SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report : February 13, 1995
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
__________________________________________________
(Exact name of registrant as specified in charter)
State or other jurisdiction of incorporation: Indiana
Commission File Number: 1-3553
IRS Employer Identification No.: 35-0672570
20 N. W. Fourth Street, Evansville, Indiana 47741-0001
______________________________________________________
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including
area code: (812) 465-5300
<PAGE>
Item 5. OTHER EVENTS.
The Company reports the availability of audited
consolidated financial statements for the year ended
December 31, 1994.
Item 7. FINANCIAL STATEMENTS AND EXHIBITS
See Exhibit Index and Exhibits following.
<PAGE>
SIGNATURE
Pursuant to the requirements 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.
Dated: February 13, 1995
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
Registrant
/s/ A. E. Goebel
A. E. Goebel
Senior Vice President,
Chief Financial Officer
Secretary and Treasurer
<PAGE>
EXHIBIT INDEX
The following exhibits are filed herewith and made a part
hereof.
<TABLE>
<CAPTION>
PAGE NO.
<S> <C> <C>
Exhibit 23 - Consent of Independent Public Accountants 5
Exhibit 27 - Financial Data Schedule
Exhibit 99 - Audited Consolidated Financial Statements for
the year ended December 31, 1994 as follows:
.1 Consolidated Statements of Income 6
.2 Consolidated Statements of Cash Flow 7
.3 Consolidated Balance Sheets 8 & 9
.4 Consolidated Statements of Capitalization 10
.5 Consolidated Statements of Retained
Earnings 11
.6 Notes to Consolidated Financial
Statements 12-23
.7 Report of Independent Public Accountants 24
.8 Management's Discussion and Analysis of
Results of Operations and Financial
Condition 25-42
.9 Selected Financial Data 43
.10 Selected Quarterly Financial Data 44
</TABLE>
<PAGE> 5
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accounts, we hereby consent to the
incorporation by reference of our report dated January 23,
1995, included in this Form 8-K, into the Company's
previously filed registration Statement on Form S-4 File No.
33-57381.
ARTHUR ANDERSEN LLP
Chicago, Illinois
February 13, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
(in thousands, except per share amounts)
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 677,936
<OTHER-PROPERTY-AND-INVEST> 81,466
<TOTAL-CURRENT-ASSETS> 115,567
<TOTAL-DEFERRED-CHARGES> 42,271
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 917,240
<COMMON> 78,152
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 218,424
<TOTAL-COMMON-STOCKHOLDERS-EQ> 296,576
0
19,605
<LONG-TERM-DEBT-NET> 273,617
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 22,060
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 42,677
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 262,705
<TOT-CAPITALIZATION-AND-LIAB> 917,240
<GROSS-OPERATING-REVENUE> 330,035
<INCOME-TAX-EXPENSE> 19,302
<OTHER-OPERATING-EXPENSES> 258,366
<TOTAL-OPERATING-EXPENSES> 277,668
<OPERATING-INCOME-LOSS> 52,367
<OTHER-INCOME-NET> 7,645
<INCOME-BEFORE-INTEREST-EXPEN> 60,012
<TOTAL-INTEREST-EXPENSE> 18,987
<NET-INCOME> 41,025
1,105
<EARNINGS-AVAILABLE-FOR-COMM> 39,920
<COMMON-STOCK-DIVIDENDS> 25,955
<TOTAL-INTEREST-ON-BONDS> 18,604
<CASH-FLOW-OPERATIONS> 102,492
<EPS-PRIMARY> $2.53
<EPS-DILUTED> $2.53
</TABLE>
<PAGE> 6
Exhibit 99.1
<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> 7 Exhibit 99.2
<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> 8
Exhibit 99.3
<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> 9
<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> 10
Exhibit 99.4
<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> 11
Exhibit 99.5
<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> 12
Exhibit 99.6
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> 13
(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 esti-
mated 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> 14
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> 15
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> 16
Reconciliation of the accumulated postretirement benefit
obligation to the accrued liability for postretirement
benefits as of December 31 is as follows:
<TABLE>
<acption>
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>
<PAGE> 17
Based on the December 1994 price of gas purchased, the
cost of replacing the current portion of gas in underground
storage exceeded the amount stated on a LIFO basis by
approximately $11,000,000 at December 31, 1994.
(m) OPERATING REVENUES AND FUEL COSTS
Revenues include all gas and electric service billed
during the year except as discussed below.
All metered gas rates contain a gas cost adjustment
clause which allows for adjustment in charges for changes in
the cost of purchased gas. As ordered by the IURC, the
calculation of the adjustment factor is based on the estimated
cost of gas in a future quarter. The order also provides that
any under- or overrecovery caused by variances between
estimated and actual cost in a given quarter, as well as
refunds from its pipeline suppliers, will be included in
adjustment factors of four future quarters beginning with the
second succeeding quarter's adjustment factor.
All metered electric rates contain a fuel adjustment
clause which allows for adjustment in charges for electric
energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. As ordered by the IURC, the
calculation of the adjustment factor is based on the estimated
cost of fuel and the net energy cost of purchased power in a
future quarter. The order also provides that any under- or
overrecovery caused by variances between estimated and actual
cost in a given quarter will be included in the second
succeeding quarter's adjustment factor.
The Company also collects through a quarterly rate
adjustment mechanism, the margin on electric sales lost due to
the implementation of demand side management programs.
Reference is made to "Demand Side Management" in Management's
Discussion and Analysis of Operations and Financial Condition
for further discussion.
The Company records monthly any under- or overrecovery as
an asset or liability, respectively, until such time as it is
billed or refunded to its customers. The IURC reviews for
approval the adjustment clauses on a quarterly basis.
The cost of gas sold is charged to operating expense as
delivered to customers and the cost of fuel for electric
generation is charged to operating expense when consumed.
(2) RATE AND REGULATORY MATTERS
On July 21, 1993, the IURC approved an overall increase
of approximately 8%, or $5.5 million in revenues, in the
Company's base gas rates. The increase was implemented in two
equal steps. The first step of the rate adjustment,
approximately 4%, took place August 1, 1993; the second step
of the rate adjustment took place on August 1, 1994.
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its investment
through March 31, 1993 in the Clean Air Act Compliance (CAAC)
project presently being constructed at the Culley Generating
Station. The majority of the costs are for the installation
of a sulfur dioxide scrubber on Culley Units 2 and 3. On
September 15, 1993, the IURC granted the Company's request for
a 1% revenue increase, approximately $1.8 million on an annual
basis, which took effect October 1, 1993. The Company
petitioned the IURC on March 1, 1994 for recovery of financing
costs related to scrubber construction expenditures incurred
from April 1, 1993 through January 31, 1994, and was granted
a 2.3% increase, approximately $4.2 million on an annual
basis, in base electric retail rates effective June 29, 1994.
On December 22, 1993, the Company petitioned the IURC for
the third of three planned general electric rate increases
related to its CAAC project. The final adjustment is
necessary to cover financing costs related to the balance of
the project construction expenditures, costs related to the
operation of the scrubber, certain nonscrubber-related
operating costs such as additional costs incurred for
postretirement benefits other than pensions beginning in 1993,
and the recovery of demand side management program
expenditures. The Company filed its case-in-chief on May 16,
1994 supporting a $12.4 million, 5.7% retail rate increase. On
October 1, 1994, the Office of the Utility Consumer Counselor
(UCC) filed its case-in-chief. On rebuttal, the Company
reduced its request to $10.5 million reflecting a stipulated
agreement with the UCC on depreciation rates and a reduction
in the final estimated cost of the Clean Air Compliance
project. The estimated impact of the UCC's recommendation is
a $1.7 million, .7%, decrease in retail revenues. The major
differences between the Company's request and the UCC's
proposal are the requested rate of return on equity, the
recovery of the additional cost of postretirement benefits
other than pensions, the fair value of ratebase investment,
and the appropriate level of operation and maintenance
expenses to be included in cost of service. All hearings have
been completed and the Company is awaiting the final rate
order, anticipated in early 1995. The Company cannot predict
what action the IURC may take with respect to this proposed
rate increase.
In April 1992, the Federal Energy Regulatory Commission
(FERC) issued Order No. 636 (the Order) which required
interstate pipelines to restructure their services. In August
1992, the FERC issued Order No. 636-A which substantially
reaffirmed the content of the original Order. On November 2,
1992, the Company's major pipeline, Texas Gas Transmission
Corporation (TGTC), filed a recovery implementation plan with
the FERC as part of its revised compliance filing regarding
the Order. On October 1, 1993, the FERC accepted, subject to
certain conditions, the TGTC recovery implementation plan.
Under the new TGTC transportation tariffs, which became
effective November 1, 1993, the Company will incur additional
annual demand-related charges which will be partially offset
by lower volume-related transportation costs. TGTC has
estimated that the Company's allocation of transition costs
will total approximately $5.2 million, to be incurred over a
<PAGE> 18
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> 19
<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, $31,500,000 of adjustable rate pollution
control series first mortgage bonds could, at the election of
the bondholder, be tendered to the Company in May 1995. If
the Company's agent is unable to remarket any bonds tendered
at that time, the Company would be required to obtain
additional funds for payment to bondholders. For financial
statement presentation purposes those bonds subject to tender
in 1995 are shown as current liabilities.
<PAGE> 20
First mortgage bonds, notes payable and partnership
obligations outstanding and classified as long-term at
December 31 are as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
First Mortgage Bonds due:
1995, 4-3/4$ $ - $ 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 its initial
investigations in early 1994 and identified the existence and
<PAGE> 21
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> 22
(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 $1,752,000
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.
<PAGE> 23
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> 24
Exhibit 99.7
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE SHAREHOLDERS OF SOUTHERN INDIANA GAS AND ELECTRIC
COMPANY:
We have audited the accompanying 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 are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial
statements 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.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 23, 1995
<PAGE> 25
Exhibit 99.8
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
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> 26
<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.
<PAGE> 27
Despite milder winter and summer temperatures, when heating
and cooling degree days were lower than in 1993 by 10% and 8%,
respectively, commercial sales rose 2.4% on increased local
economic activity. Residential sales declined about 1%. Due
to continued growth in manufacturing activity, sales to the
Company's industrial customers rose 3.2% following a 5.7%
increase in 1993. Total system sales were up 1.8% over 1993.
System sales in 1993 exceeded 1992 sales by 7.6% due to much
warmer summer temperatures.
During 1994, the Company's electric customer base grew by 829,
totaling 118,992 at year end.
System revenues declined approximately $2.3 million in 1994
due to recovery of lower unit fuel costs following a $2.7
million increase in 1993 from the recovery of higher unit fuel
costs. Changes in the cost of fuel for electric generation
and purchased power are reflected in customer rates through
commission-approved fuel cost adjustments.
Since 1987, the Company has provided electric energy to Alcoa
Generating Corporation (AGC), a wholly-owned subsidiary of
Alcoa (a wholesale customer), for one of its six potlines.
Due to market conditions in the aluminum industry, Alcoa shut
down the oldest of the six potlines at the Warrick County
manufacturing operation in July 1993. The Company estimates
that the decline in electric sales related to the potline for
1993 represented approximately $4.8 million in nonsystem
revenues and approximately $.8 million in operating income
compared to the prior year. During 1994, revenue related to
the reduced sales to AGC declined an additional $8.2 million
with a corresponding $1.4 million additional decline in
operating income. A portion of the decline in operating
income was offset by increased sales to other nonsystem
customers made possible by the reduced commitment to AGC.
Total nonsystem sales were 3.2% higher than 1993, due
primarily to the requirements of one nonassociated utility
during the first quarter of 1994. Most sales to nonsystem
customers, including AGC, are on an "as available" basis under
interchange agreements which provide for significantly lower
margins than sales to system customers.
Milder summer temperatures and the peak-shaving effect of the
Company's demand side management programs resulted in a 1994
<PAGE> 28
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
<PAGE> 29
maintenance project expenditures, the Company performed a
scheduled major turbine generator overhaul on Culley Unit 2,
performed significant repairs to one of the Company's gas
turbine peaking units and incurred greater maintenance costs
on the A. B. Brown scrubber facilities due to the plant's
significantly greater generation. Electric maintenance
expenditures in 1993 rose 20% over 1992, when such costs were
down $4.5 million. Depreciation and amortization expense
increased about 3% in 1994, following a 2% increase in 1993,
reflecting normal additions to utility plant.
While inflation has a significant impact on the replacement
cost of the Company's facilities, only the historical cost of
electric and gas plant investment is recoverable in revenues
as depreciation under the ratemaking principles followed by
the Indiana Utility Regulatory Commission (IURC), under whose
regulatory jurisdiction the Company is subject. With the
exception of adjustments for changes in fuel and gas costs and
margin on sales lost under the Company's demand side
management programs (see "Demand Side Management"), the
Company's electric and gas rates remain unchanged until a rate
application is filed and a general rate order is issued by the
IURC.
Federal and state income tax expense was lower during 1994 due
to the decrease in pretax income. Income tax expense rose
$1.9 million in 1993, the result of higher pretax income and
the provision of additional federal income tax expense to
reflect higher tax rates enacted under the Omnibus Budget
Reconciliation Act of 1993. The $3.2 million decrease in
taxes other than income taxes during the current year reflects
adjustments to prior years' provisions for property taxes
related to the favorable outcome of a property tax appeal.
GAS OPERATIONS. The following table compares changes in
operating revenues, operating expenses and gas sold and
transported between 1994 and 1993, and between 1993 and 1992,
in summary form.
<PAGE> 30
<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.
<PAGE> 31
On June 30, 1994, the Company completed its acquisition of
Lincoln Natural Gas Company, Inc. (LNG), a small gas
distribution company serving approximately 1,300 customers
contiguous to the eastern boundary of the Company's gas
service territory. (See Note 1 of the Notes to Consolidated
Financial Statements for further discussion.) In addition to
the LNG customers, 1,200 new gas customers were added to the
Company's system, raising the year end total to 102,929.
The recovery of lower unit gas costs through retail rates in
1994 lowered revenues approximately $1 million following a
$2.7 million increase in revenues related to the recovery of
higher unit costs in the prior year. During the past several
years, the market for purchase of natural gas supply has been
very volatile with the average price ranging from the low of
$1.34 per Dth in February 1992 to the peak of $2.58 per Dth in
May 1993 and then declining to $1.38 per Dth in October 1994.
The volatility of the market reflects the general tightening
of the balance between available supply and demand after
several years of excess supply, and more recently, the effect
of the further deregulation of the gas pipeline industry (see
"Rate and Regulatory Matters"). Changes in the cost of gas
sold are passed on to customers through IURC-approved gas cost
adjustments.
Cost of gas sold, the major component of gas operating
expenses, declined 17.5% ($9 million) in 1994 to $42.3
million, following a 9.9% ($4.6 million) increase in 1993.
The lower costs in 1994 reflected a 10.6% decrease in
deliveries to customers and a 7.9% decline in the average unit
cost of gas delivered to customers. The higher cost of gas
sold in 1993 was due to increased deliveries to customers and
higher unit costs.
Although the Company's former primary pipeline supplier, Texas
Gas Transmission Corporation (TGTC), implemented revised
tariffs November 1, 1993 to reflect certain changes required
by Federal Energy Regulatory Commission (FERC) Order No. 636,
the Company's 1994 and 1993 purchased gas costs were
relatively unaffected by the new tariffs. As of November 1,
1993, TGTC ceased to be a supplier of natural gas to the
Company, and the Company assumed full responsibility for the
purchase of all its natural gas supplies. (See "Rate and
Regulatory Matters" for further discussion of FERC Order No.
636 and of the impact on future purchased gas costs and
procurement practices of the Company.)
Following a 31% increase in 1993, other operation and
maintenance expenses were 8.1% ($1.1 million) greater than the
prior year due primarily to expenses associated with an
<PAGE> 32
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-
<PAGE> 33
based regulation to another form of regulation. The Company
periodically reviews these criteria to ensure the continuing
application of FAS 71 is appropriate.
In November 1992, the Company petitioned the IURC requesting
a general increase in gas rates, the first such adjustment
since 1982. On July 21, 1993, the IURC approved an overall
increase of approximately 8%, or $5.5 million in revenues, in
the Company's base gas rates. The increase was implemented in
two equal steps of approximately 4% on August 1, 1993 and
August 1, 1994. In addition to seeking relief for rising
operating and maintenance costs and substantial investment in
utility plant over the past decade, the Company sought to
restructure its tariffs, make available additional services
and "unbundle" existing services to better serve its gas
customers and strategically position itself to address the
changes brought about by the continued deregulation of the
natural gas industry.
On May 24, 1993, the Company petitioned the IURC for an
adjustment in its base electric rates representing the first
step in the recovery of the financing costs on its investment
through March 31, 1993 in the Clean Air Act Compliance project
being constructed at the Culley Generating Station. The
majority of the costs are for the installation of a sulfur
dioxide scrubber on Culley Units 2 and 3. (See "Clean Air
Act" for further discussion of the project and previous
approval of ratemaking treatment of the incurred costs.) On
September 15, 1993, the IURC granted the Company's request for
a 1% revenue increase, approximately $1.8 million on an annual
basis, which took effect October 1, 1993. The Company
petitioned the IURC on March 1, 1994 for recovery of financing
costs related to the scrubber construction costs incurred from
April 1, 1993 through January 31, 1994, and was granted a 2.3%
increase, approximately $4.2 million on an annual basis, in
base electric retail rates. This second step of the increase
was effective June 29, 1994. On December 22, 1993, the
Company petitioned the IURC for the third of the three planned
general electric rate increases related to its Clean Air Act
Compliance project. The final adjustment is necessary to
cover financing costs related to the balance of the project
construction expenditures, costs related to the operation of
the scrubber, certain nonscrubber-related operating costs such
as additional costs incurred for postretirement benefits other
than pensions beginning in 1993 and the recovery of demand
side management program expenditures (see "Demand Side
Management"). The Company filed its case-in-chief on May 16,
1994 supporting a $12.4 million, 5.7% retail rate increase.
On October 1, 1994, the Office of the Utility Consumer
Counselor (UCC) filed its case-in-chief. On rebuttal, the
Company reduced its request to $10.5 million reflecting a
<PAGE> 34
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
<PAGE>35
supplier agreed to resume coal shipments under the terms of a
letter agreement which is effective until final resolution of
the current litigation. Under the letter agreement, the
invoiced price per ton would be substantially lower than the
contract price. As approved by the IURC, the Company has
charged the full contract price to coal inventory for recovery
through the fuel adjustment clause. The difference between
the contract price and the invoice price , $22 million at
December 31, 1994, has been deposited in an escrow account and
will be paid to either the Company's ratepayers or its coal
supplier upon resolution of the litigation. The Company also
maintains that shipments from the supplier do not conform to
the agreed upon coal specifications in the contract. This
litigation came to trial conclusion based upon summary
judgment motions in June 1994. The U.S. District Court found
in favor of the Company regarding required coal quality
specifications and, in an earlier summary judgment, found in
favor of the coal supplier regarding alleged minimum annual
tonnage requirements. Both parties have initiated appeal
procedures and expect the case to be heard by the Court of
Appeals in mid-1995 with a decision from that court later in
1995. The parties are also considering mediation. Since the
litigation arose due to the Company's efforts to reduce fuel
costs, management believes that any related costs should be
recoverable through the regulatory ratemaking process.
In late 1993, in a further effort to reduce coal costs, the
Company and the supplier entered into an additional letter
agreement, effective January 1, 1994, and continuing until the
litigation is resolved, whereby the Company will purchase an
additional 50,000 tons monthly above the alleged base
requirements at a market-competitive price. The price under
this agreement is not subject to revision regardless of the
outcome of the litigation.
In April 1992, the Federal Energy Regulatory Commission (FERC)
issued Order No. 636 (the Order) which required interstate
pipelines to restructure their services. In August 1992, the
FERC issued Order No. 636-A which substantially reaffirmed the
content of the original Order. Under the Order, the stated
purpose of which is to improve the competitive structure of
the natural gas pipeline industry, existing pipeline sales
service was "unbundled" so that gas supplies are sold
separately from interstate transportation services.
Customers, such as the Company and ultimately its gas
customers, could benefit from enhanced access to competitively
priced gas supplies as well as from more flexible
transportation services. Conversely, customer costs could
rise because the Order requires pipelines to implement new
rate design methods which shift additional demand-related
costs to firm customers; additionally, the FERC has authorized
<PAGE> 36
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
<PAGE> 37
stock would be exchanged on a one-for-one basis for shares of
common stock of the new holding company. All of the Company's
debt securities and all of its outstanding shares of preferred
stock would remain securities of the Company and be
unaffected.
If the necessary approvals are received when expected, the
Company anticipates the reorganization could be completed by
late 1995.
ENVIRONMENTAL MATTERS. In 1993, the Company expensed $.5
million of anticipated cost of performing preliminary and
comprehensive investigations of the possible existence of
facilities once owned and operated by the Company, its
predecessors, previous landowners or former affiliates of the
Company, utilized for the manufacture of gas.
These facilities would have been operated from the 1850's
through the early 1950's under industry standards then in
effect. However, due to current environmental regulations,
the Company and other responsible parties may be required to
take remedial action if certain materials are found at the
sites of these former facilities.
The Company completed its initial investigation in early 1994
and identified the existence and general location of four
sites. Although the results of preliminary assessments of the
sites indicated no contamination was present, the Company
elected to conduct more comprehensive testing of the sites to
provide conclusive evidence that no such contamination exists.
Comprehensive testing of three of the sites was initiated in
late 1994; the Company expects to initiate testing of the
fourth site in 1995. Testing of one site has been completed
with no evidence of contamination present, and testing of the
remaining sites should be completed in 1995. No additional
costs for testing are anticipated at this time.
The Company has notified all known insurance carriers
providing coverage during the probable period of operation of
these facilities of potential claims for coverage of
environmental costs. The Company has not, however, recorded
any receivables representing future recovery from insurance
carriers. Additionally, the Company is attempting to identify
all potentially responsible parties for each site. The
Company has not been named a potentially responsible party by
the Environmental Protection Agency (EPA) for any of these
sites.
<PAGE> 38
The Company does not presently anticipate seeking recovery of
these investigation costs from its ratepayers. If, however,
the specific site investigations indicate that significant
remedial action is required, the Company will seek recovery of
all related costs in excess of amounts recovered from other
potentially responsible parties or insurance carriers through
rates.
Although the IURC has not yet ruled on a pending request for
rate recovery by another Indiana utility of such environmental
costs, the IURC did grant that utility authority to utilize
deferred accounting for such costs until the IURC rules on the
request.
NATIONAL ENERGY POLICY ACT OF 1992. Key provisions of the
National Energy Policy Act of 1992 (the Act) are expected to
cause some of the most significant changes in the history of
the electric industry. The primary purpose of the electric
provisions is to increase competition in electric generation
by enabling virtually nonregulated entities, such as exempt
wholesale generators, to develop power plants, and by
providing the FERC authority to require a utility to provide
transmission services, including the expansion of the
utility's transmission facilities necessary to provide such
services, to any entity generating electricity. Although the
FERC may not order retail wheeling (the transmission of
electricity directly to an ultimate consumer) it may order
wheeling of electricity generated by an exempt wholesale
generator or another utility to a wholesale customer of a
regulated utility.
The changes brought about by the Act may require, or provide
opportunities for, the Company to compete with other utilities
and wholesale generators for sales to existing wholesale
customers of the Company and other potential wholesale
customers. The Company has long-term contracts with its
wholesale customers which mitigate the opportunity for other
generators to provide service to them.
Many observers of the electric utility industry, including
major credit rating agencies, certain financial analysts and
some industry executives, have expressed an opinion that
retail wheeling to large retail customers and other elements
of a more competitive business environment will occur in the
electric utility industry, similar to developments in the
telecommunications and natural gas industries. Although there
has been much discussion of the subject during the past year,
most notably in California where the state regulatory
commission staff proposed a plan to implement retail wheeling,
the timing of these projected developments is uncertain. In
addition, the FERC has adopted a position, generically and on
<PAGE> 39
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
<PAGE> 40
"overcompliance allowances", for sale to others. Proceeds
from sales of overcompliance allowances will also be passed
through to customers.
The scrubbing process utilized by the Culley scrubber produces
a salable by-product, gypsum, a substance commonly used in
wallboard and other products. In December 1993, the Company
finalized negotiations for the sale of an estimated 150,000 to
200,000 tons annually of gypsum to a major manufacturer of
wallboard. This scrubber has been operating in a start-up
"test" mode for several months, and by early January 1995, the
Company had shipped several barge loads of gypsum to the
manufacturer. The agreement will enable the Company to reduce
certain operating costs with the proceeds from the sale of the
gypsum, further mitigating the rate impact of the Compliance
Plan.
The rate impact related to the Compliance Plan, estimated to
be 7-8%, is being phased in over a three-year period beginning
in October 1993 (see "Rate and Regulatory Matters" for further
discussion).
DEMAND SIDE MANAGEMENT. In October 1991, the IURC issued an
order approving expenditures by the Company for development
and implementation of demand side management (DSM) programs.
The primary purpose of the DSM programs is to reduce the
demand on the Company's generating capacity at the time of
system peak requirements, thereby postponing or avoiding the
addition of generating capacity. Thus, the order of the IURC
provided that the accounting and ratemaking treatment of DSM
program expenditures should generally parallel the treatment
of construction of new generating facilities.
Most of the DSM program expenditures are being capitalized per
the IURC order and will be amortized over a 15-year period
beginning at the time the Company reflects such costs in its
rates. The Company is requesting recovery of these costs in
its general electric rate increase request filed December 22,
1993 (see "Rate and Regulatory Matters"). In addition to the
recovery of DSM program costs through base rate adjustments,
the Company is collecting, through a quarterly rate adjustment
mechanism, most of the margin on sales lost due to the
implementation of DSM programs.
According to projections included in the Company's latest
update of its Integrated Resource Plan (IRP), approved by the
IURC on September 7, 1994, the Company expects to incur costs
<PAGE> 41
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> 42
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> 43
Exhibit 99.9
<TABLE>
<CAPTION>
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>
<PAGE> 44
Exhibit 99.10
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
[/TABLE]
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.
