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 June 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:
<TABLE>
<S> <C> <C>
Common Stock - Without par value 15,754,826 August 11, 2000
--------------------------------- ---------- ---------------
Class Number of shares Date
</TABLE>
<PAGE> 2
<TABLE>
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
Quantitative & Qualitative Disclosure About
3 Market Risk 19-20
Part II. Other Information
1 Legal Proceedings 21
4 Submission of Matters to a Vote of Security 21
Holders
6 Exhibits and Reports on Form 8-K 21
Signatures 22
<PAGE> 3
</TABLE>
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited - Thousands)
June 30 December 31
---------------------- -----------
2000 1999 1999
<S> <C> <C> <C>
ASSETS
Utility Plant, at original cost:
Electric $1,147,068 $1,149,334 $1,160,216
Gas 155,034 150,551 156,918
---------- ---------- ----------
1,302,102 1,299,885 1,317,134
Less: accumulated depreciation
and amortization 634,869 614,404 623,611
---------- ---------- ----------
667,233 685,481 693,523
Construction work in progress 63,595 46,130 45,393
---------- ---------- ----------
Net utility plant 730,828 731,611 738,916
Current Assets:
Cash and cash equivalents 840 343 449
Accounts receivables, less reserves
of $2,171, $2,460 and $2,138,
respectively 41,389 27,587 34,738
Accrued unbilled revenues 12,871 13,587 18,736
Inventories 28,814 38,736 39,190
Current regulatory assets 10,185 7,555 7,921
Other current assets - 3,056 2,970
---------- ---------- ----------
Total current assets 94,099 90,864 104,004
Other Investments and Property:
Environmental improvement fund
held by trustee 1,020 4,384 996
Notes receivable 7,326 - 1,159
Nonutility property and other, net 2,925 1,577 1,627
---------- ---------- ----------
Total other investments and
property 11,271 5,961 3,782
Other Assets:
Unamortized premium on reacquired
debt 3,825 4,050 3,937
Demand side management programs 25,845 24,995 25,298
Allowance inventory 2,269 2,269 2,269
Deferred charges 10,236 14,466 16,553
---------- ---------- ----------
Total other assets 42,175 45,780 48,057
TOTAL ASSETS $ 878,373 $ 874,216 $ 894,759
========== ========== ==========
<FN>
The accompanying notes are an integral part
of these financial statements.
</FN>
</TABLE>
<PAGE> 4
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited - Thousands)
June 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 254,819 246,127 256,312
Contributions (12,132) - -
-------- -------- --------
Total common shareholder's equity 320,945 324,385 334,570
Cumulative nonredeemable preferred
stock 11,090 11,090 11,090
Cumulative redeemable preferred stock 7,500 7,500 7,500
Cumulative special preferred stock 575 692 692
Long-term debt, net of current
maturities 237,697 169,799 238,282
-------- -------- --------
Total capitalization, excluding
bonds subject to tender 577,807 513,466 592,134
-------- -------- --------
Commitments and Contingencies
Current Liabilities:
Current maturities of adjustable rate
bonds subject to tender 53,700 53,700 53,700
Notes payable 16,352 83,584 22,880
Notes payable to affiliated company 14,011 20,500 -
Accounts payable 30,264 17,779 28,560
Dividends payable 104 117 117
Accrued taxes 9,813 2,124 8,408
Accrued interest 5,636 4,082 6,012
Refunds to customers 2,306 2,916 5,375
Other accrued liabilities 22,018 24,688 22,706
-------- -------- --------
Total current liabilities 154,204 209,490 147,758
-------- -------- --------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 115,706 118,555 122,977
Unamortized investment tax credits 16,658 18,087 17,372
Accrued postretirement benefits other
than pensions 13,703 13,006 12,041
Other 295 1,612 2,477
-------- -------- --------
Total deferred credits and
other liabilities 146,362 151,260 154,867
-------- -------- --------
TOTAL SHAREHOLDER'S EQUITY AND
LIABILITIES $878,373 $874,216 $894,759
========= ======== =========
<FN>
The accompanying notes are an integral part
of these financial statements.
</FN>
</TABLE>
<PAGE> 5
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Unaudited - Thousands)
Three Months Ended Six Months Ended
June 30 June 30
------------------ ------------------
2000 1999 2000 1999
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric revenues $78,289 $73,802 $151,279 $144,789
Gas revenues 14,182 10,516 43,409 40,214
------- ------- -------- --------
Total operating revenues 92,471 84,318 194,688 185,003
------ ------- -------- --------
COST OF OPERATING REVENUES:
Cost of fuel and purchased
power 26,423 23,943 48,101 44,073
Cost of gas 7,012 4,867 26,646 24,372
------- ------- -------- --------
Total cost of operating
revenues 33,435 28,810 74,747 68,445
------- ------- -------- --------
Total margin 59,036 55,508 119,941 116,558
------- ------- -------- --------
OPERATING EXPENSES:
Operations and maintenance 28,505 24,357 49,743 46,586
Merger costs 1,402 - 13,759 -
Depreciation and amortization 10,712 11,216 22,202 22,433
Income taxes 4,610 4,535 8,847 11,865
Taxes other than income taxes 3,107 3,062 6,340 6,189
------- ------- -------- --------
Total operating expenses 48,336 43,170 100,891 87,073
OPERATING INCOME 10,700 12,338 19,050 29,485
OTHER INCOME -NET 892 203 1,591 286
------- ------- -------- --------
INCOME BEFORE INTEREST AND
PREFERRED STOCK DIVIDEND 11,592 12,541 20,641 29,771
INTEREST EXPENSE 4,866 4,655 9,649 9,378
------- ------- -------- --------
NET INCOME 6,726 7,886 10,992 20,393
PREFERRED STOCK DIVIDEND 267 269 535 539
------- ------- -------- --------
NET INCOME APPLICABLE TO COMMON
SHAREHOLDERS $ 6,459 $ 7,617 $ 10,457 $ 19,854
======= ======= ======== ========
<FN>
The accompanying notes are an integral part
of these financial statements.
</FN>
</TABLE>
<PAGE> 6
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Unaudited - Thousands)
Twelve Months Ended
June 30
--------------------
2000 1999
<S> <C> <C>
OPERATING REVENUES:
Electric revenues $314,059 $299,901
Gas revenues 71,407 66,802
-------- --------
Total operating revenues 385,466 366,703
-------- --------
COST OF OPERATING REVENUES:
Cost of fuel and purchased power 96,974 92,380
Cost of gas 41,886 38,358
-------- --------
Total cost of operating revenues 138,860 130,738
-------- --------
Total margin 246,606 235,965
OPERATING EXPENSES:
Operations and maintenance 98,815 93,108
Merger costs 13,759 -
Depreciation and amortization 44,636 43,570
Income taxes 23,409 24,731
Taxes other than income taxes 12,996 12,004
-------- --------
Total operating expenses 193,615 173,413
OPERATING INCOME 52,991 62,552
OTHER INCOME -NET 3,859 689
-------- --------
INCOME BEFORE INTEREST AND PREFERRED
STOCK DIVIDEND 56,850 63,241
INTEREST EXPENSE 19,483 20,201
-------- --------
NET INCOME 37,367 43,040
PREFERRED STOCK DIVIDEND 1,074 1,086
-------- --------
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS $ 36,293 $ 41,954
======== ========
<FN>
The accompanying notes are an integral part
of these financial statements.
</FN>
</TABLE>
<PAGE> 7
<TABLE>
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited - Thousands)
Twelve Months
Six Months Ended Ended
June 30 June 30
----------------- -----------------
2000 1999 2000 1999
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $10,992 $20,393 $37,367 $43,040
Adjustments to reconcile net
income to net cash provided
from operating activities:
Depreciation and amortization 22,202 22,433 44,636 43,570
Deferred income taxes and
investment tax credits, net (7,984) (307) (4,277) 2,880
Allowance for other funds
used during construction - 51 245 43
Changes in assets and liabilities:
Receivables, net (including
accrued unbilled revenues) (6,953) 8,274 (20,410) 6,390
Inventories 10,376 5,654 9,923 (3,099)
Accounts payable 1,705 (10,348) 12,485 (2,200)
Accrued taxes 1,405 (2,647) 7,689 (1,766)
Refunds to customers and
from gas suppliers (3,069) 761 (611) 2,221
Other assets and
liabilities 5,421 10,092 3,315 5,544
------- ------- ------- -------
Net cash flows from operating
activities 34,095 54,356 90,362 96,623
------- ------- ------- -------
CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES:
Retirement of long-term debt - (45,000) (10,000) (59,000)
Proceeds from long-term debt - - 80,000 -
Dividends paid (15,545) (16,191) (31,734) (31,533)
Reduction in preferred stock (117) (116) (116) (232)
Change in environmental
improvement funds held by
trustee (23) (84) 3,364 (187)
Net change in short-term
borrowings and notes payable
to affiliated company 6,898 38,395 (75,876) 60,260
Other 3,174 213 2,815 (2)
------- ------- ------- -------
Net cash flows(required for)
financing activities (5,613) (22,783) (31,547) (30,694)
------- ------- ------- -------
CASH FLOWS (REQUIRED FOR)
INVESTING ACTIVITIES:
Construction expenditures (net
of allowance for funds
used during construction) (25,243) (31,422) (54,498) (62,565)
Change in nonutility property (1,298) - (1,348) (15)
Other (1,550) (320) (2,472) (3,112)
------- ------- ------- -------
Net cash flows (required for)
investing activities (28,091) (31,742) (58,318) (65,692)
------- ------- ------- -------
Net increase (decrease) in cash
and
cash equivalents 391 (169) 497 237
Cash and cash equivalents at
beginning of period 449 512 343 106
------- ------- ------- -------
Cash and cash equivalents at end
of period $ 840 $ 343 $ 840 $ 343
======= ======= ======= =======
<FN>
The accompanying notes are an integral part
of these financial statements.
</FN>
</TABLE>
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 generally accepted accounting
principles 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 generally accepted accounting principles
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 latest
annual report on Form 10-K.
Because all of the common stock of SIGECO is owned by
Vectren (see 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.
Southern Indiana Gas and Electric Company, 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 and six
months ended June 30, 2000 totaled $3.3 million and $30.4
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 will be substantially complete by 2001. Merger
costs are reflected in the financial statements of the
operating subsidiaries in which the merger savings are
expected to be realized. Merger costs expensed by SIGECO for
the three and six months ended June 30, 2000 totaled $1.4
million and $13.8 million, respectively.
<PAGE> 9
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>
Six Months Ended Twelve Months Ended
June 30 June 30
----------------- -------------------
2000 1999 2000 1999
<S> <C> <C> <C> <C>
Thousands
Interest (net of amount
capitalized) $ 8,798 $ 9,698 $14,537 $19,128
Income taxes $13,618 $14,766 $24,327 $23,209
</TABLE>
6. Capitalization
On July 3, 2000, all of SIGECO's $9,975,000 Adjustable Rate
Pollution Control Revenue Bonds were remarketed and the
interest rate was reset to 4.75% from 4.55%. The new
interest rate will be effective from July 1, 2000 through
June 30, 2001.
On July 7, 2000, SIGECO repurchased 22,000 shares of its
4.75% nonredeemable $100 par value preferred stock at a
purchase price of $84.25 per share. The stock was
repurchased as treasury stock and is to be retired.
7. Gas in Underground Storage
Based on the average cost of gas purchased during June 2000,
the cost of replacing the current portion of gas in
underground storage exceeded LIFO cost at June 30, 2000 by
approximately $18.9 million.
8. Refundable or Recoverable Gas and Fuel 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 pertains to the summer months of 2000 and the
parties have agreed to collaborate on a permanent 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.
<PAGE> 10
9. Environmental Costs
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.
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 $100
million, and related additional operation and maintenance
expenses could be an estimated $8 million to $10 million,
annually. Under the USEPA implementation schedule, the
emissions reductions and required control equipment must be
implemented and in place by May 15, 2003.
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.
<PAGE> 11
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 $100 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.
10. Commitments and Contingencies
SIGECO is party to various legal proceeding arising in the
normal course of business. In the opinion of management,
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
9 for litigation matters concerning the Clean Air Act.
11. 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 expenses
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 ended June 30, 2000, totaled
$10.3 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, six and
twelve months ended June 30, 2000 totaled $6.0 million, $9.3
million and $19.9 million, respectively. SIGECO's coal
purchases during the three, six and twelve months ended June
30, 1999 totaled $5.0 million, $9.9 million and $19.5
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 $4.3
million, $0 million and $2.0 million at June 30, 2000 and
1999 and December 31, 1999, respectively, and are included
in Accounts Receivable on the Consolidated Balance Sheets.
<PAGE> 12
12. 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>
Three Months Six Months
Ended June 30 Ended June 30
---------------- ------------------
2000 <1> 1999 2000 <1> 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Gas Utility Services $14,182 $10,516 $ 43,409 $ 40,214
Electric Utility Services 78,289 73,802 151,279 144,789
------- ------- -------- --------
Total operating revenues $92,471 $84,318 $194,688 $185,003
------- ------- -------- --------
Interest Expense:
Gas Utility Services $ 438 $ 419 $ 868 $ 844
Electric Utility Services 4,428 4,236 8,781 8,534
------- ------- -------- --------
Total interest expense $ 4,866 $ 4,655 $ 9,649 $ 9,378
------- ------- -------- --------
Income Taxes:
Gas Utility Services $ 345 $ 36 $ 1,321 $ 1,649
Electric Utility Services 4,265 4,499 7,526 10,216
------- ------- -------- --------
Total income taxes $ 4,610 $ 4,535 $ 8,847 $ 11,865
------- ------- -------- --------
Depreciation and amortization:
Gas Utility Services $ 1,129 $ 1,158 $ 2,374 $ 2,315
Electric Utility Services 9,583 10,058 19,828 20,118
------- ------- -------- --------
Total depreciation and
amortization $10,712 $11,216 $ 22,202 $ 22,433
------- ------- -------- --------
Net income:
Gas Utility Services $ 584 $ 187 $ 1,974 $ 3,014
Electric Utility Services 5,875 7,430 8,483 16,840
------- ------- -------- --------
Net income $ 6,459 $ 7,617 $ 10,457 $ 19,854
------- ------- -------- --------
Capital Expenditures:
Gas Utility Services $ 2,051 $ 3,025 $ 4,209 $ 5,225
Electric Utility Services 9,545 14,407 21,034 26,197
------- ------- -------- --------
Total capital expenditures $11,596 $17,432 $ 25,243 $ 31,422
------- ------- -------- --------
</TABLE>
<TABLE>
Twelve Months
Ended June 30
-------------------
2000 <1> 1999
<S> <C> <C>
Operating Revenues:
Gas Utility Services $ 71,407 $ 66,802
Electric Utility Services 314,059 299,901
-------- --------
Total operating revenues $385,466 $366,703
-------- --------
Interest Expense:
Gas Utility Services $ 1,753 $ 1,818
Electric Utility Services 17,730 18,383
-------- --------
Total interest expense $ 19,483 $ 20,201
-------- --------
Income Taxes:
Gas Utility Services $ 1,656 $ 2,554
Electric Utility Services 21,753 22,177
-------- --------
Total income taxes $ 23,409 $ 24,731
-------- --------
Depreciation and amortization:
Gas Utility Services $ 4,688 $ 4,477
Electric Utility Services 39,948 39,093
-------- --------
Total depreciation and amortization $ 44,636 $ 43,570
-------- --------
Net income:
Gas Utility Services $ 2,830 $ 4,547
Electric Utility Services 33,463 37,407
-------- --------
Net income $ 36,293 $ 41,954
-------- --------
Capital Expenditures:
Gas Utility Services $ 8,975 $ 11,203
Electric Utility Services 45,523 51,362
-------- --------
Total capital expenditures $ 54,498 $ 62,565
-------- --------
</TABLE>
<TABLE>
As of June 30 As of December 31
------------------- -----------------
2000 1999 1999
<S> <C> <C> <C>
Identifiable Assets:
Gas Utility Services $140,540 $139,875 $143,161
Electric Utility Services 737,833 734,341 751,598
Total identifiable assets $878,373 $874,216 $894,759
<FN>
<F1> The 2000 amounts include merger costs
(see Note 4).
</FN>
</TABLE>
<PAGE> 13
13. 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, and requires that a company must
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. SIGECO has not quantified
the impact of adopting this statement on its financial
position or results of operations.
14. 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
Net income applicable to common shareholders was $6.5
million for the three months ended June 30, 2000. Net
income applicable to common shareholders before merger
related charges (see merger costs below) was $8.3 million
for the three months ended June 30, 2000 as compared to net
income applicable to common shareholders of $7.6 million for
the same period in 1999.
Net income applicable to common shareholders was $10.5
million for the six months ended June 30, 2000. Net income
applicable to common shareholders before merger related
charges was $21.3 million for the six months ended June 30,
2000 as compared to net income applicable to common
shareholders of $19.9 million for the same period in 1999.
Net income applicable to common shareholders was $36.3
million for the twelve months ended June 30, 2000. Net
income applicable to common shareholders before merger
related charges was $47.1 million for the twelve months
ended June 30, 2000 as compared to net income applicable to
common shareholders of $42.0 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 June 30,
2000 was $51.9 million compared to $49.9 million for the
same period last year. During the current quarter, a $2.6
million increase in margin from nonfirm wholesale sales to
other utilities and power marketers was the primary reason
for the increase in total electric margin. Sales to these
customers were up 20 percent and average unit sales margins
were greater compared to the year ago period.
Electric utility margin for the six months ended June 30,
2000 was $103.2 million compared to $100.7 million for the
same period last year. For the six month period ending June
30, 2000, a 38 percent increase in sales to other utilities
and power marketers and higher average unit margins from
these sales contributed an additional $4.0 million to
electric margin, more than offsetting the impact of 6
percent fewer residential electric sales.
Electric utility margin for the twelve-month period ended
June 30, 2000, was $217.1 million compared to $207.5 million
for the same period last year. The $9.6 million increase in
margin reflected a $7.5 million increase in margin from
sales to other utilities and power marketers and a 4 percent
increase in retail and firm wholesale electric sales
primarily due to stronger industrial and commercial sales.
<PAGE> 15
Gas Margin (Gas Operating Revenues Less Cost of Gas)
Gas utility margin for the quarter ended June 30, 2000 was
$7.2 million compared to $5.6 million for the same period
last year reflecting a 13 percent increase in total system
throughput (combined sales and transportation volumes) due
to slightly more favorable weather conditions and continued
growth in the commercial and industrial sectors.
Gas utility margin for the six months ended June 30, 2000
was $16.8 million compared to $15.8 million for the same
period in 1999. The increase is primarily attributable to
the addition of new residential and commercial customers.
These increases were partially offset by 3 percent warmer
temperatures during the first half of 2000 compared to the
year ago period. Total throughput increased 4 percent
compared to the same period a year ago.
Gas utility margin for the twelve months ended June 30, 2000
was $29.5 million compared to $28.4 million for the same
period last year for the same reasons as described above.
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.
Operating Expenses (excluding Cost of Fuel, Purchased Power
and Cost of Gas)
Operation and maintenance expenses increased $4.1 million,
or 17 percent, for the three months ended June 30, 2000
compared to the same period in 1999. The increase is
primarily attributable to a rise in the utility operating
expenses due to $1.2 million additional scheduled
maintenance projects at SIGECO's generation facilities.
Operation and maintenance expenses increased $3.2 million,
or 7 percent, for the six months ended June 30, 2000 when
compared to the same period a year ago. The six month
increase is also primarily attributable to the rise in
utility operating expenses due to an additional $1.6 million
of scheduled maintenance projects at SIGECO's generation
facilities and increased general and administrative costs.
During the twelve-month period ended June 30, 2000 SIGECO's
operation and maintenance expenses increased $5.7 million,
or 6 percent, compared to the same period in 1999 for the
reasons discussed above.
Depreciation and amortization expense increased $1.1 million
during the twelve months ended June 30, 2000 compared to the
same period in the prior year due to additions to plant to
serve new customers.
Income taxes decreased $3.0 million and $1.3 million,
respectively, for the six and twelve months ended June 30,
2000 when compared to the same periods one year ago due to
changes in taxable income. Taxable income decreased
primarily due to the recognition of tax-deductible merger
costs.
Taxes other than income taxes increased slightly 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 and six
months ended June 30, 2000 totaled $3.3 million and $30.4
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 the merger savings are expected to be
realized. Merger costs expensed by SIGECO for the three and
six months ended June 30, 2000 totaled $1.4 million and
$13.8 million, respectively.
Other Income
Other Income - Net increased $0.7 million, $1.3 million and
$3.2 million, respectively, for the three, six and twelve
months ended June 30, 2000, compared to the prior year
periods due chiefly to additional capitalized interest costs
related to utility projects under construction.
<PAGE> 16
Environmental Matters
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.
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 $100
million, and related additional operation and maintenance
expenses could be an estimated $8 million to $10 million,
annually. Under the USEPA implementation schedule, the
emissions reductions and required control equipment must be
implemented and in place by May 15, 2003.
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.
<PAGE> 17
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 $100 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, and requires that a company must
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. SIGECO has not quantified
the impact of adopting this statement on its financial
position or results or operations.
Liquidity and Capital Resources
SIGECO's capitalization objectives are 45-60 percent common
and preferred equity and 40-55 percent long-term 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.
<PAGE> 18
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 $25.2 million have been
expended through June 30, 2000. For the twelve months ended
June 30, 2000, capital expenditures totaled $54.5 million.
SIGECO has $66 million of short-term borrowing capacity, of
which $49.6 million was available at June 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 at their highest and gas storage facilities
are being refilled.
Financing Activities
On July 3, 2000, all of SIGECO's $9,975,000 Adjustable Rate
Pollution Control Revenue Bonds were remarketed and the
interest rate was reset to 4.75% from 4.55%. The new
interest rate will be effective from July 1, 2000 through
June 30, 2001.
On July 7, 2000, SIGECO repurchased 22,000 shares of its
4.75% nonredeemable $100 par value preferred stock at a
purchase price of $84.25 per share. The stock was
repurchased as treasury stock and is to be retired.
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 June 30, 2000
was AA/Aa2.
Cash required for financing activities of $5.6 million for
the six months ended June 30, 2000 includes, among other
things, $15.5 million of dividends and $6.9 million of
additional net borrowings. Cash required for financing
activities of $31.5 million for the twelve months ended June
30, 2000 includes, among other things, $31.7 million of
dividends and $5.9 million of additional net debt pay-downs.
Cash required for investing activities of $28.1 million for
the six months ended June 30, 2000 includes, among other
things, $25.2 million of capital expenditures. Cash
required for investing activities of $58.3 million for the
twelve months ended June 30, 2000 includes, among other
things, $54.5 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.
<PAGE> 19
* 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
June 30, 2000, management believes exposure from these
positions was not material.
<PAGE> 20
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 pertains to the
summer months of 2000 and the parties have agreed to
collaborate on a permanent 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 June 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 9 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 27 Financial Data Schedule, filed herewith.
Form 8-K's
On April 14, 2000 SIGECO filed a Current Report on Form 8-K
with respect to the change in control of SIGECO as a result
of the merger of Indiana Energy, Inc. and SIGCORP, Inc into
Vectren Corporation.
Item 1. Changes in Control of Registrant
On April 17, 2000 SIGECO filed an Amended Current Report on
Form 8-K changing the signature of the report to M. Susan
Hardwick, Vice President and Controller.
Item 1. Changes in Control of Registrant
On April 27, 2000 SIGECO filed a Current Report on Form 8-K
with respect to the release by Vectren Corporation of
summary financial information to the investment community
regarding Vectren Corporation's consolidated results of
operation, financial position and cash flows for the three-
and twelve-month ended periods of March 31, 2000. Items
reported include:
Item 5. Other Events
Item 7. Exhibits
Exhibit 99-1 Press Release
Exhibit 99-2 Analyst Report - First Quarter 2000
Exhibit 99-3 Cautionary Statement for Purposes of the
"Safe Harbor" Provisions of the Private Securities
Litigation Reform Act of 1995
On April 27, 2000 SIGECO filed a Current Report on Form 8-K
with respect to an analyst teleconference call held on April
27, 2000.
Item 5. Other Events
Item 7. Exhibits
Exhibit 99 Analyst script teleconference call dated
April 27, 2000
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
ELECRIC COMPANY
Registrant
August 14, 2000 /s/ M. Susan Hardwick
M. Susan Hardwick
Vice President and Controller
August 14, 2000 /s/ Jerome A. Benkert
Jerome A. Benkert
Executive Vice President and
Chief Financial Officer
