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, 1994
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: $473,669,427 at February
28, 1995, 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, 1995
Common Stock, Without Par Value 15,754,826
Documents incorporated by reference (to the extent indicated
herein):
Part of Form 10-K into which
Document document is incorporated
Proxy Statement dated February 23, 1995 relating to the
1995 Annual Meeting of Stockholders Part III
<PAGE> 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 three active wholly-owned nonutility
subsidiaries, Southern Indiana Properties, Inc., Southern
Indiana Minerals, Inc., and Energy Systems Group, Inc., and
one wholly-owned utility subsidiary, Lincoln Natural Gas
Company, Inc. (See Note 1 (a) of the Notes To Consolidated
Financial Statements, page 31, for further discussion.)
Electric service is supplied directly to Evansville
and 74 other cities, towns and communities, and adjacent
rural areas. Wholesale electric service is supplied to an
additional nine communities. At December 31, 1994, the
Company served 118,992 electric customers and was also
obligated to provide for firm power commitments to the City
of Jasper, Indiana and to maintain spinning reserve margin
requirements under an agreement with the East Central Area
Reliability Group (ECAR).
At December 31, 1994, the Company supplied gas service
to 102,929 customers in Evansville and 64 other nearby
communities and their environs. Since 1986, the Company has
purchased its natural gas supply requirements from numerous
suppliers. During 1994, twenty-one suppliers were used.
Until November 1993, Texas Gas Transmission Corporation
(TGTC) was the Company's primary contract supplier. In
November 1993, TGTC restructured its services so that its
gas supplies are sold separately from its interstate
transportation services. The Company assumed full
responsibility for the purchase of all its natural gas
supplies. (See subsequent reference under "Gas Business" to
the restructuring of interstate pipelines.) During 1994,
twenty-two of the Company's major gas customers took
advantage of the Company's gas transportation program to
procure a portion of their gas supply needs from suppliers
other than the Company.
The principal industries served by the Company include
polycarbonate resin (Lexan) and plastic products, aluminum
smelting and recycling, aluminum sheet products, appliance
manufacturing, pharmaceutical and nutritional products,
automotive glass, gasoline and oil products, and coal
mining.
The only property the Company owns outside of Indiana
is approximately eight miles of 138,000 volt electric
transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's
transmission system at Cloverport, Kentucky. The original
cost of the property is less than $425,000. The Company
does not distribute any electric energy in Kentucky.
LINES OF BUSINESS
The percentages of operating revenues and operating
income before income taxes attributable to the electric and
gas operations of the Company for the five years ended
December 31, 1994, were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Electric 79.6% 80.6% 81.8% 79.5% 78.7%
Gas 19.4 18.2 20.8 21.6 20.9
Operating Income Before Income Taxes:
Electric 98.6% 93.0% 97.4% 99.0% 99.4%
Gas 7.0 2.6 1.0 0.5 9.1
<FN>
Periods beginning in 1992 reflect the results of Lincoln Natural Gas
Company, Inc., acquired June 30, 1994.
</FN>
</TABLE>
Reference is made to Note 12 of the Notes To
Consolidated Financial Statements, page 41, for Segments of
Business Data.
<PAGE> 2
ELECTRIC BUSINESS
The Company supplies electric service to 118,996
customers, including 104,049 residential, 14,741 commercial,
179 industrial, 23 public street and highway lighting and
four municipal customers.
The Company's installed generating capacity as of
December 31, 1994 was rated at 1,238,000 kilowatts (Kw).
Coal-fired generating units provide 1,023,000 Kw of capacity
and gas or oil-fired turbines used for peaking or emergency
conditions provide 215,000 Kw.
In addition, the Company has interconnections with
Louisville Gas and Electric Company, CINergy Services, Inc.,
Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric
Corporation, Wabash Valley Power Association, and the City
of Jasper, providing an ability to simultaneously
interchange approximately 750,000 Kw.
Record-breaking peak conditions occurred on July 28,
1993, when the Company's system summer peak load reached
1,012,700 Kw . The 1993 peak was 2.2% greater than the 1994
system summer peak load of 990,800 Kw (the second highest
summer peak in Company history) established July 20, 1994.
The Company's total load obligation for each of the years
1990 through 1994 at the time of the system summer peak, and
the related capacity margin, are presented below. The
Company's other load obligations at the time of the peak
included firm power commitments to the City of Jasper,
Indiana and the Company's reserve margin requirements under
the ECAR agreement.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Date of Summer Peak Load
07-09-90 07-22-91 07-13-92 07-28-93 07-20-94
Company System Peak Load (Kw)
942,700 948,400 916,700 1,012,700 990,800
Other Load Obligations at Peak
70,800 77,480 75,190 87,340 77,000
Total Load Obligations at Peak
1,013,500 1,025,880 991,890 1,100,040 1,067,800
Total Generating Capability (Kw)
1,163,000 <F1>1,238,000 <F1>1,238,000 <F1>1,238,000 <F1>1,238,000
Capacity Margin at Peak
13% 17% 20% 11% 14%
<FN>
<F1> Includes 80,000 Kw gas-fired turbine placed in service May 31,
1991.
</FN>
</TABLE>
The all-time record system winter peak load of 772,000
Kw occurred during the 1993-1994 season on January 19, 1994,
and was slightly greater than the previous record winter
season system peak reached on December 22, 1989 of 771,900
Kw.
The Company, primarily as agent of Alcoa Generating
Corporation (AGC), operates the Warrick Generating Station,
a coal-fired steam electric plant which interconnects with
the Company's system and provides power for the Aluminum
Company of America's Warrick Operations, which includes
aluminum smelting and fabricating facilities. Of the four
turbine generators at the plant, Warrick Units 1, 2 and 3,
with a capacity of 144,000 Kw each, are owned by AGC.
Warrick Unit 4, with a rated capacity of 270,000 Kw, is
owned by the Company and AGC as tenants in common, each
having shared equally in the cost of construction and
sharing equally in the cost of operation and in the output.
The Company (a summer peaking utility) has an
agreement with Hoosier Energy Rural Electric Cooperative,
Inc. (Hoosier Energy) for the sale of firm peaking power to
Hoosier Energy during the annual winter heating season
(November 15-March 15). The contract made available 100 Mw
during the 1994-1995 winter season, and allows for a
possible increase to 250 Mw by November 15, 1998. The
contract will terminate March 15, 2000.
Electric generation for 1994 was fueled by coal
(99.5%) and natural gas (0.5%). Oil was used only to light
fires and stabilize flames in the coal-fired boilers and for
testing of gas/oil fired peaking units.
Historically, coal for the Company's Culley Generating
Station and Warrick Unit 4 has been purchased from operators
of nearby Indiana strip mines pursuant to long-term
contracts. During 1991, the Company pursued negotiations
for new contracts with these mine operators and while doing
so, purchased coal from the respective operators under
interim
<PAGE> 3
agreements. In October 1992, the Company finalized a new
supply agreement effective through 1995 and retroactive to
1991, with one of the operators under which coal is supplied
to both locations. Included in the agreement was a
provision whereby the contract could be reopened by the
Company for modification of certain coal specifications. In
early 1993, the Company reopened the contract for such
modifications. Effective July 1, 1993, the Company bought
out the remainder of its contractual obligations with the
supplier, enabling the Company to acquire lower priced spot
market coal. The Company estimates the savings in coal
costs during the 1991-1995 period, net of the total buy out
costs, will approximate $58 million. The net savings are
being passed back to the Company's electric customers
through the fuel adjustment clause. The coal supplier
retained the right of first refusal to supply Warrick Unit 4
and the Culley plant during the years 1996-2000. (See "Rate
and Regulatory Matters" of Item 7, MANAGEMENT'S DISCUSSION
AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION, page 16, for further discussion of the contract
buy out.) The Indiana coal used in these plants is blended
by the vendor and delivered to the plants to meet
specifications set in conformance with the requirements of
the Indiana State Implementation Plan for sulfur dioxide
issued under Federal laws regulating air quality (Clean Air
Act). Approximately 1,372,000 tons of coal were used during
1994 in the generation of electricity at the Culley Station
and Warrick Unit 4. Culley Units 2 and 3 were recently
equipped with flue gas desulfurization equipment as part of
the Company's Clean Air Act Compliance Plan. (See
"Environmental Matters", page 7, for further discussion.)
For supplying the A. B. Brown Generating Station, the
Company has a contested agreement, possibly extending to
1998, with an area producer. (See Item 3, LEGAL
PROCEEDINGS, page 10, for discussion of litigation with this
producer regarding the coal supply agreement.) The amount
of coal burned at A. B. Brown Generating Station during 1994
was approximately 1,160,000 tons. Both units at the
generating station are equipped with flue gas
desulfurization equipment so that coal with a higher sulfur
content can be used. There are substantial coal reserves in
the southern Indiana area. The average cost of coal
consumed in generating electrical energy for the years 1990
through 1994 was as follows:
<TABLE>
<CAPTION>
Average Cost
Average Cost Average Cost Per Kwh
Year Per Ton Per MMBTU (In Mills)
<S> <C> <C> <C> <C>
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
1994 31.86 1.42 14.91
</TABLE>
The Broadway Turbine Units 1 and 2, Northeast Gas
Turbines and A. B. Brown Gas Turbine, when used for peaking,
reserve or emergency purposes, use natural gas for fuel.
Number 2 fuel oil can also be used in the Broadway Turbine
Units and the Brown Gas Turbine.
All metered electric rates contain a provision for
adjustment in charges for electric energy to reflect changes
in the cost of fuel and the net energy cost of purchased
power through the operation of a fuel adjustment clause
unless certain criteria contained in the regulations are not
met. The principal restriction to recovery of fuel cost
increases is that such recovery is not allowed to the extent
that operating income for the twelve month period provided
in the fuel cost adjustment filing exceeds the operating
income authorized by the Indiana Utility Regulatory
Commission (IURC) in the latest general rate case of the
Company. During 1992-1994, this restriction did not affect
the Company. As prescribed by order of the IURC, the
adjustment factor is calculated based on the estimated cost
of fuel and the net energy cost of purchased power in a
designated future quarter. The order also provides that any
over- or underrecovery caused by variances between estimated
and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor. This
continuous reconciliation of estimated incremental fuel
costs billed with actual incremental fuel costs incurred
closely matches revenues to expenses.
(See "Rate and Regulatory Matters" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 16, for discussion
of the Company's general adjustments in electric rates.)
The Company participates in research and development in
which the primary goal is cost savings through the use of
new technologies. This is accomplished, in part, through
the efforts of the Electric Power Research Institute (EPRI).
In 1994,
<PAGE> 4
the Company paid $829,000 to EPRI to help fund research and
development programs such as advanced clean coal burning
technology.
The Company is participating with 14 other electric
utility companies through Ohio Valley Electric Corporation
(OVEC) in arrangements with the United States Department of
Energy (DOE), to supply the power requirements of the DOE
plant near Portsmouth, Ohio. The sponsoring companies are
entitled to receive from OVEC, and are obligated to pay for
the right to receive, any available power in excess of the
DOE contract demand. The proceeds from the sale of power by
OVEC are designed to be sufficient to meet all of its costs
and to provide for a return on its common stock. During
1994, the Company's participation in the OVEC arrangements
was 1.5%.
The Company participates with 32 other utilities and
other affiliated groups located in eight states comprising
the east central area of the United States, in the East
Central Area Reliability group, the purpose of which is to
strengthen the area's electric power supply reliability.
GAS BUSINESS
The Company supplies natural gas service to 102,929
customers, including 93,719 residential, 8,980 commercial,
226 industrial and four public authority customers, through
2,644 miles of gas transmission and distribution lines.
The Company owns and operates three underground gas
storage fields with an estimated ready delivery from storage
of 3.9 million Dth of gas. Natural gas purchased from the
Company's suppliers is injected into these storage fields
during periods of light demand which are typically periods
of lower prices. The injected gas is then available to
supplement the contracted volumes during periods of peak
requirements. It is estimated that approximately 119,000
Dth of gas per day can be withdrawn from the three storage
fields during peak demand periods on the system.
The gas procurement practices of the Company and
several of its major customers have been altered
significantly during the past eight years as a result of
changes in the natural gas industry. In 1985 and prior
years, the Company purchased nearly its entire gas
requirements from Texas Gas Transmission Corporation (TGTC)
compared to 1994 when a total of 24 suppliers sold gas to
the Company. In total, the Company purchased 15,554,557 Dth
in 1994. In November 1993, TGTC restructured its services so
that its gas supplies are sold separately from its
interstate transportation services. The Company assumed
full responsibility for the purchase of all its natural gas
supplies. (See subsequent reference under "Gas Business" to
the restructuring of interstate pipelines.)
During 1994, twenty-two of the Company's major gas
customers took advantage of the Company's gas transportation
program to procure a portion of their gas supply needs from
suppliers other than the Company. A total of 11,584,538 Dth
was transported for these major customers in 1994 compared
to 11,370,542 Dth transported in 1993. The Company received
fees for the use of its facilities in transporting such gas,
allowing it to offset a portion of the loss of its customary
sales margin with respect to these customers.
(See "Rate and Regulatory Matters" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 16, for discussion
of the Company's general adjustment in gas rates and for
discussion of the FERC Order No. 636 which requires
interstate pipelines to restructure their services so that
gas supplies will be sold separately from interstate
transportation services.)
The all-time record send out occurred during the 1989-
1990 winter season on December 22, 1989, when 223,489 Dth of
gas were delivered to the Company's customers. Of this
amount, 89,614 Dth was purchased, 104,358 Dth was taken out
of the Company's three underground storage fields, and
29,517 Dth was transported to customers under transportation
agreements. The 1993-1994 winter season peak day send out
was 189,717 Dth on February 17, 1993.
The average cost per Dth of gas purchased by the
Company during the past five calendar years was as follows:
1990, $2.84; 1991, $2.71; 1992, $2.77; 1993, $2.85; and
1994, $2.54.
The State of Indiana has established procedures which
result in the Company passing on to its customers the
changes in the cost of gas sold unless certain criteria
contained in the regulations are not met. The principal
restriction to recovery of
<PAGE> 5
gas cost increases is that such recovery is not allowed to
the extent that operating income for the twelve month period
provided the gas cost adjustment filing exceeds the
operating income authorized by the IURC in the latest
general rate case of the Company. During 1992-1994, this
restriction did not affect the Company. Additionally, these
procedures provide for scheduled quarterly filings and IURC
hearings to establish the amount of price adjustments for a
designated future quarter. The procedures also provide for
inclusion in a later quarter of any variances between
estimated and actual costs of gas sold in a given quarter.
This reconciliation process with regard to changes in the
cost of gas sold closely matches revenues to expenses. The
Company's rate structure does not include a weather
normalization-type clause whereby a utility would be
authorized to recover the gross margin on sales established
in its last general rate case, regardless of actual weather
patterns.
Natural gas research is supported by the Company
through the Gas Research Institute in cooperation with the
American Gas Association. Since passage of the Natural Gas
Act of 1978, a major effort has gone into promoting gas
exploration by both conventional and unconventional sources.
Efforts continue through various projects to extract gas
from tight gas sands, shale and coal. Research is also
directed toward the areas of conservation, safety and the
environment.
On December 23, 1993, the Company entered into a
definitive agreement to acquire Lincoln Natural Gas Company,
Inc. (LNG), a small gas distribution company serving
approximately 1,300 customers contiguous to the eastern
boundary of the Company's gas service territory. On June
30, 1994, the Company completed its acquisition of LNG after
receiving the necessary regulatory and shareholder
approvals. The applicable financial data in this filing has
been restated to reflect this acquisition, except where
noted. (See Note 1, of the Notes to Consolidated Financial
Statements, page 31, for further discussion of this
acquisition.)
NONUTILITY SUBSIDIARIES
In addition to its wholly-owned utility subsidiary,
LNG, the Company has three active wholly-owned nonutility
subsidiaries. Southern Indiana Properties, Inc., formed in
1986, invests principally in partnerships (primarily real
estate), leveraged leases and marketable securities. Energy
Systems Group, Inc., incorporated in April 1994, provides
equipment and related design services to industrial and
commercial customers. Southern Indiana Minerals, Inc.,
incorporated in May 1994, processes and markets coal
combustion by-products. (See Note 1 of the Notes to
Consolidated Financial Statements, page 31, for further
discussion.)
PERSONNEL
The Company's network of gas and electric operations
directly involves 780 employees with an additional 182
employed at Alcoa's Warrick Power Plant. Alcoa reimburses
the Company for the entire cost of the payroll and
associated benefits at the Warrick Plant, with the exception
of one-half of the payroll costs and benefits allocated to
Warrick Unit 4, which is jointly owned by the Company and
Alcoa. The total payroll and benefits for Company employees
in 1994 (including all Warrick Plant employees) were $47.5
million, including $5 million of accrued postretirement
benefits other than pensions which the Company is deferring
as a regulatory asset until inclusion in rates. (See Note 1
of the Notes To Consolidated Financial Statements, pages 31-
36, for further discussion of the new financial accounting
standard requiring recognition of these costs effective
January 1, 1993 and related regulatory treatment.) In 1993,
total payroll and benefits were $46.1 million.
On July 1, 1994, the Company signed a new four-year
contract with Local 702 of the International Brotherhood of
Electrical Workers. The contract provides for annual wage
increases of 3.5%, 3.5%, 3.75% and 4.0%. Improvements in
productivity, work practices and the pension plan are also
included, along with initiatives to increase
labor/management cooperation. Additionally, the Company's
Hoosier Division signed a five-year labor contract with
Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The contract provides for annual wage increases of
3.5%, 3.5%, 3.75%, 4.0% and 4.0%. Also included are
improvements in health care coverage costs and pension
benefits.
CONSTRUCTION PROGRAM AND FINANCING
A total of $84,751,000 was spent in 1994 on the
Company's construction program, of which $65,949,000 was for
the electric system, $9,315,000 for the gas system,
$5,368,000 for common utility plant facilities, and
$4,119,000 for the Demand Side Management (DSM) Program.
(See "Demand Side Management" in Item 7, MANAGEMENT'S
DISCUSSION AND
<PAGE> 6
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,
page 21.) Major construction project expenditures in 1994
included $36.4 million to substantially complete the
estimated $103 million (including Allowance for Funds
It Used During Construction) Culley Unit 2 and 3 scrubber
project. (See "Clean Air Act" in Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS, page 20.) The Culley scrubber project was
completed and declared commercially in service on February
1, 1995.
Other than an $11 million increase in short-term debt,
no financing activity occurred during 1994.
For 1995, construction expenditures are presently
estimated to be $40.3 million which includes $6.8 million
for DSM programs. Expenditures in the power production area
are expected to total $8.4 million. The balance of the 1995
construction program consists of $14.3 million for additions
and improvements to other electric system facilities, $7.9
million of additions and improvements to the gas system and
$2.9 million for miscellaneous common utility plant
buildings, fixtures and equipment.
In keeping with the Company's objective to bring new
facilities on line as needed, the construction program and
amount of scheduled expenditures are reviewed periodically
to factor in load growth projections, system planning
requirements, environmental compliance and other
considerations. As a result of this program of periodic
review, construction expenditures may change in the future
from the program as presented herein.
Currently it is estimated that construction
expenditures will total about $230 million for the years
1995-1999 as follows: 1995 - $40 million; 1996 - $49
million; 1997 - $58 million; 1998 - $44 million; and 1999 -
$39 million. This construction program reflects
approximately $47 million for the Company's DSM programs;
however, as discussed in "Demand Side Management" of Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 21, the anticipated
changes in the electric industry may require changes to the
level of future DSM expenditures. While the Company
expects the majority of the construction requirements and an
estimated $90 million of required debt redemptions to be
provided by internally generated funds, external financing
requirements of $55-70 million are anticipated.
The aforementioned amounts relating to the Company's
construction program are in all cases inclusive of Allowance
for Funds Used During Construction.
REGULATION
Operating as a public utility under the laws of
Indiana, the Company is subject to regulation by the Indiana
Utility Regulatory Commission as to its rates, services,
accounts, depreciation, issuance of securities, acquisitions
and sale of utility properties or securities, and in other
respects as provided by the laws of Indiana.
In addition, the Company is subject to regulation by
the Federal Energy Regulatory Commission with respect to the
classification of accounts, rates for its sales for resale,
interconnection agreements with other utilities, and
acquisitions and sale of certain utility properties as
provided by the laws of the United States.
See "Electric Business" and "Gas Business" for further
discussion regarding regulatory matters.
The Company is subject to regulations issued pursuant
to federal and state laws, pertaining to air and water
pollution control. The economic impact of compliance with
these laws and regulations is substantial, as discussed in
detail under "Environmental Matters." The Company is also
subject to multiple regulations issued by both federal and
state commissions under the Federal Public Utility
Regulatory Policies Act of 1978.
As a result of the Company's ownership of LNG and 33%
of Community Natural Gas Company, the Company is a "Holding
Company" as such term is defined under the Public Utility
Holding Company Act of 1935 (the 1935 Act). The Company is
exempt from all provisions of the 1935 Act except for the
provisions of Section 9(A)(2), which pertains to
acquisitions of other utilities.
On December 20, 1994, the Company's Board of Directors
authorized the steps required for a corporate reorganization
<PAGE> 7
in which a holding company would become the parent of the
Company. (See "Holding Company" of Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION, page 18, for further discussion of the
proposed reorganization.)
COMPETITION
The Company does not presently compete for retail
electric or gas customers with the other utilities within
its assigned service areas. As a result of changes brought
about by the National Energy Policy Act of 1992, the Company
may be required to compete (or have the opportunity to
compete) with other utilities and wholesale generators for
sales of electricity to existing wholesale customers of the
Company and other potential wholesale customers. (See
subsequent reference to discussion of this recent
legislation.) The Company currently competes with other
utilities in connection with intersystem bulk power rates.
Some of the Company's customers have, or in the future
could acquire, access to energy sources other than those
available through the Company. (See "Gas Business", page 4,
for discussion of gas transportation.) Although federal
statute allows for bypass of a local distribution (gas
utility) company, Indiana law disallows bypass in most cases
and the Company would likely litigate such an attempt in the
Indiana courts. Additionally, the Company's geographical
location in the corner of the state, surrounded on two sides
by rivers, limits customers' ability to bypass the Company.
There is also increasing interest in research on the
development of sources of energy other than those in general
use. Such competition from other energy sources has not
been a material factor to the Company in the past. The
Company is unable, however, to predict the extent of
competition in the future or its potential effect on the
Company's operations.
As part of its efforts to develop a National Energy
Strategy, Congress has amended the Public Utility Holding
Company Act and the Federal Power Act by enacting the
National Energy Policy Act of 1992 (the Act), which will
affect the traditional structure of the electric utility
industry. (Refer to "National Energy Policy Act of 1992" in
Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 19, for discussion
of the major changes in the electric industry effected by
the Act.)
ENVIRONMENTAL MATTERS
The Company is currently investigating the possible
existence of facilities once owned and operated by the
Company, its predecessors, previous landowners, or former
affiliates of the Company utilized for the manufacture of
gas. Refer to "Environmental Matters" in Item 7,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION, page 19 , for discussion
of the Company's actions regarding the investigation.
The Company is subject to federal, state and local
regulations with respect to environmental matters,
principally air, solid waste and water quality. Pursuant to
environmental regulations, the Company is required to obtain
operating permits for the electric generating plants which
it owns or operates and construction permits for any new
plants which it might propose to build. Regulations
concerning air quality establish standards with respect to
both ambient air quality and emissions from the Company's
facilities, including particulate matter, sulfur dioxide and
nitrogen oxides. Regulations concerning water quality
establish standards relating to intake and discharge of
water from the Company's facilities, including water used
for cooling purposes in electric generating facilities.
Because of the scope and complexity of these regulations,
the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to
predict what other regulations may be adopted in the future.
The Company intends to comply with all applicable valid
governmental regulations, but will contest any regulation it
deems to be unreasonable or impossible to comply with or
which is otherwise invalid.
The implementation of federal and state regulations
designed to protect the environment, including those
hereinafter referred to, involves or may involve review,
certification or issuance of permits by federal and state
agencies. Compliance with such regulations may limit or
prevent certain operations or substantially increase the
cost of operation of existing and future generating
installations, as well as seriously delay or increase the
cost of future construction. Such compliance may also
require substantial investments above those amounts stated
under "Construction Program and Financing", page 5.
All existing Company electric generation facilities
have operating permits from the Indiana Air Board or other
agencies having jurisdiction. In order to secure approval
for these permits, the Company has installed electrostatic
precipitators on all coal-fired units and is operating flue
gas desulfurization (FGD) units to remove sulfur dioxide
from the flue gas at its A. B. Brown
<PAGE> 8
Units 1 and 2 generating facilities. The FGD units at the
Brown Station remove most of the sulfur dioxide from the
flue gas emissions by way of a scrubbing process, thereby
allowing the Company to burn high sulfur southern Indiana
coal at the station.
In October 1990, the U.S. Congress adopted major
revisions to the Federal Clean Air Act. The revisions
impose significant restrictions on future emissions of
sulfur dioxide (SO2) and nitrogen oxide (NOX) from coal-
burning electric generating facilities, including those
owned and operated by the Company. The legislation severely
affects electric utilities, especially those in the Midwest.
Two of the Company's principal coal-fired facilities (A. B.
Brown Units 1 and 2, totaling 500 megawatts of capacity) are
presently equipped with sulfur dioxide removal equipment
(scrubbers) and were not severely affected by the new
legislation. However, 523 megawatts of the Company's coal-
fired generating capacity were significantly impacted by the
lower emission requirements. The Company was required to
reduce total emissions from Culley Unit 3 (250 megawatts),
Warrick Unit 4 (135 megawatts) and Culley Unit 2 (92
megawatts) by approximately 50% to 2.5 lb/MMBTU by January
1995 (Phase I) and to 1.2 lb/MMBTU by January 2000 (Phase
II). The Company met the Phase I emission requirements by
January 1995 with the implemention of its Clean Air Act
Compliance Plan which includes equipping Culley Units 2 and
3 with a sulfur dioxide scrubber, among other provisions.
Unit 1 at Culley Station (46 megawatts) is also subject to
the 1.2 lb/MMBTU restriction by January 2000. The
legislation included various incentives to promote the
installation of scrubbers on units affected by the 1995
deadline. Current regulatory policy allows for the recovery
through rates of all authorized and approved pollution
control expenditures.
(Refer to "Clean Air Act" in Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION, page 20, for discussion of the
Company's Clean Air Act Compliance Plan, which was filed
with the IURC on January 3, 1992 and approved October 14,
1992, and the associated estimated costs. Refer also to
"Construction Program and Financing", page 5, for further
discussion of the Company's Culley scrubber project.)
On April 1, 1994 , the EPA (Region V) issued the
Company a Notice of Violation regarding the exceedance of
quarterly opacity limitations at the Company's Culley
Generating Station for six quarterly periods during 1992-
1993. The Company met with the EPA in May 1994 to present
the Company's voluntary opacity limitation compliance plan
(Compliance Plan), which is designed to eliminate future
exceedances, and which had already been implemented by the
Company. The EPA has since contacted the Company and
accepted the Compliance Plan. The EPA is developing an
Agreed Order based on the accepted Compliance Plan and
subsequent operational performance of the units. A civil
penalty may be levied on the Company by the EPA, but the
amount, if any, of such penalty is not known at this time.
Under the Federal Clean Air Act (the Act), states are
authorized to adopt implementation plans to fulfill the
requirements of the Act. The Indiana Department of
Environmental Management (IDEM), which administers the
Indiana State Implementation Plan, issued to the Company on
October 11, 1994 a Notice of Violation (NOV) regarding
exceedance of quarterly opacity limitations for the first
quarter of 1994 at the Company's Culley Generating Station.
The Company subsequently consented to an Agreed Order and a
civil penalty of $30,000. As previously discussed, actions
had already been taken by the Company to correct compliance
deficiencies with the opacity limitations before the NOV was
issued.
In connection with the use of sulfur dioxide removal
equipment at the A. B. Brown Generating Station, the Company
operates a solid waste landfill for the disposal of
approximately 200,000 tons of residue per year from the
scrubbing process. Renewal of the landfill operating permit
was granted in March 1992 by the Indiana Department of
Environmental Management
(IDEM). The permit expires in January 1997. Additionally,
IDEM granted the Company's request for modification
(expansion) of the landfill, issuing the construction permit
in March 1992.
Under the Federal Water Pollution Control Act of 1972
and Indiana law and regulations, the Company is required to
obtain permits to discharge effluents from its existing
generating stations into the navigable waterways of the
United States. The State of Indiana has received
authorization from the EPA to administer the Federal
discharge permits program in Indiana. Variances from
effluent limitations may be granted by permit on a plant-by-
plant basis where the utility can establish the limitations
are not necessary to assure the protection of aquatic life
and wildlife in and on the body of water into which the
discharge is to be made. The Company has been granted
National Pollution Discharge Elimination System (NPDES)
permits covering miscellaneous waste water and thermal
discharges for all its generating facilities to which the
NPDES is applicable, namely the Culley Station, A. B. Brown
Station, Broadway Station (gas turbines) and Warrick Unit 4.
Such discharge permits are limited in time and must be
renewed at five-year intervals. During 1994, the Company
submitted renewal applications for
<PAGE> 9
these permits. The existing permits will remain in effect
until action is taken by IDEM on the renewal applications.
At present, there are no known enforcement proceedings
concerning water quality pending or threatened against the
Company.
EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of the Company are elected at
the annual organization meeting of the Board of Directors,
held immediately after the annual meeting of stockholders,
and serve until the next such organization meeting, unless
the Board of Directors shall otherwise determine, or unless
a resignation is submitted.
<TABLE>
<CAPTION>
Age at Positions Held During
Name 12/31/94 Past Five Years Dates
<S> <C> <C> <C>
R.G.Reherman 59 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 47 Senior Vice President, Chief
Financial Officer, Secretary and
Treasurer * - Present
J.G.Hurst 51 Senior Vice President and General Manager
of Operations 03-01-92 - Present
Vice President, Gas and Warrick
Operations * - 03-01-92
R. G. Jochum 47 Vice President and Director of Power
Production 07-07-94 - Present
Director of Power
Production 09-13-93 - 07-01-94
G.M.McManus 47 Vice President and Director of Governmental
and Public Relations 03-01-92 - Present
Director of Governmental
Affairs * - 03-01-92
J.W.Picking 63 Vice President and Director
of Gas Operations 03-01-92 - Present
Director of Gas Operations * - 03-01-92
<FN>
* Indicates positions held at least since 1990.
</FN>
</TABLE>
Item 2. PROPERTIES
The Company's installed generating capacity as of
December 31, 1994 was rated at 1,238,000 Kw. The Company's
coal-fired generating facilities are: the Brown Station
with 500,000 Kw of capacity, located in Posey County about
eight miles east of Mt. Vernon, Indiana; the Culley Station
with 388,000 Kw of capacity, and Warrick Unit 4 with
135,000 Kw of capacity. Both the Culley and Warrick
Stations are located in Warrick County near Yankeetown,
Indiana. The Company's gas-fired turbine peaking units are:
the 80,000 Kw Brown Gas Turbine located at the Brown
Station; two Broadway Gas Turbines located in Evansville,
Vanderburgh County, Indiana, with a combined capacity of
115,000 Kw; and, two Northeast Gas Turbines located
northeast of Evansville in Vanderburgh County, Indiana with
a combined capacity of 20,000 Kw. The Brown and Broadway
turbines are also equipped to burn oil. Total capacity of
the Company's five gas turbines is 215,000 Kw and are
generally used only for reserve, peaking or emergency
purposes due to the higher per unit cost of generation.
The Company's transmission system consists of 798
circuit miles of 138,000 and 69,000 volt lines. The
transmission system also includes 26 substations with an
installed capacity of 3,870,349 kilovolt amperes (Kva). The
electric distribution system includes 3,175 pole miles of
lower voltage overhead lines and 186 trench miles of conduit
containing 1,046 miles of
<PAGE> 10
underground distribution cable. The distribution system
also includes 87 distribution substations with an installed
capacity of 1,493,422 Kva and 45,644 distribution
transformers with an installed capacity of 1,805,318 Kva.
The Company owns and operates three underground gas
storage fields with an estimated ready delivery from storage
capability of 3.9 million Dth of gas. The Oliver Field, in
service since 1954, is located in Posey County, Indiana,
about 13 miles west of Evansville. The Midway Field is
located in Spencer County, Indiana, about 20 miles east of
Evansville near Richland, Indiana, and was placed in service
in December 1966. The third field is the Monroe City Field,
located in Knox County, about 10 miles east of Vincennes,
Indiana. The field was placed in service in 1958.
The Company's gas transmission system includes 324
miles of transmission mains, and the gas distribution system
includes 2,320 miles of distribution mains.
The Company's properties, excluding those of its
subsidiaries, are subject to the lien of the First Mortgage
Indenture dated as of April 1, 1932 between the Company and
Bankers Trust Company, New York, as Trustee, as supplemented
by various supplemental indentures, all of which are
exhibits to this report and collectively referred to as the
"Mortgage".
Item 3. LEGAL PROCEEDINGS.
On January 27, 1993, a coal supplier filed a complaint
in the Federal District Court for the Southern District of
Indiana alleging that the Company breached a coal supply
contract between the Company and that supplier. The Company
had notified the supplier that it would not require any
delivery of coal under the contract for at least some part
of 1993. The supplier claims that this action violates
certain minimum purchase requirements imposed by the
contract, and asked the court to require specific
performance of the contract by the Company and for
unspecified monetary damages. The complaint alleges that
the Company is obligated to purchase coal at a minimum rate
of 50,000 tons per month under the contract and in any event
to purchase all of the coal consumed at the Company's A. B.
Brown generating plant below 1,000,000 tons per year. The
contested contract may run until December 31, 1998. The
Company filed counterclaims and disputes that its actions
have violated the terms of the contract. On March 26, 1993,
the Company and the coal supplier agreed to resume coal
shipments but with the invoiced price per ton substantially
lower than the contract price and subject to final outcome
of the litigation. (Refer to "Rate and Regulatory Matters"
in Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS
OF OPERATIONS AND FINANCIAL CONDITION, page 16 of this
report, for discussion of the pricing of this coal to
inventory and the associated ratemaking treatment.) On June
6, 1993, the coal supplier won a summary judgement to
require the Company to take a minimum of 600,000 tons
annually, more or less in equal weekly shipments. The
Company maintains that shipments from the supplier do not
conform to the agreed upon coal specifications in the
contract. This litigation came to trial conclusion based
upon summary judgment motions in June 1994. The U. S.
District Court found in favor of the Company regarding
required coal quality specification and, in the earlier
summary judgment, found in favor of the coal supplier
regarding alleged minimum annual tonnage requirements.
Damages of $1,442,000 were awarded to the coal supplier.
Both parties have initiated appeal procedures and expect the
case to be heard by the Court of Appeals in mid-1995 with a
decision from that court later in 1995. The parties are
also considering mediation. Since the litigation arose due
to the Company's efforts to reduce fuel costs, management
believes that any related costs should be recoverable
through the regulatory ratemaking process.
There are no other pending legal proceedings, other
than ordinary routine litigation incidental to the business,
to which the registrant is a party.
No material legal proceedings were terminated during
the fourth quarter of 1994.
Item 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
None
<PAGE> 11
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:
<TABLE>
<CAPTION>
QUARTERLY PERIOD
1 2 3 4
High Low High Low High Low High Low
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1994 $33-7/8 $28 $30-1/8 $26-1/2 $28-1/2 $26-1/4 $27-1/8 $24
1993 $34-3/4 $32-5/8 $34-7/8 $32-3/8 $34-1/2 $33 $35-1/2 $31-7/8
</TABLE>
As of February 10, 1995 there were 9,332 holders of
record of Common Stock.
Dividends declared and paid per share of Common Stock
during the past two years were:
<TABLE>
<CAPTION>
QUARTERLY PERIOD
<S> <C> <C> <C> <C>
1 2 3 4
1994 $0.4125 $0.4125 $0.4125 $0.4125
1993 $0.4025 $0.4025 $0.4025 $0.4025
</TABLE>
The quarterly dividend on Common Stock was increased to
42-1/4 cents per share in January 1995, payable March 20, 1995.
The payment of cash dividends on Common Stock is, in
effect, restricted by the Mortgage to accumulated surplus,
available for distribution to the Common Stock, earned
subsequent to December 31, 1947, subject to reduction if
amounts deducted from earnings for current repairs and
maintenance and provisions for renewals, replacements and
depreciation of all the property of the Company are less
than amounts specified in the Mortgage. See Section 1.02 of
the Supplemental Indenture dated as of July 1, 1948, as
supplemented. No amount was restricted against cash
dividends on Common Stock as of December 31, 1994, under
this restriction.
The payment of cash dividends on Common Stock is, in
effect, restricted by the Amended Articles of Incorporation
to accumulated surplus, available for distribution to the
Common Stock, earned subsequent to December 31, 1935. The
Amended Articles of Incorporation require that, immediately
after such dividends, there shall remain to the credit of
earned surplus an amount at least equal to two times the
annual dividend requirements on all then outstanding
Preferred Stock, No Par Value. See Art. VI, Terms of
Capital Stock, General Provisions (B). The amount
restricted against cash dividends on Common Stock at
December 31, 1994 under this restriction was $2,209,642,
leaving $215,823,713 unrestricted for the payment of
dividends. In addition, the Amended Articles of
Incorporation provide that surplus otherwise available for
the payment of dividends on Common Stock shall be restricted
to the extent that such surplus is included in a calculation
required to permit the Company to issue, sell or dispose of
preferred stock or other stock senior to the Common Stock
(Art. VI, Terms of Capital Stock, General Provisions (E)).
An order of the Securities and Exchange Commission
dated October 12, 1944 under the Public Utility Holding
Company Act of 1935 in effect restricts the payment of cash
dividends on Common Stock to 75% of net income available for
distribution to the Common Stock, earned subsequent to
December 31, 1943, if the percentage of Common Stock equity
to total capitalization and surplus, as defined, is less
than 25%. At December 31, 1994, such ratio amounted to
approximately 48%.
<PAGE> 12
<TABLE>
<CAPTION>
Item 6. SELECTED FINANCIAL DATA <F1>
for the years ended December 31,
1994 1993 1992 1991 1990
(in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Operating Revenues $330,035 $329,489 $306,905 $322,582 $322,520
Operating Income $ 52,367 $ 51,565 $ 50,895 $ 53,156 $ 51,934
Net Income $ 41,025 $ 39,588 $ 36,758 $ 38,513 $ 37,691
Net Income Applicable
to Common Stock $ 39,920 $ 38,483 $ 35,491 $ 37,232 $ 36,409
Average Common Shares
Outstanding 15,755 15,755 15,755 15,705 16,096
Earnings Per Share of
Common Stock $2.53 $2.44 $2.25 $2.37 $2.26
Dividends Per Share of
Common Stock $1.65 $1.61 $1.56 $1.50 $1.43
Total Assets $917,240 $860,841 $762,133 $747,445 $738,803
Redeemable Preferred
Stock $ 8,515 $ 8,515 $ 8,515 $ 1,100 $ 1,110
Long-Term Obligations $274,467 $274,884 $213,026 $236,844 $257,022
<FN>
<F1> Periods prior to 1992 were not restated to reflect the results of
Lincoln Natural Gas Company, Inc., acquired June 30, 1995, due to
immateriality.
</FN>
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS AND FINANCIAL
CONDITION.
Earnings per share of $2.53 in 1994 were the highest in Company history,
exceeding 1993 earnings of $2.44, the previous all-time high. Earnings in
1992 were $2.25.
The record earnings reflected improved gas and electric margins resulting
from recent rate adjustments, greater sales to the Company's commercial and
industrial electric customers, and increased allowance for funds used
during construction resulting from the Company's expanded construction
program. Expected increases in maintenance and nonfuel-related operating
expenses and a decline in sales to gas customers partially offset the
impact of the higher margins.
At its December 1994 meeting, the Board of Directors authorized the actions
necessary for a corporate reorganization in which a yet to be formed
holding company would become the parent of the Company. Assuming the
Company obtains shareholder approval at its March 1995 annual meeting and
receives the required authorizations from federal regulatory agencies, the
reorganization should be completed by late 1995 (see "Holding Company").
At its January 1995 meeting, the Board of Directors declared a dividend
increase to common shareholders, marking the thirty-sixth consecutive year
of dividend growth. Payable in March 1995, the Company's new quarterly
dividend is 42-1/4 cents per share, increasing the indicated annual rate to
$1.69 per share.
ELECTRIC OPERATIONS. The table below compares changes in operating
revenues, operating expenses and electric sales between 1994 and 1993, and
between 1993 and 1992, in summary form.
<PAGE> 13
<TABLE>
<CAPTION>
Increase
CHANGES IN ELECTRIC OPERATING INCOME (Decrease)
1994 1993
(in thousands)
<S> <C> <C>
Operating Revenues - System $ 4,523 $ 17,586
- Nonsystem (1,992) (2,258)
2,531 15,328
Operating Expenses:
Fuel for electric generation 2,302 (159)
Purchased electric energy (3,859) 6,434
Other operation 7,080 2,274
Maintenance 3,617 3,967
Depreciation and amortization 994 695
Federal and state income taxes (1,225) 1,921
Property and other taxes (3,217) (707)
5,692 14,425
Changes in electric operating income $ (3,161) $ 903
CHANGES IN ELECTRIC SALES - MWh:
System 82,161 319,114
Nonsystem 29,158 (82,600)
111,319 236,514
</TABLE>
The Company's implementation of the first and second steps
of a three-step increase in its base electric rates (see
"Rate and Regulatory Matters"), effective October 1, 1993
and June 29, 1994, respectively, and greater sales to the
Company's commercial and industrial customers were the
primary reasons for the 1% ($2.5 million) increase in
electric operating revenues. Lower per unit fuel costs
recovered in customer rates and lower average unit revenues
from sales to nonsystem electric customers partially offset
the impact of increased base rates and greater sales. In
1993, operating revenues rose 6.3% ($15.3 million) on higher
weather-related sales to retail customers.
System revenues rose an estimated $3.7 million due to the
effect of two increases in base electric rates. Effective
October 1, 1993, the Company implemented the first step
(about 1% of retail revenues, or $1.8 million on an annual
basis) of a three-step increase in its base electric rates
to recover the cost of complying with the Clean Air Act
Amendments of 1990 (see "Rate and Regulatory Matters").
Effective June 29, 1994, the second step (about 2.3% of
retail revenues, or $4.2 million on an annual basis) of the
increase was implemented.
Despite milder winter and summer temperatures, when heating
and cooling degree days were lower than in 1993 by 10% and
8%, respectively, commercial sales rose 2.4% on increased
local economic activity. Residential sales declined about
1%. Due to continued growth in manufacturing activity,
sales to the Company's industrial customers rose 3.2%
following a 5.7% increase in 1993. Total system sales were
up 1.8% over 1993. System sales in 1993 exceeded 1992 sales
by 7.6% due to much warmer summer temperatures.
During 1994, the Company's electric customer base grew by
829, totaling 118,992 at year end.
System revenues declined approximately $2.3 million in 1994
due to recovery of lower unit fuel costs following a $2.7
million increase in 1993 from the recovery of higher unit
fuel costs. Changes in the cost of fuel for electric
generation and purchased power are reflected in customer
rates through commission-approved fuel cost adjustments.
Since 1987, the Company has provided electric energy to
Alcoa Generating Corporation (AGC), a wholly-owned
subsidiary of Alcoa (a wholesale customer), for one of its
six potlines. Due to market conditions in the aluminum
industry, Alcoa shut down the oldest of the six potlines at
the Warrick County manufacturing operation in July 1993.
The Company estimates that the decline in electric sales
related to the potline for 1993 represented approximately
$4.8 million in nonsystem revenues and approximately $.8
million in operating income compared to the prior year.
During 1994, revenue related to the reduced sales to AGC
<PAGE> 14
declined an additional $8.2 million with a corresponding
$1.4 million additional decline in operating income. A
portion of the decline in operating income was offset by
increased sales to other nonsystem customers made possible
by the reduced commitment to AGC. Total nonsystem sales
were 3.2% higher than 1993, due primarily to the
requirements of one nonassociated utility during the first
quarter of 1994. Most sales to nonsystem customers,
including AGC, are on an "as available" basis under
interchange agreements which provide for significantly lower
margins than sales to system customers.
Milder summer temperatures and the peak-shaving effect of
the Company's demand side management programs resulted in a
1994 peak load obligation of 1,068 megawatts, 2.9% lower
than the all-time peak of 1,100 megawatts reached on July
28, 1993, despite the increased demand by industrial
customers. The Company's total generating capacity at the
time of the 1994 peak was 1,238 megawatts, representing a
14% capacity margin.
Although electric generation increased 7.2% as a result of
the increased sales and fewer purchases of electricity from
other utilities, fuel for electric generation, the most
significant electric operating cost, rose only 2.8% due to
lower coal costs and improved plant efficiencies. In 1994,
the Company experienced more favorable volume-related
pricing with its remaining long-term contract supplier and
took advantage of generally lower spot market coal prices.
The Company continues to pursue further reductions in coal
prices as a key component of its strategy to remain a low-
cost provider of electricity (see "Rate and Regulatory
Matters"). The 1993 fuel costs were comparable to 1992; in
each year, a decline in generation offset slightly higher
costs of coal consumed.
The Company reduced its purchases of electricity from other
utilities by 41% compared to the previous year due to lower
energy requirements and internally generated electricity
being more favorably priced compared to that available from
other utilities. Purchased electric energy costs in 1993
were 220% higher than in 1992 due to greater energy
requirements of the Company and the availability of lower-
priced power from other utilities.
Because the Company is undecided whether it will seek
recovery of 1993 and 1994 demand side management
expenditures and postretirement benefits other than pensions
allocable to firm wholesale customers, about $2.5 million of
these costs were expensed. As a result of these expenses,
increased employee benefit costs, higher operating costs at
the A. B. Brown scrubber due to increased generation at that
plant and consulting and legal expenditures related to on-
going coal contract negotiations and litigation (see "Rate
and Regulatory Matters"), other operation expenditures
increased 23.6% ($7.1 million) during the current year,
after an 8.2% rise in 1993.
Expected increases in production plant maintenance activity
were the primary reason for the 14.9% ($3.6 million) rise in
electric maintenance expense. In addition to normal
maintenance project expenditures, the Company performed a
scheduled major turbine generator overhaul on Culley Unit 2,
performed significant repairs to one of the Company's gas
turbine peaking units and incurred greater maintenance costs
on the A. B. Brown scrubber facilities due to the plant's
significantly greater generation. Electric maintenance
expenditures in 1993 rose 20% over 1992, when such costs
were down $4.5 million. Depreciation and amortization
expense increased about 3% in 1994, following a 2% increase
in 1993, reflecting normal additions to utility plant.
While inflation has a significant impact on the replacement
cost of the Company's facilities, only the historical cost
of electric and gas plant investment is recoverable in
revenues as depreciation under the ratemaking principles
followed by the Indiana Utility Regulatory Commission
(IURC), under whose regulatory jurisdiction the Company is
subject. With the exception of adjustments for changes in
fuel and gas costs and margin on sales lost under the
Company's demand side management programs (see "Demand Side
Management"), the Company's electric and gas rates remain
unchanged until a rate application is filed and a general
rate order is issued by the IURC.
Federal and state income tax expense was lower during 1994
due to the decrease in pretax income. Income tax expense
rose $1.9 million in 1993, the result of higher pretax
income and the provision of additional federal income tax
expense to reflect higher tax rates enacted under the
Omnibus Budget Reconciliation Act of 1993. The $3.2 million
decrease in taxes other than income taxes during the current
year reflects adjustments to prior years' provisions for
property taxes related to the favorable outcome of a
property tax appeal.
<PAGE> 15
GAS OPERATIONS. The following table compares changes in
operating revenues, operating expenses and gas sold and
transported between 1994 and 1993, and between 1993 and
1992, in summary form.
<TABLE>
<CAPTION>
Increase
CHANGES IN GAS OPERATING INCOME (Decrease)
1994 1993
<S> <C> <C>
(in thousands)
Operating Revenues - Sales $(2,257) $7,198
- Transportation 272 58
(1,985) 7,256
Operating Expenses:
Cost of gas sold (8,950) 4,616
Other operation 1,113 2,341
Maintenance (37) 662
Depreciation (249) 32
Federal and state income taxes 2,221 (105)
Property and other taxes (46) (57)
(5,948) 7,489
Changes in gas operating income $ 3,963 $ (233)
CHANGES IN GAS SOLD AND TRANSPORTED - MDth:
Sold (1,444) 912
Transported 225 1,609
(1,219) 2,521
</TABLE>
Fewer sales of natural gas and lower gas costs recovered
through retail rates more than offset the impact on gas
operating revenues of the second step (about 4% of gas
revenues, or $2.75 million on an annual basis) of the
Company's two-step increase in its base gas rates, effective
August 1, 1994 (see "Rate and Regulatory Matters"). The
overall decline in 1994 gas revenues was 2.8%.
A 32% decline in industrial sales during 1994 was the
primary reason for an 8.5% drop in the Company's gas sales.
Residential and commercial customer sales also declined,
4.7% and 4.8%, respectively, due to the milder winter
temperatures. Industrial sales were down due to increased
transportation activity of certain large customers; total
deliveries to industrial customers under the Company's sales
and transportation tariffs declined 3.9% primarily due to
the lower production levels of Alcoa, one of the Company's
largest industrial customers (see "Electric Operations").
In 1993, residential and commercial sales were up 12.8% and
10.3%, respectively, due to colder winter weather, and
industrial sales and transportation volumes increased 6.4%
on greater manufacturing activity of several of the
Company's largest customers.
On June 30, 1994, the Company completed its acquisition of
Lincoln Natural Gas Company, Inc. (LNG), a small gas
distribution company serving approximately 1,300 customers
contiguous to the eastern boundary of the Company's gas
service territory. (See Note 1 of the Notes to Consolidated
Financial Statements for further discussion.) In addition
to the LNG customers, 1,200 new gas customers were added to
the Company's system, raising the year end total to 102,929.
The recovery of lower unit gas costs through retail rates in
1994 lowered revenues approximately $1 million following a
$2.7 million increase in revenues related to the recovery of
higher unit costs in the prior year. During the past
several years, the market for purchase of natural gas supply
has been very volatile with the average price ranging from
the low of $1.34 per Dth in February 1992 to the peak of
$2.58 per Dth in May 1993 and then declining to $1.38 per
Dth in October 1994. The volatility of the market reflects
the general tightening of the balance between available
supply and demand after several years of excess supply, and
more recently, the effect of the further deregulation of the
gas pipeline industry (see "Rate and Regulatory Matters").
Changes in the cost of gas sold are passed on to customers
through IURC-approved gas cost adjustments.
<PAGE> 16
Cost of gas sold, the major component of gas operating
expenses, declined 17.5% ($9 million) in 1994 to $42.3
million, following a 9.9% ($4.6 million) increase in 1993.
The lower costs in 1994 reflected a 10.6% decrease in
deliveries to customers and a 7.9% decline in the average
unit cost of gas delivered to customers. The higher cost of
gas sold in 1993 was due to increased deliveries to
customers and higher unit costs.
Although the Company's former primary pipeline supplier,
Texas Gas Transmission Corporation (TGTC), implemented
revised tariffs November 1, 1993 to reflect certain changes
required by Federal Energy Regulatory Commission (FERC)
Order No. 636, the Company's 1994 and 1993 purchased gas
costs were relatively unaffected by the new tariffs. As of
November 1, 1993, TGTC ceased to be a supplier of natural
gas to the Company, and the Company assumed full
responsibility for the purchase of all its natural gas
supplies. (See "Rate and Regulatory Matters" for further
discussion of FERC Order No. 636 and of the impact on future
purchased gas costs and procurement practices of the
Company.)
Following a 31% increase in 1993, other operation and
maintenance expenses were 8.1% ($1.1 million) greater than
the prior year due primarily to expenses associated with an
accelerated program of relocating gas customer meters
outside of customer premises to aid in future operating
efficiencies, greater employee-related benefit costs and
increases in various other operating expenses.
Although the Company has continued to invest in gas plant
due to new business requirements and improvements to the
distribution system, depreciation expense in 1994 declined,
reflecting the impact of a full year of lower depreciation
rates implemented during 1993 as a result of the Company's
gas rate case. Depreciation expense in 1993 was relatively
unchanged from 1992 because lower depreciation rates were
only in effect during five months of 1993.
The significant increase in income tax expense resulted from
higher pretax gas income in 1994; income tax expense in 1993
was comparable to 1992.
OTHER INCOME AND INTEREST CHARGES.
Other income was $1.1 million greater during 1994 due to
increased allowance for equity funds used during
construction, resulting primarily from the continued
construction of the Company's new sulfur dioxide scrubber
(see "Clean Air Act" ). Higher other income in 1993, up
$2.5 million, also resulted from increased allowance for
equity funds used during construction related to the
scrubber project.
Interest expense during the current year and during 1993 was
relatively unchanged. Increased interest expense on short-
term debt during 1994 was offset by additional interest
capitalized due to the increased construction program.
RATE AND REGULATORY MATTERS.
As described in Note 1 of the Notes to Consolidated
Financial Statements, the Company complies with the
provisions of Financial Accounting Standard (FAS) 71,
"Accounting for the Effects of Certain Types of Regulation"
that allows certain costs incurred by the Company that have
been, or are expected to be, approved by regulatory
authorities for recovery through rates, to be deferred as
regulatory assets until recovered by the Company. In the
event the Company determines that it no longer meets the
criteria for following FAS 71, the accounting impact to the
Company would be an extraordinary noncash charge to
operations of an amount that could be material. Criteria
that could give rise to the discontinuance of FAS 71 include
(1) increasing competition that restricts the Company's
ability to establish prices to recover specific costs, and
(2) a significant change in the manner in which rates are
set by regulators from cost-based regulation to another form
of regulation. The Company periodically reviews these
criteria to ensure the continuing application of FAS 71 is
appropriate.
In November 1992, the Company petitioned the IURC requesting
a general increase in gas rates, the first such adjustment
since 1982. On July 21, 1993, the IURC approved an overall
increase of approximately 8%, or $5.5 million in revenues,
in the Company's base gas rates. The increase was
implemented in two equal steps of approximately 4% on August
1, 1993 and August 1, 1994. In addition to seeking relief
for rising operating and maintenance costs and substantial
investment in utility plant over the past decade, the
Company sought to restructure its tariffs, make available
<PAGE> 17
additional services and "unbundle" existing services to
better serve its gas customers and strategically position
itself to address the changes brought about by the continued
deregulation of the natural gas industry.
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its
investment through March 31, 1993 in the Clean Air Act
Compliance project being constructed at the Culley
Generating Station. The majority of the costs are for the
installation of a sulfur dioxide scrubber on Culley Units 2
and 3. (See "Clean Air Act" for further discussion of the
project and previous approval of ratemaking treatment of the
incurred costs.) On September 15, 1993, the IURC granted
the Company's request for a 1% revenue increase,
approximately $1.8 million on an annual basis, which took
effect October 1, 1993. The Company petitioned the IURC on
March 1, 1994 for recovery of financing costs related to the
scrubber construction costs incurred from April 1, 1993
through January 31, 1994, and was granted a 2.3% increase,
approximately $4.2 million on an annual basis, in base
electric retail rates. This second step of the increase was
effective June 29, 1994. On December 22, 1993, the Company
petitioned the IURC for the third of the three planned
general electric rate increases related to its Clean Air Act
Compliance project. The final adjustment is necessary to
cover financing costs related to the balance of the project
construction expenditures, costs related to the operation of
the scrubber, certain nonscrubber-related operating costs
such as additional costs incurred for postretirement
benefits other than pensions beginning in 1993 and the
recovery of demand side management program expenditures (see
"Demand Side Management"). The Company filed its case-in-
chief on May 16, 1994 supporting a $12.4 million, 5.7%
retail rate increase. On October 1, 1994, the Office of the
Utility Consumer Counselor (UCC) filed its case-in-chief.
On rebuttal, the Company reduced its request to $10.5
million reflecting a stipulated agreement with the UCC on
depreciation rates and a reduction in the final estimated
cost of the Clean Air Act Compliance project. The estimated
impact of the UCC's recommendation is a $1.7 million, .7%,
decrease in retail revenues. The major differences between
the Company's request and the UCC's proposal are the
requested rate of return on equity, the recovery of the
additional cost of postretirement benefits other than
pensions, the "fair value" of rate base investment and the
appropriate level of operation and maintenance expenses to
be included in cost of service. All hearings have been
completed and the Company is awaiting the final rate order,
anticipated in early 1995. The Company cannot predict what
action the IURC may take with respect to this proposed rate
increase.
Over the past several years, the Company has been actively
involved in intensive contract negotiations and legal
actions to reduce its coal costs and thereby lower its
electric rates. During 1992, the Company was successful in
negotiating a new coal supply contract with one of its major
coal suppliers. The new agreement, effective through 1995,
was retroactive to 1991. Included in the agreement was a
provision whereby the contract could be reopened by the
Company for modification of certain coal specifications. In
early 1993, the Company reopened the contract for such
modifications. In response, the coal supplier elected to
terminate the contract enabling the Company to buy out the
remainder of its contractual obligations and acquire lower-
priced spot market coal. The cost of the contract buyout in
1993, which was based on estimated tons of coal to be
consumed during the agreement period, and related legal and
consulting services, totaled approximately $18 million. In
1994, the Company incurred additional buyout costs of $.8
million. No additional buyout costs are anticipated for the
remainder of the agreement period. On September 22, 1993,
the IURC approved the Company's request to amortize all
buyout costs to coal inventory during the period
July 1, 1993 through December 31, 1995 and to recover such
costs through the fuel adjustment clause beginning February
1994. The Company estimates the total savings in coal costs
during the 1991-1995 period resulting from the renegotiation
and subsequent buyout, net of the total buyout costs, will
approximate $58 million. The net savings are being passed
back to the Company's electric customers through the fuel
adjustment clause.
The Company is currently in litigation with another coal
supplier. Under the terms of the original contract, the
Company was allegedly obligated to take 600,000 tons of coal
annually. In early 1993, the Company informed the supplier
that it would not require shipments under the contract until
later in 1993. On March 26, 1993, the Company and the
supplier agreed to resume coal shipments under the terms of
a letter agreement which is effective until final
resolution of the current litigation. Under the letter
agreement, the invoiced price per ton would be substantially
lower than the contract price. As approved by the IURC, the
Company has charged the full contract price to coal
inventory for recovery through the fuel adjustment clause.
The difference between the contract price and the invoice
price , $22 million at December 31, 1994, has been deposited
in an escrow account and will be paid to either the
Company's ratepayers or its coal supplier upon resolution of
the litigation. The Company also maintains that shipments
from the supplier do not conform to the agreed upon coal
specifications in the contract. This litigation came to
trial conclusion based upon summary judgment motions in June
<PAGE> 18
1994. The U.S. District Court found in favor of the Company
regarding required coal quality specifications and, in an
earlier summary judgment, found in favor of the coal
supplier regarding alleged minimum annual tonnage
requirements. Both parties have initiated appeal procedures
and expect the case to be heard by the Court of Appeals in
mid-1995 with a decision from that court later in 1995. The
parties are also considering mediation. Since the
litigation arose due to the Company's efforts to reduce fuel
costs, management believes that any related costs should be
recoverable through the regulatory ratemaking process.
In late 1993, in a further effort to reduce coal costs, the
Company and the supplier entered into an additional letter
agreement, effective January 1, 1994, and continuing until
the litigation is resolved, whereby the Company will
purchase an additional 50,000 tons monthly above the alleged
base requirements at a market-competitive price. The price
under this agreement is not subject to revision regardless
of the outcome of the litigation.
In April 1992, the Federal Energy Regulatory Commission
(FERC) issued Order No. 636 (the Order) which required
interstate pipelines to restructure their services. In
August 1992, the FERC issued Order No. 636-A which
substantially reaffirmed the content of the original Order.
Under the Order, the stated purpose of which is to improve
the competitive structure of the natural gas pipeline
industry, existing pipeline sales service was "unbundled" so
that gas supplies are sold separately from interstate
transportation services. Customers, such as the Company and
ultimately its gas customers, could benefit from enhanced
access to competitively priced gas supplies as well as from
more flexible transportation services. Conversely, customer
costs could rise because the Order requires pipelines to
implement new rate design methods which shift additional
demand-related costs to firm customers; additionally, the
FERC has authorized the pipelines to seek recovery of
certain "transition" costs associated with restructuring
from their customers.
On November 2, 1992, the Company's major pipeline supplier,
Texas Gas Transmission Corporation (TGTC), filed a recovery
implementation plan with the FERC as part of its revised
compliance filing regarding the Order. On October 1, 1993,
the FERC accepted, subject to certain conditions, the TGTC
recovery implementation plan (the Plan). The Plan, which
addresses numerous issues related to the implementation of
the requirements of the Order, became effective November 1,
1993. Under new TGTC transportation tariffs, which reflect
the Plan's provisions, the Company will incur additional
annual demand-related charges which will be partially offset
by lower volume-related transportation costs. TGTC has
estimated that the Company's allocation of transition costs
will total approximately $5.2 million, to be incurred over a
three-year period ending the first quarter of 1997, and has
filed and received approval for recovery of $3 million of
these costs. During 1994, the Company was billed $1.3
million of these transition costs, $.4 million of which it
deferred pending authorization by the IURC of recovery of
such costs. The Company has also recognized an additional
$1.7 million of these costs which have not yet been billed.
Since authorization for recovery of transition costs was
recently granted by the IURC to other Indiana utilities,
the Company does not expect the Order to have a detrimental
effect on its financial condition or results of operations.
HOLDING COMPANY.
On December 20, 1994, the Company's Board of Directors
authorized the steps required for a corporate reorganization
in which a yet to be formed holding company would become the
parent of the Company. Three of the Company's four
subsidiaries are expected to also become subsidiaries of the
new holding company. The Company will seek shareholder
approval at the Company's March 28, 1995 annual meeting. In
addition to shareholder approval, approval by the Federal
Energy Regulatory Commission and the Securities and Exchange
Commission is required.
The reorganization is in response to the changes created in
the electric industry by the Energy Policy Act of 1992 and
the need to respond quickly to the more competitive business
environment. The new structure will enable the Company to
better define and separate its regulated and nonregulated
businesses.
If the Company receives the required shareholder and
regulatory approvals, the outstanding shares of Company
common stock would be exchanged on a one-for-one basis for
shares of common stock of the new holding company. All of
the Company's debt securities and all of its outstanding
shares of preferred stock would remain securities of the
Company and be unaffected.
If the necessary approvals are received when expected, the
Company anticipates the reorganization could be completed by
late 1995.
<PAGE> 19
ENVIRONMENTAL MATTERS.
In 1993, the Company expensed $.5 million of anticipated
cost of performing preliminary and comprehensive
investigations of the possible existence of facilities once
owned and operated by the Company, its predecessors,
previous landowners or former affiliates of the Company,
utilized for the manufacture of gas.
These facilities would have been operated from the 1850's
through the early 1950's under industry standards then in
effect. However, due to current environmental regulations,
the Company and other responsible parties may be required to
take remedial action if certain materials are found at the
sites of these former facilities.
The Company completed its initial investigation in early
1994 and identified the existence and general location of
four sites. Although the results of preliminary assessments
of the sites indicated no contamination was present, the
Company elected to conduct more comprehensive testing of the
sites to provide conclusive evidence that no such
contamination exists. Comprehensive testing of three of the
sites was initiated in late 1994; the Company expects to
initiate testing of the fourth site in 1995. Testing of one
site has been completed with no evidence of contamination
present, and testing of the remaining sites should be
completed in 1995. No additional costs for testing are
anticipated at this time.
The Company has notified all known insurance carriers
providing coverage during the probable period of operation
of these facilities of potential claims for coverage of
environmental costs. The Company has not, however, recorded
any receivables representing future recovery from insurance
carriers. Additionally, the Company is attempting to
identify all potentially responsible parties for each site.
The Company has not been named a potentially responsible
party by the Environmental Protection Agency (EPA) for any
of these sites.
The Company does not presently anticipate seeking recovery
of these investigation costs from its ratepayers. If,
however, the specific site investigations indicate that
significant remedial action is required, the Company will
seek recovery of all related costs in excess of amounts
recovered from other potentially responsible parties or
insurance carriers through rates.
Although the IURC has not yet ruled on a pending request for
rate recovery by another Indiana utility of such
environmental costs, the IURC did grant that utility
authority to utilize deferred accounting for such costs
until the IURC rules on the request.
NATIONAL ENERGY POLICY ACT OF 1992.
Key provisions of the National Energy Policy Act of 1992
(the Act) are expected to cause some of the most significant
changes in the history of the electric industry. The
primary purpose of the electric provisions is to increase
competition in electric generation by enabling virtually
nonregulated entities, such as exempt wholesale generators,
to develop power plants, and by providing the FERC authority
to require a utility to provide transmission services,
including the expansion of the utility's transmission
facilities necessary to provide such services, to any entity
generating electricity. Although the FERC may not order
retail wheeling (the transmission of electricity directly to
an ultimate consumer) it may order wheeling of electricity
generated by an exempt wholesale generator or another
utility to a wholesale customer of a regulated utility.
The changes brought about by the Act may require, or provide
opportunities for, the Company to compete with other
utilities and wholesale generators for sales to existing
wholesale customers of the Company and other potential
wholesale customers. The Company has long-term contracts
with its wholesale customers which mitigate the opportunity
for other generators to provide service to them.
Many observers of the electric utility industry, including
major credit rating agencies, certain financial analysts and
some industry executives, have expressed an opinion that
retail wheeling to large retail customers and other elements
of a more competitive business environment will occur in the
electric utility industry, similar to developments in the
telecommunications and natural gas industries. Although
there has been much discussion of the subject during the
past year, most notably in California where the state
regulatory commission staff proposed a plan to implement
<PAGE> 20
retail wheeling, the timing of these projected developments
is uncertain. In addition, the FERC has adopted a position,
generically and on a case-by-case basis, that it will pursue
a more competitive, less regulated, electric utility
industry.
Although the Company is uncertain of the final outcome of
these developments, it is committed to pursuing, and is
moving rapidly to implement, its corporate strategy of
positioning itself as a low-cost energy producer and the
provider of high quality service to its retail as well as
wholesale customers. The Company already has some of the
lowest per-unit administrative, operation and maintenance
costs in the industry, and is continuing its efforts to
further reduce its coal costs.
CLEAN AIR ACT.
To meet the Phase I requirements of the Clean Air Act
Amendments of 1990 and nearly all of the Phase II
requirements, the Company's Clean Air Act Compliance Plan
(the Compliance Plan), which was developed as a least-cost
approach to compliance, proposed the installation of a
single scrubber at the Culley Generating Station to serve
both Culley Unit 2 (92 MW) and Culley Unit 3 (250 MW) and
the installation of state of the art low NOx burners on
these two units. In October 1992, the IURC approved a
stipulation and settlement agreement between the Company and
intervenors essentially approving the Compliance Plan.
Construction of the facilities, originally projected to cost
approximately $115 million including the related allowance
for funds used during construction, began during 1992. This
project, which is on schedule and under budget, will total
approximately $103 million. Under the settlement agreement,
the maximum capital cost of the compliance plan to be
recovered from ratepayers is capped at approximately $107
million, plus any related allowance for funds used during
construction. The estimated annual cost to operate and
maintain the facilities, including the cost of chemicals to
be used in the process, is approximately $4.3 million.
By installing a scrubber, the Company was entitled to apply
to the federal EPA for extra allowances, called "extension
allowances". The Company will receive about 88,500
extension allowances, which it has sold to another party
under a confidential agreement. As part of the IURC-
approved stipulation and agreement, the Company agreed to
credit approximately $2.5 million per year for the period
1995 through 1999 to retail customers to reduce the rate
impact of the Compliance Plan.
With the addition of the scrubber, the Company expects to
exceed the minimum compliance requirements of Phase I of the
Clean Air Act and have available unused allowances, called
"overcompliance allowances", for sale to others. Proceeds
from sales of overcompliance allowances will also be passed
through to customers.
The scrubbing process utilized by the Culley scrubber
produces a salable by-product, gypsum, a substance commonly
used in wallboard and other products. In December 1993, the
Company finalized negotiations for the sale of an estimated
150,000 to 200,000 tons annually of gypsum to a major
manufacturer of wallboard. This scrubber has been operating
in a start-up "test" mode for several months, and by early
January 1995, the Company had shipped several barge loads of
gypsum to the manufacturer. The agreement will enable the
Company to reduce certain operating costs with the proceeds
from the sale of the gypsum, further mitigating the rate
impact of the Compliance Plan.
The rate impact related to the Compliance Plan, estimated to
be 7-8%, is being phased in over a three-year period
beginning in October 1993 (see "Rate and Regulatory Matters"
for further discussion).
<PAGE> 21
DEMAND SIDE MANAGEMENT.
In October 1991, the IURC issued an order approving
expenditures by the Company for development and
implementation of demand side management (DSM) programs.
The primary purpose of the DSM programs is to reduce the
demand on the Company's generating capacity at the time of
system peak requirements, thereby postponing or avoiding the
addition of generating capacity. Thus, the order of the
IURC provided that the accounting and ratemaking treatment
of DSM program expenditures should generally parallel the
treatment of construction of new generating facilities.
Most of the DSM program expenditures are being capitalized
per the IURC order and will be amortized over a 15-year
period beginning at the time the Company reflects such costs
in its rates. The Company is requesting recovery of these
costs in its general electric rate increase request filed
December 22, 1993 (see "Rate and Regulatory Matters"). In
addition to the recovery of DSM program costs through base
rate adjustments, the Company is collecting, through a
quarterly rate adjustment mechanism, most of the margin on
sales lost due to the implementation of DSM programs.
According to projections included in the Company's latest
update of its Integrated Resource Plan (IRP), approved by
the IURC on September 7, 1994, the Company expects to incur
costs of approximately $54 million on DSM programs during
the 1995-1999 period. The projections indicate that by
1999, approximately 118 megawatts of capacity are expected
to have been postponed or eliminated due to these programs.
While the latest projections of DSM expenditures are an
estimated $201 million through the year 2012, they are
estimated to result in incremental savings of approximately
$160 million to ratepayers by deferring the need for
approximately 166 megawatts of new generating capacity.
However, due to the anticipated changes in the electric
industry precipitated by the National Energy Policy Act of
1992, the projected DSM programs, related costs and
associated results are subject to change.
In addition to the utilization of DSM programs, the 1993 IRP
forecasts the need for 125 megawatts of base-load generating
capacity in the early 21st century to meet the future
electricity needs of the Company's customers.
LIQUIDITY AND CAPITAL RESOURCES.
The Company experienced record earnings per share during
1994, and financial performance continued to be solid.
Internally generated cash provided 58.8% of the Company's
construction and DSM program expenditures, despite the
requirements of the Culley scrubber project. Earnings
continued to be of high quality, of which 12.8% represented
allowance for funds used during construction. The ratio of
earnings to fixed charges (SEC method) was 3.7:1, the
embedded cost of long-term debt is approximately 6.6%, and
the Company's long-term debt continues to be rated AA by
major credit rating agencies.
The Company has access to outside capital markets and to
internal sources of funds that together should provide
sufficient resources to meet capital requirements. The
Company does not anticipate any changes that would
materially alter its current liquidity.
Other than an $11 million increase in short-term debt, no
financing activity occurred during 1994, in contrast to 1993
when the Company called $84.5 million of its first mortgage
bonds, at a premium, and refunded them with two $45 million
issues. In addition, the Company retired $20 million of its
maturing first mortgage bonds with a $20 million issue due
2025. To provide financing for a portion of the Culley
scrubber project, the Company issued two series of
adjustable rate first mortgage bonds totaling $45 million in
May 1993 in connection with the sale of Warrick County,
Indiana environmental improvement bonds.
<PAGE> 22
During the five-year period 1995-1999, the Company
anticipates that a total of $90 million of debt securities
will be redeemed.
Construction expenditures, including $4.1 million for DSM
programs, totaled $84.8 million during 1994, compared to the
$80.2 million expended in 1993. As discussed in "Clean Air
Act", construction of the new scrubber continued in 1994,
requiring $36.4 million. The remainder of the 1994
construction expenditures consisted of the normal
replacements and improvements to gas and electric facilities
and of the construction of a $3.7 million vehicle
maintenance facility located at the Company's Norman P.
Wagner Operations Center.
At this time, the Company expects that construction
requirements for the years 1995-1999 will total
approximately $230 million, including approximately $47
million of capitalized expenditures to develop and implement
DSM programs; however, as discussed previously in "Demand
Side Management", the anticipated changes in the electric
industry may require changes to the level of future DSM
expenditures. While the Company expects the majority of the
construction program and debt redemption requirements to be
provided by internally generated funds, external financing
requirements of $55-70 million are anticipated.
At year end, the Company had $22.1 million in short-term
borrowings, leaving unused lines of credit and trust demand
note arrangements totaling $13 million.
The Company is confident that its long-term financial
objectives, which include maintaining a capital structure
near 45-50% long-term debt, 3-7% preferred stock and 43-48%
common equity, will continue to be met, while providing for
future construction and other capital requirements.
<PAGE> 23
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
Page No.
<S> <C> <C>
1. Financial Statements:
Report of Independent Public Accountants 24
Consolidated Statements of Income for the years
ended December 31, 1994, 1993 and 1992 25
Consolidated Statements of Cash Flows for the years
ended December 31, 1994, 1993 and 1992 26
Consolidated Balance Sheets - December 31, 1994
and 1993 27-28
Consolidated Statements of Capitalization -
December 31, 1994 and 1993 29
Consolidated Statements of Retained Earnings for the
years ended December 31, 1994, 1993 and 1992 30
Notes to Consolidated Financial Statements 31-42
2. Supplementary Information:
Selected Quarterly Financial Data 43
3. Supplemental Schedules:
Schedule II - Valuation and Qualifying Accounts and
Reserves for the years ended December 31, 1994,
1993 and 1992 47
<FN>
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.
<FN>
</TABLE>
<PAGE> 24
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE SHAREHOLDERS OF SOUTHERN INDIANA GAS AND ELECTRIC
COMPANY:
We have audited the consolidated balance sheets and
consolidated statements of capitalization of SOUTHERN
INDIANA GAS AND ELECTRIC COMPANY (an Indiana corporation)
AND SUBSIDIARIES as of December 31, 1994 and 1993, and the
related consolidated statements of income, retained earnings
and cash flows for each of the three years in the period
ended December 31, 1994. These financial statements and the
supplemental schedules referred to below are the
responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements and supplemental schedule based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that
we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the consolidated financial statements
referred to above present fairly, in all material respects,
the financial position of Southern Indiana Gas and Electric
Company and Subsidiaries as of December 31, 1994 and 1993,
and the results of their operations and their cash flows for
each of the three years in the period ended December 31,
1994, in conformity with generally accepted accounting
principles.
As discussed in Note 1, effective January 1, 1993, the
Company changed its methods of accounting for income taxes
and postretirement benefits other than pensions.
Our audits were made for the purpose of forming an opinion
on the basic financial statements taken as a whole. The
supplemental schedule listed under Item 8 (3) is presented
for the purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic
financial statements. This supplemental schedule has been
subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion,
fairly states in all material respects the financial data
required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 23, 1995
<PAGE> 25
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
<caption) for the years ended December 31,
1994 1993 1992
(in thousands except per share data)
<S> <C> <C> <C>
OPERATING REVENUES
Electric $260,936 $258,405 $243,077
Gas 69,099 71,084 63,828
Total operating revenues 330,035 329,489 306,905
OPERATING EXPENSES
Operation:
Fuel for electric generation 83,382 81,080 81,239
Purchased electric energy 5,489 9,348 2,914
Cost of gas sold 42,319 51,269 46,653
Other 48,911 40,718 36,103
Total operation 180,101 182,415 166,909
Maintenance 30,355 26,775 22,146
Depreciation and amortization 37,705 36,960 36,233
Federal and state income taxes 19,302 18,306 16,490
Property and other taxes 10,205 13,468 14,232
Total operating expenses 277,668 277,924 256,010
OPERATING INCOME 52,367 51,565 50,895
Other Income:
Allowance for other funds used during
construction 3,972 3,092 988
Interest 988 930 1,015
Other, net 2,685 2,533 2,101
7,645 6,555 4,104
INCOME BEFORE INTEREST CHARGES 60,012 58,120 54,999
Interest Charges:
Interest on long-term debt 18,604 18,437 17,768
Amortization of premium, discount
and expense on debt 852 773 446
Other interest 1,589 747 461
Allowance for borrowed funds used
during construction (2,058) (1,425) (434)
18,987 18,532 18,241
NET INCOME 41,025 39,588 36,758
Preferred Stock Dividends 1,105 1,105 1,267
NET INCOME APPLICABLE TO COMMON STOCK $ 39,920 $ 38,483 $ 35,491
AVERAGE COMMON SHARES OUTSTANDING 15,755 15,755 15,755
EARNINGS PER SHARE OF COMMON STOCK $2.53 $2.44 $2.25
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</FN>
</TABLE>
<PAGE> 26
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION> for the years ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 41,025 $ 39,588 $ 36,758
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 37,705 36,960 36,233
Deferred income taxes and investment tax
credits, net (1,683) 9,459 26
Allowance for other funds used during
construction (3,972) (3,092) (988)
Change in assets and liabilities:
Receivables, net 2,959 (4,087) 3,788
Inventories (8,251) 9,734 (7,232)
Coal contract settlement 5,610 (13,295) -
Accounts payable 1,244 (105) 4,734
Accrued taxes (1,092) (1,837) 2,387
Refunds from gas suppliers 1,755 1,545 12
Refunds to customers 10,285 (412) (3,499)
Accrued coal liability 13,269 8,749 -
Other assets and liabilities 3,638 7,145 (1,808)
Net cash provided by operating
activities 102,492 90,352 70,410
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (net of allowance for
other funds used during construction) (76,660) (72,574) (49,217)
Demand side management program
expenditures (4,119) (4,530) (1,920)
Investments in leveraged leases - (2,769) -
Purchases of investments (7,990) (6,569) (20,532)
Sales of investments 7,258 7,016 21,570
Investments in partnerships (3,430) (2,488) (2,476)
Change in nonutility property (2,922) (862) (1,258)
Other 2,194 307 1,031
Net cash used in investing activities (85,669) (82,469) (52,802)
CASH FLOWS FROM FINANCING ACTIVITIES
First mortgage bonds - 155,000 -
Preferred stock - - 7,500
Dividends paid (27,060) (26,395) (25,764)
Reduction in preferred stock and
long-term debt (105) (104,500) (7,685)
Change in environmental improvement funds
held by Trustee 12,087 (22,613) -
Change in notes payable 11,149 7,650 4,426
Other 434 (5,849) (496)
Net cash (used) provided in financing
activities (3,495) 3,293 (22,019)
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 13,328 11,176 (4,411)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 14,732 3,556 7,967
CASH AND CASH EQUIVALENTS AT END OF
PERIOD $ 28,060 $ 14,732 $ 3,556
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.</FN></TABLE>
<PAGE> 27
<TABLE>
CONSOLIDATED BALANCE SHEETS
<CAPTION> December 31,
1994 1993
(in thousands)
<S> <C> <C>
ASSETS
Utility Plant, at original cost:
Electric $ 907,591 $879,476
Gas 114,951 107,864
__________ ________
1,022,542 987,340
Less-accumulated provision for depreciation 456,922 424,086
__________ ________
565,620 563,254
Construction work in progress 112,316 72,615
Net Utility Plant 677,936 635,869
Other Investments and Property:
Investments in leveraged leases 34,746 34,924
Investments in partnerships 23,411 25,023
Environmental improvement funds held by Trustee 10,526 22,613
Nonutility property and other 12,783 9,861
__________ ________
81,466 92,421
Current Assets:
Cash and cash equivalents 6,042 5,983
Restricted cash 22,018 8,749
Temporary investments, at market 5,444 4,676
Receivables, less allowance of $231 and
$166, respectively 25,582 28,541
Inventories 46,441 38,190
Coal contract settlement 7,685 5,610
Other current assets 2,355 3,048
__________ ________
115,567 94,797
Deferred Charges:
Coal contract settlement - 7,685
Unamortized premium on reacquired debt 6,621 7,100
Postretirement benefits other than pensions 8,011 4,125
Demand side management program 11,530 7,411
Other deferred charges 16,109 11,433
__________ ________
42,271 37,754
$ 917,240 $860,841
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
</FN>
</TABLE>
<PAGE> 28
<TABLE>
<CAPTION>
December 31,
1994 1993
(in thousands)
<S> <C> <C>
SHAREHOLDERS' EQUITY AND LIABILITIES
Common Stock $102,798 $102,798
Retained Earnings 218,424 204,449
Less-unrealized loss on debt and equity
securities 106 -
321,116 307,247
Less-Treasury Stock, at cost 24,540 24,540
Common Shareholders' Equity 296,576 282,707
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 264,110 261,100
Long-Term Partnership Obligations, net of
current maturities 9,507 12,881
Total capitalization, excluding bonds subject to
tender (see Consolidated Statements of
Capitalization) 589,798 576,293
Current Liabilities:
Current Portion of Adjustable Rate Bonds
Subject to Tender 31,500 41,475
Current Maturities of Long-Term Debt, Interim Financing
and Long-Term Partnership Obligations:
Maturing long-term debt 7,803 763
Notes payable 22,060 11,040
Partnership obligations 3,374 3,849
Total current maturities of long-term debt,
interim financing and long-term
partnership obligations 33,237 15,652
Other Current Liabilities:
Accounts payable 35,183 33,939
Dividends payable 125 135
Accrued taxes 6,849 7,941
Accrued interest 4,599 4,517
Refunds to customers 14,844 3,398
Accrued coal liability 22,018 8,749
Other accrued liabilities 16,339 10,125
Total other current liabilities 99,957 68,804
Total current liabilities 164,694 125,931
Deferred Credits and Other:
Accumulated deferred income taxes 120,576 117,267
Accumulated deferred investment tax credits,
being amortized over lives of property 24,702 26,549
Regulatory income tax liability 4,052 7,197
Postretirement benefits other than pensions 8,384 4,125
Other 5,034 3,479
162,748 158,617
$917,240 $860,841
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
</FN></TABLE>
<PAGE> 29
<TABLE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION> December 31,
1994 1993
(in thousands)
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY
Common Stock, without par value, authorized
50,000,000 shares, issued 16,865,003 shares $102,798 $102,798
Retained Earnings, $2,209,642 restricted as
to payment of cash dividends on common stock 218,424 204,449
Less-unrealized loss on debt and equity
securities 106 -
321,116 307,247
Less-Treasury Stock, at cost, 1,110,177 shares 24,540 24,540
296,576 282,707
PREFERRED STOCK
Cumulative, $100 par value, authorized
800,000 shares, issuable in series:
Nonredeemable
4.8% Series, outstanding 85,895 shares,
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 259,615 254,740
Notes payable 5,345 7,263
Unamortized debt premium and discount, net (850) (903)
264,110 261,100
LONG-TERM PARTNERSHIP OBLIGATIONS, NET OF
CURRENT MATURITIES 9,507 12,881
CURRENT PORTION OF ADJUSTABLE RATE POLLUTION
CONTROL BONDS SUBJECT TO TENDER, DUE
2015, Series A, presently 4.60% - 9,975
2015, Series B, presently 3.5% 31,500 31,500
31,500 41,475
Total capitalization, including bonds
subject to tender $621,298 $617,768
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
</FN>
</TABLE>
<PAGE> 30
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION> for the years ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Balance Beginning of Period $204,449 $191,256 $180,787
Net income 41,025 39,588 36,758
245,474 230,844 217,545
Preferred Stock Dividends 1,105 1,105 1,235
Common Stock Dividends ($1.65 per share in 1994,
$1.61 per share in 1993 and $1.56 per
share in 1992) 25,955 25,290 24,529
Capital Stock Expenses (10) - 525
27,050 26,395 26,289
Balance End of Period (See Consolidated
Statements of Capitalization
for restriction) $218,424 $204,449 $191,256
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
</FN>
</TABLE>
<PAGE> 31
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts
of the Company and its wholly-owned subsidiaries Southern
Indiana Properties, Inc., Southern Indiana Minerals, Inc.,
Energy Systems Group, Inc. and Lincoln Natural Gas Company,
Inc. All significant intercompany transactions and balances
have been eliminated.
Southern Indiana Properties, Inc. invests principally in
partnerships (primarily in real estate), leveraged leases
and marketable securities. Energy Systems Group, Inc.,
incorporated in April 1994, provides equipment and related
design services to industrial and commercial customers.
Southern Indiana Minerals, Inc., incorporated in May 1994,
processes and markets coal combustion by-products. The
operating results of these subsidiaries are included in
"Other, net" in the Consolidated Statements of Income.
On June 30, 1994, the Company completed the acquisition of
Lincoln Natural Gas Company, Inc. (LNG), a small gas
distribution company with approximately 1,300 customers
contiguous to the eastern boundary of the Company's gas
service territory. The Company issued 49,399 shares of its
common stock for all common stock of LNG. This transaction
was accounted for as a pooling of interests. Prior period
financial statements have been restated to reflect this
merger and to conform to current period presentation.
(b) REGULATION
The Indiana Utility Regulatory Commission (IURC) has
jurisdiction over all investor-owned gas and electric
utilities in Indiana. The Federal Energy Regulatory
Commission (FERC) has jurisdiction over those investor-owned
utilities that make wholesale energy sales. These agencies
regulate the Company's utility business operations, rates,
accounts, depreciation allowances, services, security issues
and the sale and acquisition of properties. The financial
statements of the Company are based on generally accepted
accounting principles, which give recognition to the
ratemaking and accounting practices of these agencies.
(c) REGULATORY ASSETS
The Company is subject to the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71 "Accounting for
the Effects of Certain Types of Regulation." Regulatory
assets represent probable future revenues to the Company
associated with certain incurred costs which will be
recovered from customers through the ratemaking process.
Because of the expected favorable regulatory treatment, the
following regulatory assets are reflected in the
Consolidated Balance Sheets as of December 31:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Regulatory Assets:
Demand side management program costs $11,530 $ 7,411
Postretirement benefit costs (Note 1(i)) 8,011 4,125
Coal contract buydown costs (Note 2) 7,685 13,295
Unamortized premium on reacquired debt 6,621 7,100
FERC Order No. 636 transition costs (Note 2) 2,147 -
Coal contract litigation costs (Note 2) 1,442 -
Regulatory study costs 1,020 489
Fuel and gas costs (Note 1(m)) 467 394
Total 38,923 32,814
Less current amounts 8,152 6,004
$30,771 $26,810
<FN>
Refer to the individual footnotes referenced above for discussion of
specific regulatory assets.
</FN>
</TABLE>
<PAGE> 32
(d) CONCENTRATION OF CREDIT RISK
The Company's customer receivables from gas and
electric sales and gas transportation services are primarily
derived from a broadly diversified base of residential,
commercial and industrial customers located in a
southwestern region of Indiana. The Company serves 118,992
electric customers in the city of Evansville and 74 other
communities and serves 102,929 gas customers in the city of
Evansville and 64 other communities. The Company
continually reviews customers' creditworthiness and requests
deposits or refunds deposits based on that review. See Note
3 of Notes to Consolidated Financial Statements for a
discussion of receivables related to its leveraged lease
investments.
(e) UTILITY PLANT
Utility plant is stated at the historical original
cost of construction. Such cost includes payroll-related
costs such as taxes, pensions and other fringe benefits,
general and administrative costs and an allowance for the
cost of funds used during construction (AFUDC), which
represents the estimated debt and equity cost of funds
capitalized as a cost of construction. While capitalized
AFUDC does not represent a current source of cash, it does
represent a basis for future cash revenues through
depreciation and return allowances. The weighted average
AFUDC rate (before income tax) used by the Company was 9.5%
in 1994, 10.5% in 1993 and 11.5% in 1992.
(f) DEPRECIATION
Depreciation of utility plant is provided using the
straight-line method over the estimated service lives of the
depreciable plant. Provisions for depreciation, expressed
as an annual percentage of the cost of average depreciable
plant in service, were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
<S> <C> <C> <C>
Electric 4.0% 4.0% 4.0%
Gas 3.3% 3.7% 3.9%
</TABLE>
(g) INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS No.
109, "Accounting for Income Taxes." The standard did not
have a material impact on results of operations, cash flow
or financial position. The Company utilizes the liability
method of accounting for income taxes, providing deferred
taxes on temporary differences. Investment tax credits have
been deferred and are amortized through credits to income
over the lives of the related property.
The components of the net deferred income tax liability
at December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Deferred Tax Liabilities:
Depreciation and cost recovery timing differences $104,783 $100,796
Deferred fuel costs, net 1,624 5,307
Leveraged leases 28,577 27,064
Regulatory assets recoverable through future rates 28,397 27,660
Deferred Tax Assets:
Unbilled revenue (7,571) (6,149)
Regulatory liabilities to be settled through
future rates (32,454) (34,857)
Other, net (2,780) (2,554)
Net deferred income tax liability $120,576 $117,267
</TABLE>
Of the $3,309,000 increase in the net deferred income
tax liability from December 31, 1993 to December 31, 1994,
$234,000 is due to current year deferred federal and state
income tax expense and the remaining $3,075,000 increase is
primarily a result of the change in the net regulatory
assets and liabilities.
<PAGE> 33
The components of current and deferred income tax
expense for the years ended December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Current
Federal $19,739 $ 9,302 $16,152
State 2,722 1,497 2,543
Deferred, net
Federal (1,451) 7,957 (624)
State 138 1,418 292
Investment tax credit, net (1,846) (1,868) (1,873)
Income tax expense as shown on
Consolidated Statements of Income 19,302 18,306 16,490
Current income tax expense included
in Other Income (4,685) (3,608) (3,203)
Deferred income tax expense included
in Other Income 1,547 1,887 1,322
Total income tax expense $16,164 $16,585 $14,609
</TABLE>
The components of deferred federal and state income tax
expense for the years ended December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Depreciation and cost recovery
timing differences $ 3,785 $ 3,923 $ 1,234
Deferred fuel costs (3,680) 5,593 340
Unbilled revenue (1,422) 43 (1,054)
Leveraged leases 1,549 1,887 1,322
Other, net 2 (184) (852)
Total deferred federal and state
income tax expense $ 234 $11,262 $ 990
</TABLE>
A reconciliation of the statutory tax rates to the
Company's effective income tax rate for the years ended
December 31 is as follows:
<TABLE>
<CAPTION>
1994 1993 1992
<S> <C> <C> <C>
Statutory federal and state rate 37.9% 37.9% 37.0%
Equity portion of allowance for funds
used during construction (2.6) (2.1) (0.7)
Book depreciation over related tax
depreciation - nondeferred 2.1 1.9 2.0
Amortization of deferred investment
tax credit (3.2) (3.3) (3.7)
Low-income housing credit (4.8) (4.4) (4.3)
Other, net (1.1) (0.5) (1.9)
Effective tax rate 28.3% 29.5% 28.4%
</TABLE>
(h) PENSION BENEFITS
The Company has trusteed, noncontributory defined benefit
plans which cover eligible full-time regular employees. The
plans provide retirement benefits based on years of service
and the employee's highest 60 consecutive months'
compensation during the last 120 months of employment. The
funding policy of the Company is to contribute amounts to
the plans equal to at least the minimum funding requirements
of the Employee Retirement Income Security Act of 1974
(ERISA) but not in excess of the maximum deductible for
federal income tax purposes. The plans' assets as of
December 31, 1994 consist of investments in interest-bearing
obligations and common stocks of 52% and 48%, respectively.
The components of net pension cost related to these plans
for the years ended December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Service cost - benefits earned
during the period $ 1,963 $ 1,454 $ 1,408
Interest cost on projected benefit
obligation 3,842 3,605 3,390
Actual return on plan assets (469) (2,669) (3,060)
Net amortization and deferral (3,978) (1,712) (1,319)
Net pension cost $ 1,358 $ 678 $ 419
</TABLE>
Part of the pension cost is charged to construction and
other accounts.
<PAGE> 34
The funded status of the trusteed retirement plans at
December 31 is as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Actuarial present value of:
Vested benefit obligation $41,438 $44,502
Accumulated benefit obligation $41,660 $44,742
Plan assets at fair value $49,899 $51,869
Projected benefit obligation 51,511 56,230
Excess of projected benefit obligation over
plan assets (1,612) (4,361)
Remaining unrecognized transitional asset (3,486) (3,904)
Unrecognized net loss 1,397 5,621
Accrued pension liability $(3,701) $(2,644)
</TABLE>
The projected benefit obligation at December 31, 1993
was determined using an assumed discount rate of 7%. Due to
the increase in yields on high quality fixed income
investments, a discount rate of 8% was used to determine the
projected benefit obligation at December 31, 1994. For both
periods, the long-term rate of compensation increases was
assumed to be 5%, and the long-term rate of return on plan
assets was assumed to be 8%. The transitional asset is
being recognized over approximately 15, 18 and 14 years for
the Salaried, Hourly and Hoosier plans, respectively.
In addition to the trusteed pension plans discussed
above, the Company provides supplemental pension benefits to
certain current and former officers under nonqualified and
nonfunded plans. In 1994, the Company charged $1,978,000 to
pension expense representing the projected value of these
future benefits earned as of December 31, 1994, but not yet
recognized. Future annual service cost related to these
benefits will be approximately $150,000.
(i) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company provides certain postretirement health care
and life insurance benefits for retired employees and their
dependents through fully insured plans. Retired employees
are eligible for lifetime medical and life insurance
coverage if they retire on or after attainment of age 55,
regardless of length of service. Their spouses are eligible
for medical coverage until age 65. Prior to 1993, the cost
of retiree health care and life insurance benefits was
recognized as insurance premiums were paid, which was
consistent with ratemaking practices. The costs for
retirees totaled $670,000 in 1992.
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions," which requires the expected cost of
these benefits be recognized during the employees' years of
service. As authorized by the Indiana Utility Regulatory
Commission in a December 30, 1992 generic ruling, the
Company is deferring as a regulatory asset the additional
SFAS No. 106 costs accrued over the costs of benefits
actually paid after date of adoption, but prior to inclusion
in rates.
The components of the net periodic other postretirement
benefit cost for the years ended December 31 are as
follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Service cost - benefits earned during the period $1,133 $ 924
Interest cost on accumulated benefit obligation 2,404 2,463
Amortization of transition obligation 1,472 1,472
Net periodic postretirement benefit cost $5,009 $4,859
Deferred postretirement benefit obligation 3,886 4,125
Charged to operations and construction $1,123 $ 734
</TABLE>
The net periodic cost determined under the new standard
includes the amortization of the discounted present value of
the obligation at the adoption date, $29,400,000, over a 20-
year period.
Because the Company is undecided whether it will seek
recovery of 1993 and 1994 postretirement benefits other than
pensions allocable to firm wholesale customers, $372,000 of
these costs, which had previously been deferred as
regulatory assets, were expensed in 1994.
<PAGE> 35
Reconciliation of the accumulated postretirement
benefit obligation to the accrued liability for
postretirement benefits as of December 31 is as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Accumulated other postretirement benefit obligation:
Retirees $ 11,599 $ 13,096
Other fully eligible participants 6,311 7,120
Other active participants 13,132 15,725
Total accumulated benefit obligation 31,042 35,941
Unrecognized transition obligation (26,491) (27,962)
Unrecognized net loss (gain) 3,833 (3,854)
Accrued postretirement benefit liability $ 8,384 $ 4,125
</TABLE>
The assumptions used to develop the accumulated
postretirement benefit obligation at December 31, 1993
included a discount rate of 7.25% and a health care cost
trend rate of 13.5% in 1994 declining to 5.5% in 2008. Due
to the increase in yields on high quality fixed income
investments, a discount rate of 8.25% was used to determine
the accumulated postretirement benefit obligation at
December 31, 1994. All other actuarial assumptions remained
unchanged at year end. The estimated cost of these future
benefits could be significantly affected by future changes
in health care costs, work force demographics, interest
rates or plan changes. A 1% increase in the assumed health
care cost trend rate each year would increase the aggregate
service and interest costs for 1994 by $750,000 and the
accumulated postretirement benefit obligation by $5,800,000.
The Company anticipates that beginning in 1995,
postretirement benefits costs other than pensions will be
funded as recognized, through a Voluntary Employee Benefit
Association (VEBA) trust.
(j) POSTEMPLOYMENT BENEFITS
In November 1992, the Financial Accounting Standards
Board issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," which requires the Company to
accrue the estimated cost of benefits provided to former or
inactive employees after employment but before retirement.
The Company adopted SFAS No. 112 on January 1, 1994. The
adoption of the new standard did not affect financial
position or results of operations.
(k) CASH FLOW INFORMATION
For the purposes of the Consolidated Balance Sheets and
the Consolidated Statements of Cash Flows, the Company
considers all highly liquid debt instruments purchased with
an original maturity of three months or less to be cash
equivalents.
The Company, during 1994, 1993 and 1992, paid interest
(net of amounts capitalized) of $18,053,000, $18,359,000 and
$17,890,000, respectively, and income taxes of $15,447,000,
$10,248,000 and $14,291,000, respectively. The Company is
involved in several partnerships which are partially
financed by partnership obligations amounting to $12,881,000
and $16,730,000 at December 31, 1994 and 1993, respectively.
(l) INVENTORIES
The Company accounts for its inventories under the
average cost method except for gas in underground storage
which is accounted for under two inventory methods: the
average cost method for the Company's Hoosier Division
(formerly Hoosier Gas Corporation) and the last-in, first-
out (LIFO) method for all other gas in storage. Inventories
at December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Fuel (coal and oil) for electric generation $21,355 $14,533
Materials and supplies 14,678 13,721
Gas in underground storage - at LIFO cost 6,544 6,907
- at average cost 3,864 3,029
Total inventories $46,441 $38,190
</TABLE>
Based on the December 1994 price of gas purchased, the
cost of replacing the current portion of gas in underground
storage exceeded the amount stated on a LIFO basis by
approximately $11,000,000 at December 31, 1994.
<PAGE> 36
(m) OPERATING REVENUES AND FUEL COSTS
Revenues include all gas and electric service billed
during the year except as discussed below.
All metered gas rates contain a gas cost adjustment
clause which allows for adjustment in charges for changes in
the cost of purchased gas. As ordered by the IURC, the
calculation of the adjustment factor is based on the
estimated cost of gas in a future quarter. The order also
provides that any under- or overrecovery caused by variances
between estimated and actual cost in a given quarter, as
well as refunds from its pipeline suppliers, will be
included in adjustment factors of four future quarters
beginning with the second succeeding quarter's adjustment
factor.
All metered electric rates contain a fuel adjustment
clause which allows for adjustment in charges for electric
energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. As ordered by the IURC, the
calculation of the adjustment factor is based on the
estimated cost of fuel and the net energy cost of purchased
power in a future quarter. The order also provides that any
under- or overrecovery caused by variances between estimated
and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor.
The Company also collects through a quarterly rate
adjustment mechanism, the margin on electric sales lost due
to the implementation of demand side management programs.
Reference is made to "Demand Side Management" in
Management's Discussion and Analysis of Operations and
Financial Condition for further discussion.
The Company records monthly any under- or overrecovery
as an asset or liability, respectively, until such time as
it is billed or refunded to its customers. The IURC reviews
for approval the adjustment clauses on a quarterly basis.
The cost of gas sold is charged to operating expense as
delivered to customers and the cost of fuel for electric
generation is charged to operating expense when consumed.
(2) RATE AND REGULATORY MATTERS
On July 21, 1993, the IURC approved an overall increase
of approximately 8%, or $5.5 million in revenues, in the
Company's base gas rates. The increase was implemented in
two equal steps. The first step of the rate adjustment,
approximately 4%, took place August 1, 1993; the second step
of the rate adjustment took place on August 1, 1994.
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its
investment through March 31, 1993 in the Clean Air Act
Compliance (CAAC) project presently being constructed at the
Culley Generating Station. The majority of the costs are
for the installation of a sulfur dioxide scrubber on Culley
Units 2 and 3. On September 15, 1993, the IURC granted the
Company's request for a 1% revenue increase, approximately
$1.8 million on an annual basis, which took effect October
1, 1993. The Company petitioned the IURC on March 1, 1994
for recovery of financing costs related to scrubber
construction expenditures incurred from April 1, 1993
through January 31, 1994, and was granted a 2.3% increase,
approximately $4.2 million on an annual basis, in base
electric retail rates effective June 29, 1994.
On December 22, 1993, the Company petitioned the IURC
for the third of three planned general electric rate
increases related to its CAAC project. The final adjustment
is necessary to cover financing costs related to the balance
of the project construction expenditures, costs related to
the operation of the scrubber, certain nonscrubber-related
operating costs such as additional costs incurred for
postretirement benefits other than pensions beginning in
1993, and the recovery of demand side management program
expenditures. The Company filed its case-in-chief on May
16, 1994 supporting a $12.4 million, 5.7% retail rate
increase. On October 1, 1994, the Office of the Utility
Consumer Counselor (UCC) filed its case-in-chief. On
rebuttal, the Company reduced its request to $10.5 million
reflecting a stipulated agreement with the UCC on
depreciation rates and a reduction in the final estimated
cost of the Clean Air Compliance project. The estimated
impact of the UCC's recommendation is a $1.7 million, .7%,
decrease in retail revenues. The major differences between
the Company's request and the UCC's proposal are the
requested rate of return on equity, the recovery of the
additional cost of postretirement benefits other than
pensions, the fair value of ratebase investment, and the
appropriate level of operation and maintenance expenses to
be included in cost of service. All hearings have been
completed and the Company is awaiting the final rate order,
anticipated in early 1995. The Company cannot predict what
action the IURC may take with respect to this proposed rate
increase.
In April 1992, the Federal Energy Regulatory Commission
(FERC) issued Order No. 636 (the Order) which required
interstate pipelines to restructure their services. In
August 1992, the FERC issued Order No. 636-A which
substantially reaffirmed the content of the original Order.
On November 2, 1992, the Company's major pipeline, Texas Gas
Transmission Corporation (TGTC), filed a recovery
implementation plan with the FERC as part of its revised
compliance filing regarding the Order. On October 1, 1993,
the FERC accepted, subject to certain conditions, the TGTC
recovery implementation plan.
Under the new TGTC transportation tariffs, which became
effective November 1, 1993, the Company will incur
additional annual demand-related charges which will be
partially offset by lower volume-related transportation
costs. TGTC has estimated that the Company's allocation of
transition costs will total approximately $5.2 million, to
be incurred over a
<PAGE> 37
three-year period ending the first quarter of 1997, and has
filed and received approval for recovery of $3 million of
these costs. During 1994, the Company was billed $1,285,000
of these transition costs, $445,000 of which it deferred
pending authorization by the IURC of recovery of such costs.
The Company has also recognized an additional $1.7 million
of these costs, which have not yet been billed. Since
authorization for the recovery of transition costs was
recently granted by the IURC to other Indiana utilities, the
Company does not expect the Order to have a detrimental
effect on its financial condition or results of operations.
Over the past several years, the Company has been
involved in contract negotiations and legal actions to
reduce its coal costs. During 1992, the Company
successfully negotiated a new coal supply contract with a
major supplier which was retroactive to 1991 and effective
through 1995. In 1993, the Company exercised a provision of
the agreement which allowed the Company to reopen the
contract for the modification of certain coal
specifications. In response, the coal supplier elected to
terminate the contract enabling the Company to buy out the
remainder of its contractual obligations and acquire lower
priced spot market coal.
The cost of the contract buyout in 1993, which was
based on estimated tons of coal to be consumed during the
agreement period, and related legal and consulting services,
totaled approximately $18 million. In 1994, the Company
incurred additional buyout costs of $.8 million. No
additional buyout costs are anticipated for the remainder of
the agreement period. On September 22, 1993, the IURC
approved the Company's request to amortize all buyout costs
to coal inventory during the period July 1, 1993 through
December 31, 1995 and to recover such costs through the fuel
adjustment clause beginning February 1994. As of December
31, 1994, $7,685,000 of settlement costs paid to date had
not yet been amortized to coal inventory.
The Company is currently in litigation with another
coal supplier. Under the terms of the contract, the
Company was allegedly obligated to take 600,000 tons of coal
annually. In early 1993, the Company informed the supplier
that it would not require shipments under the contract until
later in 1993. On March 26, 1993, the Company and the
supplier agreed to resume coal shipments under the terms of
a letter agreement which is effective until final resolution
of the current litigation. Under the letter agreement the
invoiced price per ton would be substantially lower than the
contract price. As approved by the IURC, the Company has
charged the full contract price to coal inventory for
recovery through the fuel adjustment clause. The difference
between the contract price and the invoice price,
$22,018,000 at December 31, 1994, has been deposited in an
escrow account with an offsetting accrued liability which
will be paid to either the Company's ratepayers or its coal
supplier upon resolution of the litigation. The Company
also maintains that shipments from the supplier do not
conform to the agreed upon coal specifications in the
contract. This litigation came to trial conclusion based
upon summary judgment motions in June 1994. The U.S.
District Court found in favor of the Company regarding
required coal quality specifications and, in an earlier
summary judgement, found in favor of the coal supplier
regarding alleged minimum annual tonnage requirements. Both
parties have initiated appeal procedures and expect the case
to be heard by the Court of Appeals in mid-1995 with a
decision from that court later in 1995. The parties are
also considering mediation. Since the litigation arose due
to the Company's efforts to reduce fuel costs, management
believes that any related costs should be recoverable
through the regulatory ratemaking process.
In late 1993, in a further effort to reduce coal
costs, the Company and the supplier entered into an
additional letter agreement, effective January 1, 1994, and
continuing until the litigation is resolved, whereby the
Company will purchase an additional 50,000 tons monthly
above the alleged base requirements at a market-competitive
price. The price under this agreement is not subject to
revision regardless of the outcome of the litigation.
Reference is made to "Rate and Regulatory Matters" in
Management's Discussion and Analysis of Operations and
Financial Condition for further discussion of these matters.
(3) LEVERAGED LEASES
Southern Indiana Properties, Inc. is a lessor in four
leveraged lease agreements under which an office building, a
part of a reservoir, an interest in a paper mill and
passenger railroad cars are leased to third parties. The
economic lives and lease terms vary with the leases. The
total equipment and facilities cost was approximately
$101,200,000 at December 31, 1994 and 1993, respectively.
The cost of the equipment and facilities was partially
financed by nonrecourse debt provided by lenders, who have
been granted an assignment of rentals due under the leases
and a security interest in the leased property, which they
accepted as their sole remedy in the event of default by the
lessee. Such debt amounted to approximately $77,900,000 and
$78,700,000 at December 31, 1994 and 1993, respectively.
The Company's net investment in leveraged leases at those
dates was $6,169,000 and $8,184,000, respectively, as shown:
<PAGE> 38
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Minimum lease payments receivable $62,624 $64,120
Estimated residual value 22,095 22,095
Less unearned income 49,973 51,291
Investment in lease financing receivables and loans 34,746 34,924
Less deferred taxes arising from leveraged leases 28,577 26,740
Net investment in leveraged leases $ 6,169 $ 8,184
</TABLE>
(4) SHORT-TERM FINANCING
The Company has trust demand note arrangements totaling
$17,000,000 with several banks, of which $13,000,000 was
utilized at December 31, 1994. Funds are also borrowed
periodically from banks on a short-term basis, made
available through lines of credit. These available lines of
credit totaled $18,000,000 at December 31, 1994 of which
$9,000,000 was utilized at that date.
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Notes Payable:
Balance at year end $22,060 $11,040 $5,000
Weighted average interest rate on
year end balance 6.83% 3.44% 3.59%
Average daily amount outstanding
during the year $13,827 $ 6,992 $ 309
Weighted average interest rate on
average daily amount outstanding
during the year 5.46% 3.36% 3.91%
</TABLE>
(5) LONG-TERM DEBT
The annual sinking fund requirement of the Company's
first mortgage bonds is 1% of the greatest amount of bonds
outstanding under the Mortgage Indenture. This requirement
may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in
the Mortgage Indenture. The Company intends to meet the
1995 sinking fund requirement by this means and,
accordingly, the sinking fund requirement for 1995 is
excluded from current liabilities on the balance sheet. At
December 31, 1994, $163,063,000 of the Company's utility
plant remained unfunded under the Company's Mortgage
Indenture.
Several of the Company's partnership investments have
been financed through obligations with such partnerships.
Additionally, the Company's investments in leveraged leases
have been partially financed through notes payable to banks.
Of the amount of first mortgage bonds, notes payable, and
partnership obligations outstanding at December 31, 1994,
the following amounts mature in the five years subsequent to
1994: 1995 - $11,178,000; 1996 - $12,340,000; 1997 -
$2,712,000; 1998 - $16,617,000; and 1999 - $47,074,000.
In addition, $31,500,000 of adjustable rate pollution
control series first mortgage bonds could, at the election
of the bondholder, be tendered to the Company in May 1995.
If the Company's agent is unable to remarket any bonds
tendered at that time, the Company would be required to
obtain additional funds for payment to bondholders. For
financial statement presentation purposes those bonds
subject to tender in 1995 are shown as current liabilities.
<PAGE> 39
First mortgage bonds, notes payable and partnership
obligations outstanding and classified as long-term at
December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
First Mortgage Bonds due:
1995, 4-3/4$ $ - $ 5,000
1996, 6% 8,000 8,000
1998, 6-3/8% 12,000 12,000
1999, 6% 45,000 45,000
2003, 5.60% Pollution Control Series A 5,140 5,240
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
2023, 7.60% 45,000 45,000
2025, 7-5/8% 20,000 20,000
Adjustable Rate Pollution Control:
2015, Series A, presently 4.60% 9,975 -
Adjustable Rate Environmental Improvement:
2023, Series B, presently 6% 22,800 22,800
2028, Series A, presently 4.65% 22,200 22,200
$259,615 $254,740
Notes Payable:
Banks, due 1996 through 1999, presently 8% to 9% $ 4,345 $ 6,263
Tax Exempt, due 2003, 6.25% 1,000 1,000
$ 5,345 $ 7,263
Partnership Obligations, due 1996 through 2001,
without interest $ 9,507 $ 12,881
</TABLE>
(6) CUMULATIVE PREFERRED STOCK
The amount payable in the event of involuntary
liquidation of each series of the $100 par value preferred
stock is $100 per share, plus accrued dividends.
The nonredeemable preferred stock is callable at the
option of the Company as follows:
4.8% Series at $110 per share, plus accrued dividends;
and
4.75% Series at $101 per share, plus accrued dividends.
(7) CUMULATIVE REDEEMABLE PREFERRED STOCK
On December 8, 1992, the Company issued $7,500,000 of
its Cumulative Redeemable Preferred Stock to replace a like
amount of 8.75% of Cumulative Preferred Stock. The new
series has an interest rate of 6.50% and is redeemable at
$100 per share on December 1, 2002. In the event of
involuntary liquidation of this series of $100 par value
preferred stock, the amount payable is $100 per share, plus
accrued dividends.
(8) CUMULATIVE SPECIAL PREFERRED STOCK
The Cumulative Special Preferred Stock contains a
provision which allows the stock to be tendered on any of
its dividend payment dates. On April 1, 1992, the Company
repurchased 850 shares of the Cumulative Special Preferred
Stock at a cost of $85,000 as a result of a tender within
the provision of the issuance.
(9) COMMITMENTS AND CONTINGENCIES
The Company presently estimates that approximately
$40,000,000 will be expended for construction purposes in
1995, including those amounts applicable to the Company's
demand side management (DSM) programs. Commitments for the
1995 construction program are approximately $21,000,000 at
December 31, 1994. Reference is made to "Demand Side
Management" in Management's Discussion and Analysis of
Operations and Financial Condition for discussion of the
implementation of the Company's DSM programs.
In 1993, the Company expensed $500,000 for the
anticipated cost of performing preliminary and comprehensive
investigations of the possible existence of facilities once
owned and operated by the Company, its predecessors,
previous landowners or former affiliates of the Company
utilized for the manufacture of gas. The Company completed
<PAGE> 40
its initial investigations in early 1994 and identified the
existence and general location of four sites at which
contamination may be present. The Company completed its
preliminary assessments of all four sites in 1994. Although
the results of the preliminary assessments of the sites
indicated no contamination was present, the Company elected
to conduct more comprehensive testing to provide conclusive
evidence that no such contamination exists. Comprehensive
testing of three of the sites was initiated in late 1994;
the Company expects to initiate testing of the fourth site
in 1995. Testing of one site has been completed with no
evidence of contamination present, and testing of the
remaining sites should be completed in 1995. No additional
costs for testing are anticipated at this time. The Company
is attempting to identify all potentially responsible
parties for each site. The Company has not been named a
potentially responsible party by the Environmental
Protection Agency for any of these sites.
The Company does not presently anticipate seeking
recovery of these investigation costs from its ratepayers.
If the specific site investigations indicate that
significant remedial action is required, the Company will
seek recovery of all related costs in excess of amounts
recovered from other potentially responsible parties or
insurance carriers through rates.
Although the IURC has not yet ruled on a pending
request for rate recovery by another Indiana utility of such
environmental costs, the IURC did grant that utility
authority to utilize deferred accounting for such costs
until the IURC rules on the request.
(10) COMMON STOCK
Since 1986, the Board of Directors of the Company
authorized the repurchase of up to $25,000,000 of the
Corporation's common stock. As of December 31, 1994, the
Company had accumulated 1,110,177 common shares with an
associated cost of $24,540,000 under this plan.
On January 21, 1992, the Board of Directors of the
Company approved a four-for-three common stock split
effective March 30, 1992. The stock split was authorized by
the IURC on March 18, 1992. Average common shares
outstanding, earnings per share of common stock and
dividends per share of common stock as shown in the
accompanying financial statements have been adjusted to
reflect the split. Shares issued during 1992 as a result of
the stock split were 3,923,706.
On June 30, 1994, the Company completed its acquisition
of Lincoln Natural Gas Company, Inc. (LNG). The Company
issued 49,399 shares of common stock for all common stock of
LNG. Average common shares outstanding, earnings per share
of common stock and dividends per share of common stock as
shown in the accompanying financial statements have been
restated to reflect the issued shares. No shares of common
stock were issued during 1993.
After obtaining stockholder approval at the Company's
1994 Annual Stockholders Meeting, the Company established a
common stock option plan for key management employees of the
Company. During 1994, 153,666 options were granted to
participants, of which 76,996 options are exercisable one
year after the grant date. Since the impact of the
outstanding options on earnings per share is antidilutive,
only primary earnings per share have been presented.
Each outstanding share of the Company's stock contains
a right which entitles registered holders to purchase from
the Company one one-hundredth of a share of a new series of
the Company's Redeemable Preferred Stock, no par value,
designated as Series 1986 Preferred Stock, at an initial
price of $120.00 (Purchase Price) subject to adjustment.
The rights will not be exercisable until a party acquires
beneficial ownership of 20% of the Company's common shares
or makes a tender offer for at least 30% of its common
shares. The rights expire October 15, 1996. If not
exercisable, the rights in whole may be redeemed by the
Company at a price of $.01 per right at any time prior to
their expiration. If at any time after the rights become
exercisable and are not redeemed and the Company is involved
in a merger or other business combination transaction,
proper provision shall be made to entitle a holder of a
right to buy common stock of the acquiring company having a
value of two times such Purchase Price.
(11) OWNERSHIP OF WARRICK UNIT 4
The Company and Alcoa Generating Corporation (AGC), a
subsidiary of Aluminum Company of America, own the 270 MW
Unit 4 at the Warrick Power Plant as tenants in common.
Construction of the unit was completed in 1970. The cost of
constructing this unit was shared equally by AGC and the
Company, with each providing its own financing for its share
of the cost. The Company's share of the cost of this unit
at December 31, 1994 is $30,914,000 with accumulated
depreciation totaling $19,045,000. AGC and the Company also
share equally in the cost of operation and output of the
unit. The Company's share of operating costs is included in
operating expenses in the Consolidated Statements of Income.
<PAGE> 41
(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:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Operating Information-
Operating revenues:
Electric $260,936 $258,405 $243,077
Gas 69,099 71,084 63,828
Total 330,035 329,489 306,905
Operating expenses, excluding provision
for income taxes:
Electric 195,790 188,875 176,371
Gas 62,576 70,743 63,149
Total 258,366 259,618 239,520
Pretax operating income:
Electric 65,146 69,530 66,706
Gas 6,523 341 679
Total 71,669 69,871 67,385
Allowance for funds used during
construction 6,030 4,517 1,422
Other income, net 535 1,742 1,235
Interest charges (21,045) (19,957) (18,675)
Provision for income taxes (16,164) (16,585) (14,609)
Net income per accompanying
Consolidated Statements of Income $ 41,025 $ 39,588 $ 36,758
Other Information-
Depreciation and amortization expense:
Electric $ 34,475 $ 33,481 $ 32,786
Gas 3,230 3,479 3,447
Total $ 37,705 $ 36,960 $ 36,233
Capital expenditures:
Electric <F1> $ 74,577 $ 74,246 $ 44,387
Gas 10,174 5,950 7,738
Total $ 84,751 $ 80,196 $ 52,125
Investment Information-
Identifiable assets <F2>:
Electric $718,154 $672,771 $591,778
Gas 102,762 94,479 90,305
Total $820,916 $767,250 $682,083
Nonutility plant and other investments 70,256 67,944 62,318
Assets utilized for overall Company
operations 26,068 25,647 17,732
Total assets $917,240 $860,841 $762,133
<FN>
<F1> Includes $4,119,000, $4,530,000 and $1,920,000 of demand side
management program expenditures for 1994, 1993 and 1992, respectively.
<F2> Utility plant less accumulated provision for depreciation,
inventories, receivables (less allowance) and other identifiable assets.
</FN> </TABLE>
(13) DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The company adopted in 1994 SFAS 115, "Accounting for
Certain Investments in Debt and Equity Securities," which
requires accounting for certain investment in debt or equity
securities at either amortized cost or fair value. Of the
$5,444,000 of temporary investments, $2,990,000 are
available-for-sale securities and $200,000 are held-to-
maturity securities. Nonutility property and other includes
<PAGE> 42
of held-to-maturity securities, which are valued at
amortized cost. The unrealized loss, net of tax, of
$106,000 on these investments is recorded as a separate
component of shareholders' equity.
The carrying amount and estimated fair values of the
Company's financial instruments at December 31 are as
follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
(in thousands)
<S> <C> <C> <C> <C>
Cash and Temporary Investments $ 33,504 $ 33,479 $ 19,408 $ 19,609
Noncurrent held-to-maturity
securities 1,752 1,752 - -
Long-Term Debt (including current
portion) 303,413 289,480 303,338 323,776
Partnership Obligations 12,881 11,597 16,730 14,447
Redeemable Preferred Stock 7,500 6,608 7,500 7,135
</TABLE>
At December 31, 1994, the carrying amounts of the
Company's debt relating to utility operations exceeded fair
market value by $14,000,000. Fair value of long-term debt
at December 31, 1993 exceeded carrying amounts by
$20,400,000. Anticipated regulatory treatment of the excess
or deficiency of fair value over carrying amounts of the
Company's long-term debt, if in fact settled at amounts
approximating those above, would dictate that these amounts
be used to reduce or increase the Company's rates over a
prescribed amortization period. Accordingly, any settlement
would not result in a material impact on the Company's
financial position or results of operations.
The following methods and assumptions were used to
estimate the fair value of each class of financial
instruments for which it is practicable to estimate that
value:
CASH AND TEMPORARY INVESTMENTS
The carrying amount is based on fair value or amortized
cost. The fair value was determined based on current market
values.
NONUTILITY PROPERTY AND OTHER
Included in Nonutility property are held-to-maturity
debt securities. Held-to-maturity debt securities are
valued at amortized cost, which approximates fair value.
LONG-TERM DEBT
The fair value of the Company's long-term debt was
estimated based on the current quoted market rate of
utilities with a comparable debt rating. Nonutility long-
term debt was valued based upon the most recent debt
financing.
PARTNERSHIP OBLIGATIONS
The fair value of the Company's partnership obligations
was estimated based on the current quoted market rate of
comparable debt.
REDEEMABLE PREFERRED STOCK
Fair value of the Company's redeemable preferred stock
was estimated based on the current quoted market of
utilities with a comparable debt rating.
<PAGE> 43
<TABLE>
<CAPTION>
SELECTED QUARTERLY FINANCIAL DATA
(Unaudited) Quarters Ended
<S><C> <C> <C> <C> <C> <C> <C> <C>
March 31, June 30, September 30, December 31,
1994 1993 1994 1993 1994 1993 1994 1993
(in thousands except per share data)
Operating Revenues
$104,723 $93,581 $74,258 $76,123 $77,206 $82,883 $73,848 $76,902
Operating Income
$ 17,218 $16,140 $10,316 $12,666 $17,294 $17,440 $ 7,539 $ 5,319
Net Income
$ 14,660 $12,711 $ 8,007 $ 9,194 $14,137 $14,766 $ 4,221 $ 2,917
Earnings Per Share of Common Stock
$0.91 $0.79 $0.49 $0.57 $0.88 $0.92 $0.25 $ 0.17
Average Common Shares Outstanding
15,755 15,755 15,755 15,755 15,755 15,755 15,755 15,755
<FN>
Periods prior to the quarter ended June 30, 1994 were restated to
reflect the results of Lincoln Natural Gas, Inc. acquired June 30, 1994.
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.
</TABLE>
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.
<PAGE> 44
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 23,
(a) 2) filed as part of this report.
(a) 3) Exhibits:
EX-2(a)Merger Agreement - Plan of Reorganization and
Agreement of Merger, by and among: Southern Indiana Gas and
Electric Company; Southern Indiana Group, Inc.; Horizon
Investments, Inc.; and MPM Investment Corporation, dated
August 27, 1987. (Physically filed and designated as
Exhibit A in Form S-4 Registration Statement filed
November 12, 1987, File No. 33-18475.)
EX-3(a)Amended Articles of Incorporation as amended
March 26, 1985. (Physically filed and designated in Form
10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit
3-A.) Articles of Amendment of the Amended Articles of
Incorporation, dated March 24, 1987. (Physically filed and
designated in Form 10-K for the fiscal year 1987, File No.
1-3553, as Exhibit 3-A.) Articles of Amendment of the
Amended Articles of Incorporation, dated November 27, 1992.
(Physically filed and designated in Form 10-K for the fiscal
year 1992, File No. 1-3553, as Exhibit 3-A).
EX-3(b)By-Laws as amended through December 18, 1990.
(Physically filed in Form 10-K for the fiscal year 1990,
File No. 1-3553, as Exhibit 3-B.) By-Laws as amended
through September 22, 1993. (Physically filed and
designated in Form 10-K for the fiscal year 1993, File No.
1-3553, as EX-3 (b).)
EX-4(a)*Mortgage and Deed of Trust dated as of April 1,
1932 between the Company and Bankers Trust Company, as
Trustee, and Supplemental Indentures thereto dated August
31, 1936, October 1, 1937, March 22, 1939, July 1, 1948,
June 1, 1949, October 1, 1949, January 1, 1951,
April 1, 1954, March 1, 1957, October 1, 1965, September 1,
1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1,
1972, October 1, 1973, April 1, 1975, January 15, 1977,
April 1, 1978, June 4, 1981, January 20, 1983, November 1,
1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1,
1985, November 1, 1985, June 1, 1986. (Physically filed and
designated in Registration No. 2-2536 as Exhibits B-1 and B-
2; in Post-effective Amendment No. 1 to Registration No. 2-
62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as
Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1,
1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986
as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3,
1986 as Exhibit (4).) July 1, 1985 and November 1, 1985
(Physically filed and designated in Form 10-K, for the
fiscal year 1985, File No. 1-3553, as Exhibit 4-A.)
November 15, 1986 and January 15, 1987. (Physically filed
and designated in Form 10-K, for the fiscal year 1986, File
No. 1-3553, as Exhibit 4-A.) December 15, 1987.
(Physically filed and designated in Form 10-K, for the
fiscal year 1987, File No. 1-3553, as Exhibit 4-A.)
December 13, 1990. (Physically filed and designated in Form
10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit
4-A.) April 1, 1993. (Physically filed and designated in
Form 8-K, dated April 13, 1993, File 1-3553, as Exhibit 4.)
June 1, 1993 (Physically filed and designated in Form 8-K,
dated June 14, 1993, File 1-3553, as Exhibit 4.) May 1,
1993. (Physically filed and designated in Form 10-K, for
the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).)
EX-10.1 Agreement, dated, January 30, 1968, for Unit
No. 4 at the Warrick Power Plant of Alcoa Generating
Corporation ("Alcoa"), between Alcoa and the Company.
(Physically filed and designated in Registration No. 2-29653
as Exhibit 4(d)-A.)
EX-10.2 Letter of Agreement, dated June 1, 1971, and
Letter Agreement, dated June 26, 1969, between Alcoa and the
Company. (Physically filed and designated in Registration
No. 2-41209 as Exhibit 4(e)-2.)
*Pursuant to paragraph (b)(4)(iii)(a) of Item 601 of
Regulation S-K, the Company agrees to furnish to the
Commission on request any instrument with respect to long-
term debt if the total amount of securities authorized
thereunder does not exceed 10% of the total assets of the
Company, and has therefore not filed such documents as
exhibits to this Form 10-K.
<PAGE> 45
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.
<PAGE> 46
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K (Continued)
EX-10.18* Supplemental Post Retirement Death Benefits
Plan, dated October 10, 1984. (Physically filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 10-A-18.)
EX-10.19* Summary description of the Company's
Corporate Performance Incentive Plan. (Physically filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 10-A-19.)
EX-10.20* Company's Corporate Performance Incentive
Plan as amended for the plan year beginning January 1, 1994.
(Physically filed and designated in Form 10-K for the fiscal
year 1993, File No. 1-3553, as Exhibit 10-A-20.)
EX-12 Computation of Ratio of Earnings to Fixed
Charges
EX-21 Subsidiaries of the Registrant
EX-24 Power of Attorney
* Filed pursuant to paragraph (b)(10)(iii)(A) of Item
601 of Regulation S-K.
(b) Reports on Form 8-K
No Form 8-K reports were filed by the Company during
the fourth quarter of 1994.
<PAGE> 47
SCHEDULE II
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
VALUATION AND QUALIFYING
ACCOUNTS:
Year 1994 - Accumulated
provision for uncollectible
accounts $ 166 $ 819 $ - $ 754 $ 231
Year 1993 - Accumulated
provision for uncollectible
accounts $ 136 $ 616 $ - $ 586 $ 166
Year 1992 - Accumulated
provision for uncollectible
accounts $ 260 $ 330 $ - $ 454 $ 136
OTHER RESERVES:
Year 1994 - Reserve
for injuries and
damages $1,321 $ 705 $ 95<F1> $ 429 $1,692
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
<FN>
<F1> Charged to construction accounts
</TABLE>
<PAGE> 50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
Date: March 30, 1995 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
By R. G. Reherman, Chairman, President
and Chief Executive Officer
BY /s/R. G. Reherman
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signatures Title Date
<S> <C> <C>
R.G.Reherman Chairman, President, Chief
Executive Officer (Principal
Executive Officer) March 30, 1995
A.E.Goebel* Senior Vice President, Chief Financial
Officer, Secretary and Treasurer
(Principal Financial Officer) March 30, 1995
S.M.Kerney* Controller (Principal Accounting
Officer) March 30, 1995
Melvin H. Dodson* )
)
Walter B. Emge* )
)
Robert L. Koch II* )
)
Jerry A. Lamb* )
)
Donald A. Rausch* ) Directors March 30, 1995
)
Richard W. Shymanski* )
)
Donald E. Smith* )
)
James S. Vinson* )
)
N. P. Wagner* )
*By
(R. G. Reherman, Attorney-in-fact)
</TABLE>
<PAGE> 51
SIGECO
10-K
<TABLE>
<CAPTION>
EXHIBIT INDEX
Sequential
Page Number
<S> <C> <C>
Exhibits incorporated by reference are found on 45-47
EX-12 Computation of ratio of earnings to fixed
charges 49
EX-21 Subsidiaries of the Registrant 50
EX-24 Power-of-Attorney 53-54
</TABLE>
EX-12
<PAGE> 49
<TABLE>
<CAPTION> SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
For the Five Years Ended December 31, 1994
1994 1993 1992 1991 1990
(in thousands)
Earnings as Defined
<S> <C> <C> <C> <C> <C>
Net income $41,025 $39,588 $36,758 $38,513 $37,691
Add:
Income Taxes:
Current:
Federal 15,257 5,880 13,049 14,176 12,025
State 2,519 1,310 2,444 2,436 1,642
Deferred, net:
Federal (80) 9,682 550 2,996 5,597
State 314 1,581 439 690 1,532
Deferred investment
tax credit, net (1,846) (1,868) (1,873) (1,877) (1,883)
Interest on long-term
debt 18,604 18,437 17,768 18,238 18,249
Amortization of premium,
discount and expense
on debt 852 773 446 740 667
Other interest 1,589 747 461 719 572
Interest component of
rent expense <F1> 416 405 391 382 369
Earnings as defined $78,650 $76,535 $70,433 $77,013 $76,461
Fixed Charges as Defined
Interest on long-term
debt $18,604 $18,437 $17,768 $18,238 $18,249
Amortization of premium,
discount and expense
on debt 852 773 446 740 667
Other interest 1,589 747 461 719 572
Interest component of
rent expense <F1> 416 405 391 382 369
Fixed charges as
defined $21,461 $20,362 $19,066 $20,079 $19,857
Ratio of Earnings to
Fixed Charges <F2> 3.67 3.76 3.69 3.84 3.85
<FN>
NOTES:
<F1> One-third of rentals represents a reasonable approximation of the
interest factor.
<F2> The ratios shown above do not reflect the fixed charge component in
the Company's power contract with OVEC (see "Electric Business", page 2).
Inclusion of the component in the computation would not have a significant
effect on the ratios.
<F3> Periods beginning in 1992 reflect the results of Lincoln Natural Gas
Company, Inc., acquired June 30, 1994.
</FN></TABLE>
<PAGE> 50
EX-21
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
SUBSIDIARY OF THE REGISTRANT
Southern Indiana Properties, Incorporated in Indiana
Energy System Group, Incorporated in Indiana
Southern Indiana Minerals, Incorporated in Indiana
Lincoln Natural Gas Company, Incorporated in Indiana
Exhibit 24
<PAGE> 53-54
February 21, 1995
Mr. R. G. Reherman
Mr. A. E. Goebel
Southern Indiana Gas and Electric Company
29 N.W. Fourth Street
Evansville, Indiana 47741
J. H. Byington, Jr., Esq.
Winthrop, Stimson, Putnam & Roberts
40 Wall Street
New York, New York 10005
Dear Gentlemen:
Southern Indiana Gas and Electric Company will file an
Annual Report on Form 10-K for the fiscal year ended
December 31, 1994 ("Form 10-K") before April 1, 1995 which
will be accompanied by certain exhibits.
We hereby authorize you, or any one of you, to complete
said Form 10-K and to remedy any deficiencies with respect
to said Form 10-K by appropriate amendment or amendments;
and we hereby make, constitute and appoint each of you our
true and lawful attorney for each of us and in each of our
names, places and steads, both in our individual capacities
as directors and that of officers of Southern Indiana Gas
and Electric Company, to sign and cause to be filed with the
Securities and Exchange Commission said Form 10-K, any
appropriate amendment or amendments thereto, and any
exhibits thereto.
The undersigned, Southern Indiana Gas and Electric
Company, also authorizes you and any one of you to sign said
Form 10-K and any amendment or amendments thereto on its
behalf as attorney-in-fact for its respective officers, and
to file the same as aforesaid together with exhibits.
Very truly yours,
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
By (R. G. Reherman)
R. G. Reherman, Chairman, President and
Chief Executive Officer
(Melvin H. Dodson) (R. W. Shymanski)
Melvin H. Dodson Richard W. Shymanski
(Walter R. Emge) (Donald E. Smith)
Walter R. Emge Donald E. Smith
(Robert L. Koch II) (James S. Vinson)
Robert L. Koch II James S. Vinson
(Jerry A. Lamb) (N. P. Wagner)
Jerry A. Lamb N. P. Wagner
(Donald A. Rausch) (A. E. Goebel)
Donald A. Rausch A. E. Goebel
(Ronald G. Reherman) (S. M. Kerney)
Ronald G. Reherman S. M. Kerney
(John H. Schroeder)
John H. Schroeder
