100,398 customers in Evansville and 63 other nearby
communities and their environs. Since 1986, the Company has
purchased its natural gas supply requirements from numerous
suppliers. During 1993, twenty-five suppliers were used;
however, Texas Gas Transmission Corporation (TGTC) remained
the Company's primary contract supplier. In November 1993,
TGTC restructured its services so that its gas supplies are
sold separately from its interstate transportation services.
TGTC ceased to be a supplier of natural gas to the Company,
and the Company assumed full responsibility for the purchase
of all its natural gas supplies. (See subsequent reference
under "Gas Business" to the restructuring of interstate
pipelines.) During 1993, eighteen of the Company's major
gas customers took advantage of the Company's gas
transportation program to procure a portion of their gas
supply needs from suppliers other than the Company.
The principal industries served by the Company include
aluminum smelting and recycling, aluminum sheet products,
polycarbonate resin (Lexan) and plastic products, appliance
manufacturing, pharmacuetical and nutritional products,
automotive glass, gasoline and oil products, and coal
mining.
The only property the Company owns outside of Indiana
is approximately eight miles of 138,000 volt electric
transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's
transmission system at Cloverport, Kentucky. The original
cost of the property is less than $425,000. The Company
does not distribute any electric energy in Kentucky.
LINES OF BUSINESS
The percentages of operating revenues and operating
income before income taxes attributable to the electric and
gas operations of the Company for five years ended December
31, 1993, were as follows:
Year Ended December 31,
1989 1990 1991 1992 1993
Operating Revenues:
Electric 79.6% 80.6% 81.8% 79.5% 78.7%
Gas 20.4 19.4 18.2 20.5 21.3
Operating Income Before Income Taxes:
Electric 98.6% 93.0% 97.4% 99.0% 99.4%
Gas 1.4 7.0 2.6 1.0 .6
<FN>
Reference is made to Note 12 of the Notes To
Consolidated Financial Statements, page 38, for Segments of
Business data.
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ELECTRIC BUSINESS
The Company supplies electric service to 118,163
customers, including 103,318 residential, 14,645 commercial,
177 industrial, 19 public street and highway lighting and
four municipal customers.
The Company's installed generating capacity as of
December 31, 1993 was rated at 1,238,000 kilowatts (Kw).
Coal-fired generating units provide 1,023,000 Kw of capacity
and gas or oil-fired turbines used for peaking or emergency
conditions provide 215,000 Kw.
In addition, the Company has interconnections with
Louisville Gas and Electric Company, Public Service Company
of Indiana, Inc., Indianapolis Power & Light Company,
Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers
Electric Corporation, and the City of Jasper, providing an
ability to simultaneously interchange approximately 750,000
Kw.
Record-breaking peak conditions occurred on July 28,
1993, when the Company's system summer peak load of
1,012,700 Kw was 6.5% greater than the previous record
system summer peak load of 951,200 Kw established August 17,
1988. The Company's total load obligation for each of the
years 1989 through 1993 at the time of the system summer
peak, and the related capacity margin, are presented below.
The Company's other load obligations at the time of the peak
included firm power commitments to Alcoa Generating
Corporation (AGC) except as noted, the City of Jasper,
Indiana, and the Company's reserve margin requirements under
the ECAR agreement.
Date of Summer Peak Load
08-28-89 07-09-90 07-22-91 07-13-92 07-28-93
Company System Peak Load (Kw)
884,900 942,700 948,400 916,700 1,012,700
Other Load Obligations at Peak (Kw)
84,100 70,800<F1> 77,480<F1> 75,190<F1> 87,340<F1>
Total Load Obligations at Peak (Kw)
969,000 1,013,500 1,025,880 991,890 1,100,040
Total Generating Capability (Kw)
1,167,000 1,163,000 1,238,000<F2> 1,238,000<F2> 1,238,000<F2>
Capacity Margin at Peak
17% 13% 17% 20% 11%
<FN>
<F1> Effective February 1, 1990, the Company had no firm
power commitments to AGC.
<F2> Includes 80,000 Kw gas-fired turbine placed in service
May 31, 1991.
The all-time record system winter peak load of 771,900
Kw occurred during the 1989-1990 season on December 22,
1989, and was 10.8% greater than the 1992-1993 winter season
system peak (the second highest winter peak) reached on
February 18, 1993 at 696,800 Kw.
The Company, primarily as agent of AGC, operates the
Warrick Generating Station, a coal-fired steam electric
plant which interconnects with the Company's system and
provides power for the Aluminum Company of America's Warrick
Operations, which includes aluminum smelting and fabricating
facilities. Of the four turbine generators at the plant,
Warrick Units 1, 2 and 3, with a capacity of 144,000 Kw
each, are owned by AGC. Warrick Unit 4, with a rated
capacity of 270,000 Kw, is owned by the Company and AGC as
tenants in common, each having shared equally in the cost of
construction and sharing equally in the cost of operation
and in the output.
The Company (a summer peaking utility) has an agreement
with Hoosier Energy Rural Electric Cooperative, Inc.
(Hoosier Energy) for the sale of firm power to Hoosier
Energy during the annual winter heating season (November 15-
March 15). The contract made available 100 Mw during the
1993-1994 winter season, and allows for a possible increase
to 250 Mw by November 15, 1998. The contract will terminate
March 15, 2000.
Electric generation for 1993 was fueled by coal (99.8%)
and natural gas (.2%). Oil was used only to light fires and
stabilize flames in the coal-fired boilers and for testing
of gas/oil fired peaking units.
Historically, coal for the Company's Culley Generating
Station and Warrick Unit 4 has been purchased from operators
of nearby Indiana strip mines pursuant to long-term
contracts. During 1991, the Company pursued negotiations
for new contracts with these mine operators and while doing
so, purchased coal from the respective operators under
interim agreements. In October 1992, the Company finalized
a new supply agreement effective through 1995 and
retroactive to 1991, with one of the operators under which
coal is supplied to both locations. Included in the
agreement was a provision whereby the contract could be
3
reopened by the Company for modification of certain coal
specifications. In early 1993, the Company reopened the
contract for such modifications. Effective July 1, 1993,
the Company bought out the remainder of its contractual
obligations with the supplier, enabling the Company to
acquire lower priced spot market coal. The Company
estimates the savings in coal costs during the 1991-1995
period, net of the total buyout costs, will approximate $56
million. The net savings are being passed back to the
Company's electric customers through the fuel adjustment
clause. The coal supplier retained the right of first
refusal to supply Warrick Unit 4 and the Culley plant during
the years 1996-2000. (See "Rate and Regulatory Matters" of
Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 15, for further
discussion of the contract buyout.) The Indiana coal used
in these plants is blended by the vendor and delivered to
the plants to meet quality specifications set in conformance
with the requirements of the Indiana State Implementation
Plan for sulfur dioxide. Approximately 1,572,000 tons of
coal were used during 1993 in the generation of electricity
at the Culley Station and Warrick Unit 4. (See discussion
under "Environmental Matters", page 7.) For supplying the
A. B. Brown Generating Station, the Company has a contested
agreement, possibly extending to 1998, with an area
producer. (See Item 3, LEGAL PROCEEDINGS, page 10 for
discussion of litigation with this producer regarding the
coal supply agreement.) The amount of coal burned at A. B.
Brown Generating Station during 1993 was approximately
862,000 tons. Both units at the generating station are
equipped with flue gas desulfurization equipment so that
coal with a higher sulfur content can be used. There are
substantial coal reserves in the southern Indiana area. The
average cost of coal consumed in generating electrical
energy for the years 1989 through 1993 was as follows:
Average Cost
Average Cost Average Cost Per Kwh
Year Per Ton Per MMBTU (In Mills)
1989 $32.13 $1.44 15.36
1990 34.71 1.54 16.55
1991 33.01 1.46 15.87
1992 32.04 1.42 15.30
1993 32.56 1.46 15.66
The Broadway Turbine Units 1 and 2, Northeast Gas
Turbines and A. B. Brown Gas Turbine, when used for peaking,
reserve or emergency purposes, use natural gas for fuel.
Number 2 fuel oil can also be used in the Broadway Turbine
Units and the Brown Gas Turbine.
All metered electric rates contain a provision for
adjustment in charges for electric energy to reflect changes
in the cost of fuel and the net energy cost of purchased
power through the operation of a fuel adjustment clause
unless certain criteria contained in the regulations are not
met. The principal restriction to recovery of fuel cost
increases is that such recovery is not allowed to the extent
that operating income for the twelve month period provided
in the fuel cost adjustment filing exceeds the operating
income authorized by the Indiana Utility Regulatory
Commission (IURC) in the latest general rate case of the
Company. During 1991-1993, this restriction did not affect
the Company. As prescribed by order of the IURC, the
adjustment factor is calculated based on the estimated cost
of fuel and the net energy cost of purchased power in a
designated future quarter. The order also provides that any
over- or underrecovery caused by variances between estimated
and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor. This
continuous reconciliation of estimated incremental fuel
costs billed with actual incremental fuel costs incurred
closely matches revenues to expenses.
The Company's primary goal in the area of research and
development is cost savings through the use of new
technologies. This is accomplished, in part, through the
efforts of the Electric Power Research Institute (EPRI). In
1993, the Company paid $893,000 to EPRI to help fund
research and development programs such as advanced clean
coal burning technology.
The Company is participating with 14 other electric
utility companies, through Ohio Valley Electric Corporation
(OVEC) in arrangements with the United States Department of
Energy (DOE), to supply the power requirements of the DOE
plant near Portsmouth, Ohio. The sponsoring companies are
entitled to receive from OVEC, and are obligated to pay for
the right to receive, any available power in excess of the
DOE contract demand. The proceeds from the sale of power by
OVEC are designed to be sufficient to meet all of its costs
and to provide for a return on its common stock. During
1993, the Company's participation in the OVEC arrangements
was 1.5%.
4
The Company participates with 32 other utilities,
located in eight states comprising the east central area of
the United States, in the East Central Area Reliability
Group, the purpose of which is to strengthen the area's
electric power supply reliability.
GAS BUSINESS
The Company supplies natural gas service to 100,398
customers, including 91,476 residential, 8,682 commercial,
236 industrial and four public authority customers, through
2,520 miles of gas transmission and distribution lines.
The Company owns and operates three underground gas
storage fields with an estimated ready delivery from storage
of 3.9 million Dth of gas. Natural gas purchased from the
Company's suppliers is injected into these storage fields
during periods of light demand which are typically periods
of lower prices. The injected gas is then available to
supplement the normal contract volume from the pipeline
during periods of peak requirements. It is estimated that
approximately 119,000 Dth of gas per day can be withdrawn
from the three storage fields during peak demand periods on
the system.
The gas procurement practices of the Company and
several of its major customers have been altered
significantly during the past eight years as a result of
changes in the natural gas industry. In 1985 and prior
years, the Company purchased nearly its entire gas
requirements from Texas Gas Transmission Corporation (TGTC)
compared to 1993 when a total of 25 suppliers sold gas to
the Company. In total, the Company purchased 17,270,415 Dth
in 1993. Of this amount, 5,046,509 Dth, or 29%, was
purchased from TGTC, which continued to be the Company's
largest supplier and its major pipeline. In November 1993,
TGTC restructured its services so that its gas supplies are
sold separately from its interstate transportation services.
TGTC ceased to be a supplier of natural gas to the Company,
and the Company assumed full responsibility for the purchase
of all its natural gas supplies. (See subsequent reference
under "Gas Business" to the restructuring of interstate
pipelines.) During 1993, eighteen of the Company's major
gas customers took advantage of the Company's gas
transportation program to procure a portion of their gas
supply needs from suppliers other than the Company. A total
of 11,370,542 Dth was transported for these major customers
in 1993 compared to 9,497,059 Dth transported in 1992. The
Company received fees for the use of its facilities in
transporting such gas, allowing it to offset a portion of
the loss of its customary sales margin with respect to these
customers.
(See "Rate and Regulatory Matters" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 15 of this report,
for discussion of the Company's general adjustment in gas
rates and for discussion of the FERC Order No. 636 which
requires interstate pipelines to restructure their services
so that gas supplies will be sold separately from interstate
transportation services.)
The all-time record send out occurred during the 1989-
1990 winter season on December 22, 1989, when 223,489 Dth of
gas was delivered to the Company's customers. Of this
amount, 89,614 Dth was purchased, 104,358 Dth was taken out
of the Company's three underground storage fields, and
29,517 Dth was transported to customers under transportation
agreements. The 1992-1993 winter season peak day send out
was 189,717 Dth on February 17, 1993.
The average cost per Dth of gas purchased by the
Company during the past five calendar years was as follows:
1989, $2.84; 1990, $2.84; 1991, $2.71; 1992, $2.77; and 1993
$2.85.
The State of Indiana has established procedures which
result in the Company passing on to its customers the
changes in the cost of gas sold unless certain criteria
contained in the regulations are not met. The principal
restriction to recovery of gas cost increases is that such
recovery is not allowed to the extent that operating income
for the twelve month period provided in the gas cost
adjustment filing exceeds the operating income authorized by
the IURC in the latest general rate case of the Company.
During 1991-1993, this restriction did not affect the
Company. Additionally, these procedures provide for
scheduled quarterly filings and IURC hearings to establish
the amount of price adjustments for a designated future
quarter. The procedures also provide for inclusion in a
later quarter of any variances between estimated and actual
costs of gas sold in a given quarter. This reconciliation
process with regard to changes in the cost of gas sold
closely matches revenues to expenses. The Company's rate
structure does not include a weather normalization-type
clause whereby a utility would be authorized to recover the
gross margin on sales established in its last general rate
case, regardless of actual weather patterns.
Natural gas research is supported by the Company
through the Gas Research Institute in cooperation with the
American Gas Association. Since passage of the Natural Gas
Act of 1978, a major effort has gone into promoting gas
5
exploration by both conventional and unconventional sources.
Efforts continue through various projects to extract gas
from tight gas sands, shale and coal. Research is also
directed toward the areas of conservation, safety and the
environment.
On December 23, 1993, the Company entered into a
definitive agreement to acquire Lincoln Natural Gas Company,
Inc., a small gas distribution company of approximately
1,300 customers contiguous to the eastern boundary of the
Company's gas service territory. The acquisition is
expected to be completed by mid-1994, subject to necessary
regulatory and shareholder approvals.
NONUTILITY SUBSIDIARY
During 1986, the Company formed a wholly-owned
subsidiary, Southern Indiana Properties, Inc., which owns
and/or operates certain nonutility assets. Currently
included in the holdings of the subsidiary are an industrial
park, investments in several leveraged-lease financing
arrangements, investments in several tax oriented limited
partnerships, a portfolio of financial investments
(principally adjustable rate preferred stocks and municipal
bonds), and other nonutility property. (See Note 3 of the
Notes To Consolidated Financial Statements, page 35, for
further discussion of Southern Indiana Properties, Inc.)
PERSONNEL
The Company's network of gas and electric operations
directly involves 774 employees with an additional 190
employed at Alcoa's Warrick Power Plant. Alcoa reimburses
the Company for the entire cost of the payroll and
associated benefits at the Warrick Plant, with the exception
of one-half of the payroll costs and benefits allocated to
Warrick Unit 4, which is jointly owned by the Company and
Alcoa. The total payroll and benefits for Company employees
in 1993 (including all Warrick Plant employees) were $46.1
million, including $4.1 million of accrued postretirement
benefits other than pensions which the Company is deferring
as a regulatory asset until inclusion in rates. (See Note 1
of the Notes To Consolidated Financial Statements, page 29,
for further discussion of the new financial accounting
standard requiring recognition of these costs effective
January 1, 1993 and related regulatory treatment.) In 1992,
total payroll and benefits were $40.1 million.
On July 3, 1991, the Company signed a new three-year
contract with Local 702 of the International Brotherhood of
Electric Workers. The contract provided for a 4% general
wage increase each of the three years of the contract.
Certain cost-containment measures related to health care
coverage were adopted. Improvements in productivity, work
practices and the pension plan are also provided.
Additionally, the Company's Hoosier Division signed a three-
year labor contract with Local 135 of the Teamsters,
Chauffeurs, Warehousemen and Helpers effective January 14,
1992. The contract provided for a 4% general wage increase
each of the first and second years of the contract and a
3.75% general wage increase the third year of the contract.
Also provided are improvements in health care coverage
costs, pension benefits, sick pay, work practices and
productivity.
CONSTRUCTION PROGRAM AND FINANCING
A total of $80,109,000 was spent in 1993 on the
Company's construction program, of which $68,840,000 was for
the electric system, $5,772,000 for the gas system, $967,000
for common utility plant facilities, and $4,530,000 for the
Demand Side Management (DSM) Program. (See "Demand Side
Management" in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, page 19.)
Major construction project expenditures in 1993 included
$49.2 million of the originally projected $115 million
(including Allowance for Funds Used During Construction)
Culley Unit 2 and 3 scrubber project which is scheduled to
be completed by 1995. (See "Clean Air Act" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS, page 18.)
On May 11, 1993, the Company issued two series of
adjustable rate first mortgage bonds totaling $45.0 million
in connection with the sale of Warrick County, Indiana
environmental improvement revenue bonds. The proceeds of
the revenue bonds have been placed in trust are being used
to finance a portion of the Culley scrubber project. (See
"Liquidity and Capital Resources" in Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS, page 20 for further discussion of this
financing and discussion of the issuance of $110 million of
first mortgage bonds used to refinance existing long-term
debt.) No other securities were issued by the Company
during 1993 for the purpose of funding its construction
program.
6
For 1994, construction expenditures are presently
estimated to be $92.2 million which includes $8.7 million
for DSM programs. Expenditures in the power production area
are expected to total $55.8 million and include $41.7
million for the construction of the Culley scrubber project.
The balance of the 1994 construction program consists of
$14.9 million for additions and improvements to other
electric system facilities, $8.1 million of additions and
improvements to the gas system and $4.7 million for the
final phase of the $27 million Norman P. Wagner operations
complex and miscellaneous common utility plant buildings,
fixtures and equipment.
In keeping with the Company's objective to bring new
facilities on line as needed, the construction program and
amount of scheduled expenditures are reviewed periodically
to factor in load growth projections, system balance
requirements, environmental compliance and other
considerations. As a result of this program of periodic
review, construction expenditures may change in the future
from the program as presented herein.
For the five-year period of 1994-1998, it is estimated
that construction expenditures will total about $270 million
as follows: 1994 - $92 million; 1995 - $41 million; 1996 -
$44 million; 1997 - $48 million; and 1998 - $45 million.
This construction program reflects approximately $51 million
for the Company's DSM programs and $44 million to meet the
Phase I requirements of the Clean Air Act Amendments of
1990. While the Company expects the majority of the
construction requirements and an estimated $48 million in
debt security redemptions and other long-term obligations to
be provided by internally generated funds, external
financing requirements of $50-70 million are anticipated.
The aforementioned amounts relating to the Company's
construction program are in all cases inclusive of Allowance
for Funds Used During Construction.
REGULATION
Operating as a public utility under the laws of
Indiana, the Company is subject to regulation by the Indiana
Utility Regulatory Commission as to its rates, services,
accounts, depreciation, issuance of securities, acquisitions
and sale of utility properties or securities, and in other
respects as provided by the laws of Indiana.
In addition, the Company is subject to regulation by
the Federal Energy Regulatory Commission with respect to the
classification of accounts, rates for its sales for resale,
interconnection agreements with other utilities, and
acquisitions and sale of certain utility properties as
provided by the laws of the United States.
See "Electric Business" and "Gas Business" for further
discussion regarding regulatory matters.
The Company is subject to regulations issued pursuant
to federal and state laws, pertaining to air and water
pollution control. The economic impact of compliance with
these laws and regulations is substantial, as discussed in
detail under "Environmental Matters." The Company is also
subject to multiple regulations issued by both federal and
state commissions under the Federal Public Utility
Regulatory Policies Act of 1978.
As a result of the Company's ownership of 33% of
Community Natural Gas Company, the Company is a "Holding
Company" as such term is defined under the Public Utility
Holding Company Act of 1935 (the 1935 Act). The Company is
exempt from all provisions of the 1935 Act except for the
provisions of Section 9(A)(2), which pertains to
acquisitions of other utilities.
COMPETITION
The Company does not presently compete for electric or
gas customers with the other utilities within its assigned
service areas. As a result of changes brought about by the
National Energy Policy Act of 1992, the Company may be
required to compete (or have the opportunity to compete)
with other utilities and wholesale generators for sales of
electricity to existing wholesale customers of the Company
and other potential wholesale customers. (See subsequent
reference to discussion of this recent legislation.) The
Company currently competes with other utilities in
connection with intersystem bulk power rates.
Some of the Company's customers have, or in the future
could acquire, access to energy sources other than those
available through the Company. (See "Gas Business", page 4,
for discussion of gas transportation.) Although federal
statute allows for bypass of a local distribution (gas
utility) company, Indiana law disallows bypass in most cases
7
and the Company would likely litigate such an attempt in the
Indiana courts. Additionally, the Company's geographical
location in the corner of the state, surrounded on two sides
by rivers, limits customers' ability to bypass the Company
(by running long pipelines). There is also increasing
interest in research on the development of sources of energy
other than those in general use. Such competition from
other energy sources has not been a material factor to the
Company in the past. The Company is unable, however, to
predict the extent of competition in the future or its
potential effect on the Company's operations.
As part of its efforts to develop a National Energy
Strategy, Congress has amended the Public Utility Holding
Company Act and the Federal Power Act by enacting the
National Energy Policy Act of 1992 (the Act), which will
affect the traditional structure of the electric utility
industry. (Refer to "National Energy Policy Act of 1992" in
Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 18 of this report,
for discussion of the major changes in the electric industry
effected by the Act.)
ENVIRONMENTAL MATTERS
The Company is currently investigating the possible
existence of facilities once owned and operated by the
Company, its predecessors, previous landowners, or former
affiliates of the Company utilized for the manufacture of
gas. Refer to "Environmental Matters" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 17 of this report,
for discussion of the Company's actions regarding the
investigation.
The Company is subject to federal, state and local
regulations with respect to environmental matters,
principally air, solid waste and water quality. Pursuant to
environmental regulations, the Company is required to obtain
operating permits for the electric generating plants which
it owns or operates and construction permits for any new
plants which it might propose to build. Regulations
concerning air quality establish standards with respect to
both ambient air quality and emissions from the Company's
facilities, including particulate matter, sulfur dioxide and
nitrogen oxides. Regulations concerning water quality
establish standards relating to intake and discharge of
water from the Company's facilities, including water used
for cooling purposes in electric generating facilities.
Because of the scope and complexity of these regulations,
the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to
predict what other regulations may be adopted in the future.
The Company intends to comply with all applicable valid
governmental regulations, but will contest any regulation it
deems to be unreasonable or impossible to comply with or
which is otherwise invalid.
The implementation of federal and state regulations
designed to protect the environment, including those
hereinafter referred to, involves or may involve review,
certification or issuance of permits by federal and state
agencies. Compliance with such regulations may limit or
prevent certain operations or substantially increase the
cost of operation of existing and future generating
installations, as well as seriously delay or increase the
cost of future construction. Such compliance may also
require substantial investments above those amounts stated
under "Construction Program and Financing", page 5.
All existing Company facilities have operating permits
from the Indiana Air Board. In order to secure approval for
these permits, the Company has installed electrostatic
precipitators on all coal-fired units and is operating flue
gas desulfurization (FGD) units to remove sulfur dioxide
from the flue gas at its A. B. Brown Units 1 and 2
generating facilities. The FGD units at the Brown Station
remove most of the sulfur dioxide from the flue gas
emissions by way of a scrubbing process, thereby allowing
the Company to burn high sulfur southern Indiana coal at the
station.
Under the Federal Clean Air Act (the Act), states are
authorized to adopt implementation plans to fulfill the
requirements of the Act. These state plans are subject to
approval by the U. S. Environmental Protection Agency (EPA).
In 1972, Indiana adopted stringent regulations which
comprise the State Implementation Plan (SIP) for attaining
ambient air standards for particulates, sulfur dioxide and
nitrogen oxides. The EPA approved that part of the SIP
which sets forth emission standards, fixes time schedules
for compliance with such standards and designates air
quality regions for the State. The SIP was revised in 1979
to reflect revision of the Act and the State submitted the
revised plan to the EPA for approval. On August 10, 1986,
the Sierra Club filed a lawsuit against the EPA under Civil
No. NA86-194-C seeking declaratory and injunctive relief to
compel the EPA to take action pursuant to the Act to reduce
sulfur dioxide emissions from power plants in Indiana
including the Company's Warrick Unit 4 and Culley Generating
Station. In settlement of this suit, the EPA agreed that
there would be a SIP for the State by November 1988. The
EPA gave final approval on December 16, 1988 to the Warrick
County sulfur dioxide emission limits which had been
8
approved by the Indiana Air Pollution Control Board. The
ruling provided for the reduction of sulfur dioxide
emissions from the two Warrick County generating stations,
Warrick and Culley, to take place in two phases. The first
reduction, required by December 31, 1989, provided that
sulfur dioxide emissions from all units at both stations be
reduced to 5.41 lb/MMBTU from 6.00 lb/MMBTU. Under the
second phase, which was effective August 1, 1991, sulfur
dioxide emissions from Culley Units 1 and 2 had to be
decreased to 2.79 lb/MMBTU, Culley Unit 3 was allowed to
remain at 5.41 lb/MMBTU, and emissions from all units at the
Warrick Generating Station had to be reduced to 5.11
lb/MMBTU. The Company is currently in compliance with these
provisions.
In October 1990, the U.S. Congress adopted major
revisions to the Act. The revisions impose significant
restrictions on future emissions of sulfur dioxide (SO2) and
nitrogen oxide (NOX) from coal-burning electric generating
facilities, including those owned and operated by the
Company. The legislation severely affects electric
utilities, especially those in the Midwest. Two of the
Company's principal coal-fired facilities (A. B. Brown Units
1 and 2, totaling 500 megawatts of capacity) are presently
equipped with sulfur dioxide removal equipment (scrubbers)
and are not expected to be severely affected by the new
legislation. However, 523 megawatts of the Company's coal-
fired generating capacity will be significantly impacted by
the lower emission requirements. The Company will be
required to reduce total emissions from Culley Unit 3 (250
megawatts), Warrick Unit 4 (135 megawatts) and Culley Unit 2
(92 megawatts) by approximately 50% to 2.5 lb/MMBTU by
January 1995 (Phase I) and to 1.2 lb/MMBTU by January 2000
(Phase II). In addition, Unit 1 at Culley Station (46
megawatts) is also subject to the 1.2 lb/MMBTU restriction
by January 2000. The legislation includes various
incentives to promote the installation of scrubbers on units
affected by the 1995 deadline. Current regulatory policy
allows for the recovery through rates of all authorized and
approved pollution control expenditures.
(Refer to "Clean Air Act" in Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION, page 18 of this report, for discussion
of the Company's Clean Air Act Compliance Plan, which was
filed with the IURC on January 3, 1992 and approved October
14, 1992, and the associated estimated costs.)
In connection with the use of sulfur dioxide removal
equipment at the A. B. Brown Generating Station, the Company
operates a solid waste landfill for the disposal of
approximately 200,000 tons of residue per year from the
scrubbing process. Renewal of the landfill operating permit
was granted in March 1992 by the Indiana Department of
Environmental Management (IDEM). The permit expires in
January 1997. Additionally, IDEM granted the Company's
request for modification (expansion) of the landfill,
issuing the construction permit in March 1992.
Under the Federal Water Pollution Control Act of 1972
and Indiana law and regulations, the Company is required to
obtain permits to discharge effluents from its existing
generating stations into the navigable waterways of the
United States. The State of Indiana has received
authorization from the EPA to administer the Federal
discharge permits program in Indiana. Variances from
effluent limitations may be granted by permit on a plant-by-
plant basis where the utility can establish the limitations
are not necessary to assure the protection of aquatic life
and wildlife in and on the body of water into which the
discharge is to be made. The Company has been granted
National Pollution Discharge Elimination System (NPDES)
permits covering miscellaneous waste water and thermal
discharges for all its generating facilities to which the
NPDES is applicable, namely the Culley Station, A. B. Brown
Station and Warrick Unit 4. Such discharge permits are
limited in time and must be renewed at five-year intervals.
During 1989, the Company was granted renewed five-year
permits for effluent discharge for such generating
facilities, which are required to be renewed again in 1994.
At present there are no known enforcement proceedings
concerning water quality pending or threatened against the
Company.
9
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.
Age at Positions Held During
Name 12/31/93 Past Five Years Dates
R. G. Reherman 58 Chairman of the Board of Directors,
President and Chief Executive
Officer 03-24-92 - Present
President, Chief Executive Officer
and Director 04-01-90 - 03-24-92
President, Chief Operating Officer
and Director * - 04-01-90
A.E.Goebel 46 Senior Vice President, Chief Financial
Officer, Secretary and Treasurer 02-21-89 - Present
Vice President, Secretary and
Treasurer * - 02-21-89
J.G.Hurst 50 Senior Vice President and General Manager
of Operations 03-01-92 - Present
Vice President, Gas and Warrick
Operations 01-01-89 - 03-01-92
G.M.McManus 46 Vice President and Director of Governmental
and Public Relations 03-01-92 - Present
Director of Governmental Affairs 12-01-89 - 03-01-92
J.W.Picking 62 Vice President and Director of Gas
Operations 03-01-92 - Present
Director of Gas Operations 01-01-89 - 03-01-92
<FN>
* Indicates positions held at least since 1989.
Item 2. PROPERTIES
The Company's installed generating capacity as of
December 31, 1993 was rated at 1,238,000 Kw. The Company's
coal-fired generating facilities are: the Brown Station
with 500,000 Kw of capacity, located in Posey County about
eight miles east of Mt. Vernon, Indiana; the Culley Station
with 388,000 Kw of capacity, and Warrick Unit 4 with
135,000 Kw of capacity. Both the Culley and Warrick
Stations are located in Warrick County near Yankeetown,
Indiana. The Company's gas-fired turbine peaking units are:
the 80,000 Kw Brown Gas Turbine located at the Brown
Station; two Broadway Gas Turbines located in Evansville,
Vanderburgh County, Indiana, with a combined capacity of
115,000 Kw; and, two Northeast Gas Turbines located
northeast of Evansville in Vanderburgh County, Indiana with
a combined capacity of 20,000 Kw. The Brown and Broadway
turbines are also equipped to burn oil. Total capacity of
the Company's five gas turbines is 215,000 Kw and are
generally used only for reserve, peaking or emergency
purposes due to the higher per unit cost of generation.
The Company's transmission system consists of 871
circuit miles of 138,000, 69,000 and 36,000 volt lines. The
transmission system also includes 26 substations with an
installed capacity of 3,874,724 kilovolt amperes (Kva). The
electric distribution system includes 3,177 pole miles of
lower voltage overhead lines and 180 trench miles of conduit
containing 987 miles of underground distribution cable. The
distribution system also includes 86 distribution
substations with an installed capacity of 1,306,508 Kva and
45,057 distribution transformers with an installed capacity
of 1,771,152 Kva.
The Company owns and operates three underground gas
storage fields with an estimated ready delivery from storage
capability of 3.9 million Dth of gas. The Oliver Field, in
service since 1954, is located in Posey County, Indiana,
about 13 miles west of Evansville. The Midway Field is
located in Spencer County, Indiana, about 20 miles east
10
of Evansville near Richland, Indiana, and was placed in
service in December 1966. The third field is the Monroe
City Field, located in Knox County, about 10 miles east of
Vincennes, Indiana. The field was placed in service in
1958.
The Company's gas transmission system includes 324
miles of transmission mains, and the gas distribution system
includes 2,196 miles of distribution mains.
The Company's properties, but not those of its
subsidiary, are subject to the lien of the First Mortgage
Indenture dated as of April 1, 1932 between the Company and
Bankers Trust Company, New York, as Trustee, as supplemented
by various supplemental indentures, all of which are
exhibits to this report and collectively referred to as the
"Mortgage".
Item 3. LEGAL PROCEEDINGS.
On January 27, 1993, a coal supplier filed a complaint
in the Federal District Court for the Southern District of
Indiana alleging that the Company breached a coal supply
contract between the Company and that supplier. The Company
had notified the supplier that it would not require any
delivery of coal under the contract for at least some part
of 1993. The supplier claims that this action violates
certain minimum purchase requirements imposed by the
contract, and asked the court to require specific
performance of the contract by the Company and for
unspecified monetary damages. The complaint alleges that
the Company is obligated to purchase coal at a minimum rate
of 50,000 tons per month under the contract and at any event
to purchase all of the coal consumed at the Company's A. B.
Brown generating plant below 1,000,000 tons per year. The
contested contract may run until December 31, 1998. The
Company filed counterclaims and disputes that its actions
have violated the terms of the contract. On March 26, 1993,
the Company and the coal supplier agreed to resume coal
shipments but with the invoiced price per ton substantially
lower than the contract price and subject to final outcome
of the litigation. (Refer to "Rate and Regulatory Matters"
in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS
OF OPERATIONS AND FINANCIAL CONDITION, page 15 of this
report, for discussion of the pricing of this coal to
inventory and the associated ratemaking treatment.) On June
6, 1993, the coal supplier won a summary judgement to
require the Company to take a minimum of 600,000 tons
annually, more or less in equal weekly shipments. The
decision cannot be appealed until resolution of other
contract provisions still before the court.
There are no other pending legal proceedings, other
than ordinary routine litigation incidental to the business,
to which the registrant is a party.
No material legal proceedings were terminated during
the fourth quarter of 1993.
Item 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
None
PART II
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:
QUARTERLY PERIOD
1 2 3 4
High Low High Low High Low High Low
1993 $34-3/4 $32-3/4 $34-7/8 $32-3/8 $34-3/8 $33 $35-1/2 $31-7/8
1992<F1> $33.84 $30.47 $32-1/8 $30-3/8 $32-3/4 $31-1/8 $34-1/8 $31-3/4
As of February 4, 1994 there were 9,445 holders of
record of Common Stock.
11
Dividends declared and paid per share of Common Stock
during the past two years were:
QUARTERLY PERIOD
1 2 3 4
1993 $0.4025 $0.4025 $0.4025 $0.4025
1992 <F1> $0.39 $0.39 $0.39 $0.39
<FN>
<F1> Stock prices and dividends per share for the first
quarter of 1992 have been restated to reflect the four-for-
three stock split effective March 30, 1992.
The quarterly dividend on Common Stock was increased to
41-1/4 cents per share in January 1994, payable March 21, 1994.
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, 1993, 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, 1993 under this restriction was $2,209,642,
leaving $201,848,514 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, 1993, such ratio amounted to
approximately 47%.
Item 6. SELECTED FINANCIAL DATA
For The Years Ended December 31,
1993 1992 1991 1990 1989
(in thousands except per share data)
Operating Revenues $328,521 $305,947 $322,582 $322,520 $311,542
Operating Income $ 51,642 $ 50,919 $ 53,156 $ 51,934 $ 51,600
Net Income $ 39,653 $ 36,767 $ 38,513 $ 37,691 $ 36,216
Net Income Applicable
to Common Stock $ 38,548 $ 35,500 $ 37,232 $ 36,409 $ 34,931
Average Common Shares
Outstanding 15,705 15,705 15,705 16,096 16,588
Earnings Per Share
of Common Stock $ 2.45 $ 2.26 $ 2.37 $ 2.26 $ 2.11
Dividends Per Share
of Common Stock $ 1.61 $ 1.56 $ 1.50 $ 1.43 $ 1.35
Total Assets $860,023 $761,281 $747,445 $738,803 $721,059
Redeemable Preferred
Stock $ 8,515 $ 8,515 $ 1,100 $ 1,110 $ 1,110
Long-Term Obligations $274,884 $213,026 $236,844 $257,022 $219,682
12
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS
AND FINANCIAL CONDITION
Earnings per share of $2.45 in 1993 were the highest in
Company history, following 1992 earnings of $2.26. The
record 1993 earnings exceeded the previous all-time high of
$2.37 in 1991 by 3%.
The 1993 earnings were favorably impacted by higher
operating revenues due to weather-related increases in
retail gas and electric sales. Greater maintenance and
nonfuel-related operating expenses and fewer sales to
wholesale electric customers partially offset the impact of
the higher retail sales. Increased allowance for funds used
during construction resulting from the Company's expanded
construction program also contributed to the higher
earnings.
For the thirty-fifth consecutive year, the Board of
Directors declared a dividend increase to common
shareholders at its January 1994 meeting. Payable in March
1994, the Company's new quarterly dividend is 41-1/4cents
per share, increasing the indicated annual rate to $1.65 per
share.
ELECTRIC OPERATIONS.
The table below compares changes in operating revenues,
operating expenses, and electric sales between 1993 and 1992,
and between 1992 and 1991, in summary form.
Increase
CHANGES IN ELECTRIC OPERATING INCOME (Decrease)
1993 1992
in thousands)
Operating Revenues - System $17,586 $(12,909)
- Nonsystem (2,258) (7,901)
15,328 (20,810)
Operating Expenses:
Fuel for electric generation (159) (8,815)
Purchased electric energy 6,434 (2,739)
Other operation 2,274 (1,180)
Maintenance 3,967 (4,538)
Depreciation and amortization 695 (793)
Federal and state income taxes 1,921 (1,824)
Property and other taxes (707) 1,236
_______ ________
14,425 (18,653)
Changes in electric operating income $ 903 $ (2,157)
CHANGES IN ELECTRIC SALES - MWh:
System 319,114 (133,795)
Nonsystem (82,600) 369,189)
________ _________
236,514 (502,984)
Higher weather-related sales to the Company's retail
customers was the primary reason for the 6.3% ($15.3
million) rise in electric operating revenues. Effective
October 1, 1993, the Company implemented the first step
(about 1% overall) of a three-step increase in its base
electric rates to recover the cost of complying with the
Clean Air Act Amendments of 1990 (see "Rate and Regulatory
Matters"), however, the rate increase had little impact on
electric revenues during 1993. In 1992, operating revenues
declined 7.9% ($20.8 million) due to fewer sales to retail
and wholesale customers.
Cooler winter weather and much warmer summer temperatures,
when cooling degree days were 30% greater than the prior
year and about 17% above normal, were responsible for the
12.1% and 6.3% increases in residential and commercial
sales, respectively. Following flat sales in 1992,
industrial sales rose 5.7% during the current year due to
increased manufacturing activity. Total system sales were
up 7.6% over 1992. The Company experienced a 3.1% overall
decline in system sales in 1992 when cooling degree days
were down 30%.
During 1993, the Company's electric customer base grew by
1,276, or 1%, totaling 118,163 at year end.
13
In addition to greater system sales, 1993 system revenues
increased approximately $2.7 million due to the recovery of
higher unit fuel costs (see subsequent discussion of changes
in the cost of fuel for electric generation), following a
$4.7 million reduction in electric revenues in 1992 due to
lower unit costs. Changes in the cost of fuel for electric
generation and purchased power are reflected in customer
rates through commission approved fuel cost adjustments.
Because of the current worldwide oversupply of primary
aluminum and softening demand for rolled can sheet aluminum
in the United States, the Aluminum Company of America
(Alcoa) shut down several older potlines at various
manufacturing facilities. Alcoa Generating Corporation
(AGC), a wholly-owned subsidiary of Alcoa, provides the
energy requirements for five potlines at Alcoa's Warrick
County, Indiana facility from its Warrick Generating
Station. Since 1987, the Company has provided electric
energy to AGC (a wholesale customer) for a sixth potline.
On July 20,1993, Alcoa shut down the oldest of the six
potlines at the Warrick County manufacturing operation. The
Company estimates that the decline in electric sales related
to the potline for 1993 represented approximately $4.8
million in nonsystem revenues and approximately $.8 million
in operating income compared to the prior year. Greater
sales to other nonsystem customers, due in part to the
region's warmer summer temperatures, partially offset the
decline in sales to AGC. Total nonsystem sales by the
Company declined 8.3% during the year. On an annual basis,
the decline in revenue related to the reduced sales to AGC
is estimated at $14.4 million with a corresponding $2.4
million decline in operating income. The Company
anticipates that a portion of the decline in operating
income will be offset in the future by increases in sales to
other nonsystem customers made possible by the reduced
commitment to AGC. Most sales to nonsystem customers,
including AGC, are on an "as available" basis under
interchange agreements which provide for significantly lower
margins than sales to system customers.
Due to the much warmer summer temperatures, and to the
increased demand by industrial customers, a new all-time
peak load obligation of 1,100 megawatts was reached on July
28, 1993. The previous record peak, 1,054 megawatts, was
set in 1988. The 1992 peak of 992 megawatts was held down
by the unseasonably cool summer weather. The Company's
total generating capacity at the time of the 1993 peak was
1,238 megawatts, representing an 11% capacity margin.
Fuel for electric generation, the most significant electric
operating cost, was comparable to 1992. Slightly (2.8%)
higher costs of coal per MMBtu consumed due to less
favorable volume-related pricing, higher average per unit
mine production costs, and the amortized cost of the buyout
of one of the Company's long-term coal contracts (see "Rate
and Regulatory Matters"), were offset by a decline in
generation. The Company continues to pursue further
reductions in coal prices as a key component of its strategy
to remain a low-cost provider of electricity. The decline
in 1992 fuel cost reflected a 6.2% decrease in generation
and a lower average cost of coal consumed.
The greater energy requirements of the Company's customers
and favorably priced power were the primary reasons for the
increased purchases of electricity from other utilities, up
substantially (220%) during 1993. Purchased electric energy
costs decreased 48% in 1992 due to fewer purchases and lower
average rates paid for such power.
After a 4.1% decrease in 1992, other operation expenditures
rose 8.2% ($2.3 million) during the current year chiefly due
to increased provisions for injuries and damages, consulting
and legal expenditures related to a coal contract buyout
(see "Rate and Regulatory Matters") and ongoing coal
contract negotiations and litigation, and increases in
various administrative and general costs.
Greater production plant maintenance activity was the
primary reason for the 20% ($4 million) increase in electric
maintenance expense. The Company performed a scheduled
major turbine generator overhaul on A.B. Brown Unit 2 during
the year and completed a major overhaul on the Culley Unit 1
turbine generator begun in late 1992. The Culley Unit 1
turbine generator overhaul was the only major maintenance
project during 1992, when electric maintenance expenditures
were down $4.5 million.
Depreciation and amortization expense increased slightly in
1993 reflecting normal additions to utility plant and the
completion of the warehouse and operations building at the
Company's new Norman P. Wagner Operations Center. A decline
in depreciation and amortization occurred in 1992 when
amortization provisions related to the deferred return on
the phasein of A. B. Brown Unit 2 expired.
While inflation has a significant impact on the replacement
cost of the Company's facilities, under the rate-making
principles followed by the Indiana Utility Regulatory
Commission (IURC), under whose regulatory jurisdiction the
Company is subject, only the historical cost of electric and
gas plant investment is recoverable in revenues as
14
depreciation. With the exception of adjustments for changes
in fuel and gas costs and margin on sales lost under the
Company's demand side management programs (see "Demand Side
Management"), the Company's electric and gas rates remain
unchanged until a rate application is filed and a general
rate order is issued by the IURC.
In addition to the impact of higher 1993 pretax income on
income tax expense, the Company provided approximately $.5
million of additional federal income tax expense to reflect
the higher tax rates enacted under the Omnibus Budget
Reconciliation Act of 1993. (See Note1 of the Notes to
Consolidated Financial Statements for further discussion.)
Decreased income tax expense in 1992 was chiefly
attributable to lower pretax income. The decrease in taxes
other than income taxes during the current year resulted
from a 1992 increase in property tax expense reflecting the
general reassessment of the Company's property.
GAS OPERATIONS.
The following table compares changes in operating revenues,
operating expenses, and gas sold and transported between 1993
and 1992, and between 1992 and 1991, in summary form.
Increase
CHANGES IN GAS OPERATING INCOME (Decrease)
1993 1992
(in thousands)
Operating Revenues - Sales $7,068 $4,621
- Transportation 178 (446)
7,246
4,175
Operating Expenses:
Cost of gas sold 4,482 5,369
Other operation 2,314 (146)
Maintenance 741 (632)
Depreciation 31 211
Federal and state income taxes (86) (1,083)
Property and other taxes (56) 536
7,426 4,255
Changes in gas operating income $ (180) $ (80)
CHANGES IN GAS SOLD AND TRANSPORTED - MDth:
Sold 889 818
Transported 1,874 26
______ ______
2,763 844
Greater sales of natural gas and higher gas costs recovered
through retail rates led to an 11.5% ($7.2 million) increase
in gas operating revenues. Effective August 1, the Company
implemented the first step (about 4% overall) of a two-step
increase in its base gas rates (see "Rate and Regulatory
Matters"), however, the impact on gas revenues during 1993
was not significant.
A 5.6% rise in the Company's gas sales in 1993 reflected
increased sales to residential and commercial customers, up
12.8% and 10.2%, respectively. Although heating degree days
during the period were about normal, they were 10% greater
than those recorded in 1992. Deliveries to industrial
customers under the Company's sales and transportation
tariffs were up 7.6%, reflecting the increased manufacturing
activity of several of the Company's largest industrial
customers. In 1992, residential sales were flat and
commercial sales were up only 3.1% due to milder winter
weather; industrial sales and transportation volumes
increased 6.7% during the same period.
During 1993, 1,402 new gas customers were added to the
Company's system, raising the year end total 1.4% to
100,398.
On December 23, 1993, the Company entered into a definitive
agreement to acquire Lincoln Natural Gas, a small gas
distribution company of approximately 1,300 customers
contiguous to the eastern boundary of the Company's gas
15
service territory. The acquisition is expected to be
completed by mid-1994, subject to necessary regulatory and
shareholder approvals.
The recovery of higher unit gas costs, up 6.1%, through
retail rates in 1993 raised revenues $2.7 million following
a $1.3 million increase in revenues related to the recovery
of higher unit costs in the prior year. During the past two
years, the market for purchase of natural gas supply has
been very volatile with the average price ranging from a low
of $1.34 per Dth in February 1992 to the peak of $2.58 per
Dth in May 1993. Prices have declined somewhat since May
but remain above the February low reflecting a general
tightening of the balance between available supply and
demand after several years of excess supply. Changes in the
cost of gas sold are passed on to customers through IURC
approved gas cost adjustments.
Cost of gas sold, the major component of gas operating
expenses, was up 9.7% ($4.5 million) in 1993, following a
13.2% ($5.4 million) increase in 1992. The higher costs in
both 1993 and 1992 reflected the increased deliveries to
customers and higher unit costs.
Although the Company's primary pipeline supplier, Texas Gas
Transmission Corporation (TGTC), implemented revised tariffs
November 1, 1993 to reflect certain changes required by
Federal Energy Regulatory Commission (FERC) Order 636, the
Company's 1993 purchased gas costs were relatively
unaffected by the new tariffs. As of November 1,1993, TGTC
ceased to be a supplier of natural gas to the Company, and
the Company assumed full responsibility for the purchase of
all its natural gas supplies. (See "Rate and Regulatory
Matters" for further discussion of FERC Order No. 636 and of
the impact on future purchased gas costs and procurement
practices of the Company.)
Other operation and maintenance expenses were 31% ($3.1
million) greater than the prior year due to increased
provisions for injuries and damages (see "Environmental
Matters" for discussion of the Company's investigation of
the possible existence of facilities utilized for the
manufacture of gas), abnormally low distribution maintenance
expenses in 1992, and increases in various administrative
and general costs.
Depreciation expense for 1993 and 1992 reflected increased
gas plant additions during the past several years due to new
business requirements and various improvements made to the
distribution system. Partially offsetting the impact of
increased gas plant additions were lower depreciation rates
implemented during 1993 as a result of the Company's recent
gas rate case.
Income tax expense for the current year was comparable to
1992, following a substantial decrease in income tax expense
in 1992 resulting from lower pretax operating income.
OTHER INCOME AND INTEREST CHARGES.
Other income was $2.5million greater during 1993 due to
increased allowance for equity funds used during construction,
resulting primarily from the construction of the Company's
new sulfur dioxide scrubber. (See "Clean Air Act" for further
discussion.) Following a significant increase in nonutility
income in 1991, nonutility income declined in 1992. The
decline was largely due to lower fees from AGC for operation
of its Warrick Generating Station.
Interest expense during the current year was relatively
unchanged. The impact of an additional $45 million of long-
term debt issued during the second quarter was offset by
savings from refinancing $105 million of long-term debt in
the second quarter, which reduced annual interest expense by
$1 million, and by additional interest capitalized due to
the increased construction program.
RATE AND REGULATORY MATTERS.
In November 1992, the Company petitioned the IURC requesting
a general increase in gas rates, the first such adjustment
since 1982. On July 21,1993, the IURC approved an overall
increase of approximately 8%, or $5.5 million in revenues,
in the Company's base gas rates. The increase is to be
implemented in two equal steps. The first step of the rate
adjustment, approximately 4%, took place August 1, 1993; the
second step will become effective August 1, 1994.
16
In addition to seeking relief for rising operating and
maintenance costs and substantial investment in utility
plant over the past decade, the Company sought to
restructure its tariffs, make available additional services,
and "unbundle" existing services to better serve its gas
customers and strategically position itself to address the
changes brought about by the continued deregulation of the
natural gas industry. (See subsequent discussion of FERC
Order No. 636 in this section.)
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its
investment through March 31, 1993 in the Clean Air Act
Compliance project presently being constructed at the Culley
Generating Station. The majority of the costs are for the
installation of a sulfur dioxide scrubber on Culley Units 2
and 3. (See "Clean Air Act" for further discussion of the
project and previous approval of ratemaking treatment of the
incurred costs.) On September 15,1993, the IURC granted the
Company's request for a 1% revenue increase, approximately
$1.8 million on an annual basis, which took effect October
1, 1993. The Company anticipates petitioning the IURC in
February 1994 for a 2-3% increase for financing costs
related to the project construction expenditures incurred
since April 1,1993, with implementation of the new rates
effective mid-1994.
On December 22, 1993, the Company filed a request with the
IURC for the third of the three planned general electric
rate increases. This final adjustment, expected to occur in
early 1995, is estimated to be 6-9% and is necessary to
recover financing costs related to the balance of the
project construction expenditures, costs related to the
operation of the scrubber, and certain nonscrubber-related
costs such as additional costs incurred for postretirement
benefits other than pensions beginning in 1993 and the
recovery of demand side management program expenditures (see
"Demand Side Management").
Over the past several years, the Company has been actively
involved in intensive contract negotiations and legal
actions to reduce its coal costs and thereby lower its
electric rates. During 1992, the Company was successful in
negotiating a new coal supply contract with one of its major
coal suppliers. The new agreement, effective through 1995,
was retroactive to 1991. Included in the agreement was a
provision whereby the contract could be reopened by the
Company for modification of certain coal specifications. In
early 1993, the Company reopened the contract for such
modifications. In response, the coal supplier elected to
terminate the contract enabling the Company to buy out the
remainder of its contractual obligations and acquire lower
priced spot market coal. The cost of the contract buyout in
1993, which was based on estimated tons of coal to be
consumed during the agreement period, and related legal and
consulting services, totaled approximately $18 million. The
Company anticipates that $2 million in additional buyout
costs for actual tons of coal consumed above the previously
estimated amount may be incurred during the 1994-1995
period. On September 22, 1993, the IURC approved the
Company's request to amortize all buyout costs to coal
inventory during the period July 1,1993 through December 31,
1995 and to recover such costs through the fuel adjustment
clause beginning February 1994.
The Company estimates the savings in coal costs during the
1991-1995 period, net of the total buyout costs, will
approximate $56 million. The net savings are being passed
back to the Company's electric customers through the fuel
adjustment clause.
The Company is currently in litigation with another coal
supplier in an attempt to restructure an existing contract.
Under the terms of the original contract, the Company was
allegedly obligated to take 600,000 tons of coal annually.
In early 1993, the Company informed the supplier that it
would not require shipments under the contract until later
in 1993. On March 26, 1993, the Company and the supplier
agreed to resume coal shipments under the terms of their
original contract except the invoiced price per ton would be
substantially lower than the contract price. As approved by
the IURC, the Company has charged the full contract price to
coal inventory for subsequent recovery through the fuel
adjustment clause. The difference between the contract
price and the invoice price has been deposited in an escrow
account with an offsetting accrued liability which will be
paid either to the Company's ratepayers or its coal supplier
upon settlement of the litigation. The escrowed amount was
$8,749,000 at December 31, 1993. This litigation is
scheduled for trial in June of 1994. Since the litigation
arose due to the Company's efforts to reduce fuel costs,
management believes that any related costs should be
recoverable through the regulatory ratemaking process.
In late 1993, in a further effort to reduce coal costs, the
Company and the supplier entered into a letter agreement,
effective January 1, 1994, and until the litigation is
settled, whereby the Company will purchase an additional
50,000 tons monthly above the alleged base requirements at a
price lower than the original contract price for tons over
50,000 per month.
In April 1992, the Federal Energy Regulatory Commission
(FERC) issued Order No. 636 (the Order) which required
interstate pipelines to restructure their services. In
August 1992, the FERC issued Order No. 636-A which
17
substantially reaffirmed the content of the original Order.
Under the Order, the stated purpose of which is to improve
the competitive structure of the natural gas pipeline
industry, existing pipeline sales service was "unbundled" so
that gas supplies are sold separately from interstate
transportation services. This restructuring has occurred
through tariff filings by pipelines after negotiations with
their customers. Customers, such as the Company and
ultimately its gas customers, could benefit from enhanced
access to competitively priced gas supplies as well as from
more flexible transportation services. Conversely, customer
costs will rise because the Order requires pipelines to
implement new rate design methods which shift additional
demand-related costs to firm customers; additionally, the
FERC has authorized the pipelines to seek recovery of
certain "transition" costs associated with restructuring
from their customers.
On November 2, 1992, the Company's major pipeline supplier,
Texas Gas Transmission Corporation (TGTC), filed a recovery
implementation plan with the FERC as part of its revised
compliance filing regarding the Order. On October 1, 1993,
the FERC accepted, subject to certain conditions, the TGTC
recovery implementation plan (the Plan). The Plan, which
addresses numerous issues related to the implementation of
the requirements of the Order, became effective November 1,
1993. Under new TGTC transportation tariffs, which reflect
the Plan's provisions, the Company will incur additional
annual demand-related charges of approximately $1.9 million.
Savings from lower volume-related transportation costs will
partially offset the additional charges. TGTC has not yet
determined the Company's allocation of transition costs,
however, an estimate of such costs and implementation of
revised TGTC tariffs to recover such costs are expected
during the first quarter of 1994. Due to the anticipated
regulatory treatment at the state level, the Company does
not expect the Order to have a detrimental effect on its
financial condition or results of operations.
ENVIRONMENTAL MATTERS.
The Company is currently investigating the possible
existence of facilities once owned and operated by the
Company, its predecessors, previous landowners, or former
affiliates of the Company utilized for the manufacture of
gas.
These facilities, if they existed, would have been operated
from the 1850's through the early 1950's under industry
standards then in effect. Operations at these facilities
would have ceased many years ago. However, due to current
environmental regulations, the Company and other responsible
parties may be required to take remedial action if certain
materials are found at the sites of these former facilities.
The Company has just recently initiated its investigation,
and preliminary assessments have not yet been performed on
any sites. However, based on its research, the Company has
identified the existence and general location of four sites
at which contamination may be present. The Company intends
to perform preliminary assessments of all four sites during
1994 and, more than likely, will perform comprehensive
investigations of some, or all, of these sites to determine
if remedial action is required and to estimate the extent of
such action and the associated costs.
The Company has notified all known insurance carriers
providing coverage during the probable period of operation
of these facilities of potential claims for coverage of
environmental costs. The Company has not, however, recorded
any receivables representing future recovery from insurance
carriers. Additionally, the Company is attempting to
identify all potentially responsible parties for each site.
The Company has not been named a potentially responsible
party by the Environmental Protection Agency for any of
these sites.
While the Company intends to seek recovery from other
responsible parties or insurance carriers, the Company does
not presently anticipate seeking recovery of these
investigation costs from its ratepayers. Therefore, the
Company has expensed the $.5 million of anticipated cost of
performing preliminary site assessments and the more
comprehensive specific site investigations of all four
sites. If, however, the specific site investigations
indicate that significant remedial action is required, the
Company will seek recovery of all related costs in excess of
amounts recovered from other potentially responsible parties
or insurance carriers through rates.
Although the IURC has not yet ruled on a pending request for
rate recovery by another Indiana utility of such
environmental costs, the IURC did grant that utility
authority to utilize deferred accounting for such costs
until the IURC rules on the request.
18
NATIONAL ENERGY POLICY ACT OF 1992.
In late 1992, the National Energy Policy Act of 1992 (the
Act) was signed into law, enacting the first comprehensive
energy legislation since the National Energy Act of 1978.
Key provisions contained in the Act, specifically Title VII
(Electricity), are expected to cause some of the most
significant changes in the history of the electric industry.
The primary purpose of Title VII is to increase competition
in electric generation by enabling virtually nonregulated
entities, such as exempt wholesale generators, to develop
power plants, and by providing the FERC authority to require
a utility to provide transmission services, including the
expansion of the utility's transmission facilities necessary
to provide such services, to any entity generating
electricity. Although the FERC may not order retail
wheeling, the transmission of electricity directly to an
ultimate consumer, it may order wheeling of electricity
generated by an exempt wholesale generator or another
utility to a wholesale customer of a regulated utility.
The changes brought about by the Act may require, or provide
opportunities for, the Company to compete with other
utilities and wholesale generators for sales to existing
wholesale customers of the Company and other potential
wholesale customers. The Company has long-term contracts
with its five wholesale customers which mitigate the
opportunity for other generators to provide service to them.
Many observers of the electric utility industry, including
major credit rating agencies, certain financial analysts,
and some industry executives, have expressed an opinion that
retail wheeling to large retail customers and other elements
of a more competitive business environment will occur in the
electric utility industry, similar to developments in the
telecommunications and natural gas industries. The timing
of these projected developments is uncertain. In addition,
the FERC has adopted a position, generically and on a case-
by-case basis, that it will pursue a more competitive, less
regulated, electric utility industry. Although the Company
is uncertain of the final outcome of these developments, it
is committed to pursuing, and is moving rapidly to
implement, its corporate strategy of positioning itself as a
low-cost energy producer and the provider of high quality
service to its retail as well as wholesale customers.
The Company already has some of the lowest per unit
administrative, operation, and maintenance costs in the
nation, and is continuing its efforts to further reduce its
coal costs (see previous discussion of coal contract
renegotiation in "Rates and Regulatory Matters").
CLEAN AIR ACT.
Revisions to federal clean air laws were enacted in 1990
which have a significant impact on all of American industry.
Electric utilities, especially in the Midwest, were severely
impacted by Title IV (acid rain provisions) of the Clean Air
Act Amendments of 1990.
Title IV mandates utilities to significantly reduce
emissions of sulfur dioxide (SO2) and nitrogen oxide (NOx)
from coal-burning electric generating facilities in two
steps. The Company is required to reduce annual emissions
of SO2 on a Company-wide basis by approximately 50% by 1995
(Phase I). By the year 2000 (PhaseII), the Company must
reduce emissions of SO2 by approximately 50% from the
allowed 1995 level. Since the Company's two newest coal-
fired generating units, A.B. Brown Units 1 and2 (500 MW
total), are equipped with SO2 removal equipment (scrubbers),
the impact of the law, although significant, is not as great
for the Company as for some other midwestern utilities.
To meet the Phase I requirements and nearly all of the Phase
II requirements, the Company's Clean Air Act Compliance Plan
(the Compliance Plan), which was developed as a least-cost
approach to compliance, proposed the installation of a
single scrubber at the Culley Generating Station to serve
both Culley Unit 2 (92MW) and Culley Unit 3 (250 MW) and the
installation of state of the art low NOx burners on these
two units.
In January 1992, the Company filed a petition with the IURC,
requesting preapproval of the Compliance Plan and proposing
recovery of financing costs to be incurred during the
construction period. In October 1992, the IURC approved a
stipulation and settlement agreement between the Company and
intervenors pertaining to the petition, which essentially
granted the request.
Construction of the facilities, originally projected to cost
approximately $115 million including the related allowance
for funds used during construction, began during 1992 with
completion and testing expected to occur in late 1994.
Construction costs are currently running under budget.
Commercial operation will begin about January 1, 1995 to
19
comply with requirements of the Clean Air Act Amendments of
1990. Under the settlement agreement, the maximum capital
cost of the compliance plan to be recovered from ratepayers
is capped at approximately $107 million, plus any related
allowance for funds used during construction. The estimated
cost to operate and maintain the facilities, including the
cost of chemicals to be used in the process, is $4-6 million
per year, beginning in 1995.
By installing a scrubber, the Company was entitled to apply
for extra allowances, called "extension allowances", to the
federal EPA. However, because utilities applied for more
extension allowances than the Act made available, the
federal EPA established a lottery procedure to determine
which utilities would actually receive the extension
allowances. In order to ensure receipt of a majority of the
extension allowances, the Company, and nearly all of the
other applying utilities, formed an allowance pooling group.
As a result, the Company will receive about 88,000 extension
allowances, which it has sold to another party under a
confidential agreement. The Company will credit the
proceeds to customers over 1995-1999, reducing the rate
impact of the Compliance Plan.
With the addition of the scrubber, the Company expects to
exceed the minimum compliance requirements of Phase I of the
Clean Air Act and have available unused allowances, called
"overcompliance allowances", for sale to others. Proceeds
from sales of overcompliance allowances will also be passed
through to customers.
The scrubbing process utilized by the Culley scrubber
produces a salable by-product, gypsum, a substance commonly
used in wallboard and other products. In December 1993, the
Company finalized negotiations for the sale of an estimated
150,000 to 200,000 tons annually of gypsum to a major
manufacturer of wallboard. The agreement will enable the
Company to reduce certain operating costs and to credit
ratepayers with the proceeds from the sale of the gypsum,
further mitigating the rate impact of the Compliance Plan.
The rate impact related to the Compliance Plan, estimated to
be 7-10%, is being phased in over a three year period
beginning in October 1993. (See "Rate and Regulatory
Matters" for further discussion.)
DEMAND SIDE MANAGEMENT.
In October 1991, the IURC issued an order approving
expenditures by the Company for development and
implementation of demand side management (DSM) programs.
The primary purpose of the DSM programs is to reduce the
demand on the Company's generating capacity at the time of
system peak requirements, thereby postponing or avoiding the
addition of generating capacity. Thus, the order of the
IURC provided that the accounting and ratemaking treatment
of DSM program expenditures should generally parallel the
treatment of construction of new generating facilities.
Most of the DSM program expenditures are being capitalized
per the IURC order and will be amortized over a 15 year
period beginning at the time the Company reflects such costs
in its rates. The Company is requesting recovery of these
costs in its general electric rate increase request filed
December 22, 1993 (see "Rates and Regulatory Matters" for
further discussion). In addition to the recovery of DSM
program costs through base rate adjustments, the Company is
collecting, through a quarterly rate adjustment mechanism,
most of the margin on sales lost due to the implementation
of DSM programs.
The Company expects to incur costs of approximately $51
million on DSM programs during the 1994-1998 period. By
1998, approximately 108 megawatts of capacity are expected
to be postponed or eliminated due to these programs. Based
on the latest projections, the expenditures for DSM
programs, as approved by the IURC, will total an estimated
$195 million through the year 2012 and result in overall
savings of $160 million to ratepayers due to deferring the
construction of about 156 megawatts of new generating
capacity.
INTEGRATED RESOURCE PLAN.
In November 1993, the Company filed with the IURC a
biannual update to its Integrated Resource Plan (IRP),
including the DSM program expenditures referred to above.
The IRP process is a least-cost approach to determining the
combination of new generating facilities and conservation
and load management options that will best meet customers'
future energy needs.
20
The 1993 IRP update was the result of a nine month
evaluation of detailed technology costs, customer energy use
patterns, and market information, and includes natural gas
conservation options not in the initial 1991 IRP. If the
new IRP is approved by the IURC, the Company will implement
several new DSM programs recommended by the IRP, including a
residential weatherization pilot project. Supply side
options recommended by the IRP include strategies to
diversify the Company's natural gas suppliers, maximize the
use of economical purchased power during peak usage periods,
and expand the strategic use of the Company's gas storage
fields.
While the Company intends to aggressively utilize various
DSM programs to help delay the need for additional power
sources, the 1993 IRP forecasts the need of a 125 megawatt
base-load generating plant in the early 21st century to meet
the future electricity needs of the Company's customers.
POSTEMPLOYMENT BENEFITS.
In November 1992, the FASB issued SFAS No. 112,
"Employers' Accounting for Postemployment Benefits",
effective for years beginning after December 15, 1993, which
will require the Company to accrue the estimated cost of
benefits provided to former or inactive employees after
employment but before retirement age. Postemployment
benefits include, but are not limited to, salary
continuation, supplemental unemployment benefits, severance
benefits, disability-related benefits (including workers'
compensation), and continuation of benefits such as health
care and life insurance coverage. The Company will adopt
SFAS No. 112 on January 1, 1994. The impact of the new
statement will not have a material impact on financial
position or results of operations.
LIQUIDITY AND CAPITAL RESOURCES.
The Company experienced record earnings per share during
1993, and financial performance continued to be solid.
Internally generated cash, bolstered by the increased retail
sales, provided over 74% of the Company's construction and
DSM program expenditures, despite the requirements of the
Culley scrubber project. Earnings continued to be of high
quality, of which 11.4% represented allowance for funds used
during construction. The ratio of earnings to fixed charges
(SEC method) was 3.8:1, the embedded cost of long-term debt
is approximately 6.6%, and the Company's long-term debt
continues to be rated AA by major credit rating agencies.
The Company has access to outside capital markets and to
internal sources of funds that together should provide
sufficient resources to meet capital requirements. The
Company does not anticipate any changes that would
materially alter its current liquidity.
On April 30, 1993, the Company called $84.5 million of its
first mortgage bonds at a premium, plus accrued interest.
The bonds called were the 8% due 2001, the 8% due 2002, the
8.35% due 2007, the 9-1/4% due 2016, and the 8-5/8% due
2017. The bonds called, having a weighted average interest
rate of 8.5%, were refunded with two $45 million issues
carrying interest rates of 6% and 7.6%, due 1999 and 2023,
respectively.
On May 11, 1993, the Company issued two series of adjustable
rate first mortgage bonds in connection with the sale of
Warrick County, Indiana environmental improvement revenue
bonds. The proceeds of the bonds have been placed in trust
and are being used to finance a portion of the Culley
scrubber project. The first series of bonds was for $22.2
million due 2028, the interest rate of which is fixed at
4.65% through April 30, 1998. The second series of bonds
was for $22.8 million due 2023; the interest rate of this
series is fixed at 6% through maturity.
On June 15, 1993, the Company retired $20 million of 8.50%
first mortgage bonds maturing in June of 1993 with $20
million of 7-5/8% first mortgage bonds due 2025.
The only financing activity during 1992 was in December when
the Company called 75,000 shares of 8.75% series cumulative
preferred stock at $102 per share, plus accrued dividends,
with the issuance of 75,000 shares of 6.50% series
redeemable cumulative preferred stock, at $100 per share.
During the five year period 1994-1998, the Company
anticipates that a total of $47.7 million of debt securities
will be redeemed.
21
Construction expenditures, including $4.5 million for DSM
programs, totaled $80.1 million during 1993, compared to the
$52.1 million expended in 1992. As discussed in "Clean Air
Act", construction of the new scrubber continued in 1993,
requiring $49.2 million. The remainder of the 1993
construction expenditures consisted of the normal
replacements and improvements to gas and electric
facilities.
The Company expects that construction requirements for the
years 1994-1998 will total approximately $270 million.
Included in this amount is approximately $44 million to
comply with the Clean Air Act amendments by 1995 and
approximately $51 million of capitalized expenditures to
develop and implement DSM programs. While the Company
expects the majority of the construction program and debt
redemption requirements to be provided by internally
generated funds, external financing requirements of $50-70
million are anticipated.
At year end, the Company had $11 million in short-term
borrowings, leaving unused lines of credit and trust demand
note arrangements totaling $16 million.
The Company is confident that its long-term financial
objectives, which include maintaining a capital structure
near 45-50% long-term debt, 3-7% preferred stock, and 43-48%
common equity, will continue to be met, while providing for
future construction and other capital requirements.
22
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
1. Financial Statements:
Report of Independent Public Accountants 23
Consolidated Statements of Income for the
years ended December 31, 1993, 1992 and 1991 24
Consolidated Statements of Cash Flows for the
years ended December 31, 1993, 1992 and 1991 25
Consolidated Balance Sheets - December 31,
1993 and 1992 26 - 27
Consolidated Statements of Capitalization -
December 31, 1993 and 1992 28
Consolidated Statements of Retained Earnings
for the years ended December 31, 1993,
1992 and 1991 29
Notes to Consolidated Financial Statements 29 - 39
2. Supplementary Information:
Selected Quarterly Financial Data 40
3. Supplemental Schedules:
Schedule V - Property, Plant and Equipment
for the years ended December 31, 1993, 1992
and 1991 44 - 46
Schedule VI - Accumulated Provision for
Depreciation and Amortization of Property,
Plant and Equipment for the years ended
December 31, 1993, 1992 and 1991 47 - 49
Schedule VIII - Valuation and Qualifying
Accounts and Reserves for the years ended
December 31, 1993, 1992 and 1991 50
Schedule IX - Short-Term Borrowings 51
Schedule X - Supplementary Income Statement
Information 52
Schedule XIII - Other Investments 53
All other schedules have been omitted as not applicable
or not required or because the information required to
be shown is included in the Consolidated Financial
Statements or the accompanying Notes to Consolidated
Financial Statements.
23
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Southern Indiana Gas and Electric
Company:
We have audited the consolidated balance sheets and
consolidated statements of capitalization of SOUTHERN
INDIANA GAS AND ELECTRIC COMPANY (an Indiana corporation)
AND SUBSIDIARY as of December 31, 1993 and 1992, and the
related consolidated statements of income, retained earnings
and cash flows for each of the three years in the period
ended December 31, 1993. These financial statements and the
supplemental schedules referred to below are the
responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements and supplemental schedules based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that
we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the consolidated financial statements
referred to above present fairly, in all material respects,
the financial position of Southern Indiana Gas and Electric
Company and Subsidiary as of December 31, 1993 and 1992, and
the results of their operations and their cash flows for
each of the three years in the period ended December 31,
1993, in conformity with generally accepted accounting
principles.
As discussed in Note 1, effective January 1, 1993, the
Company changed its methods of accounting for income taxes
and postretirement benefits other than pensions.
Our audits were made for the purpose of forming an
opinion on the basic financial statements taken as a whole.
The supplemental schedules listed under Item 8 (3) are
presented for the purposes of complying with the Securities
and Exchange Commission's rules and are not part of the
basic financial statements. These supplemental schedules
have been subjected to the auditing procedures applied in
the audits of the basic financial statements and, in our
opinion, fairly state in all material respects the financial
data required to be set forth therein in relation to the
basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Chicago, Illinois
January 24, 1994
24
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
for the years ended December 31,
1993 1992 1991
(in thousands except per share data)
OPERATING REVENUES
Electric $258,405 $243,077 $263,887
Gas 70,116 62,870 58,695
Total operating revenues 328,521 305,947 322,582
OPERATING EXPENSES
Operation:
Fuel for electric generation 81,080 81,239 90,054
Purchased electric energy 9,348 2,914 5,653
Cost of gas sold 50,544 46,063 40,694
Other 40,541 35,952 37,278
Total operation 181,513 166,168 173,679
Maintenance 26,655 21,947 27,117
Depreciation and amortization 36,939 36,213 36,795
Federal and state income taxes 18,325 16,490 19,397
Property and other taxes 13,447 14,210 12,438
Total operating expenses 276,879 255,028 269,426
OPERATING INCOME 51,642 50,919 53,156
Other Income:
Allowance for other funds used
during construction 3,092 988 974
Interest 920 1,001 907
Other, net 2,530 2,100 2,680
________ ________ ________
6,542 4,089 4,561
INCOME BEFORE INTEREST CHARGES 58,184 55,008 57,717
Interest Charges:
Interest on long-term debt 18,437 17,768 18,238
Amortization of premium, discount,
and expense on debt 773 446 740
Other interest 746 461 719
Allowance for borrowed funds
used during construction (1,425) (434) (493)
________ ________ ________
18,531 18,241 19,204
NET INCOME 39,653 36,767 38,513
Preferred Stock Dividends 1,105 1,267 1,281
NET INCOME APPLICABLE TO COMMON STOCK $ 38,548 $ 35,500 $ 37,232
AVERAGE COMMON SHARES OUTSTANDING 15,705 15,705 15,705
EARNINGS PER SHARE OF COMMON STOCK $2.45 $2.26 $2.37
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
25
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31,
1993 1992 1991
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 39,653 $ 36,767 $ 38,513
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 36,939 36,213 36,795
Deferred income taxes and investment
tax credits, net 9,459 26 285
Allowance for other funds used
during construction (3,092) (988) (974)
Change in assets and liabilities:
Receivables, net (4,076) 3,770 (2,795)
Inventories 9,734 (7,232) 1,586
Coal contract settlement (13,295) - -
Accounts payable (185) 4,739 (2,777)
Accrued taxes (1,837) 2,387 785
Refunds from gas suppliers 1,545 12 290
Refunds to customers (412) (3,499) (3,674)
Accrued coal liability 8,749 - -
Other 7,120 (1,886) 1,564
Net cash provided by operating
activities 90,302 70,309 69,598
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (net of allowance for
other funds used during construction) (72,487) (49,203) (34,733)
Demand side management program
expenditures (4,530) (1,920) (962)
Investments in leveraged leases (2,769) - -
Purchases of investments (6,569) (20,532) (23,995)
Sales of investments 7,016 21,570 23,981
Investments in partnerships (2,488) (2,476) (2,723)
Change in nonutility property (862) (1,258) (440)
Other 307 1,031 247
Net cash used in investing activities (82,382) (52,788) (38,625)
CASH FLOWS FROM FINANCING ACTIVITIES
First mortgage bonds 155,000 - -
Preferred stock - 7,500 -
Dividends paid (26,391) (25,737) (24,844)
Reduction in preferred stock
and long-term debt (104,500) (7,685) (110)
Change in environmental improvement
funds held by Trustee (22,613) - -
Change in notes payable 7,610 4,426 (1,224)
Other (5,849) (496) (158)
Net cash provided (used)
in financing activities 3,257 (21,992) (26,336)
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 11,177 (4,471) 4,637
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 3,328 7,799 3,162
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 14,505 $ 3,328 $ 7,799
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
26
CONSOLIDATED BALANCE SHEETS
December 31,
1993 1992
(in thousands)
ASSETS
Utility Plant, at original cost:
Electric $879,476 $865,862
Gas 107,100 103,138
________ ________
986,576 969,000
Less-Accumulated provision for depreciation 423,730 391,541
________ ________
562,846 577,459
Construction work in progress 72,615 19,668
Net Utility Plant 635,461 597,127
Other Investments and Property:
Investments in leveraged leases 34,924 32,332
Investments in partnerships 25,023 22,851
Environmental improvement funds
held by Trustee 22,613 -
Nonutility property and other 7,997 7,135
________ ________
90,557 62,318
Current Assets:
Cash and cash equivalents 5,756 3,328
Restricted cash 8,749 -
Temporary investments, at cost which
approximates market 6,540 6,988
Receivables, less allowance of $166
and $136, respectively 28,360 24,284
Inventories 38,189 47,923
Other current assets 3,047 2,460
________ ________
90,641 84,983
Deferred Charges:
Coal contract settlement 13,295 -
Unamortized premium on reacquired debt 7,100 3,118
Postretirement benefits other than pensions 4,125 -
Demand side management program 7,411 2,881
Other deferred charges 11,433 10,854
________ ________
43,364 16,853
________ ________
$860,023 $761,281
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
27
December 31,
1993 1992
(in thousands)
SHAREHOLDERS' EQUITY AND LIABILITIES
Common Stock $102,691 $102,691
Retained Earnings 204,058 190,796
________ ________
306,749 293,487
Less Treasury Stock, at cost 24,540 24,540
________ ________
Common Shareholders' Equity 282,209 268,947
Cumulative Nonredeemable Preferred Stock 11,090 11,090
Cumulative Redeemable Preferred Stock 7,500 7,500
Cumulative Special Preferred Stock 1,015 1,015
Long-Term Debt, net of current maturities 261,100 198,764
Long-Term Partnership Obligations,
net of current maturities 12,881 13,255
Total capitalization, excluding bonds
subject to tender (see Consolidated
Statements of Capitalization) 575,795 500,571
Current Liabilities:
Current Portion of Adjustable Rate
Bonds Subject to Tender 41,475 31,500
Current Maturities of Long-Term Debt, Interim Financing,
and Long-Term Partnership Obligations:
Maturing long-term debt 763 20,859
Notes payable 11,000 5,000
Partnership obligations 3,849 2,859
Total current maturities of long-term
debt, interim financing, and
long-term partnership obligations 15,612 28,718
Other Current Liabilities:
Accounts payable 33,753 33,938
Dividends payable 135 135
Accrued taxes 7,931 9,768
Accrued interest 4,517 5,117
Refunds to customers 3,398 2,537
Accrued coal liability 8,749 -
Other accrued liabilities 10,041 6,554
Total other current liabilities 68,524 58,049
Total current liabilities 125,611 118,267
Deferred Credits and Other:
Accumulated deferred income taxes 117,267 113,138
Accumulated deferred investment tax credits, being
amortized over lives of property 26,549 28,416
Regulatory income tax liability 7,197 -
Postretirement benefits other
than pensions 4,125 -
Other 3,479 889
________ ________
158,617 142,443
________ ________
$860,023 $761,281
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
28
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1993 1992
(in thousands)
COMMON SHAREHOLDERS' EQUITY
Common Stock, without par value, authorized
50,000,000 shares, issued 16,815,604 shares $102,691 $102,691
Retained Earnings, $2,209,642 restricted
as to payment of cash dividends on
common stock 204,058 190,796
________ ________
306,749 293,487
Less Treasury Stock, at cost,
1,110,177 shares 24,540 24,540
________ ________
282,209 268,947
PREFERRED STOCK
Cumulative, $100 par value, authorized
800,000 shares, issuable in series:
Nonredeemable
4.8% Series, outstanding 85,895 shares,
callable at $110 per share 8,590 8,590
4.75% Series, outstanding 25,000 shares,
callable at $101 per share 2,500 2,500
________ ________
11,090 11,090
Redeemable
6.50% Series, outstanding 75,000 shares,
redeemable at $100 per share
December 1, 2002 7,500 7,500
SPECIAL PREFERRED STOCK
Cumulative, no par value, authorized 5,000,000
shares, issuable in series: 8-1/2% series,
outstanding 10,150 shares, redeemable
at $100 per share 1,015 1,015
LONG-TERM DEBT, NET OF CURRENT MATURITIES
First mortgage bonds 254,740 194,315
Notes payable 7,263 5,456
Unamortized debt premium and discount, net (903) (1,007)
________ ________
261,100 198,764
LONG-TERM PARTNERSHIP OBLIGATIONS,
NET OF CURRENT MATURITIES 12,881 13,255
CURRENT PORTION OF ADJUSTABLE RATE POLLUTION
BONDS SUBJECT TO TENDER, DUE
2015, Series A, presently 5.75% 9,975 -
2015, Series B, presently 2.7% 31,500 31,500
________ ________
41,475 31,500
Total capitalization, including
bonds subject to tender $617,270 $532,071
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
29
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
for the years ended December 31,
1993 1992 1991
(in thousands)
Balance Beginning of Period $190,796 $180,291 $166,622
Net income 39,653 36,767 38,513
________ ________ ________
230,449 217,058 205,135
Preferred Stock Dividends 1,105 1,235 1,281
Common Stock Dividends ($1.61 per share
in 1993, $1.56 per share in 1992,
and $1.50 per share in 1991) 25,286 24,502 23,563
Capital Stock Expenses - 525 -
________ ________ ________
26,391 26,262 24,844
Balance End of Period (See Consolidated
Statements of Capitalization
for restriction) $204,058 $190,796 $180,291
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiary
Southern Indiana Properties, Inc. All significant
intercompany transactions and balances have been eliminated.
CUSTOMER RECEIVABLES, SALES, AND TRANSPORTATION REVENUES
The Company's customer receivables, gas and electric
sales, and gas transportation revenues are primarily derived
from supplying electricity and natural gas to a broadly
diversified base of residential, commercial, and industrial
customers located in a southwestern region of Indiana. The
Company serves 118,163 electric customers in the city of
Evansville and 74 other communities and serves 100,398 gas
customers in the city of Evansville and 63 other
communities.
UTILITY PLANT
Utility plant is stated at the historical original cost
of construction. Such cost includes payroll-related costs
such as taxes, pensions, and other fringe benefits, general
and administrative costs, and an allowance for the cost of
funds used during construction (AFUDC), which represents the
estimated debt and equity cost of funds capitalized as a
cost of construction. While capitalized AFUDC does not
represent a current source of cash, it does represent a
basis for future cash revenues through depreciation and
return allowances. The weighted average AFUDC rate (before
income tax) used by the Company was 10.5% in 1993, 11.5% in
1992, and 11.2% in 1991.
DEPRECIATION
Depreciation of utility plant is provided using the
straight-line method over the estimated service lives of the
depreciable plant. Provisions for depreciation, expressed
as an annual percentage of the cost of average depreciable
plant in service, were 4.0% for electric and 3.7 % for gas
in 1993, 4.0% for electric and 3.9% for gas in 1992, and
4.0% for both electric and gas in 1991.
30
INCOME TAXES
The Company utilizes a comprehensive interperiod income
tax allocation policy, providing deferred taxes on temporary
timing differences. Investment tax credits recorded have
been deferred and are amortized through credits to income
over the lives of the related property.
Effective January 1, 1993, the Company adopted
Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes". SFAS No. 109 requires an
asset and liability approach for financial accounting and
reporting for income taxes rather than the deferred method.
The new standard requires the Company to establish deferred
tax assets and liabilities, as appropriate, for all
temporary differences and to adjust deferred tax balances to
reflect changes in tax rates expected to be in effect during
the periods the temporary differences reverse. In the first
quarter of 1993, because of the effects of rate regulation,
the Company recorded an increase of $4,987,000 in deferred
tax assets and a decrease of $8,551,000 in deferred tax
liabilities, and established a corresponding regulatory
liability of $13,538,000, primarily to recognize the
probable future reduction in rates to flow back to customers
deferred taxes previously collected in excess of current tax
rates. The adoption of this standard did not have a
material impact on results of operations, cash flow, or
financial position.
The components of the net deferred income tax liability
at January 1, 1993 and December 31, 1993 are as follows:
January 1 December 31
(in thousands)
Deferred Tax Liabilities:
Depreciation and cost recovery
timing differences $96,460 $100,796
Deferred fuel costs, net 257 5,307
Leveraged leases 25,112 27,064
Regulatory assets recoverable through
future rates 26,246 27,660
Deferred Tax Assets:
Unbilled revenue (6,428) (6,149)
Regulatory liabilities to be settled
through future rates (39,784) (34,857)
Other, net (2,264) (2,554)
Net deferred income tax liability $99,599 $117,267
Of the $17,668,000 increase in the net deferred income
tax liability from January 1, 1993 to December 31, 1993,
$11,263,000 is due to current year deferred federal and
state income tax expense and the remaining $6,405,000
increase is primarily a result of the decrease in the net
regulatory liability.
The components of current and deferred income tax
expense for the years ended December 31 are as follows:
1993 1992 1991
(in thousands)
Current
Federal $ 9,320 $16,152 $17,967
State 1,497 2,543 2,732
Deferred, net
Federal 7,958 (624) 252
State 1,418 292 323
Investment tax credit, net (1,868) (1,873) (1,877)
Income tax expense as shown on Consolidated
Statements of Income 18,325 16,490 19,397
Current income tax expense included
in Other Income (3,608) (3,203) (4,087)
Deferred income tax expense included
in Other Income 1,887 1,322 3,111
Total income tax expense $16,604 $14,609 $18,421
31
The components of deferred federal and state income tax
expense for the years ended December 31 are as follows:
1993 1992 1991
(in thousands)
Depreciation and cost recovery
timing differences $ 3,924 $1,234 $1,858
Debt component of deferred return
on A. B. Brown Unit 2 - (37) (357)
Deferred fuel costs 5,593 340 (21)
Unbilled revenue 43 (1,054) (359)
Leveraged leases 1,887 1,322 2,905
Other, net (184) (815) (340)
Total deferred federal and state
income tax expense $11,263 $ 990 $3,686
As a result of the Omnibus Budget Reconciliation Act of
1993, signed into law on August 10, 1993, the Company
provided additional income tax expense of $524,000 in 1993
to recognize the impact of the 1% increase in federal income
tax rates. A reconciliation of the statutory tax rates to
the Company's effective income tax rate for the years ended
December 31 is as follows:
1993 1992 1991
Statutory federal and state rate 37.9% 37.0% 37.0%
Equity portion of allowance for funds
used during construction (2.1) (0.7) (0.6)
Equity portion of deferred return
on A. B. Brown Unit 2 - 0.1 0.9
Book depreciation over related tax
depreciation-nondeferred 1.9 2.0 2.2
Amortization of deferred investment
tax credit (3.3) (3.7) (3.3)
Low income housing credit (4.4) (4.3) (2.3)
Other, net (0.5) (2.0) (1.5)
Effective tax rate 29.5% 28.4% 32.4%
PENSION PLANS
The Company has trusteed, noncontributory defined
benefit plans which cover eligible full-time regular
employees. The plans provide retirement benefits based on
years of service and the employee's highest 60 consecutive
months' base compensation during the last 120 months of
employment. The funding policy of the Company is to
contribute amounts to the plans equal to at least the
minimum funding requirements of the Employee Retirement
Income Security Act of 1974 (ERISA) but not in excess of the
maximum deductible for federal income tax purposes. The
plans' assets as of December 31, 1993 consist of investments
in interest bearing obligations and common stocks of 51% and
49%, respectively.
The components of net pension cost for the years ended
December 31 are as follows:
1993 1992 1991
(in thousands)
Service cost - benefits earned
during the period $ 1,454 $ 1,408 $ 1,324
Interest cost on projected
benefit obligation 3,605 3,390 3,152
Actual return on plan assets (2,669) (3,060) (9,759)
Net amortization and deferral (1,712) (1,319) 6,071
Net pension cost $ 678 $ 419 $ 788
Part of the pension cost is charged to construction and
other accounts.
The funded status of the retirement plans at December
31 is as follows:
1993 1992
(in thousands)
Actuarial present value of:
Vested benefit obligation $44,502 $37,538
Accumulated benefit obligation $44,742 $37,605
Plan assets at fair value $51,869 $51,559
Projected benefit obligation 56,230 46,075
(Deficit)excess of assets over projected
benefit obligation (4,361) 5,484
Remaining unrecognized transitional asset (3,904) (4,322)
Unrecognized net loss (gain) 5,621 (3,205)
Accrued pension liability $(2,644) $(2,043)
32
The projected benefit obligation at December 31, 1992
was determined using an assumed discount rate of 8%. Due to
the decline in yields on high quality fixed income
investments, a discount rate of 7% was used to determine the
projected benefit obligation at December 31, 1993. For both
periods, the long-term rate of compensation increases was
assumed to be 5%, and the long-term rate of return on plan
assets was assumed to be 8%. The transitional asset is
being recognized over approximately 15, 18, and 14 years for
the Salaried, Hourly, and Hoosier plans, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company provides certain postretirement health care
and life insurance benefits for retired employees and their
dependents through fully insured plans. Retired employees
are eligible for lifetime medical and life insurance
coverage if they retire on or after attainment of age 55,
regardless of length of service. Their spouses are eligible
for medical coverage until age 65. Prior to age 65,
retirees are covered by the same insured health care plans
provided to active employees. After attaining age 65, the
retirees are covered by insured Medicare supplement plans.
Additionally, the Company reimburses the retirees for
Medicare Part B premiums incurred. The health care plans
pay stated percentages of covered medical expenses incurred,
after subtracting payments by Medicare or other providers
and after a stated deductible has been met. Prior to 1993,
the cost of retiree health care and life insurance benefits
was recognized as insurance premiums were paid, which was
consistent with current ratemaking practices. The costs for
retirees totaled $670,000 and $598,000 in 1992 and 1991,
respectively.
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions" which requires the expected cost of
these benefits be recognized during the employees' years of
service. The actuarial assumptions and calculations
involved in determining the recognized costs closely
parallel pension accounting requirements. As authorized by
the Indiana Utility Regulatory Commission in a December 30,
1992 generic ruling, the Company is deferring as a
regulatory asset the additional SFAS No. 106 costs accrued
over the costs of benefits actually paid after date of
adoption, but prior to inclusion in rates. As required by
the generic order, the Company anticipates including the
additional costs of the benefits in rates within four years
after date of adoption of SFAS No. 106.
The components of the net periodic other postretirement
benefit cost for the year ended December 31, 1993, is as
follows:
(in thousands)
Service cost-benefits earned during the period $ 924
Interest cost on accumulated benefit obligation 2,463
Amortization of transition obligation 1,472
Net periodic postretirement benefit cost $4,859
Deferred postretirement benefit obligation 4,125
Charged to operations and construction $ 734
The 1993 cost determined under the new standard
includes the amortization of the discounted present value of
the obligation at the adoption date, $29,400,000, over a 20
year period.
Reconciliation of the accumulated postretirement
benefit obligation to the accrued liability for
postretirement benefits as of January 1, 1993 and December
31, 1993, is as follows:
January 1 December 31
(in thousands)
Accumulated other postretirement
benefit obligation:
Retirees $12,159 $13,096
Other fully eligible participants 6,013 7,120
Other active participants 11,262 15,725
Total accumulated benefit obligation 29,434 35,941
Unrecognized transition obligation (29,434) (27,962)
Unrecognized net loss - (3,854)
Accrued postretirement benefit liability $ - $ 4,125
The assumptions used to develop the accumulated
postretirement benefit obligation at January 1, 1993
included a discount rate of 8.5% and a health care cost
trend rate applicable to gross eligible charges of 14% in
1993 declining to 6% in 2008, and remaining level
thereafter. Due to the decline in yields on high quality
fixed income investments and general inflation, a discount
rate of 7.25% and a health care cost trend rate of 13.5% in
1994 declining to 5.5% in 2008 were used to determine the
accumulated postretirement benefit obligation at December
31, 1993. The estimated cost of these future benefits could
33
be significantly impacted by future changes in health care
costs, work force demographics, interest rates, or plan
changes. A 1% increase in the assumed health care cost
trend rate each year would increase the aggregate service
and interest costs for 1993 by $900,000 and the accumulated
postretirement benefit obligation by $4,700,000. The
Company currently anticipates continuing its policy of
funding postretirement benefits costs other than pensions as
incurred.
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112,
"Employers' Accounting for Postemployment Benefits", which
will require the Company to accrue the estimated cost of
benefits provided to former or inactive employees after
employment but before retirement.
The Company will adopt SFAS No. 112 on January 1,
1994. The impact of the new statement will not have a
material impact on financial position or results of
operations.
CASH FLOW INFORMATION
For the purposes of the Consolidated Balance Sheets and
the Consolidated Statements of Cash Flows, the Company
considers all highly liquid debt instruments purchased with
an original maturity of three months or less to be cash
equivalents.
The Company, during 1993, 1992, and 1991, paid interest
(net of amounts capitalized) of $18,359,000, $17,890,000,
and $18,502,000, respectively, and income taxes of
$10,248,000, $14,291,000, and $18,289,000, respectively.
The Company is involved in several partnerships which are
partially financed by partnership obligations amounting to
$16,730,000 and $16,114,000 at December 31, 1993 and 1992,
respectively.
INVENTORIES
The Company accounts for its inventories under the
average cost method except for gas in underground storage
which is accounted for under two inventory methods: the
average cost method for the Company's Hoosier Division
(formerly Hoosier Gas Corporation) and the last-in, first-
out (LIFO) method for all other gas in storage. Inventories
at December 31 are as follows:
1993 1992
(in thousands)
Fuel (coal and oil) for electric generation $14,533 $24,718
Materials and supplies 13,720 13,686
Gas in underground storage - at LIFO cost 6,907 6,601
- at average cost 3,029 2,918
Total inventories $38,189 $47,923
Based on the December 1993 price of gas purchased, the
cost of replacing the current portion of gas in underground
storage exceeded the amount stated on a LIFO basis by
approximately $12,400,000 at December 31, 1993.
OPERATING REVENUES AND FUEL COSTS
Revenues include all gas and electric service billed
during the year except as discussed below.
All metered gas rates contain a gas cost adjustment
clause which allows for adjustment in charges for changes in
the cost of purchased gas. As ordered by the IURC, the
calculation of the adjustment factor is based on the
estimated cost of gas in a future quarter. The order also
provides that any under- or overrecovery caused by variances
between estimated and actual cost in a given quarter, as
well as refunds from its pipeline suppliers, will be
included in adjustment factors of four future quarters
beginning with the second succeeding quarter's adjustment
factor.
All metered electric rates contain a fuel adjustment
clause which allows for adjustment in charges for electric
energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. As ordered by the IURC, the
calculation of the adjustment factor is based on the
estimated cost of fuel and the net energy cost of purchased
power in a future quarter. The order also provides that any
under- or overrecovery caused by variances between estimated
and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor.
The Company also collects through a quarterly rate
adjustment mechanism, the margin on electric sales lost due
to the implementation of demand side management programs.
Reference is made to "Demand Side Management" in
Management's Discussion and Analysis of Operations and
Financial Condition for further discussion.
The Company records monthly any under- or overrecovery
as an asset or liability, respectively, until such time as
it is billed or refunded to its customers. The IURC reviews
for approval the adjustment clauses on a quarterly basis.
34
The cost of gas sold is charged to operating expense as
delivered to customers and the cost of fuel for electric
generation is charged to operating expense when consumed.
2. REGULATORY AND OTHER MATTERS
The IURC has jurisdiction over all investor-owned gas
and electric utilities in Indiana. The FERC has
jurisdiction over those investor-owned utilities that make
wholesale energy sales. These agencies regulate the
Company's utility business operations, rates, accounts,
depreciation allowances, services, security issues, and the
sale and acquisition of properties.
On July 21, 1993, the IURC approved an overall increase
of approximately 8%, or $5.5 million in revenues, in the
Company's base gas rates. The increase is to be implemented
in two equal steps. The first step of the rate adjustment,
approximately 4%, took place August 1, 1993; the second step
will become effective August 1, 1994.
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its
investment through March 31, 1993 in the Clean Air Act
Compliance project presently being constructed at the Culley
Generating Station. The majority of the costs are for the
installation of a sulfur dioxide scrubber on Culley Units 2
and 3. On September 15, 1993, the IURC granted the
Company's request for a 1% revenue increase (approximately
$1,800,000 on an annual basis), which took effect October 1,
1993. The Company anticipates petitioning the IURC in
February 1994 for a 2-3% increase for financing costs
related to project construction expenditures incurred since
April 1, 1993, with implementation of the new rates
effective mid-1994.
On December 22, 1993, the Company filed a request with
the IURC for a general electric rate increase. This
adjustment, expected to occur in early 1995, is estimated to
be 6-9% and is necessary to recover financing costs related
to the balance of the scrubber project construction
expenditures, costs related to the operation of the
scrubber, and certain nonscrubber-related costs such as
additional costs incurred for postretirement benefits other
than pensions beginning in 1993 and the recovery of demand
side management program expenditures.
In April 1992, the Federal Energy Regulatory Commission
(FERC) issued Order No. 636 (the Order) which required
interstate pipelines to restructure their services. In
August 1992, the FERC issued Order No. 636-A which
substantially reaffirmed the content of the original Order.
On November 2, 1992, the Company's major pipeline , Texas
Gas Transmission Corporation (TGTC), filed a recovery
implementation plan with the FERC as part of its revised
compliance filing regarding the Order. On October 1, 1993,
the FERC accepted, subject to certain conditions, the TGTC
recovery implementation plan.
Under the new TGTC transportation tariffs, which became
effective November 1, 1993, the Company will incur
additional annual demand-related charges of approximately
$1.9 million. Savings from lower volume-related
transportation costs will partially offset the additional
charges. TGTC has not yet determined the Company's
allocation of transition costs, however, an estimate of such
costs and implementation of revised TGTC tariffs to recover
such costs, are expected during the first quarter of 1994.
Due to the anticipated regulatory treatment at the state
level, the Company does not expect the Order to have a
detrimental effect on its financial condition or results of
operations.
Over the past several years, the Company has been
involved in contract negotiations and legal actions to
reduce its coal costs. During 1992, the Company
successfully negotiated a new coal supply contract with a
major supplier which was retroactive to 1991 and effective
through 1995. In 1993, the Company exercised a provision of
the agreement which allowed the Company to reopen the
contract for the modification of certain coal
specifications. In response, the coal supplier elected to
terminate the contract enabling the Company to buy out the
remainder of its contractual obligations and acquire lower
priced spot market coal.
The cost of the contract buyout in 1993, which was
based on estimated tons of coal to be consumed during the
agreement period, and related legal and consulting services,
totaled approximately $18 million. The Company anticipates
that $2 million in additional buyout costs for actual tons
of coal consumed above the previously estimated amount may
be incurred during the 1994-1995 period. On September 22,
1993, the IURC approved the Company's request to amortize
all buyout costs to coal inventory during the period July 1,
1993 through December 31, 1995 and to recover such costs
through the fuel adjustment clause beginning February 1994.
As of December 31, 1993, $13,295,000 of settlement costs
paid to date had not yet been amortized to coal inventory.
The Company is currently in litigation with another
coal supplier in an attempt to restructure an existing
contract. Under the terms of the contract, the Company
was allegedly obligated to take 600,000 tons of coal
annually. In early 1993, the Company informed the supplier
that it would not require shipments under the contract until
later in 1993. On March 26, 1993, the Company and the
supplier agreed to resume coal shipments under the terms of
their original contract except the invoiced price per ton
would be substantially lower than the contract price. As
approved by the IURC, the Company has charged the full
contract price to coal inventory for subsequent recovery
through the fuel adjustment clause. The difference between
the contract price and the invoice price has been deposited
in an escrow account with an offsetting accrued liability
which will be paid to either the Company's ratepayers or its
coal supplier upon resolution of the litigation. The
escrowed amount was $8,749,000 at December 31, 1993. This
litigation is scheduled for trial in June of 1994. Since
the litigation arose due to the Company's efforts to reduce
fuel costs, management believes that any related costs
should be recoverable through the regulatory ratemaking
process.
In late 1993, in a further effort to reduce coal
costs, the Company and the supplier entered into a letter
agreement, effective January 1, 1994, and until the
litigation is settled, whereby the Company will purchase an
additional 50,000 tons monthly above the alleged base
requirements at a price lower than the original contract
price for tons over 50,000 per month. Reference is made to
35
"Rate and Regulatory Matters" in Management's Discussion and
Analysis of Operations and Financial Condition for further
discussion.
3. SOUTHERN INDIANA PROPERTIES, INC.
Southern Indiana Properties, Inc. (SIPI), a wholly-
owned subsidiary, was formed to conduct nonutility
investment activities while segregating such activities from
the Company's regulated utility business. Net income for
the years 1993, 1992, and 1991 was $2,525,000, $2,321,000,
and $1,936,000, respectively, and is included in "Other,
net" in the Consolidated Statements of Income. SIPI
investment activities consist principally of investments in
partnerships (primarily in real estate), leveraged leases,
and marketable securities.
SIPI is a lessor in four leveraged lease agreements
under which an office building, a part of a reservoir, an
interest in a paper mill, and passenger railroad cars are
leased to third parties. The economic lives and lease terms
vary with the leases. The total equipment and facilities
cost was approximately $101,200,000 and $83,400,000 at
December 31, 1993 and 1992, respectively. The cost of the
equipment and facilities was partially financed by
nonrecourse debt provided by lenders, who have been granted
an assignment of rentals due under the leases and a security
interest in the leased property, which they accept as their
sole remedy in the event of default by the lessee. Such
debt amounted to approximately $78,700,000 and $63,700,000
at December 31, 1993 and 1992, respectively. The Company's
net investment in leveraged leases at those dates was
$8,184,000 and $7,191,000, respectively, as shown:
1993 1992
(in thousands)
Minimum lease payments receivable $64,120 $64,046
Estimated residual value 22,095 18,544
Less: Unearned income 51,291 50,258
Investment in lease financing receivables and loans 34,924 32,332
Less: Deferred taxes arising from leveraged leases 26,740 25,141
Net investment in leveraged leases $ 8,184 $ 7,191
4. SHORT-TERM FINANCING
The Company has trust demand note arrangements totaling
$17,000,000 with several banks, of which $11,000,000 was
utilized at December 31, 1993. Funds are also borrowed from
time to time from banks on a short-term basis, made
available through lines of credit. These available lines of
credit totaled $10,000,000 at December 31, 1993 of which
none was utilized at that date.
1993 1992 1991
(in thousands)
Notes Payable:
Balance at year end $11,000 $5,000 $ -
Weighted average interest rate on
year end balance 3.44% 3.59% -
Maximum amount outstanding during
the year $17,000 $9,000 $2,000
Average daily amount outstanding
during the year $ 6,992 $ 309 $ 52
Weighted average interest rate on
average daily amount outstanding
during the year 3.36% 3.91% 6.55%
5. LONG-TERM DEBT
The annual sinking fund requirement of the Company's
first mortgage bonds is 1% of the greatest amount of bonds
outstanding under the Mortgage Indenture. This requirement
may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in
the Mortgage Indenture. The Company intends to meet the
1994 sinking fund requirement by this means and,
accordingly, the sinking fund requirement for 1994 is
excluded from current liabilities on the balance sheet. At
December 31, 1993, $106,887,000 of the Company's utility
plant remained unfunded under the Company's Mortgage
Indenture.
Several of the Company's partnership investments have
been financed through obligations with such partnerships.
Additionally, the Company's investments in leveraged leases
have been partially financed through notes payable to banks.
Of the amount of first mortgage bonds, notes payable, and
partnership obligations outstanding at December 31, 1993,
the following amounts mature in the five years subsequent to
1993: 1994 - $4,612,000; 1995 - $11,143,000; 1996 -
$12,394,000; 1997 - $2,672,000; and 1998 - $16,577,000.
In addition, $41,475,000 of adjustable rate pollution
control series first mortgage bonds could, at the election
of the bondholder, be tendered to the Company in 1994 on
certain interest payment dates. If the Company's agent is
36
unable to remarket any bonds tendered at that time, the
Company would be required to obtain additional funds for
payment to bondholders. For financial statement
presentation purposes those bonds subject to tender in 1994
are shown as current liabilities.
First mortgage bonds, notes payable, and partnership
obligations outstanding and classified as long-term at
December 31 are as follows:
1993 1992
(in thousands)
First Mortgage Bonds due:
1995, 4-3/4% $ 5,000 $ 5,000
1996, 6% 8,000 8,000
1998, 6-3/8% 12,000 12,000
1999, 6% 45,000 -
2001, 8% - 7,500
2002, 8% - 12,000
2003, 5.60% Pollution Control Series A 5,240 5,340
2007, 8.35% - 30,000
2008, 6.05% Pollution Control Series A 22,000 22,000
2014, 7.25% Pollution Control Series A 22,500 22,500
2016, 8-7/8% 25,000 25,000
2016, 9-1/4% - 15,000
2017, 8-5/8% - 20,000
2023, 7.60% 45,000 -
2025, 7-5/8% 20,000 -
Adjustable Rate Pollution Control:
2015, Series A, presently 5.75% - 9,975
Adjustable Rate Environmental Improvement:
2023, Series B, presently 6% 22,800 -
2028, Series A, presently 4.65% 22,200 -
$254,740 $194,315
Notes Payable:
Banks, due 1995 through 1998, presently 6% to 8% $ 6,263 $ 4,456
Tax Exempt, due 2003, 6.25% 1,000 1,000
$ 7,263 $ 5,456
Partnership Obligations, due 1995 through 2001,
without interest $ 12,881 $ 13,255
6. CUMULATIVE PREFERRED STOCK
The amount payable in the event of involuntary
liquidation of each series of the $100 par value preferred
stock is $100 per share, plus accrued dividends.
The nonredeemable preferred stock is callable at the
option of the Company as follows:
4.8% Series at $110 per share, plus accrued
dividends; and
4.75% Series at $101 per share, plus accrued
dividends.
7. CUMULATIVE REDEEMABLE PREFERRED STOCK
On December 8, 1992, the Company issued $7,500,000 of
its Cumulative Redeemable Preferred Stock to replace a like
amount of 8.75% of Cumulative Preferred Stock. The new
series has an interest rate of 6.50% and is redeemable at
$100 per share on December 1, 2002. In the event of
involuntary liquidation of this series of $100 par value
preferred stock, the amount payable is $100 per share, plus
accrued dividends.
8. CUMULATIVE SPECIAL PREFERRED STOCK
The Cumulative Special Preferred Stock contains a
provision which allows the stock to be tendered on any of
its dividend payment dates. On April 1, 1992, the Company
repurchased 850 shares of the Cumulative Special Preferred
Stock at a cost of $85,000 as a result of a tender within
the provision of the issuance. On March 8, 1991, the
Company repurchased 100 shares at a cost of $10,000 as a
result of the same provision.
37
9. COMMITMENTS AND CONTINGENCIES
The Company presently estimates that approximately
$90,000,000 will be expended for construction purposes in
1994, including those amounts applicable to the Company's
Clean Air Act Compliance Plan and demand side management
(DSM) programs. Commitments for the 1994 construction
program are approximately $44,000,000 at December 31, 1993.
Reference is made to "Clean Air Act" and "Demand Side
Management" in Management's Discussion and Analysis of
Operations and Financial Condition for discussion of the
impact of the Federal Clean Air Act and implementation of
the Company's DSM programs.
The Company is currently investigating the possible
existence of facilities once owned and operated by the
Company, its predecessors, previous landowners, or former
affiliates of the Company utilized for the manufacture of
gas. Based on its investigations, the Company has
identified the existence and general location of four sites
at which contamination may be present. The Company is
attempting to identify all potentially responsible parties
for each site. The Company has not been named a potentially
responsible party by the Environmental Protection Agency for
any of these sites.
While the Company intends to seek recovery from other
responsible parties or insurance carriers, the Company does
not presently anticipate seeking recovery of these
investigation costs from its ratepayers. Therefore, the
Company has expensed the $500,000 anticipated cost of
performing preliminary and comprehensive specific site
investigations of all four sites. If the specific site
investigations indicate that significant remedial action is
required, the Company will seek recovery of all related
costs in excess of amounts recovered from other potentially
responsible parties or insurance carriers through rates.
Although the IURC has not yet ruled on a pending
request for rate recovery by another Indiana utility of such
environmental costs, the IURC did grant that utility
authority to utilize deferred accounting for such costs
until the IURC rules on the request.
10. COMMON STOCK
Since 1986, the Board of Directors of the Company
authorized the repurchase of up to $25,000,000 of the
Corporation's common stock. As of December 31, 1993, the
Company had accumulated 1,110,177 common shares with an
associated cost of $24,540,000 under this plan.
On January 21, 1992, the Board of Directors of the
Company approved a four-for-three common stock split
effective March 30, 1992. The stock split was authorized by
the IURC on March 18, 1992. Average common shares
outstanding, earnings per share of common stock and
dividends per share of common stock as shown in the
accompanying financial statements have been adjusted to
reflect the split. Shares issued during 1992 as a result of
the stock split were 3,923,706. No shares of common stock
were issued during 1993 and 1991.
Each outstanding share of the Company's stock contains
a right which entitles registered holders to purchase from
the Company one one-hundredth of a share of a new series of
the Company's Redeemable Preferred Stock, no par value,
designated as Series 1986 Preferred Stock, at an initial
price of $120.00 (Purchase Price) subject to adjustment.
The rights will not be exercisable until a party acquires
beneficial ownership of 20% of the Company's common shares
or makes a tender offer for at least 30% of its common
shares. The rights expire October 15, 1996. If not
exercisable, the rights in whole may be redeemed by the
Company at a price of $.01 per right at any time prior to
their expiration. If at any time after the rights become
exercisable and are not redeemed and the Company is involved
in a merger or other business combination transaction,
proper provision shall be made to entitle a holder of a
right to buy common stock of the acquiring company having a
value of two times such Purchase Price.
11. OWNERSHIP OF WARRICK UNIT 4
The Company and Alcoa Generating Corporation (AGC), a
subsidiary of Aluminum Company of America, own the 270 MW
Unit 4 at the Warrick Power Plant as tenants in common.
Construction of the unit was completed in 1970. The cost of
constructing this unit was shared equally by AGC and the
Company, with each providing its own financing for its share
of the cost. The Company's share of the cost of this unit
at December 31, 1993 is $30,733,000 with accumulated
depreciation totaling $17,846,000. AGC and the Company also
share equally in the cost of operation and output of the
unit. The Company's share of operating costs is included in
operating expenses in the Consolidated Statements of Income.
38
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:
1993 1992 1991
(in thousands)
OPERATING INFORMATION-
Operating revenues:
Electric $258,405 $243,077 $263,887
Gas 70,116 62,870 58,695
Total 328,521 305,947 322,582
Operating expenses, excluding
provision for income taxes:
Electric 188,875 176,371 193,200
Gas 69,679 62,167 56,829
Total 258,554 238,538 250,029
Pre-tax operating income:
Electric 69,530 66,706 70,687
Gas 437 703 1,866
Total 69,967 67,409 72,553
Allowance for funds used during
construction 4,517 1,422 1,467
Other income, net 1,729 1,220 2,611
Interest charges (19,956) (18,675) (19,697)
Provision for income taxes (16,604) (14,609) (18,421)
Net income per accompanying
Consolidated Statements of Income $ 39,653 $ 36,767 $ 38,513
OTHER INFORMATION -
Depreciation and amortization expense:
Electric $ 33,481 $ 32,786 $ 33,579
Gas 3,458 3,427 3,216
Total $ 36,939 $ 36,213 $ 36,795
Capital expenditures:
Electric <F1> $ 74,182 $ 44,387 $ 28,967
Gas 5,927 7,723 7,702
Total $ 80,109 $ 52,110 $ 36,669
INVESTMENT INFORMATION -
Identifiable assets:<F2>
Electric $679,044 $596,836 $577,014
Gas 87,632 84,752 85,277
Total $766,676 $681,588 $662,291
Nonutility plant and other investments 67,944 62,318 62,263
Assets utilized for overall Company
operations 25,403 17,375 22,891
Total assets $860,023 $761,281 $747,445
<FN>
<F1>(a) Includes $4,530,000, $1,920,000, and $962,000 of demand side
management program expenditures for 1993, 1992, and 1991, respectively.
<F2>(b) Utility plant less accumulated provision for depreciation,
inventories, receivables (less allowance), and other identifiable assets.
39
13. TAXES OTHER THAN INCOME TAXES
The items comprising property and other taxes for the
years ended December 31 are as follows:
1993 1992 1991
(in thousands)
Real estate and personal property $ 7,168 $ 8,479 $ 6,480
Indiana gross income 4,078 3,686 3,901
Social security and unemployment 1,707 1,591 1,571
Other 494 454 486
Property and other taxes as shown on
Consolidated Statements of Income 13,447 14,210 12,438
Property and other taxes included
in Other Income 44 42 40
Total property and other taxes $13,491 $14,252 $12,478
14. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to
estimate the fair value of each class of financial
instruments for which it is practicable to estimate that
value:
CASH AND TEMPORARY INVESTMENTS
The carrying amount approximates fair value because of
the short maturity of those investments. The fair value of
temporary investments were based on current market values.
LONG-TERM DEBT
The fair value of the Company's long-term debt was
estimated based on the current quoted market rate of
utilities with a comparable debt rating. Nonutility long-
term debt was valued based upon the most recent debt
financing.
PARTNERSHIP OBLIGATIONS
The fair value of the Company's partnership obligations
was estimated based on the current quoted market rate of
comparable debt.
REDEEMABLE PREFERRED STOCK
Fair value of the Company's redeemable preferred stock
was estimated based on the current quoted market of
utilities with a comparable debt rating.
The carrying amount and estimated fair values of the
Company's financial instruments at December 31 are as
follows:
1993 1992
Carrying Estimated Carrying Estimated
Amount Fair ValueAmount Fair Value
(in thousands) (in thousands)
Cash and Temporary Investments $ 21,045 $ 21,268 $ 10,316 $ 10,346
Long-Term Debt (including
current portion) 304,241 323,776 252,130 263,549
Partnership Obligations 16,730 14,447 16,114 13,200
Redeemable Preferred Stock 7,500 7,135 7,500 7,500
At December 31, 1993 and 1992, approximately
$19,100,000 and $11,200,000, respectively, represent the
excess of fair value over carrying amounts of the Company's
long-term debt relating to utility operations. Anticipated
regulatory treatment of the excess of fair value over
carrying amounts of the Company's long-term debt, if in fact
settled at amounts approximating those above, would dictate
that these amounts be used to reduce the Company's rates
over a prescribed amortization period. Accordingly, any
settlement would not result in a material impact on the
Company's financial position or results of operations.
40
SELECTED QUARTERLY FINANCIAL DATA
(Unaudited) Quarters Ended
March 31, June 30, September 30, December 31,
1993 1992 1993 1992 1993 1992 1993 1992
(in thousands except per share data)
Operating Revenues
$93,236 $84,737 $75,941 $70,839 $82,778 $74,815 $76,566 $75,556
Operating Income
$16,169 $15,185 $12,668 $13,798 $17,495 $14,957 $ 5,310 $ 6,979
Net Income
$12,733 $11,334 $ 9,188 $10,402 $14,819 $11,458 $ 2,913 $ 3,573
Earnings Per Share of Common Stock
$ 0.79 $ 0.70 $ 0.57 $ 0.64 $ 0.93 $ 0.71 $ 0.17 $ 0.21
Average Common Shares Outstanding
15,705 15,705 15,705 15,705 15,705 15,705 15,705 15,705
<FN>
Information for any one quarterly period is not
indicative of the annual results which may be expected due
to seasonal variations common in the utility industry.
The quarterly earnings per share may not add to the
total earnings per share for the year due to rounding.
Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None
PART III
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. 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. 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. 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.
41
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
(a) 1) The financial statements, including supporting
schedules, are listed in the Index to Financial
Statements, page 22,
(a) 2) filed as part of this report.
(a) 3) Exhibits:
EX-2(a) Merger Agreement - Plan of Reorganization
and Agreement of Merger, by and among: Southern
Indiana Gas and Electric Company; Southern
Indiana Group, Inc.; Horizon Investments,
Inc.; and MPM Investment Corporation, dated
August 27, 1987. (Physically filed and
designated as Exhibit A in Form S-4
Registration Statement filed November 12, 1987,
File No. 33-18475.)
EX-3(a) Amended Articles of Incorporation as amended
March 26, 1985. (Physically filed and
designated in Form 10-K, for the fiscal year
1985, File No. 1-3553, as Exhibit 3-A.)
Articles of Amendment of the Amended Articles
of Incorporation, dated March 24, 1987.
(Physically filed and designated in Form 10-K
for the fiscal year 1987, File No. 1-3553, as
Exhibit 3-A.) Articles of Amendment of the
Amended Articles of Incorporation, dated
November 27, 1992. (Physically filed and
designated in Form 10-K for the fiscal year
1992, File No. 1-3553, as Exhibit 3-A).
EX-3(b) By-Laws as amended through December 18, 1990.
(Physically filed in Form 10-K for the fiscal
year 1990, File No. 1-3553, as Exhibit 3-B.)
By-Laws as amended through September 22, 1993.
(Physically filed herewith as EX-3(b).)
EX-4(a)*Mortgage and Deed of Trust dated as of April 1,
1932 between the Company and Bankers Trust
Company, as Trustee, and Supplemental
Indentures thereto dated August 31, 1936,
October 1, 1937, March 22, 1939, July 1, 1948,
June 1, 1949, October 1, 1949, January 1,
1951, April 1, 1954, March 1, 1957, October 1,
1965, September 1, 1966, August 1, 1968, May
1, 1970, August 1, 1971, April 1, 1972,
October 1, 1973, April 1, 1975, January 15,
1977, April 1, 1978, June 4, 1981, January 20,
1983, November 1, 1983, March 1, 1984, June 1,
1984, November 1, 1984, July 1, 1985, November
1, 1985, June 1, 1986. (Physically filed and
designated in Registration No. 2-2536 as
Exhibits B-1 and B-2; in Post-effective
Amendment No. 1 to Registration No. 2-62032 as
Exhibit (b)(4)(ii), in Registration No.
2-88923 as Exhibit 4(b)(2), in Form 8-K, File
No. 1-3553, dated June 1, 1984 as Exhibit (4),
File No. 1-3553, dated March 24, 1986 as
Exhibit 4-A, in Form 8-K, File No. 1-3553,
dated June 3, 1986 as Exhibit (4).) July 1,
1985 and November 1, 1985 (Physically filed
and designated in Form 10-K, for the fiscal
year 1985, File No. 1-3553, as Exhibit 4-A.)
November 15, 1986 and January 15, 1987.
(Physically filed and designated in Form 10-K,
for the fiscal year 1986, File No. 1-3553, as
Exhibit 4-A.) December 15, 1987. (Physically
filed and designated in Form 10-K, for the
fiscal year 1987, File No. 1-3553, as Exhibit
4-A.) December 13, 1990. (Physically filed
and designated in Form 10-K, for the fiscal
year 1990, File No. 1-3553, as Exhibit 4-A.)
April 1, 1993. (Physically filed and
designated in Form 8-K, dated April 13, 1993,
File 1-3553, as Exhibit 4.) June 1, 1993
(Physically filed and designated in Form 8-K,
dated June 14, 1993, File 1-3553, as Exhibit
4.) May 1, 1993. (Physically filed herewith
as EX-4(a).)
EX-10.1 Agreement, dated, January 30, 1968, for Unit
No. 4 at the Warrick Power Plant of Alcoa
Generating Corporation ("Alcoa"), between
Alcoa and the Company. (Physically filed and
designated in Registration No. 2-29653 as
Exhibit 4(d)-A.)
EX-10.2 Letter of Agreement, dated June 1, 1971, and
Letter Agreement, dated June 26, 1969, between
Alcoa and the Company. (Physically filed and
designated in Registration No. 2-41209 as
Exhibit 4(e)-2.)
*Pursuant to paragraph (b)(4)(iii)(a) of Item 601 of
Regulation S-K, the Company agrees to furnish to the
Commission on request any instrument with respect to long-
term debt if the total amount of securities authorized
thereunder does not exceed 10% of the total assets of the
Company, and has therefore not filed such documents as
exhibits to this Form 10-K.
42
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.
43
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K (Continued)
EX-10.18* Supplemental Post Retirement Death Benefits
Plan, dated October 10, 1984. (Physically
filed and designated in Form 10-K for the
fiscal year 1992, File No. 1-3553, as
Exhibit 10-A-18.)
EX-10.19* Summary description of the Company's
Corporate Performance Incentive Plan.
(Physically filed and designated in Form 10-
K for the fiscal year 1992, File No. 1-3553,
as Exhibit 10-A-19.)
EX-10.20* Company's Corporate Performance Incentive
Plan as amended for the plan year beginning
January 1, 1994. (Physically filed herewith
as Exhibit 10-A-20.)
* Filed pursuant to paragraph (b)(10)(iii)(A) of Item
601 of Regulation S-K.
(b) Reports on Form 8-K
No Form 8-K reports were filed by the Company
during the fourth quarter of 1993.
44
SCHEDULE V
Page 1 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
PROPERTY, PLANT AND EQUIPMENT
Year 1993
Column A Column B Column C Column D Column E Column F
Retirements
Balance Additions or Sales at Other Balance
Classification Jan. 1, At Cost Orig. Cost Changes Dec. 31,
1993 1993
(in thousands)
ELECTRIC PLANT:
Production:
Steam $519,788 $ 5,403 $ 540 $ 5 $ 524,656
Other 43,870 - - - 43,870
Transmission 94,610 2,555 215 (91) 96,859
Distribution 167,115 8,174 1,212 95 174,172
General 9,966 667 418 764) 9,451
Total
Electric Plant $853,349 $16,799 $2,385 $(755) $ 849,008<F1>
GAS PLANT:
Gas Prod. &
Gathering $ 54 $ - $ - $ - $ 54
Underground
Storage 7,933 245 - - 8,178
Transmission 11,854 229 58 34 12,059
Distribution 73,103 4,482 560 (34) 76,991
General 4,383 455 129 (693) 4,016
Total Gas Plant $ 97,327 $ 5,411 $ 747 $(693) $ 101,298<F1>
COMMON PLANT: $ 36,324 $ 416 $1,922 $1,452 $ 36,270
Plant in
Service $969,000 $22,626 $5,054 $ 4 $ 986,576
CONSTRUCTION WORK
IN PROGRESS $ 19,668 $52,947 $ - $ - $ 72,615
Total Utility
Plant $988,668 $75,573 $5,054 $ 4 $1,059,191
<FN>
<F1>(a)Amounts do not agree with balance sheet totals as
common plant is allocated between electric and gas plant for
financial statement purposes.
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1993 were:
Electric - 3.9%; Gas 3.6%; and Common - 6.1%.
/TABLE
44
SCHEDULE V
Page 2 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
PROPERTY, PLANT AND EQUIPMENT
Year 1992
Column A Column B Column C Column D Column E Column F
Retirements
Balance Additions or Sales at Other Balance
Classification Jan. 1, At Cost Orig. Cost Changes Dec. 31,
1992 1992
(in thousands)
ELECTRIC PLANT:
Production:
Steam $516,533 $ 4,068 $ 481 $ (332) $519,788
Other 44,274 (404) - - 43,870
Transmission 88,390 6,850 598 (32) 94,610
Distribution 160,631 8,021 1,501 (36) 167,115
General 9,391 841 266 - 9,966
Total Electric
Plant $819,219 $19,376 $2,846 $ (400) $835,349 <F1>
GAS PLANT:
Gas Prod. &
Gathering $ 54 $ - $ - $ - $ 54
Underground
Storage 7,642 291 - - 7,933
Transmission 10,608 1,258 12 - 11,854
Distribution 69,273 4,479 641 (8) 73,103
General 4,129 464 210 - 4,383
Total Gas Plant $ 91,706 $ 6,492 $ 863 $ (8) $ 97,327 <F1>
COMMON PLANT: $ 22,183 $14,444 $ 303 $ - $ 36,324
Plant in
Service $933,108 $40,312 $4,012 $(408) $969,000
CONSTRUCTION WORK
IN PROGRESS $ 9,792 $ 9,876 $ - $ - $ 19,668
Total Utility
Plant $942,900 $50,188 $4,012 $(408) $988,668
<FN>
<F1>(a)Amounts do not agree with balance sheet totals as
common plant is allocated between electric and gas plant
for financial statement purposes.
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1992 were:
Electric - 3.9%; Gas 3.8%; and Common - 6.5%
/TABLE
46
SCHEDULE V
Page 3 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
PROPERTY, PLANT AND EQUIPMENT
Year 1991
Column A Column B Column C Column D Column E Column F
Retirements
Balance Additions or Sales at Other Balance
Classification Jan. 1, At Cost Orig. Cost Changes Dec. 31,
1991 1991
(in thousands)
ELECTRIC PLANT:
Production:
Steam $510,413 $ 7,331 $1,211 $ - $516,533
Other 18,183 26,145 54 - 44,274
Transmission 87,014 1,698 323 1 88,390
Distribution 154,844 7,001 1,228 14 160,631
General 8,733 906 253 5 9,391
Total Electric
Plant $779,187 $ 43,081 $3,069 $ 20 $819,219<F1>
GAS PLANT:
Gas Prod. &
Gathering $ 54 $ - $ - $ - $ 54
Underground
Storage 7,355 358 71 - 7,642
Transmission 10,364 249 5 - 10,608
Distribution 64,852 4,880 459 - 69,273
General 3,651 645 167 - 4,129
Total Gas Plant $ 86,276 $ 6,132 $ 702 $ - $ 91,706<F1>
COMMON PLANT: $ 19,740 $ 2,803 $ 360 $ - $ 22,183
Plant in
Service $885,203 $ 52,016 $4,131 $ 20 $933,108
CONSTRUCTION WORK
IN PROGRESS $ 26,064 $(16,272) $ - $ - $ 9,792
Total Utility
Plant $911,267 $ 35,744 $4,131 $ 20 $942,900
<FN>
<F1>Amounts do not agree with balance sheet totals as common
plant is allocated between electric and gas plant for
financial statement purposes.
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1991 were:
Electric - 3.9%; Gas 3.8%; and Common - 8.2%.
/TABLE
47
SCHEDULE VI
Page 1 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Year 1993
Column A Column B Column C Column D Column E Column F
Additions
Charged to
Balance Costs and Net Other Balance
Classification Jan. 1, Expenses Retirements Changes Dec. 31,
1993 1993
(in thousands)
ELECTRIC PLANT:
Production:
Steam $216,349 $20,197 $ 653 $ - $235,893
Other 16,131 2,188 - - 18,319
Transmission 45,194 3,533 304 - 48,423
Distribution 61,537 5,796 1,393 - 65,940
General 6,676 851 368 (349) 6,810
Total Electric
Plant $345,887 $32,565 $2,718 $(349) $375,385
GAS PLANT:
Gas Prod. &
Gathering $ 23 $ 1 $ - $ - $ 24
Underground
Storage 2,275 91 - - 2,366
Transmission 5,223 381 - - 5,604
Distribution 29,180 2,602 691 - 31,091
General 2,095 278 93 (186) 2,094
Total Gas Plant $ 38,796 $ 3,353 $ 784 $(186) $ 41,179
COMMON PLANT: $ 6,858 $ 2,037 $2,264 $ 535 $ 7,166
Total Utility
Plant $391,541 $37,955 $5,766 $ - $423,730
<FN>
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1993 were:
Electric - 3.9%; Gas 3.6%; and Common - 6.1%.
/TABLE
48
SCHEDULE VI
Page 2 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Year 1992
Column A Column B Column C Column D Column E Column F
Additions
Charged to
Balance Costs and Net Other Balance
Classification Jan. 1, Expenses Retirements Changes Dec. 31,
1992 1992
(in thousands)
ELECTRIC PLANT:
Production:
Steam $196,788 $20,053 $ 492 $ - $216,349
Other 14,039 2,092 - - 16,131
Transmission 42,601 3,377 784 - 45,194
Distribution 57,519 5,566 1,548 - 61,537
General 6,101 812 229 (8) 6,676
Total Electric
Plant $317,048 $31,900 $3,053 $ (8) $345,887
GAS PLANT:
Gas Prod. &
Gathering $ 21 $ 2 $ - $ - $ 23
Underground
Storage 2,212 63 - - 2,275
Transmission 4,860 375 12 - 5,223
Distribution 27,224 2,654 698 - 29,180
General 1,985 301 169 (22) 2,095
Total Gas Plant $ 36,302 $ 3,395 $ 879 $ (22) $ 38,796
COMMON PLANT: $ 5,583 $ 1,703 $ 458 $ 30 $ 6,858
Total Utility
Plant $358,933 $36,998 $4,390 $ - $391,541
<FN>
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1992 were:
Electric - 3.9%; Gas 3.8%; and Common - 6.5%.
49
SCHEDULE VI
Page 3 of 3
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Year 1991
Column A Column B Column C Column D Column E Column F
Additions
Charged to
Balance Costs and Net Other Balance
Classification Jan. 1, Expenses Retirements Changes Dec. 31,
1991 1991
(in thousands)
ELECTRIC PLANT:
Production:
Steam $178,501 $19,880 $1,593 $ - $196,788
Other 12,283 1,756 - - 14,039
Transmission 39,722 3,226 347 - 42,601
Distribution 53,430 5,363 1,274 - 57,519
General 5,560 750 220 11 6,101
Total Electric
Plant $289,496 $30,975 $3,434 $ 11 $317,048
GAS PLANT:
Gas Prod. &
Gathering $ 20 $ 1 $ - $ - $ 21
Underground
Storage 2,205 83 76 - 2,212
Transmission 4,509 356 5 - 4,860
Distribution 25,338 2,500 614 - 27,224
General 1,847 263 136 11 1,985
Total Gas Plant $ 33,919 $ 3,203 $ 831 $ 11 $ 36,302
COMMON PLANT: $ 4,450 $ 1,480 $ 325 $ (22) $ 5,583
Total Utility
Plant $327,865 $35,658 $4,590 $ - $358,933
<FN>
NOTE:Depreciation of utility plant is computed using the
straight-line method over the estimated lives of depreciable
plant. The average depreciation rates for 1991 were:
Electric - 3.9%; Gas 3.8%; and Common - 8.2%.
/TABLE
50
SCHEDULE VIII
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
Additions
Balance Charged Charged Deductions Balance
Beginning to to Other from Re- End of
Description of Year Expenses Accounts serves, Net Year
(in thousands)
VALUATION AND QUALIFYING
ACCOUNTS:
Year 1993 - Accumulated
provision for uncollectible
accounts $ 136 $ 616 $ - $ 586 $ 166
Year 1992 - Accumulated
provision for uncollectible
accounts $ 260 $ 330 $ - $ 454 $ 136
Year 1991 - Accumulated
provision for uncollectible
accounts $ 605 $ 777 $ - $1,122 $ 260
OTHER RESERVES:
Year 1993 - Reserve for
injuries and
damages $ 334 $1,177 $ 97<F1> $ 287 $1,321
Year 1992 - Reserve for
injuries and
damages $ 626 $ 58 $ 58<F1> $ 408 $ 334
Year 1991 - Reserve for
injuries and
damages $1,086 $ 89 $ 122<F1> $ 671 $ 626
<FN>
<F1> Charged to construction accounts
51
SCHEDULE IX
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
SHORT-TERM BORROWINGS
Reference is made to Note 4 of the Notes to
Consolidated Financial Statements, page 35, regarding short-
term borrowings.
52
SCHEDULE X
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
SUPPLEMENTARY INCOME STATEMENT INFORMATION
Reference is made to Note 13 of the Notes to
Consolidated Financial Statements, page 39, regarding taxes
other than income taxes.
Maintenance and depreciation, other than set forth in
the "Consolidated Statements of Income," rents, advertising
costs, research and development and royalties during the
periods were not significant.
53
SCHEDULE XIII
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
OTHER INVESTMENTS
December 31, 1993
Column A Column B Column C
Cost of Each Amount Carried
Type of Investment Investment on Balance Sheet
(in thousands)
Leveraged Leases
JVA 1 - Paper Mill $ 7,219 $ 8,632
JVA 2 - Reservoir 10,069 13,895
MCN Equities - Office Building 6,882 9,501
Dutch Rail Equipment 2,769 2,896
Total Leveraged Leases 26,939 34,924
Limited Partnerships
Low income housing projects 26,821 21,833
Other 2,735 3,190
Total Limited Partnerships 29,556 25,023
Environmental improvement funds
held by Trustee 22,613 22,613
Real estate and other 8,794 7,997
Total other investments $87,902 $90,557
56
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Date: March 28, 1994 SOUTHERN INDIANA GAS AND
ELECTRIC COMPANY
By R. G. Reherman, Chairman, President
and Chief Executive Officer
BY (R. G. Reherman)
R. G. Reherman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signatures Title Date
R. G. Reherman Chairman, President, Chief
Executive Officer (Principal
Executive Officer) March 28, 1994
A. E. Goebel* Senior Vice President, Chief Financial
Officer, Secretary and Treasurer
(Principal Financial
Officer) March 28, 1994
S. M. Kerney* Controller (Principal
Accounting Officer) March 28, 1994
Melvin H. Dodson* )
)
Walter B. Emge* )
)
Robert L. Koch II* )
)
Jerry A. Lamb* )
)
Donald A. Rausch* ) Directors March 28, 1994
)
John H. Schroeder* )
)
Richard W. Shymanski*)
)
Donald E. Smith* )
)
James S. Vinson* )
)
N. P. Wagner* )
*By
(R. G. Reherman, Attorney-in-fact)
SIGECO
10-K
EXHIBIT INDEX
Sequential
Page Number
Exhibits incorporated by reference are found on 42-44
EX-3(b) By-Laws as amended through
September 22, 1993 63-79
EX-4(a) Supplemental Indentures dated May 1, 1993 81-108
EX-10.20 Company's Corporate Performance
Incentive Plan as amended for the
plan year beginning January 1, 1994 110-114
EX-12 Computation of ratio of earnings to
fixed charges 55
EX-21 Subsidiary of the Registrant 56
EX-24 Power-of-Attorney 60-61