SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT of 1934
For the quarterly period ended September 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-3553
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
-----------------------------------------
(Exact name of registrant as specified in its charter)
INDIANA 35-0672570
--------- -----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
20 N. W. Fourth Street, Evansville, Indiana 47741
(Address of principal executive offices) (Zip Code)
(812) 465-5300
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrants were required to
file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the
Registrants' classes of common stock, as of the latest
practicable date:
Common Stock - Without par value 15,754,826 November 10, 2000
--------------------------------- ----------- ----------------
Class Number of Date
shares
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
Item Page
Number Number
<S> <C> <C>
Part I. Financial Information
1 Financial Statements (Unaudited)
Southern Indiana Gas and Electric Company
Balance Sheets 3-4
Statements of Income 5-6
Statements of Cash Flows 7
Notes to Financial Statements 8-13
2 Management's Discussion and Analysis of Financial
Condition and Results of Operations 14-19
3 Quantitative & Qualitative Disclosure About
Market Risk 20
Part II. Other Information
1 Legal Proceedings 21
4 Submission of Matters to a Vote of Security
Holders 21
6 Exhibits and Reports on Form 8-K 21
Signatures 21
</TABLE>
<PAGE> 3
<TABLE>
<CAPTION>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited - Thousands)
September 30 December 31
2000 1999 1999
<S> <C> <C> <C>
ASSETS
Utility Plant, at original cost:
Electric $ 1,150,734 $ 1,152,180 $ 1,160,216
Gas 155,733 150,652 156,918
----------- ----------- -----------
1,306,467 1,302,832 1,317,134
Less: accumulated depreciation
and amortization 643,872 624,435 623,611
---------- ---------- -----------
662,595 678,397 693,523
Construction work in
progress 70,794 57,518 45,393
---------- ----------- -----------
Net utility plant 733,389 735,915 738,916
Current Assets:
Cash and cash equivalents 1,302 327 449
Accounts receivables, less
reserves of $2,285, $2,253
and $2,138, respectively 39,521 40,809 34,738
Accounts receivable from
affiliate 10,575 - 1,159
Accrued unbilled revenues 12,389 11,837 18,736
Inventories 34,596 38,419 39,190
Recoverable fuel and
natural gas costs 14,462 7,230 5,585
Other current assets 2,005 6,424 5,306
---------- ----------- -----------
Total current assets 114,850 105,046 105,163
Other Investments and Property:
Environmental improvement
fund held by trustee 1,020 984 996
Nonutility property and
other, net 1,960 1,577 1,627
---------- ---------- -----------
Total other investments
and property 2,980 2,561 2,623
Other Assets:
Unamortized premium on
reacquired debt 3,769 3,993 3,937
Demand side management
programs 25,687 25,404 25,298
Allowance inventory 2,269 2,269 2,269
Deferred charges 16,101 13,787 16,553
---------- ----------- -----------
Total other assets 47,826 45,453 48,057
TOTAL ASSETS $899,045 $888,975 $894,759
========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
<PAGE> 4
<TABLE>
<CAPTION>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited - Thousands)
September 30 December 31
2000 1999 1999
<S> <C> <C> <C>
SHAREHOLDER'S EQUITY AND LIABILITIES
Capitalization:
Common Stock $ 78,258 $ 78,258 $ 78,258
Retained Earnings 264,910 255,903 256,312
Contribution of assets to parent (12,132) - -
--------- --------- ---------
Total common shareholder's
equity 331,036 334,161 334,570
Cumulative nonredeemable
preferred stock 11,090 11,090 11,090
Cumulative redeemable preferred
stock 5,300 7,500 7,500
Cumulative special preferred
stock 576 692 692
Long-term debt, net of current
maturities 237,748 249,299 238,282
--------- --------- ---------
Total capitalization, excluding
bonds subject to tender 585,750 602,742 592,134
Commitments and Contingencies
Current Liabilities:
Current maturities of adjustable
rate bonds subject to tender 53,700 53,700 53,700
Notes payable 23,041 21,414 22,880
Accounts payable to affiliated
company 11,094 44 -
Accounts payable 36,709 20,551 28,560
Dividends payable 144 117 117
Accrued taxes 15,895 5,823 8,408
Accrued interest 5,236 5,541 6,012
Refunds to customers 1,027 4,196 5,375
Other accrued liabilities 21,835 21,909 22,706
-------- -------- ---------
Total current liabilities 168,681 133,295 147,758
Deferred Credits And Other
Liabilities:
Accumulated deferred income
taxes 113,634 118,757 122,977
Unamortized investment tax
credits 16,301 17,729 17,372
Accrued postretirement
benefits
other than pensions 14,384 13,996 12,041
Other 295 2,456 2,477
--------- --------- ---------
Total deferred credits and
other liabilities 144,614 152,938 154,867
TOTAL SHAREHOLDER'S EQUITY AND
LIABILITIES $ 899,045 $ 888,975 $ 894,759
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
financial statements.
<PAGE> 5
<TABLE>
<CAPTION>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Unaudited - Thousands)
Three Months Ended Nine Months Ended
September 30 September 30
2000 1999 2000 1999
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric revenues $ 97,936 $ 94,171 $ 249,215 $ 238,960
Gas revenues 14,739 7,759 58,148 47,973
-------- -------- --------- ---------
Total operating 112,675 101,930 307,363 286,933
revenues
COST OF OPERATING REVENUES:
Cost of fuel and
purchased power 32,603 30,351 80,704 74,424
Cost of gas 9,877 2,454 36,523 26,826
-------- -------- --------- ---------
Total cost of operating
revenues 42,480 32,805 117,227 101,250
-------- -------- -------- --------
Total margin 70,195 69,125 190,136 185,683
OPERATING EXPENSES:
Operations and 25,191 22,623 74,934 69,209
maintenance
Merger costs 433 - 14,192 -
Depreciation and
amortization 10,634 11,217 32,836 33,650
Income taxes 9,738 10,774 18,585 22,638
Taxes other than income
taxes 3,332 3,292 9,672 9,481
-------- -------- -------- ---------
Total operating 49,328 47,906 150,219 134,978
expenses
OPERATING INCOME 20,867 21,219 39,917 50,705
OTHER INCOME -NET 1,107 1,566 2,698 2,407
-------- -------- --------- --------
INCOME BEFORE INTEREST AND
PREFERRED STOCK DIVIDEND 21,974 22,785 42,615 53,112
INTEREST EXPENSE 4,951 4,915 14,600 14,847
-------- -------- --------- ---------
NET INCOME 17,023 17,870 28,015 38,265
PREFERRED STOCK DIVIDEND 241 269 776 809
-------- -------- --------- ---------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDERS $ 16,782 $ 17,601 $ 27,239 $ 37,456
======== ======== ========= =========
</TABLE>
The accompanying notes are an integral part of these
financial statements.
<PAGE> 6
<TABLE>
<CAPTION>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Unaudited - Thousands)
Twelve Months Ended
September 30
2000 1999
<S> <C> <C>
OPERATING REVENUES:
Electric revenues $ 317,824 $ 306,143
Gas revenues 78,387 69,130
--------- ---------
Total operating revenues 396,211 375,273
COST OF OPERATING REVENUES:
Cost of fuel and purchased power 99,226 96,893
Cost of gas 49,309 39,710
--------- ---------
Total cost of operating revenues 148,535 136,603
--------- ---------
Total margin 247,676 238,670
OPERATING EXPENSES:
Operations and maintenance 101,383 94,165
Merger costs 14,192 -
Depreciation and amortization 44,053 44,154
Income taxes 22,374 25,579
Taxes other than income taxes 13,036 12,376
--------- ---------
Total operating expenses 195,038 176,274
OPERATING INCOME 52,638 62,396
OTHER INCOME -NET 3,399 1,873
--------- ---------
INCOME BEFORE INTEREST AND PREFERRED STOCK 56,037 64,269
DIVIDEND
INTEREST EXPENSE 19,519 20,062
--------- ---------
NET INCOME 36,518 44,207
PREFERRED STOCK DIVIDEND 1,045 1,081
--------- ---------
NET INCOME APPLICABLE TO COMMON
SHAREHOLDERS $ 35,473 $ 43,126
========= =========
</TABLE>
The accompanying notes are an integral part of these
financial statements.
<PAGE> 7
<TABLE>
<CAPTION>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited - Thousands)
Nine Months Twelve Months
Ended Ended
September 30 September 30
2000 1999 2000 1999
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 28,015 $ 38,265 $ 36,518 $ 44,207
Adjustments to reconcile
net income to net cash
provided from operating
activities:
Depreciation and
amortization 32,836 33,650 44,053 44,154
Deferred income taxes and
investment tax credits,
net (10,413) (463) (6,551) 2,986
Allowance for other funds
used during construction - 238 58 165
Changes in assets and
liabilities:
Receivables, net
(including accrued
unbilled revenues) (6,888) (3,197) (8,874) (5,689)
Inventories 4,594 5,971 3,824 4,627
Accounts payable 8,149 (7,576) 16,158 (1,703)
Accrued taxes 7,487 1,052 10,072 686
Refunds to customers and
from gas suppliers (13,225) 739 (10,747) 1,345
Other assets and
liabilities 2,292 9,923 357 5,490
-------- -------- -------- --------
Net cash flows from
operating activities 52,847 78,602 84,868 96,268
CASH FLOWS (REQUIRED FOR)
FINANCING ACTIVITIES:
Retirement of long-term
debt - (45,000) (10,000) (45,000)
Proceeds from long-term
debt - 80,000 - 80,000
Dividends paid (21,445) (24,285) (29,540) (32,205)
Reduction in preferred
stock (2,316) (116) (2,316) (232)
Change in environmental
improvement funds held by
trustee (24) 3,316 (36) 3,271
Net change in short-term
borrowings and notes pay-
able to affiliated company 10,721 (44,752) 11,093 (31,638)
Other 2,196 (220) 2,272 (500)
-------- -------- -------- --------
Net cash flows (required
for) financing activities (10,868) (31,057) (28,527) (26,304)
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES:
Construction expenditures
(net of allowance for
funds used during
construction) (37,816) (47,116) (51,376) (70,332)
Change in nonutility
property (1,297) - (1,347) (25)
Other (2,014) (614) (2,643) (812)
-------- -------- -------- --------
Net cash flows (required
for) investing activities (41,127) (47,730) (55,366) (71,169)
Net increase (decrease) in
cash and cash equivalents 852 (185) 975 (1,205)
Cash and cash equivalents at
beginning of period 450 512 327 1,532
--------- -------- -------- --------
Cash and cash equivalents at
end of period $ 1,302 $ 327 $ 1,302 $ 327
========= ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these
financial statements.
<PAGE> 8
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Southern Indiana Gas and Electric Company (SIGECO) is an
operating public utility. SIGECO provides generation,
transmission, distribution and sales of electric power to
Evansville, Indiana and 74 other communities and the distribution
of natural gas to Evansville, Indiana and 64 other communities in
ten counties in southwestern Indiana.
2. Financial Statements
The interim consolidated financial statements included in this
report have been prepared, without audit, as provided in the
rules and regulations of the Securities and Exchange Commission
(SEC). Certain information and footnote disclosures normally
included in financial statements prepared in accordance with
accounting principles generally accepted in the United States
have been omitted as provided in such rules and regulations.
SIGECO believes that the information in this report reflects all
adjustments necessary to fairly state the results of the interim
periods reported, that all such adjustments are of a normal
recurring nature, and the disclosures are adequate to make the
information presented not misleading. The preparation of
financial statements in conformity with accounting principles
generally accepted in the United States requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the statements and the reported
amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. These interim
financial statements should be read in conjunction with the
financial statements and notes thereto included in SIGECO's Form
10-K, filed on March 30, 2000.
Because all of the common stock of SIGECO is owned by Vectren (see
Note 3 below), SIGECO does not report earnings per share.
Because of the seasonal nature of SIGECO's utility operations,
the results shown on a quarterly basis are not necessarily
indicative of annual results.
3. Indiana Energy, Inc. and SIGCORP, Inc. Merger
On June 14, 1999, Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP) jointly announced the signing of a
definitive agreement to combine into a new holding company named
Vectren Corporation (Vectren). The merger was conditioned, among
other things, upon the approvals of the shareholders of each
company and customary regulatory approvals. Such approvals were
obtained and the merger was consummated on March 31, 2000. As
provided for in the merger agreement, Indiana Energy shareholders
received one share of Vectren common stock for each share of
Indiana Energy held at the March 31, 2000 closing date. SIGCORP
shareholders received one and one-third shares of Vectren common
stock for each share of SIGCORP held at the March 31, 2000
closing date. The transaction was accounted for as a pooling of
interests. The transaction was a tax-free exchange of shares.
SIGECO, formerly a wholly owned subsidiary of SIGCORP, operates
as a separate wholly owned subsidiary of Vectren.
4. Merger Costs
Merger costs incurred by Vectren for the three, nine and twelve
months ended September 30, 2000 totaled $0.9 million, $31.3
million and $31.3 million, respectively. These costs relate
primarily to transaction costs, severance and other merger
integration activities. Merger costs are reflected in the
financial statements of the operating subsidiaries in which
merger savings are expected to be realized. Merger costs
expensed by SIGECO for the three, nine and twelve months ended
September 30, 2000 totaled $0.4 million, $14.2 million and $14.2
million, respectively.
5. Cash Flow Information
For purposes of the Statements of Cash Flows, SIGECO considers
cash investments with an original maturity of three months or
less to be cash equivalents. Cash paid during the periods
reported for interest and income taxes were as follows:
<TABLE>
<CAPTION>
Nine Months Ended Twelve Months
September 30 Ended September 30
-------------------- ---------------------
2000 1999 2000 1999
<S> <C> <C> <C> <C>
Thousands
Interest (net of
amount capitalized) $13.6 $11.9 $17.1 $17.9
Income taxes $16.6 $20.6 $21.5 $22.1
</TABLE>
6. Gas in Underground Storage
Based on the average cost of gas purchased during September
2000, the cost of replacing the current portion of gas in
underground storage exceeded LIFO cost at September 30, 2000
by approximately $22.7 million.
7. Refundable or Recoverable Fuel and Natural Gas Costs
All metered gas rates contain a gas cost adjustment
clause, which allows for adjustment in charges for changes
in the cost of purchased gas. Metered electric rates
typically 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. SIGECO also collects, through a quarterly
rate adjustment mechanism, the margin on electric sales
lost due to the implementation of demand side management
programs.
SIGECO records any adjustment clause under-or-overrecovery
each month in revenues. A corresponding asset or liability
is recorded until such time as the under-or-overrecovery
is billed or refunded to utility customers. 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.
On August 18, 1999, the Indiana Utility Regulatory
Commission (IURC) issued a generic order which established
new guidelines for the recovery of purchased power costs.
Those guidelines provided that SIGECO is able to recover
through rates the total cost incurred for purchased power
if over a period of seven days the average cost of
purchased power is below the highest cost of internal
generation at SIGECO or the higher costs can be justified
in a fuel adjustment clause filing. The generic order
issued by the IURC was appealed by the Indiana Office of
Utility Consumer Counselor (OUCC). On August 9, 2000, the
IURC approved a settlement between SIGECO and the OUCC
which resolved all issues between SIGECO and the OUCC
regarding the IURC's generic order and dismissed the
OUCC's appeal. The settlement covers the period through
March 31, 2001, and the parties have agreed to attempt to
negotiate an agreement covering future periods. The
settlement provides a price cap on the recovery from
retail electric customers of purchased power costs
incurred by SIGECO during normal economic dispatch
conditions and provides for 85 percent recoverability of
purchased power costs incurred during unplanned forced
outages. SIGECO does not anticipate the potential
limitation of recoverability of its purchased power costs
to be material under this settlement.
8. Environmental Matters
NOx SIP Call Matter. In October 1997, the United States
Environmental Protection Agency (USEPA) proposed a
rulemaking that could require uniform NOx emissions
reductions of 85 percent by utilities and other large
sources in a 22-state region spanning areas in the
Northeast, Midwest, Great Lakes, Mid-Atlantic and South.
This rule is referred to as the "NOx SIP call". The USEPA
provided each state a proposed budget of allowed NOx
emissions, a key ingredient of ozone, which requires a
significant reduction of such emissions. Under that budget,
utilities may be required to reduce NOx emissions to a rate
of 0.15 lb/mmBtu below levels already imposed by Phase I and
Phase II of the Clean Air Act Amendments of 1990.
Midwestern states (the alliance) have been working together
to determine the most appropriate compliance strategy as an
alternative to the USEPA proposal. The alliance submitted
its proposal, which calls for a smaller, phased in reduction
of NOx levels, to the USEPA and the Indiana Department of
Environmental Management in June 1998.
In July 1998, Indiana submitted its proposed plan to the
USEPA in response to the USEPA's proposed new NOx rule and
the emissions budget proposed for Indiana. The Indiana
plan, which calls for a reduction of NOx emissions to a rate
of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA
proposal but more stringent than the alliance proposal.
On October 27, 1998, USEPA issued a final rule "Finding of
Significant Contribution and Rulemaking for Certain States
in the Ozone Transport Assessment Group Region for Purposes
of Reducing Regional Transport of Ozone," (63 Fed. Reg.
57355). The final rule requires that 23 states and
jurisdictions must file revised state implementation plans
(SIPs) with the USEPA by no later than September 30, 1999,
which was essentially unchanged from its October 1997,
proposed rule. The USEPA has encouraged states to target
utility coal-fired boilers for the majority of the
reductions required, especially NOx emissions. Northeastern
states have claimed that ozone transport from midwestern
states (including Indiana) is the primary reason for their
ozone concentration problems. Although this premise is
challenged by others based on various air quality modeling
studies, including studies commissioned by the USEPA, the
USEPA intends to incorporate a regional control strategy to
reduce ozone transport. The USEPA's final ruling is being
litigated in the federal courts by approximately ten
midwestern states, including Indiana.
During the second quarter of 1999, the USEPA lost two
federal court challenges to key air-pollution control
requirements. In the first ruling by the U.S. Circuit Court
of Appeals for the District of Columbia on May 14, 1999, the
Court struck down the USEPA's attempt to tighten the one-
hour ozone standard to an eight-hour standard and the
attempt to tighten the standard for particulate emissions,
finding the actions unconstitutional. In the second ruling
by the same Court on May 25, 1999, the Court placed an
indefinite stay on the USEPA's attempts to reduce the
allowed NOx emissions rate from levels required by the Clean
Air Act Amendments of 1990. The USEPA appealed both court
rulings. On October 29, 1999, the Court refused to
reconsider its May 14, 1999 ruling.
On March 3, 2000, the D.C. Circuit of Appeals upheld the
USEPA's October 27, 1998 final rule requiring 23 states and
the District of Columbia to file revised SIPs with the USEPA
by no later than September 30, 1999. Numerous petitioners,
including several states, have filed petitions for rehearing
with the U.S. Court of Appeals for the District of Columbia
in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit
Court of Appeals denied petition for rehearing en banc and
lifted its May 25, 1999 stay. Following this decision, on
August 30, 2000, the D.C. Circuit Court of Appeals issued an
extension of the SIP Call implementation deadline,
previously May 1, 2003, to May 31, 2004.
The proposed NOx emissions budget for Indiana stipulated in
the USEPA's final ruling requires a 36 percent reduction in
total NOx emissions from Indiana. The ruling could require
SIGECO to lower its system-wide emissions by approximately
70 percent. Depending on the level of system-wide emissions
reductions ultimately required, and the control technology
utilized to achieve the reductions, the estimated
construction costs of the control equipment could reach $160
million, which are expected to be expended during the 2001-
2004 period, and related additional operation and
maintenance expenses could be an estimated $8 million to $10
million, annually.
Culley Generating Station Investigation Matter. The USEPA
initiated an investigation under Section 114 of the Clean
Air Act (the Act) of SIGECO's coal-fired electric generating
units in commercial operation by 1977 to determine
compliance with environmental permitting requirements
related to repairs, maintenance, modifications and
operations changes. The focus of the investigation was to
determine whether new source performance standards should be
applied to the modifications and whether the best available
control technology was, or should have been, used. Numerous
other electric utilities were, and are currently, being
investigated by the USEPA under an industry-wide review for
similar compliance. SIGECO responded to all of the USEPA's
data requests during the investigation. In July 1999,
SIGECO received a letter from the Office of Enforcement and
Compliance Assurance of the USEPA discussing the industry-
wide investigation, vaguely referring to the investigation
of SIGECO and inviting SIGECO to participate in a discussion
of the issues. No specifics were noted; furthermore, the
letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were
conducted in September and October with the USEPA and
targeted utilities, including SIGECO, regarding potential
remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven
utilities, including SIGECO. The USEPA alleges that,
beginning in 1992, SIGECO violated the Clean Air Act by: (i)
making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits; (ii)
making major modifications to the Culley Generating Station
without installing the best available emission control
technology; and (iii) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the
modifications to the Culley Generating Station required
SIGECO to begin complying with federal new source
performance standards.
SIGECO believes it performed only maintenance, repair and
replacement activities at the Culley Generating Station, as
allowed under the Clean Air Act. Because proper maintenance
does not require permits, application of the best available
emission control technology, notice to the USEPA, or
compliance with new source performance standards, SIGECO
believes that the lawsuit is without merit, and intends to
vigorously defend the lawsuit.
The lawsuit seeks fines against SIGECO in the amount of
$27,500 per day per violation. The lawsuit does not specify
the number of days or violations the USEPA believes
occurred. The lawsuit also seeks a court order requiring
SIGECO to install the best available emissions technology at
the Culley Generating Station. If the USEPA is successful
in obtaining an order, SIGECO estimates that it would incur
capital costs of approximately $40 million to $50 million
complying with the order. In the event that SIGECO is
required to install system-wide NOx emission control
equipment, as a result of the NOx SIP call issue, the
majority of the $40 million to $50 million for best
available emissions technology at Culley Generating Station
would be included in the $160 million expenditure previously
discussed.
The USEPA has also issued an administrative notice of
violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to
criminal penalties if the Culley Generating Station
continues to operate without complying with the new source
performance standards and the allegations are determined by
a court to be valid, SIGECO believes such penalties are
unlikely as the USEPA and the electric utility industry have
a bonafide dispute over the proper interpretation of the
Clean Air Act. Consequently, SIGECO anticipates at this
time that the plant will continue to operate while the
matter is being decided.
9. Commitments and Contingencies
SIGECO is party to various legal proceedings arising in the
normal course of business. In the opinion of
management,with the exception of litigation matters related
to the Clean Air Act, there are no legal proceedings pending
against SIGECO that are likely to have a material adverse
effect on the financial position or results of operations.
Refer to Note 8 for litigation matters concerning the Clean
Air Act.
10. Affiliated Transactions
Certain wholly owned subsidiaries of Vectren began providing
support services to SIGECO beginning April 1, 2000. As of
March 31, 2000, certain assets owned by SIGECO were
contributed to a wholly owned subsidiary of Vectren (Vectren
Resources, LLC). The contribution of assets is reflected as
a reduction of common shareholder's equity. Vectren
Resources, LLC provides asset services to SIGECO, the fee
for which is reflected in operation and maintenance expense
in the accompanying financial statements. Services provided
include corporate-level management services, information
technology, financial, human resources, purchasing, building
and fleet services. Amounts billed by the affiliates to
SIGECO for the three months and nine months ended September
30, 2000, totaled $10.5 million and $20.8 million. Prior to
April 1, 2000, these costs were incurred by SIGECO directly.
SIGECO purchases coal from a wholly owned subsidiary of
Vectren. SIGECO's coal purchases during the three, nine and
twelve months ended September 30, 2000 totaled $4.2 million,
$14.3 million and $18.8 million, respectively. SIGECO's
coal purchases during the three, nine and twelve months
ended September 30, 1999 totaled $6.1 million, $16.0 million
and $20.4 million, respectively.
SIGECO also participates in a centralized cash management
program with its parent, affiliated companies and banks
which permits funding of checks as they are presented.
Amounts due from unconsolidated affiliates totaled $9.3
million, $6.5 million and $2.0 million at September 30, 2000
and 1999 and December 31, 1999, respectively, and are
included in Accounts Receivable on the Consolidated Balance
Sheets.
11. Segments of Business
SIGECO adopted Statement of Financial Accounting Standards
(SFAS) No. 131 "Disclosure about Segments of an Enterprise
and Related Information." SFAS No. 131 establishes
standards for the reporting of information about operating
segments in financial statements and disclosures about
products, services and geographical areas. Operating
segments are defined as components of an enterprise for
which separate financial information is available and
evaluated regularly by the chief operating decision makers
in deciding how to allocate resources and in the assessment
of performance.
The operating segments of SIGECO are defined as (1) Gas Utility
Services and (2) Electric Utility Services.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30 Ended September 30
2000 <F1> 1999 2000 <F1> 1999
---------- -------- ---------- --------
<S> <C> <C> <C> <C>
Operating Revenues:
Gas Utility Services $14,739 $7,759 $58,148 $47,973
Electric Utility 97,936 94,171 249,215 238,960
Services
-------- -------- -------- --------
Total operating
revenues $112,675 $101,930 $307,363 $286,933
-------- -------- -------- --------
Interest Expense:
Gas Utility Services $446 $457 $1,314 $1,336
Electric Utility
Services 4,505 4,458 13,286 13,511
------ ------ ------- -------
Total interest expense $4,951 $4,915 $14,600 $14,847
------ ------ ------- -------
Income Taxes:
Gas Utility Services $(622) $(20) $699 $1,565
Electric Utility
Services 10,360 10,794 17,886 21,073
------- ------- ------- -------
Total income taxes $9,738 $10,774 $18,585 $22,638
------- ------- ------- -------
Depreciation and
Amortization:
Gas Utility Services $1,124 $1,157 $3,498 $3,472
Electric Utility
Services 9,510 10,060 29,338 30,178
------- ------- ------- -------
Total depreciation and
amortization $10,634 $11,217 $32,836 $33,650
------- ------- ------- -------
Net Income:
Gas Utility Services $(788) $29 $1,186 $3,043
Electric Utility
Services 17,570 17,572 26,053 34,413
------- ------- ------- -------
Net income $16,782 $17,601 $27,239 $37,456
------- ------- ------- -------
Capital Expenditures:
Gas Utility Services $2,853 $3,188 $7,063 $8,413
Electric Utility
Services 9,720 12,844 30,753 38,703
------- ------- ------- -------
Total capital
expenditures $12,573 $16,032 $37,816 $47,116
======= ======= ======= =======
Twelve Months
Ended September 30
2000 (1) 1999
---------- ---------
<S> <C> <C>
Operating Revenues:
Gas Utility Services $78,387 $69,130
Electric Utility Services 317,824 306,143
-------- --------
Total operating revenues $396,211 $375,273
-------- --------
Interest Expense:
Gas Utility Services $1,757 $1,805
Electric Utility Services 17,762 18,257
------- -------
Total interest expense $19,519 $20,062
Income Taxes:
Gas Utility Services $1,065 $2,839
Electric Utility Services 21,309 22,740
------- -------
Total income taxes $22,374 $25,579
------- -------
Depreciation and Amortization:
Gas Utility Services $4,655 $4,554
Electric Utility Services 39,398 39,600
------- -------
Total depreciation and
amortization $44,053 $44,154
------- -------
Net Income:
Gas Utility Services $2,013 $4,930
Electric Utility Services 33,460 38,196
------- -------
Net income $35,473 $43,126
------- -------
Capital Expenditures:
Gas Utility Services $8,688 $12,052
Electric Utility Services 42,688 58,280
------- -------
Total capital expenditures $51,376 $70,332
As of September 30 As of December 31
2000 1999 1999
-------- -------- -----------------
<S> <C> <C> <C>
Identifiable Assets:
Gas Utility Services $143,847 $142,236 $143,161
Electric Utility
Services 755,198 746,739 751,598
--------- -------- ---------
Total identifiable
assets $899,045 $888,975 $894,759
-------- -------- --------
<FN>
<F1> The 2000 amounts include merger costs (see Note 4).
</FN>
</TABLE>
12. New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board
(FASB) issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". The statement, as
amended by SFAS No. 138, establishes accounting and
reporting standards requiring that every derivative
instrument, including certain derivative instruments
embedded in other contracts, be recorded in the balance
sheet as either an asset or liability measured at its fair
value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in
the income statement. SFAS No. 133 requires that a company
formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SIGECO is
required to adopt SFAS No. 133 no later than January 1,
2001. In certain of its operations, SIGECO utilizes
derivative instruments to manage pricing decisions, minimize
the risk of price volatility, and minimize price risk
exposure in the energy markets. In preparation for the
implementation of this new statement, Vectren has formed a
team to identify its contracts and its subsidiaries'
contracts which could be subject to the new statement,
develop required documentation, define relevant processes
and information system needs and promote internal awareness
of the requirements and potential effects of the new
statement. While Vectren continues to analyze and follow
the development of implementation guidelines, at this time,
Vectren has not quantified the impact of adopting this
statement on SIGECO's financial position or results of
operations and is unable to predict whether the
implementation of this accounting standard will be material
to SIGECO's results of operations or financial position.
However, the adoption of SFAS No. 133 could increase
volatility in earnings and other comprehensive income.
13. Reclassifications
Certain reclassifications have been made to the prior
periods' financial statements to conform to the current year
presentation. These reclassifications have no impact on net
income previously reported.
<PAGE> 14
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Indiana Energy, Inc. and SIGCORP, Inc. Merger
On June 14, 1999, Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP) jointly announced the signing of a
definitive agreement to combine into a new holding company
named Vectren Corporation (Vectren). The merger was
conditioned, among other things, upon the approvals of the
shareholders of each company and customary regulatory
approvals. Such approvals were obtained and the merger was
consummated on March 31, 2000. As provided for in the
merger agreement, Indiana Energy shareholders received one
share of Vectren common stock for each share of Indiana
Energy held at the March 31, 2000 closing date. SIGCORP
shareholders received one and one-third shares of Vectren
common stock for each share of SIGCORP held at the March 31,
2000 closing date. The transaction was accounted for as a
pooling of interests. The transaction was a tax-free
exchange of shares.
Southern Indiana Gas and Electric Company (SIGECO), formerly
a wholly owned subsidiary of SIGCORP, operates as a separate
wholly owned subsidiary of Vectren.
Results of Operations
Net Income Applicable to Common Shareholders
Net income applicable to common shareholders was $16.8 million
for the three months ended September 30, 2000. Net income
applicable to common shareholders before merger related charges
(see merger costs below) was $17.1 million for the three months
ended September 30, 2000 as compared to net income applicable to
common shareholders of $17.6 million for the same period in 1999.
Net income applicable to common shareholders was $27.2
million for the nine months ended September 30, 2000. Net
income applicable to common shareholders before merger
related charges was $38.3 million for the nine months ended
September 30, 2000 as compared to net income applicable to
common shareholders of $37.5 million for the same period in
1999.
Net income applicable to common shareholders was $35.5
million for the twelve months ended September 30, 2000. Net
income applicable to common shareholders before merger
related charges was $46.6 million for the twelve months
ended September 30, 2000 as compared to net income
applicable to common shareholders of $43.1 million for the
same period in 1999.
Electric Margin (Electric Operating Revenues Less Cost of
Fuel and Purchased Power)
Electric utility margin for the three months ended September
30, 2000 was $65.3 million compared to $63.8 million for the
same period last year. Margin from sales to retail and firm
wholesale customers rose $0.8 million compared to the year
ago period on slightly higher average unit sales margins.
Despite customer growth, these sales were flat due to
weather 8 percent cooler than the prior year period. Margin
from nonfirm wholesale sales to other utilities and power
marketers increased $0.5 million during the current quarter.
Sales to these customers increased 50 percent, however
average unit sales margins were down 28 percent compared to
the year ago period when warmer temperatures caused higher
electric energy prices in the wholesale markets.
Electric utility margin for the nine months ended September
30, 2000 was $168.5 million compared to $164.5 million for
the same period last year. For the nine month period ending
September 30, 2000, a 42 percent increase in sales to other
utilities and power marketers contributed an additional $4.6
million to electric margin, more than offsetting the impact
of 4 percent fewer residential electric sales due to milder
winter and summer temperatures.
Electric utility margin for the twelve-month period ended
September 30, 2000, was $218.6 million compared to $209.3 million
for the same period last year. The $9.3 million increase in
margin reflected a $4.2 million increase in margin from nonfirm
wholesale sales to other utilities and power marketers and a 3
percent increase in retail and firm wholesale electric sales
primarily due to stronger industrial and commercial sales.
Total cost of fuel for electric generation and purchased
power increased $2.3 million, or 7 percent, and $6.3
million, or 8 percent, for the three and nine month periods
ended September 30, 2000, compared to the same periods one
year ago due primarily to increased purchased power related
to the greater sales to other utilities and power marketers.
Gas Margin (Gas Operating Revenues Less Cost of Gas)
Gas utility margin for the quarter ended September 30, 2000
was $4.9 million compared to $5.3 million for the same
period last year despite slightly more favorable weather
conditions and an 8 percent increase in total system
throughput (combined sales and transportation volumes). The
slightly lower margin reflects a decrease in average unit
sales margins due to a less favorable sales mix.
Gas utility margin for the nine months ended September 30,
2000 was $21.6 million compared to $21.1 million for the
same period in 1999. The increase is primarily attributable
to the addition of new residential and commercial customers
and growth in large commercial and industrial customer
consumption.
Gas utility margin for the twelve months ended September 30,
2000 of $29.1 million was comparable to the same period last
year.
SIGECO's rates for gas transportation generally provide for
the same margins as are earned on the sale of gas under its
applicable sales tariffs.
Total cost of gas sold increased $7.4 million, or 202
percent, $9.7 million, or 36 percent, and $9.6 million, or
24 percent, respectively, for the three, nine and twelve
month periods ended September 30, 2000, compared to the
comparable periods in 1999 due to significantly higher
average per unit purchased gas costs. SIGECO is allowed
full recovery of such changes in purchased gas costs from
its retail customers through commission-approved gas cost
adjustment mechanisms.
Operating Expenses (excluding Cost of Fuel, Purchased Power and
Cost of Gas)
Operation and maintenance expenses increased $2.6 million,
or 11.4 percent, for the three months ended September 30,
2000 compared to the same period in 1999. The increase is
attributable to additional general and administrative costs.
Operation and maintenance expenses increased $5.7 million,
or 8.3 percent, for the nine months ended September 30, 2000
when compared to the same period a year ago. The nine month
increase is also primarily attributable to higher general
and administrative costs. Maintenance expense for the nine
month period was comparable to the year ago period.
During the twelve-month period ended September 30, 2000,
SIGECO's operation and maintenance expenses increased $7.2
million, or 7.7 percent, compared to the same period in 1999
for the reasons discussed above.
Depreciation and amortization expenses for the current
three, nine and twelve month periods were comparable to the
same periods one year ago.
Income taxes decreased $1.0 million, $4.1 million and $3.2
million, respectively, for the three, nine and twelve
months ended September 30, 2000 when compared to the same
periods one year ago due to lower taxable income.
Taxes other than income taxes increased slightly in all
three periods primarily due to higher property tax expense,
which is the result of additions to utility plant.
Merger Costs
Merger costs incurred by Vectren for the three, nine and
twelve months ended September 30, 2000 totaled $0.9 million,
$31.3 million and $31.3 million, respectively. These costs
relate primarily to transaction costs, severance and other
merger integration activities. Vectren expects to realize
net merger savings of nearly $200 million over the next ten
years from the elimination of duplicate corporate and
administrative programs and greater efficiencies in
operations, business processes and purchasing. The
continued merger integration activities, which will
contribute to the merger savings, will be substantially
complete by 2001. Merger costs are reflected in the
financial statements of the operating subsidiaries in which
merger savings are expected to be realized. Merger costs
expensed by SIGECO for the three, nine and twelve months
ended September 30, 2000 totaled $0.4 million, $14.2 million
and $14.2 million, respectively.
Other Income - Net
Other Income - Net decreased $0.5 million during the three
months ended September 30, 2000 and increased $0.3 million
and $1.5 million, respectively, for the nine and twelve
months ended September 30, 2000, compared to the prior year
periods. The decrease in the current quarter was due
primarily to lower capitalized interest costs related to
utility projects under construction. Higher miscellaneous
and interest income during the current nine and twelve month
periods were the primary reasons for the respective
increases in those periods.
Other Operating Matters
Operation of Warrick Generating Station
On August 21, 2000, SIGECO announced that no later than April 18,
2001, Alcoa will begin operating the Warrick Generating Station.
In 1956, arrangements were made for SIGECO to operate the Warrick
Generating Station as an agent for Alcoa. Three generating units
at the plant are owned by Alcoa. SIGECO owns the fourth unit
equally with Alcoa. The operating change will have no impact on
SIGECO's generating capacity and is not expected to have any
negative impact on SIGECO's financial results. Additionally,
SIGECO will retain Alcoa as a wholesale power and transmission
services customer. Planning of the plant operations transition
is underway.
Environmental Matters
NOx SIP Call Matter. In October 1997, the United States
Environmental Protection Agency (USEPA) proposed a
rulemaking that could require uniform NOx emissions
reductions of 85 percent by utilities and other large
sources in a 22-state region spanning areas in the
Northeast, Midwest, Great Lakes, Mid-Atlantic and South.
This rule is referred to as the "NOx SIP call". The USEPA
provided each state a proposed budget of allowed NOx
emissions, a key ingredient of ozone, which requires a
significant reduction of such emissions. Under that budget,
utilities may be required to reduce NOx emissions to a rate
of 0.15 lb/mmBtu below levels already imposed by Phase I and
Phase II of the Clean Air Act Amendments of 1990.
Midwestern states (the alliance) have been working together
to determine the most appropriate compliance strategy as an
alternative to the USEPA proposal. The alliance submitted
its proposal, which calls for a smaller, phased in reduction
of NOx levels, to the USEPA and the Indiana Department of
Environmental Management in June 1998.
In July 1998, Indiana submitted its proposed plan to the
USEPA in response to the USEPA's proposed new NOx rule and
the emissions budget proposed for Indiana. The Indiana
plan, which calls for a reduction of NOx emissions to a rate
of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA
proposal but more stringent than the alliance proposal.
On October 27, 1998, USEPA issued a final rule "Finding of
Significant Contribution and Rulemaking for Certain States
in the Ozone Transport Assessment Group Region for Purposes
of Reducing Regional Transport of Ozone," (63 Fed. Reg.
57355). The final rule requires that 23 states and
jurisdictions must file revised state implementation plans
(SIPs) with the USEPA by no later than September 30, 1999,
which was essentially unchanged from its October 1997,
proposed rule. The USEPA has encouraged states to target
utility coal-fired boilers for the majority of the
reductions required, especially NOx emissions. Northeastern
states have claimed that ozone transport from midwestern
states (including Indiana) is the primary reason for their
ozone concentration problems. Although this premise is
challenged by others based on various air quality modeling
studies, including studies commissioned by the USEPA, the
USEPA intends to incorporate a regional control strategy to
reduce ozone transport. The USEPA's final ruling is being
litigated in the federal courts by approximately ten
midwestern states, including Indiana.
During the second quarter of 1999, the USEPA lost two
federal court challenges to key air-pollution control
requirements. In the first ruling by the U.S. Circuit Court
of Appeals for the District of Columbia on May 14, 1999, the
Court struck down the USEPA's attempt to tighten the one-
hour ozone standard to an eight-hour standard and the
attempt to tighten the standard for particulate emissions,
finding the actions unconstitutional. In the second ruling
by the same Court on May 25, 1999, the Court placed an
indefinite stay on the USEPA's attempts to reduce the
allowed NOx emissions rate from levels required by the Clean
Air Act Amendments of 1990. The USEPA appealed both court
rulings. On October 29, 1999, the Court refused to
reconsider its May 14, 1999 ruling.
On March 3, 2000, the D.C. Circuit of Appeals upheld the
USEPA's October 27, 1998 final rule requiring 23 states and
the District of Columbia to file revised SIPs with the USEPA
by no later than September 30, 1999. Numerous petitioners,
including several states, have filed petitions for rehearing
with the U.S. Court of Appeals for the District of Columbia
in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit
Court of Appeals denied petition for rehearing en banc and
lifted its May 25, 1999 stay. Following this decision, on
August 30, 2000, the D.C. Circuit Court of Appeals issued an
extension of the SIP Call implementation deadline,
previously May 1, 2003, to May 31, 2004.
The proposed NOx emissions budget for Indiana stipulated in
the USEPA's final ruling requires a 36 percent reduction in
total NOx emissions from Indiana. The ruling could require
SIGECO to lower its system-wide emissions by approximately
70 percent. Depending on the level of system-wide emissions
reductions ultimately required, and the control technology
utilized to achieve the reductions, the estimated
construction costs of the control equipment could reach $160
million, which are expected to be expended during the 2001-
2004 period, and related additional operation and
maintenance expenses could be an estimated $8 million to $10
million, annually.
Culley Generating Station Investigation Matter. The USEPA
initiated an investigation under Section 114 of the Clean
Air Act (the Act) of SIGECO's coal-fired electric generating
units in commercial operation by 1977 to determine
compliance with environmental permitting requirements
related to repairs, maintenance, modifications and
operations changes. The focus of the investigation was to
determine whether new source performance standards should be
applied to the modifications and whether the best available
control technology was, or should have been, used. Numerous
other electric utilities were, and are currently, being
investigated by the USEPA under an industry-wide review for
similar compliance. SIGECO responded to all of the USEPA's
data requests during the investigation. In July 1999,
SIGECO received a letter from the Office of Enforcement and
Compliance Assurance of the USEPA discussing the industry-
wide investigation, vaguely referring to the investigation
of SIGECO and inviting SIGECO to participate in a discussion
of the issues. No specifics were noted; furthermore, the
letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were
conducted in September and October with the USEPA and
targeted utilities, including SIGECO, regarding potential
remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven
utilities, including SIGECO. The USEPA alleges that,
beginning in 1992, SIGECO violated the Clean Air Act by: (i)
making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits; (ii)
making major modifications to the Culley Generating Station
without installing the best available emission control
technology; and (iii) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the
modifications to the Culley Generating Station required
SIGECO to begin complying with federal new source
performance standards.
SIGECO believes it performed only maintenance, repair and
replacement activities at the Culley Generating Station, as
allowed under the Clean Air Act. Because proper maintenance
does not require permits, application of the best available
emission control technology, notice to the USEPA, or
compliance with new source performance standards, SIGECO
believes that the lawsuit is without merit, and intends to
vigorously defend the lawsuit.
The lawsuit seeks fines against SIGECO in the amount of
$27,500 per day per violation. The lawsuit does not specify
the number of days or violations the USEPA believes
occurred. The lawsuit also seeks a court order requiring
SIGECO to install the best available emissions technology at
the Culley Generating Station. If the USEPA is successful
in obtaining an order, SIGECO estimates that it would incur
capital costs of approximately $40 million to $50 million
complying with the order. In the event that SIGECO is
required to install system-wide NOx emission control
equipment, as a result of the NOx SIP call issue, the
majority of the $40 million to $50 million for best
available emissions technology at Culley Generating Station
would be included in the $160 million expenditure previously
discussed.
The USEPA has also issued an administrative notice of
violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to
criminal penalties if the Culley Generating Station
continues to operate without complying with the new source
performance standards and the allegations are determined by
a court to be valid, SIGECO believes such penalties are
unlikely as the USEPA and the electric utility industry have
a bonafide dispute over the proper interpretation of the
Clean Air Act. Consequently, SIGECO anticipates at this
time that the plant will continue to operate while the
matter is being decided.
New Accounting Pronouncement
In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities". The
statement, as amended by SFAS No. 138, establishes
accounting and reporting standards requiring that every
derivative instrument, including certain derivative
instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in
the income statement. SFAS 133 requires that a company
formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SIGECO is
required to adopt SFAS No. 133 no later than January 1,
2001. In certain of its operations, SIGECO utilizes
derivative instruments to manage pricing decisions, minimize
the risk of price volatility, and minimize price risk
exposure in the energy markets. In preparation for the
implementation of this new statement, Vectren has formed a
team to identify and analyze its contracts which could be
subject to the new statement, develop required
documentation, define relevant processes and information
system needs and promote internal awareness of the
requirements and potential effects of the new statement.
While Vectren continues to analyze and follow the
development of implementation guidelines, at this time,
Vectren has not quantified the impact of adopting this
statement on SIGECO's financial position or results of
operations and is unable to predict whether the
implementation of this accounting standard will be material
to SIGECO's results of operations or financial position.
However, the adoption of SFAS No. 133 could increase
volatility in earnings and other comprehensive income.
Liquidity and Capital Resources
SIGECO's capitalization objectives are 45-60 percent common and
preferred equity and 40-55 percent permanent debt. These
objectives may have varied, and will vary, from time to time,
depending on particular business opportunities and seasonal
factors that affect the company's operations. SIGECO's common
equity component was 52 percent of its total capitalization at
September 30, 2000.
New construction and normal system maintenance and improvements
needed to provide service to a growing customer base will
continue to require substantial expenditures. Capital
expenditures for fiscal 2000 are estimated at approximately $50
million, of which $37.8 million have been expended through
September 30, 2000. For the twelve months ended September 30,
2000, capital expenditures totaled $51.4 million.
SIGECO has $66.0 million of short-term borrowing capacity, of
which $43.0 million was available at September 30, 2000.
Short-term cash working capital is required primarily to
finance customer accounts receivable, unbilled utility
revenues resulting from cycle billing, gas in underground
storage, prepaid gas delivery services, capital expenditures
and investments until permanently financed. Short-term
borrowings tend to be greatest during the summer when
accounts receivable and unbilled utility revenues related to
electricity are highest and gas storage facilities are being
refilled.
Financing Activities
SIGECO expects the majority of its capital expenditure
requirements and debt security redemptions to be provided
by internally generated funds.
SIGECO's credit rating on outstanding debt at September 30, 2000
was AA/Aa2. Effective October 2000, the credit rating on SIGECO's
outstanding debt was lowered to A/A1.
Cash required for financing activities of $10.9 million for the
nine months ended September 30, 2000 includes $10.7 million of
additional net borrowings offset by $21.4 million of dividends.
Cash required for financing activities of $28.5 million for the
twelve months ended September 30, 2000 includes $29.5 million of
dividends.
Cash required for investing activities of $41.1 million for
the nine months ended September 30, 2000 includes $37.8
million of capital expenditures. Cash required for investing
activities of $55.4 million for the twelve months ended
September 30, 2000 includes $51.4 million of capital
expenditures.
Forward-Looking Information
A "safe harbor" for forwarding-looking statements is
provided by the Private Securities Litigation Reform Act of
1995 (Reform Act of 1995). The Reform Act of 1995 was
adopted to encourage such forward-looking statements without
the threat of litigation, provided those statements are
identified as forward-looking and are accompanied by
meaningful cautionary statements identifying important
factors that could cause the actual results to differ
materially from those projected in the statements. Certain
matters described in Management's Discussion and Analysis of
Financial Condition and Results of Operations, including,
but not limited to, Vectren's realization of net merger
savings, are forward-looking statements. Such statements
are based on management's beliefs, as well as assumptions
made by and information currently available to management.
When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection,"
"forecast," "goal," and similar expressions are intended to
identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors
that could cause SIGECO's actual results to differ
materially from those contemplated in any forward-looking
statements included, among others, the following:
* Factors affecting utility operations such as unusual
weather conditions; catastrophic weather-related damage;
unusual maintenance or repairs; unanticipated changes to
fossil fuel costs; unanticipated changes to gas supply
costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental
or pipeline incidents; transmission or distribution
incidents; unanticipated changes to electric energy supply
costs, or availability due to demand, shortages,
transmission problems or other developments; or electric
transmission or gas pipeline system constraints.
* Increased competition in the energy environment including
effects of industry restructuring and unbundling.
* Regulatory factors such as unanticipated changes in rate-
setting policies or procedures, recovery of investments and
costs made under traditional regulation, and the frequency
and timing of rate increases.
* Financial or regulatory accounting principles or policies
imposed by the Financial Accounting Standards Board, the
Securities and Exchange Commission, the Federal Energy
Regulatory Commission, state public utility commissions,
state entities which regulate natural gas transmission,
gathering and processing, and similar entities with
regulatory oversight.
* Economic conditions including inflation rates and
monetary fluctuations.
* Changing market conditions and a variety of other factors
associated with physical energy and financial trading
activities including, but not limited to, price, basis,
credit, liquidity, volatility, capacity, interest rate, and
warranty risks.
* Availability or cost of capital, resulting from changes
in SIGECO, interest rates, and securities ratings or market
perceptions of the utility industry and energy-related
industries.
* Employee workforce factors including changes in key
executives, collective bargaining agreements with union
employees, or work stoppages.
* Legal and regulatory delays and other obstacles
associated with mergers, acquisitions, and investments in
joint ventures.
* Costs and other effects of legal and administrative
proceedings, settlements, investigations, claims, and other
matters, including, but not limited to, those described in
the Other Operating Matters section of Management's
Discussion and Analysis of Financial Condition and Results
of Operations.
* Changes in federal, state or local legislature
requirements, such as changes in tax laws or rates,
environmental laws and regulations.
SIGECO undertakes no obligation to publicly update or revise
any forward-looking statements, whether as a result of
changes in actual results, changes in assumptions, or other
factors affecting such statements.
Seasonality
Because of the seasonal nature of SIGECO's utility
operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.
Item 3. Quantitative and Qualitative Disclosures about
Market Risk
SIGECO's debt portfolio contains a substantial amount of
fixed-rate long-term debt and, therefore, does not expose
the company to the risk of material earnings or cash flow
loss due to changes in market interest rates. SIGECO
attempts to mitigate its exposure to interest rate
fluctuations through management of its short-term borrowings
and the use of interest rate hedging instruments. An
internal guideline to manage short-term interest rate
exposure has been established. This guideline targets a
level of 25 percent of the company's total debt portfolio to
consist of adjustable rate bonds with a maturity of less
than one year, short-term notes and commercial paper.
However, it is acknowledged that there may be times that the
guideline may be exceeded.
SIGECO utilizes contracts for the forward sale of
electricity to effectively manage the utilization of its
available generating capability. Such contracts include
forward physical contracts for wholesale sales of its
generating capability, during periods when SIGECO's
available generating capability is expected to exceed the
demands of its retail, or native load, customers. To
minimize the risk related to these forward contracts, SIGECO
may utilize call option contracts to hedge against the
unexpected loss of its generating capability during periods
of heavy demand. SIGECO also utilizes forward physical
contracts for the wholesale purchase of generating
capability to resell to other utilities and power marketers
through non-firm "buy-resell" transactions where the sale
and purchase prices of power are concurrently set. As of
September 30, 2000, management believes exposure from these
positions was not material.
Exposure to electricity market price risk results from the
use of forward contracts to effectively manage the supply
of, and demand for, the generation capability of SIGECO's
generating plants related to its wholesale power marketing
activities. SIGECO is not currently exposed to market
risks for purchases of electric energy power and natural
gas for its retail customers due to current Indiana
regulations which allow for recovery of such purchases
through SIGECO's fuel and natural gas cost adjustment
mechanisms. A 1999 generic order issued by the IURC
established new guidelines for the recovery of purchased
electric power costs through the fuel adjustment clauses.
This order was appealed by the Indiana Office of the
Utility Consumer Counselor (OUCC). On August 9, 2000, the
IURC approved a settlement between SIGECO and the OUCC
which resolved all issues between SIGECO and the OUCC
regarding the IURC's generic order and dismissed the
OUCC's appeal. The settlement covers the period through
March 31, 2001. The parties have agreed to attempt to
negotiate an agreement covering future periods. The
settlement provides a price cap on the recovery from
retail electric customers of purchased power costs
incurred by SIGECO during normal economic dispatch
conditions and provides for 85 percent recoverability of
purchased power costs incurred during unplanned forced
outages. SIGECO does not anticipate the potential
limitation of recoverability of its purchased power costs
to be material under this settlement.
SIGECO is also exposed to counterparty credit risk when a
supplier defaults upon a contract to pay or deliver the
commodity. To mitigate risk, procedures to determine and
monitor the creditworthiness of counterparties have been
established.
At September 30, 2000, SIGECO was not engaged in other
contracts which would cause exposure to the risk of material
earnings or cash flow loss due to changes in market
commodity prices, foreign currency exchange rates, or
interest rates.
<PAGE> 21
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 8 of the Notes to Financial Statements for
discussion of the litigation matters relating to USEPA
allegations that SIGECO violated the Clean Air Act.
Item 4. Submission of Matters to a Vote of
Security Holders
None
Item 6. Exhibits and Reports on Form 8-K
Exhibits
27 Financial Data Schedule, filed herewith.
Reports on Form 8-K
None
SIGNATURES
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.
SOUTHERN INDIANA GAS AND ELECTRIC
COMPANY
Registrant
November 14, 2000 /s/ M. Susan Hardwick
M. Susan Hardwick
Vice President and Controller
November 14, 2000 /s/ Jerome A. Benkert
Jerome A. Benkert
Executive Vice President and
Chief Financial Officer
