SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K/A
Amendment No. 1
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
- -
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
__TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
----
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission Registrant, State of Incorporation; IRS Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------
1-3553 Southern Indiana Gas and Electric Company 35-0672570
(An Indiana Corporation)
20 N. W. Fourth Street
Evansville, Indiana 47741-0001
(812) 491-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
- -------------------- ------------------------ -------------------------
Southern Indiana Gas None
and Electric Company
Securities registered pursuant to Section 12(g) of the Act:
Name of each exchange
Registrant Title of each class on which registered
- --------------------- -------------------------- -----------------------
Southern Indiana Gas Cumulative Preferred Stock, New York Stock Exchange
and Electric Company $100 Par Value
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X.
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) have been subject to such filing
requirements for the past 90 days: Yes X No
At January 30, 2001, the aggregate market values of Southern Indiana Gas and
Electric Company Cumulative Preferred Stock, $100 Par Value, 163,895 shares,
held by non-affiliates was $13,812,650.
As of March 21, 2001, the number of shares outstanding of the Registrant's
classes of common stock were:
Southern Indiana Gas
and Electric Company: Common stock, no par value, 15,754,826 shares
Outstanding and held by Vectren Corporation
2
Table of Contents
Item Page
Number Number
7 Management's Discussion and Analysis
of Financial Condition and Results of Operations 3
8 Financial Statements and Supplementary Data 11
14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 33
Signatures 36
3
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Results of Operations
Net Income
Net income applicable to common shareholder was $40.0 million for the year ended
December 31, 2000. Net income applicable to common shareholder before merger and
integration costs of $14.1 million, or 11.0 million after tax, was $51.0 million
for the year ended December 31, 2000, as compared to net income of $45.7 million
and $42.4 million for 1999 and 1998, respectively. (See merger and integration
costs below.)
Utility Margin (Utility Operating Revenues Less Cost of Gas, Cost of Fuel and
Purchased Power)
Electric margin increased $9.7 million, or 5 percent, to $224.3 million for the
twelve-month period in 2000 compared to the same period in 1999. Although unit
prices were lower than in 1999, sales to the wholesale energy markets
contributed $4.4 million of the margin increase with volumes up 39 percent for
2000 compared to 1999. Additionally, the impact of much colder temperatures on
electric heating sales and a 5 percent growth in commercial customers
contributed to the 2000 electric margin increase. Mild summer temperatures
impacted both 2000 and 1999. Retail and firm wholesale electric sales for 2000
increased 2 percent and total electric sales increased 8 percent.
Electric utility margin for the year ended December 31, 1999 was $214.6 million,
compared to $208.3 million for the prior year. The $6.4 million increase in
margin reflects a 5 percent increase in retail and firm wholesale electric sales
primarily due to stronger industrial and commercial sales and a $1.0 million
increase in margin from sales to other wholesale customers. Although sales to
other wholesale customers declined 17 percent in 1999 due to milder summer
temperatures which eased demand in these markets, several new sales contracts
produced higher average unit sales prices to these customers.
A 1 percent increase in electric generation and higher per unit coal costs
resulted in a $3.5 million, or 5 percent, increase in fuel costs for electric
generation for 2000 compared to the prior year. Fuel costs for electric
generation increased $3.3 million, or 5 percent, in 1999.
Although SIGECO's sales of electric energy to other wholesale customers are
provided primarily from otherwise unutilized capacity, SIGECO's purchases of
electricity from other utilities for resale to other wholesale customers
typically represent the majority of SIGECO's total purchased electric energy
costs. The 39 percent increase in sales to other wholesale customers combined
with higher average market prices caused purchased electric energy costs to
increase $15.6 million, or 75 percent, for the year ended December 31, 2000
compared to 1999. During 1999, total purchases of electric energy declined 13
percent due to the 17 percent decline in sales to wholesale customers, however
higher average market prices for energy purchased resulted in total costs
remaining comparable to 1998 costs.
Gas margin increased $1.8 million to $30.4 million, or 6 percent, compared to
the twelve-month period in 1999. The increase reflects 12 percent (4 MMDth)
greater throughput (combined sales and transportation) due to much colder
temperatures during 2000 than in 1999. Although temperatures were 7 percent
warmer than normal for the year, temperatures during 2000 were 13 percent colder
than in 1999 causing residential and commercial sales to rise 11 percent and 14
percent, respectively.
In 1999, gas utility margin was $28.6 million, as compared to $27.2 million for
the prior year. The 1999 increase is primarily attributable to weather being 8
percent colder than the previous year and the addition of new residential and
commercial customers.
Total cost of gas sold was $78.9 million in 2000 and $39.6 million in 1999 and
1998. Total cost of gas sold increased $39.3 million, or 99 percent, for the
year ended December 31, 2000 compared to 1999, primarily due to significantly
higher average per unit purchased gas costs. The total average cost per Dth of
gas purchased was $5.09 in 2000, compared to $3.10 in 1999. The price changes
are due primarily to changing commodity costs in the marketplace. Decreases in
the average per unit cost of gas sold in 1999 as compared to 1998 more than
offset the impact of the increased throughput, making costs of gas sold in 1999
comparable to 1998.
4
Commodity prices for natural gas purchases during the last six months of 2000
unexpectedly increased significantly, primarily due to the expectation of a
colder winter, which led to increased demand and tighter supplies. SIGECO is
allowed full recovery of such charges in purchased gas costs from their retail
customers through commission-approved gas cost adjustment mechanisms, and margin
on gas sales should not be impacted. In 2001, SIGECO may experience higher
working capital requirements, increased expenses, including unrecoverable
interest costs and uncollectibles, and possibly some level of price sensitive
reduction in volumes sold.
Operating Expenses
SIGECO's operations and maintenance expenses increased $7.4 million, or 8
percent, for the year ended December 31, 2000, compared to the same period in
1999. The increase is primarily attributable to higher general and
administrative costs.
Operations and maintenance expenses rose $2.3 million, or 2 percent, for 1999 as
compared to 1998. This increase results from increased compensation and benefits
and other general operation expenses, offset by lower maintenance costs.
Depreciation and amortization decreased $ 1.7 million, or 4 percent, and
increased $ 2.5 million, or 6 percent, for the years ended December 31, 2000 and
1999, respectively. The decrease in 2000 is primarily attributable to the
contribution of certain information systems and equipment to a wholly owned
subsidiary of SIGECO's parent, Vectren Corporation. The increase in expense over
1998 reflects depreciation of normal additions of utility plant.
Federal and state income taxes declined $1.6 million in 2000, compared to 1999
due primarily to $7.3 million lower pre-tax earnings, partially offset by a
higher effective tax rate resulting from the non-deductibility of certain merger
costs. Federal and state income taxes increased $1.4 million, or 6 percent
during 1999 compared to 1998 due primarily to higher pre-tax income in 1999.
Taxes other than income taxes for 2000 and 1999 were comparable to the prior
periods.
Merger and Integration Costs
Merger and integration costs incurred for the year ended December 31, 2000
totaled $14.1 million ($11.0 million after tax). 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 completed in 2001. Merger costs are reflected in the financial
statements of the operating subsidiaries in which merger savings are expected to
be realized.
Of the $14.1 million of merger and integration costs incurred in 2000 by SIGECO,
accruals were established at March 31, 2000 totaling $7.4 million. Of this
amount, $0.7 million related to employee and executive severance and $6.7
million related to transaction costs and filing fees. At December 31, 2000, the
accrual remaining for such costs totaled $0.5 million, all related to severance
costs. Of the total $14.1 million, the remaining $6.7 million was expensed
throughout the year for accounting fees resulting from merger related filing
requirements, consulting fees related to integration activities such as
organization structure, employee travel between company locations as part of
integration activities, internal labor of employees assigned to integration
teams, and investor relations communications activities.
During the merger planning process, approximately 54 positions were identified
for elimination. As of December 31, 2000, approximately 35 positions had been
vacated, with the remaining 19 positions to be eliminated in 2001."
The integration activities experienced by the company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
Other Income
Other income increased $ 1.6 million and $.9 million, respectively, for the
years ended December 31, 2000 and 1999 due primarily to increased additional
funds used during construction (AFUDC) of utility plant. The increase in 1999
related to capitalized interest was partially offset by the loss of other income
resulting from sales of emission allowance credits under a five year contract
ending in 1998. Other income from Emission allowance credits sold in 1998
approximated $1.4 million.
5
Other Operating Matters
Operation of Warrick Generating Station
On August 21, 2000, SIGECO announced that no later than April 18, 2001, ALCOA,
INC. (ALCOA) would 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 the company's financial results. Additionally, SIGECO will
retain ALCOA as a wholesale power and transmission services customer. Transition
of the plant operations was completed in March 2001.
Realignment
Effective January 1, 2001, the SIGECO's operations were reorganized into two
primary business units, Energy Delivery and Power Supply.
Environmental Matters
NOx SIP Call Matter. In October 1997, the United States Environmental Protection
Agency (USEPA) proposed a rulemaking that could require uniform nitrogen oxide
(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 (the Act). 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 (IDEM) 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. On September
20, 2000, petitioners filed a Petition of Writ of Certiori with the United
6
States Supreme Court requesting review of the D.C. Circuit Court's March 3, 2000
Order. The Court has not yet ruled on the Petition for Certiorari. The EPA
granted Section 126 Petitions filed by northeastern states that require named
sources in the eastern half of Indiana to achieve NOx reduction by May 1, 2003.
No SIGECO facilities are named in the Section 126 Petitions filed by
northeastern states, therefore the compliance date remains 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, pending finalization of state rule making, 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. No accrual
has been recorded by the company related to the NOx SIP Call matter. The rules
governing NOx emissions, once finalized, are to be applied prospectively.
Mercury Emissions. On December 14, 2000, the USEPA released a statement
announcing that reductions of mercury emissions from coal-fired plants will be
required in the near future. The USEPA will propose regulations by December 2003
and issue final rules by December 2004.
Under the Act, the USEPA is required to study emissions from power plants in
order to determine if additional regulations are necessary to protect public
health. The USEPA reported its study to Congress in February 1998. That study
concluded that of all toxic pollution examined, mercury posed the greatest
concern to public health. An earlier USEPA study concluded that the largest
source of human-made mercury pollution in the United States was coal-fired power
plants.
After completion of the study, the Act required the USEPA to determine whether
to proceed with the development of regulations. The USEPA announced that it had
affirmatively decided that mercury air emissions from power plants should be
regulated. Because rules governing mercury emissions are under development, the
determination of exposure, if any, is impossible as there are no standards or
rules by which compliance (or lack thereof) can be measured. Accordingly, no
accrual has been recorded by the company related to the Mercury Emissions
matter.
Culley Generating Station Investigation Matter. The USEPA initiated an
investigation under Section 114 of 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
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 to comply 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 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.
7
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
Act. Accordingly, no accrual has been recorded by the company, and SIGECO
anticipates at this time that the plant will continue to operate while the
matter is being decided.
Information Request. On January 23, 2001, SIGECO received an information request
from the USEPA under Section 114(a) of the Act for historical operational
information on the Warrick and A.B. Brown generating stations. SIGECO plans to
provide all information requested, and management believes that no significant
issues will arise from this request.
As a result of the ongoing appeal of a generic order issued by the IURC in
August 1999 regarding guidelines for the recovery of purchased power costs,
SIGECO entered into a settlement agreement with the Indiana Office of Utility
Consumer Counselor (OUCC) that provides certain terms with respect to the
recoverability of such costs. The settlement, originally approved by the IURC on
August 9, 2000, has been extended by agreement through March 2002. Under the
settlement, SIGECO can recover the entire cost of purchased power up to an
established benchmark, and during forced outages, SIGECO will bear a limited
share of its purchased power costs regardless of the market costs at that time.
Based on this agreement, SIGECO believes it has significantly limited its
exposure to unrecoverable purchased power costs.
Regulatory Matters
See Note 13 in SIGECO's financial statements included in Item 8 Financial
Statements and Supplementary Data regarding matters affecting operations
regarding purchased power costs recovery.
New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), which
requires that every derivative instrument be recorded on the balance sheet as an
asset or liability measured at its fair value and that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met.
SFAS 133, as amended, is effective for fiscal years beginning after June 15,
2000 and must be applied to derivative instruments and certain derivative
instruments embedded in hybrid contracts that were issued, acquired or
substantively modified after December 31, 1998. SIGECO has completed the process
of identifying all derivative instruments, determining fair market values of
these derivatives, designating and documenting hedge relationships, and
evaluating the effectiveness of those hedge relationships. As a result of the
successful completion of this process, SIGECO adopted SFAS 133 as of January 1,
2001.
SFAS 133 requires that as of the date of initial adoption, the difference
between the fair market value of derivative instruments recorded on the balance
sheet and the previous carrying amount of those derivatives be reported in net
income or other comprehensive income, as appropriate, as the cumulative effect
of a change in accounting principle in accordance with APB 20, "Accounting
Changes."
A limited number of SIGECO's contracts are defined as derivatives under SFAS
133. These derivatives are forward physical contracts for the purchase and sale
of electricity by power marketing operations. The cumulative impact of the
adoption of SFAS 133 on January 1, 2001 is an earnings gain of approximately
$6.3 million.
8
Liquidity and Capital Resources
SIGECO's capitalization objectives are 40-55 percent permanent capitalization.
This objective may have varied, and will vary, from time to time, depending on
particular business opportunities and seasonal factors that affect the company's
operation. SIGECO's common equity component was 52 percent of its total
capitalization, including current maturities of long-term debt and adjustable
rate bonds subject to tender, at December 31, 2000 and 1999.
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. During 2000, however, short-term borrowings related to working capital
requirements were greatest during the last six months of the year due to the
higher natural gas costs.
Cash Flow From Operations
SIGECO's primary source of liquidity to fund working capital requirements has
been cash generated from operations, which totaled approximately $66.3 million,
$110.1 million and $88.4 million in 2000, 1999 and 1998 respectively.
Cash provided by operations decreased during 2000 as compared to 1999 by
approximately $43.8 million. The decrease is primarily attributable to merger
and integration costs causing lower net income, increased recoverable fuel and
natural gas costs and increased working capital requirements resulting from
higher natural gas costs. The increase of 1999 cash flow from operations as
compared to 1998 of approximately $21.7 million is primarily attributable to
lower inventories in storage at year end and increased net income.
Capital Expenditures and Other Investing Activities
Cash required for investing activities was $52.7 million for the year ended
December 31, 2000. This is a decrease of approximately $9.0 million over prior
year due primarily to increased expenditures in 1999 for the design and
implementation of several comprehensive information systems necessary to meet
expanding customer needs and to better manage resources. This expenditure was
also the primary reason 1999 investing activities exceeded 1998 levels.
New construction and normal system improvements needed to provide service to a
growing customer base will continue to require substantial capital expenditures.
Additionally, during the four year period 2001 through 2004, construction costs
for NOx emissions control equipment are estimated to total approximately $160
million. Capital expenditures for the five year period 2001 - 2005 are as
follows (in millions):
2001 $ 96.5
2002 84.8
2003 83.4
2004 62.4
2005 73.6
----
Total $ 400.7
The above projected expenditures include the following:
- - Expenditures for NOx compliance of approximately $40 million in 2001, $30
million in 2002, $55 million in 2003 and $35 million in 2004.
- - Expenditures for an 80-megawatt gas combustion turbine generator of $20
million in 2001 and $13 million in 2002.
- - Expenditures for additional generation assets of approximately $40 million
in 2005.
Financing Activities
Cash flow required for financing activities of $12.4 million for the year ended
December 31, 2000 includes $16.8 million of additional net borrowings offset by
$32.0 million of dividends on shares of common and preferred stock and
reductions in preferred stock.
9
Cash required for financing activities in 1999 increased $16.7 million compared
to 1998 requirements. The increase is primarily the result of internally
generated funds used to pay down short term borrowings. The decrease in
short-term borrowings was partially offset by the issuance of long term notes
payable.
SIGECO has $53.7 million of adjustable rate pollution control series first
mortgage bonds which could, at the election of the bondholder, be tendered to
SIGECO when the interest rates are reset. Prior to the latest reset on March 1,
2001, the interest rates were set annually and the bonds subject to tender were
presented as current liabilities.
On March 1, 2000, the interest rate on $31.5 million of Adjustable Rate
Pollution Control bonds of SIGECO, due March 1, 2025, was changed from 3.00
percent to 4.30 percent. The new interest rate was fixed through February 28,
2001. Also on March 1, 2000, the interest rate on $22.2 million of Adjustable
Rate Pollution Control bonds of SIGECO, due March 1, 2020, was changed from 3.05
percent to 4.45 percent. The new interest rate was also fixed through February
28, 2001. On March 1, 2001, the two series of bonds were reset for a five-year
period effective on that date at 4.65 percent for the $31.5 million bonds and
5.00 percent for the $22.2 million bonds. As a result, the bonds will be
presented as long-term debt going forward.
SIGECO's credit rating on outstanding debt at December 31, 2000 was A/A1.
At December 31, 2000, SIGECO had $63 million of short-term borrowing capacity
for use in its operations, of which approximately $23 million was available.
Forward-Looking Information
A "safe harbor" for forward-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:
o 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.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o 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.
o 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.
o Economic conditions including inflation rates and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
10
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o 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.
o Employee workforce factors including changes in key executives, collective
bargaining agreements with union employees, or work stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o 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.
o 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.
11
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(in thousands)
December 31
2000 1999
---- ----
ASSETS
Utility Plant, at original cost:
Electric $1,175,552 $1,160,216
Gas 160,872 156,918
---------- ----------
1,336,424 1,317,134
Less: accumulated depreciation and amortization 650,499 623,611
---------- ----------
685,925 693,523
Construction work in progress 52,582 45,393
---------- ----------
Net utility plant 738,507 738,916
---------- ----------
Current Assets:
Cash and cash equivalents 1,613 449
Accounts receivables, less reserves of $2,639
and $2,138, respectively 49,554 34,738
Accounts receivable from affiliated company 27,829 1,159
Accrued unbilled revenues 24,414 18,736
Inventories 31,055 41,459
Recoverable fuel and natural gas costs 28,703 5,585
Other current assets 312 5,306
---------- ----------
Total current assets 163,480 107,432
---------- ----------
Other Investments and Property:
Environmental improvement fund held by trustee 1,056 996
Nonutility property and other, net 1,960 1,627
---------- ----------
Total other investments and property 3,016 2,623
---------- ----------
Other Assets:
Regulatory assets 33,443 34,027
Deferred charges 12,868 11,761
---------- ----------
Total other assets 46,311 45,788
---------- ----------
TOTAL ASSETS $ 951,314 $ 894,759
========== ==========
The accompanying notes to financial statements are an
integral part of these statements.
12
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(in thousands)
December 31
2000 1999
---- ----
SHAREHOLDER'S EQUITY AND LIABILITIES
Capitalization:
Common Stock $ 78,258 $ 78,258
Retained Earnings 258,877 256,312
-------- --------
Total common shareholder's equity 337,135 334,570
Cumulative nonredeemable preferred stock 8,890 11,090
Cumulative redeemable preferred stock 7,500 7,500
Cumulative special preferred stock 576 692
Long-term debt, net of current maturities 237,799 238,282
-------- --------
Total capitalization, net of current maturities 591,900 592,134
-------- --------
Commitments and Contingencies
Current Liabilities:
Current maturities of adjustable rate bonds
subject to tender 53,700 53,700
Short-term borrowings 40,154 22,880
Accounts payable to affiliated company 11,486 -
Accounts payable 60,085 28,560
Dividends payable 144 117
Accrued taxes 9,956 8,408
Accrued interest 6,047 6,012
Refunds to customers 3,543 5,375
Deferred income taxes 11,295 2,427
Other accrued liabilities 14,278 14,346
-------- --------
Total current liabilities 210,688 141,825
-------- --------
Deferred Credits And Other Liabilities:
Deferred income taxes 112,122 120,550
Unamortized investment tax credits 15,944 17,372
Accrued postretirement benefits other than pensions 14,054 12,041
Accrued pensions 6,310 8,360
Other 296 2,477
-------- --------
Total deferred credits and other liabilities 148,726 160,800
-------- --------
TOTAL SHAREHOLDER'S EQUITY AND LIABILITIES $951,314 $894,759
======== ========
The accompanying notes to financial statements are an
integral part of these statements.
13
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(in thousands)
Year Ended
December 31
-----------
2000 1999 1998
---- ---- ----
OPERATING REVENUES:
Electric revenues $336,409 $307,569 $297,865
Gas revenues 109,284 68,212 66,801
-------- -------- --------
Total operating revenues 445,693 375,781 364,666
-------- -------- --------
COST OF OPERATING REVENUES:
Cost of fuel and purchased power 112,093 92,946 89,611
Cost of gas 78,903 39,612 39,627
-------- -------- --------
Total cost of operating revenues 190,996 132,558 129,238
-------- -------- --------
Total margin 254,697 243,223 235,428
OPERATING EXPENSES:
Operations and maintenance 103,053 95,658 93,399
Merger and integration costs 14,072 - -
Depreciation and amortization 43,214 44,868 42,401
Income taxes 24,832 26,428 25,035
Taxes other than income taxes 13,258 12,844 12,591
-------- -------- --------
Total operating expenses 198,429 179,798 173,426
-------- -------- --------
OPERATING INCOME 56,268 63,425 62,002
OTHER INCOME -NET 4,674 3,109 2,221
-------- -------- --------
INCOME BEFORE INTEREST AND PREFERRED
STOCK DIVIDEND 60,942 66,534 64,223
INTEREST EXPENSE 19,894 19,766 20,681
-------- -------- --------
NET INCOME 41,048 46,768 43,542
PREFERRED STOCK DIVIDEND 1,017 1,078 1,095
-------- -------- --------
NET INCOME APPLICABLE TO COMMON
SHAREHOLDER $ 40,031 $ 45,690 $ 42,447
======== ======== ========
The accompanying notes to financial statements are an
integral part of these statements.
14
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended
December 31
2000 1999 1998
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 41,048 $ 46,768 $ 43,542
Adjustments to reconcile net income to net cash
Provided from operating activities:
Depreciation and amortization 43,214 44,868 42,401
Deferred income taxes and investment tax credits, net 13 3,396 2,665
Allowance for other funds used during construction (2,051) (296) -
Changes in assets and liabilities:
Receivables, net (including accrued unbilled revenues) (47,163) (5,183) 5,152
Inventories 10,404 5,201 (12,586)
Recoverable fuel costs (23,117) 346 3,198
Regulatory assets 584 1,435 970
Accounts payable 43,012 433 1,061
Accrued taxes 1,548 3,637 (1,153)
Refunds to customers (1,832) 3,219 1,000
Other assets and liabilities 661 6,312 2,163
--------- --------- ---------
Net cash flows from operating activities 66,321 110,136 88,413
--------- --------- ---------
CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES:
Retirement of long-term debt - (55,000) (14,000)
Proceeds from long-term debt - 80,000 -
Dividends paid (29,656) (32,380) (30,188)
Reduction in preferred stock (2,316) (116) (116)
Net change in short-term borrowings 16,791 (44,379) 13,588
Other 2,773 3,393 (1,065)
--------- --------- ---------
Net cash flows (required for) financing activities (12,408) (48,482) (31,781)
--------- --------- ---------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES:
Construction expenditures (net of allowance for
funds used during construction) (51,119) (60,677) (55,313)
Change in nonutility property (333) (50) (25)
Other (1,297) (990) (1,896)
--------- --------- ---------
Net cash flows (required for) investing activities (52,749) (61,717) (57,234)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 1,164 (63) (602)
Cash and cash equivalents at beginning of period 449 512 1,114
--------- --------- ---------
Cash and cash equivalents at end of period $ 1,613 $ 449 $ 512
========= ========= =========
The accompanying notes to financial statements are an
integral part of these statements.
15
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF RETAINED EARNINGS
(in thousands)
December 31
-----------
2000 1999 1998
--------- --------- ---------
Balance Beginning of Period $ 256,312 $ 241,924 $ 228,570
Net Income 41,048 46,768 43,542
--------- --------- ---------
297,360 288,692 272,112
Preferred Stock Dividends 1,017 1,078 1,095
Common Stock Dividends 28,639 31,302 29,093
--------- --------- ---------
29,656 32,380 30,188
--------- --------- ---------
Other 317 - -
Contribution of assets to parent (9,144) - -
--------- --------- ---------
Balance End of Period $ 258,877 $ 256,312 $ 241,924
========= ========= =========
The accompanying notes to financial statements are an integral part of
these statements
16
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Southern Indiana Gas and Electric Company (SIGECO) provides generation,
transmission, distribution and the sale of electric power to Evansville,
Indiana, and 74 other communities, and the distribution and sale of natural gas
to Evansville, Indiana, and 64 communities in ten counties in southwestern
Indiana.
Vectren Corporation (Vectren) was organized on June 10, 1999 solely for the
purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP), SIGECO's former parent company. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax-free exchange of shares that has been accounted for as a
pooling-of-interests. The merger did not affect SIGECO's preferred stock or debt
securities. SIGECO operates as a separate wholly owned subsidiary of Vectren.
2. Merger and Integration Costs
Merger and integration costs incurred for the year ended December 31, 2000
totaled $14.1 million. The continued merger and integration activities will be
substantially completed in 2001. Merger costs are reflected in the operating
subsidiaries in which merger savings are expected to be realized.
Of the $14.1 million of merger and integration costs incurred in 2000 by SIGECO,
accruals were established at March 31, 2000 totaling $7.4 million. Of this
amount, $0.7 million related to employee and executive severance and $6.7
million related to transaction costs and filing fees. At December 31, 2000, the
accrual remaining for such costs totaled $0.5 million, all related to severance
costs. Of the total $14.1 million, the remaining $6.7 million was expensed
throughout the year for accounting fees resulting from merger related filing
requirements, consulting fees related to integration activities such as
organization structure, employee travel between company locations as part of
integration activities, internal labor of employees assigned to integration
teams, and investor relations communications activities.
During the merger planning process, approximately 54 positions were identified
for elimination. As of December 31, 2000, approximately 35 positions had been
vacated, with the remaining 19 positions to be eliminated in 2001."
The integration activities experienced by the company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
3. Summary of Significant Accounting Policies
A. Utility Plant and Depreciation Utility plant is stated at historical cost,
including an allowance for the cost of funds used during construction.
Depreciation of utility property is provided using the straight-line method over
the estimated service lives of the depreciable assets.
The average depreciation rates, expressed as a percentage of original cost, were
3.3 percent, 3.5 percent and 3.4 percent for the years ended December 31, 2000,
1999 and 1998, respectively.
SIGECO follows the practice of charging maintenance and repairs, including the
cost of removal of minor items of property, to expense as incurred. When
property that represents a retirement unit is replaced or removed, the cost of
such property is credited to utility plant, and such cost, together with the
cost of removal less salvage, is charged to the accumulated provision for
depreciation.
17
B. 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:
Year Ended December 31 (in thousands) 2000 1999 1998
------- ------- -------
Cash paid during the year for
Interest (net of amount capitalized) $17,506 $15,437 $18,484
Income taxes 21,627 25,476 23,789
During 2000, SIGECO contributed computer software and hardware with a book value
of approximately $9.1 million to Vectren as a special dividend. This transaction
resulted in no gain or loss and is omitted from the Statement of Cash Flows.
C. Revenues
Revenues are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, SIGECO records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period.
Excise taxes are embedded in rates charged to customers. Accordingly, the
company records excise tax received as a component of operating revenues. Excise
taxes paid are recorded as a component of taxes other than income taxes.
D. Earnings Per Share
Historical earnings per share are not presented as Vectren holds the common
shares of SIGECO.
E. Reclassifications
Certain reclassifications have been made to the prior years' financial
statements to conform to the current year presentation. These reclassifications
have no impact on net income previously reported.
F. Inventories
SIGECO accounts for inventories under the average cost method except for gas in
underground storage which is accounted for under the last-in, first-out (LIFO)
method.
At December 31 (in thousands) 2000 1999
------- -------
Fuel (coal and oil) for electric generation $ 4,111 $12,229
Materials and supplies 15,022 13,352
Emission allowances 3,860 4,437
Gas in underground storage - at LIFO cost 8,062 11,441
------- -------
Total inventories $31,055 $41,459
======= =======
Based on the average cost of gas purchased during December, the cost of
replacing the current portion of gas in underground storage exceeded LIFO cost
at December 31, 2000 and 1999 by approximately $35 million and $12 million,
respectively.
G. Refundable or Recoverable Gas Costs, Fuel for Electric Production and
Purchased Power
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 that 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.
18
H. Allowance for Funds used During Construction
An allowance for funds used during construction (AFUDC), which represents the
cost of borrowed and equity funds used for construction purposes, is charged to
construction work in progress during the period of construction and included in
other - net on the Statements of Income.
The table below reflects the total AFUDC capitalized and the portion of which
was computed on borrowed and equity funds for all periods reported.
Year Ended December 31 (in thousands) 2000 1999 1998
------ ------ ------
AFUDC - borrowed funds $1,817 $2,508 $1,465
AFUDC - equity funds 2,051 296 -
------ ------ ------
Total AFUDC capitalized $3,868 $2,804 $1,465
====== ====== ======
I. Income Taxes
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized, at currently enacted income tax rates, to reflect
the tax effect of temporary differences between the book and tax bases of assets
and liabilities. Deferred investment tax credits are being amortized over the
life of the related asset.
J. Use of Estimates
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 financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
K. Regulation
SIGECO is subject to regulation by the Indiana Utility Regulatory Commission
(IURC). The wholesale energy sales of SIGECO are subject to regulation by the
Federal Energy Regulatory Commission (FERC). The accounting policies of SIGECO
give recognition to the ratemaking and accounting practices of these agencies
and to accounting principles generally accepted in the United States, including
the provisions of Statement of Financial Accounting Standards No. 71 "Accounting
for the Effects of Certain Types of Regulation" (SFAS 71). Regulatory assets
represent probable future revenues associated with certain incurred costs, which
will be recovered from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues associated with
amounts that are to be credited to customers through the ratemaking process.
The following regulatory assets and liabilities are reflected in the financial
statements:
At December 31 (in thousands) 2000 1999
------- -------
Regulatory Assets:
Demand side management programs $26,243 $25,900
Unamortized premium on reacquired debt 4,192 4,416
Unamortized debt discount and expenses 2,886 2,456
Other 122 1,255
------- -------
Regulatory assets in other assets 33,443 34,027
Recoverable fuel and natural gas costs 28,703 5,585
------- -------
Total regulatory assets $62,146 $39,612
======= =======
As of December 31, 2000, the recovery of $40.7 million of SIGECO's $ 62.1
million of total regulatory assets is reflected in rates charged to customers.
The remaining $21.4 million of regulatory assets, which are not yet included in
rates, represent SIGECO's demand side management (DSM) costs incurred after
1993. When SIGECO files its next electric base rate case, these costs will be
included in rate base and requested to earn a return. Amortization of the costs
over a period anticipated to be 15 years will be recovered through rates as a
cost of operations. SIGECO is currently recovering $4.8 million of DSM costs in
rates. Based upon this prior regulatory authority, management believes that
future recovery of the $21.4 million of regulatory assets for DSM costs is
probable.
19
Of the $40.7 million of regulatory assets currently reflected in rates, a total
of $9.1 million is earning a return: $4.9 million of pre-1994 DSM costs and $4.2
million of unamortized premium on reacquired debt. The remaining recovery
periods for the DSM costs and premium on reacquired debt are 11.5 years and 20
years, respectively. The remaining $31.6 million of regulatory assets included
in rates, but not earning a return, are being recovered over varying periods:
$7.1 million of fuel costs and $21.6 million of gas costs, over 12 months; and
$2.9 million of unamortized debt discount and expense to be recovered over the
lives of the related issues.
SIGECO's policy is to continually assess the recoverability of costs recognized
as regulatory assets and the ability to continue to account for their activities
in accordance with SFAS 71, based on the criteria set forth in SFAS 71. Based on
current regulation, SIGECO believes such accounting is appropriate. If all or
part of SIGECO's operations cease to meet the criteria of SFAS 71, a write-off
of related regulatory assets and liabilities could be required. In addition,
SIGECO would be required to determine any impairment to the carrying costs of
deregulated plant and inventory assets.
L. New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), which
requires that every derivative instrument be recorded on the balance sheet as an
asset or liability measured at its fair value and that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met.
SFAS 133, as amended, is effective for fiscal years beginning after June 15,
2000 and must be applied to derivative instruments and certain derivative
instruments embedded in hybrid contracts that were issued, acquired or
substantively modified after December 31, 1998. SIGECO has completed the process
of identifying all derivative instruments, determining fair market values of
these derivatives, designating and documenting hedge relationships, and
evaluating the effectiveness of those hedge relationships. As a result of the
successful completion of this process, SIGECO adopted SFAS 133 as of January 1,
2001.
SFAS 133 requires that as of the date of initial adoption, the difference
between the fair market value of derivative instruments recorded on the balance
sheet and the previous carrying amount of those derivatives be reported in net
income or other comprehensive income, as appropriate, as the cumulative effect
of a change in accounting principle in accordance with APB 20, "Accounting
Changes."
A limited number of SIGECO's contracts are defined as derivatives under SFAS
133.
SIGECO uses derivative and non-derivative forward contracts in its power
marketing operations to effectively manage the utilization of its generation
capability. Certain forward sales contracts are used to sell the excess
generation capacity of SIGECO when demand conditions warrant this activity.
These contracts involve the normal sale of electricity and therefore do not
require fair value accounting under SFAS 133. Certain forward purchase and sale
contracts entered into as part of "buy-sell" transactions with other utilities
and power marketers are derivatives but do not qualify for hedge accounting. The
mark to market impact of these derivatives upon adoption of SFAS 133 is
reflected as part of the transition adjustment recorded to earnings on January
1, 2001. The cumulative impact of the adoption of SFAS 133 on January 1, 2001 is
an earnings gain of approximately $6.3 million.
M. Impairment Review of Long Lived Assets
Long-lived assets are reviewed for impairment in accordance with SFAS No. 121,
Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of, as facts and circumstances indicate that the carrying amount may be
impaired. Specifically, the evaluation for impairment involves the comparison of
an asset's carrying value and the estimated undiscounted future cash flows the
asset is expected to generate over its remaining life. If this evaluation were
to conclude that the carrying value of the asset is impaired, an impairment
charge would be recorded as a charge to operations based on the difference
between the asset's carrying amount and its fair value.
4. Preferred Stock
Cumulative Preferred Stock
The amount payable in the event of involuntary liquidation of each series of the
$100 par value preferred stock is $100 per share, plus accrued dividends. This
nonredeemable preferred stock is callable at the option of SIGECO as follows:
20
the 4.8% Series at $110 per share, plus accrued dividends; and the 4.75% Series
at $101 per share, plus accrued dividends. As of December 31, 2000 and 1999,
there were 85,895 shares of the 4.8% Series outstanding and 3,000 shares and
25,000 shares of the 4.75% Series outstanding, respectively.
Cumulative Redeemable Preferred Stock
The Series has a dividend rate of 6.50% and is redeemable at $100 per share on
December 1, 2002. In the event of involuntary liquidation of this series of $100
par value preferred stock, the amount payable is $100 per share, plus accrued
dividends. As of December 31, 2000 and 1999, there were 75,000 shares
outstanding.
Cumulative Special Preferred Stock
The Cumulative Special Preferred Stock has a dividend rate of 8.5% and in the
event of involuntary liquidation the amount payable is $100 per share, plus
accrued dividends. This Series is callable at the option of the company at a
rate of 1,160 shares per year. As of December 31, 2000 and 1999, there were
5,757 shares and 6,917 shares outstanding, respectively.
5. Long-Term Debt
First mortgage bonds and notes payable outstanding and classified as long-term
are as follows:
At December 31 (in thousands) 2000 1999
--------- ---------
First Mortgage Bonds due:
2014, 4.60% Pollution Control Series A $ 22,500 $ 22,500
Adjustable Rate Pollution Control:
2015, Series A, presently 4.55% 9,975 9,975
2016, 8.875% 13,000 13,000
2020, 4.40% Pollution Control Series B 4,640 4,640
Adjustable Rate Environmental Improvement:
2023, Series B, presently 6% 22,800 22,800
2023, 7.60% 45,000 45,000
2025, 7.625% 20,000 20,000
2029, 6.72% 80,000 80,000
2030, 4.40% Pollution Control Series B 22,000 22,000
--------- ---------
Total first mortgage bonds 239,915 239,915
--------- ---------
Notes Payable:
Tax Exempt, due 2003, 6.25% 1,000 1,000
--------- ---------
Total long-term debt outstanding 240,915 240,915
Less: Maturities and sinking fund requirements - -
Unamortized debt premium and discount, net (3,116) (2,633)
--------- ---------
Total long-term debt and other obligations, net
of current maturities $ 237,799 $ 238,282
========= =========
Consolidated maturities and sinking fund requirements on long-term debt subject
to mandatory redemption during the five years following 2000 (in millions) are
$0 in 2001, $0 in 2002, $1.0 in 2003, $0 in 2004, and $0 in 2005.
In addition to the obligations presented in the table above, SIGECO has $53.7
million of adjustable rate pollution control series first mortgage bonds which
could, at the election of the bondholder, be tendered to SIGECO annually in
March. If SIGECO's agent is unable to remarket any bonds tendered at that time,
SIGECO would be required to obtain additional funds for payment to bondholders.
For financial statement presentation purposes those bonds subject to tender in
2001 are shown as current liabilities. The two series of bonds will be re-set
for a five-year period effective March 1, 2001.
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1
percent of the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the Trustee of
21
unfunded property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2001 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2001 is excluded from
current liabilities on the Balance Sheets. At December 31, 2000, $220.9 million
of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.
The above debt agreements contain certain financial covenants and other
restrictions with which SIGECO must comply, and SIGECO was in compliance with
all financial covenants and restrictions.
6. Short-Term Borrowings
At December 31, 2000, SIGECO has approximately $63 million of short-term
borrowing capacity of which approximately $23 million is available for
operations. See the table below for outstanding balances and interest rates.
At December 31 (in thousands) 2000 1999
---------- ----------
Notes Payable
Balance at year end $ 40,154 $ 22,880
Weighted average interest rate on
year end balance 7.26% 6.42%
Average daily amount outstanding
during the year $ 20,026 $ 54,576
Weighted average interest rate on average
daily amount outstanding during the year 6.24% 5.74%
7. Income Taxes
The components of income tax expense were as follows:
Year Ended December 31 ( in thousands) 2000 1999 1998
-------- -------- --------
Current:
Federal $ 21,754 $ 19,837 $ 19,521
State 3,065 3,195 2,849
-------- -------- --------
Total current taxes 24,819 23,032 22,370
-------- -------- --------
Deferred:
Federal 1,030 4,080 3,270
State 411 746 842
-------- -------- --------
Total deferred taxes 1,441 4,826 4,112
-------- -------- --------
Amortization of Investment tax credit (1,428) (1,430) (1,447)
Income tax expense $ 24,832 $ 26,428 $ 25,035
======== ======== ========
A reconciliation of the statutory rate to the effective income tax rate is as
follows:
Year Ended December 31 2000 1999 1998
------ ------ ------
Statutory federal and state rate 37.9% 37.9% 37.9%
Non deductible merger costs 3.5 - -
Amortization of deferred investment
tax credit (2.2) (1.9) (2.1)
All other, net (0.9) 0.6 1.3
------ ------ ------
Effective tax rate 38.3% 36.6% 37.1%
------ ------ ------
Significant components of SIGECO's net deferred tax liability as of December 31,
2000 and 1999 are as follows:
At December 31 (in thousands) 2000 1999
--------- ---------
Deferred Tax Liabilities:
Depreciation and cost recovery timing
differences $ 113,075 $ 120,307
Deferred fuel costs, net 8,168 2,427
Regulatory assets recoverable through
future rates 24,836 26,128
Other 3,128 -
Deferred Tax Assets:
Regulatory liabilities to be settled
through future rates (17,654) (20,388)
Other (8,136) (5,497)
--------- ---------
Net deferred income tax liability $ 123,417 $ 122,977
========= =========
22
8. Retirement Plans and Other Postretirement Benefits
Prior to July 1, 2000, SIGECO and Indiana Energy had separate retirement and
other postretirement benefit plans. Effective July 1, 2000, the SIGECO and
Indiana Energy pension plans and retirement savings plans for employees not
covered by a collective bargaining unit were merged. The pension plans and
retirement savings plans described above became Vectren plans. As a result, the
respective plan assets and plan obligations were transferred to Vectren. Vectren
paid cash to SIGECO for assets received and received cash from SIGECO for the
assumption of liabilities. The transfers resulted in no gain or loss.
SIGECO has multiple defined benefit pension and other postretirement benefit
plans which cover eligible full-time regular employees. All of the plans are
non-contributory. The nonpension plans include plans for health care and life
insurance through a combination of self-insured and fully insured plans.
The IURC has authorized SIGECO to recover the costs related to postretirement
benefits other than pensions under the accrual method of accounting consistent
with Statement of Financial Accounting Standards No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions. Amounts accrued prior to that
authorization were deferred as allowed by the IURC and amortized over a 60-month
period.
The detailed disclosures of benefit components that follow are based on an
actuarial valuation performed for the December 31, 2000 financial statements
using a measurement date as of September 30, 2000. Net periodic benefit cost
consisted of the following components:
Year Ended December 31,
-------------------------------
Pension Benefits Other Benefits
--------------------------- --------------------------
In thousands 2000 1999 1998 2000 1999 1998
------- ------- ------- ------- ------- -------
Service cost $ 1,907 $ 3,020 $ 2,639 $ 542 $ 620 $ 578
Interest cost 4,346 5,637 5,020 1,914 1,707 1,664
Expected return on plan assets (4,891) (6,517) (5,985) (921) (751) (577)
Amortization of prior service cost 210 307 178 - - -
Amortization of transitional (asset)
obligation (330) (418) (418) 1,294 1,311 1,311
Recognized actuarial gain (464) (300) (47) (816) (757) (743)
Settlement charge 711 - - - - -
Special termination benefit charge - - - - - -
------- ------- ------- ------- ------- -------
Net periodic benefit cost $ 1,489 $ 1,729 $ 1,387 $ 2,013 $ 2,130 $ 2,233
======= ======= ======= ======= ======= =======
A reconciliation of the plan's benefit obligations, fair value of plan assets,
funded status and amounts recognized in the Balance Sheets follows:
At December 31,
-------------------------------------
Benefit obligation Pension Benefits Other Benefits
-------------------- --------------------
In thousands 2000 1999 2000 1999
-------- -------- -------- --------
Benefit obligation at beginning of year $ 81,702 $ 79,743 $ 24,908 $ 25,529
Service cost - benefits earned
during the year 1,907 3,020 542 620
Interest cost on projected benefit
obligation 4,346 5,637 1,914 1,707
Plan amendments - 33 (711) -
Transfers (46,989) - - -
Settlements 711 - - -
Benefits paid (2,118) (3,286) (1,082) (661)
Actuarial (gain) loss (610) (3,445) 111 (2,287)
-------- -------- -------- --------
Benefit obligation at end of year $ 38,949 $ 81,702 $ 25,682 $ 24,908
======== ======== ======== ========
23
Fair value of Plan Assets Pension Benefits Other Benefits
-------------------- --------------------
In thousands 2000 1999 2000 1999
-------- -------- -------- --------
Plan assets at fair value at beginning of year $ 86,051 $ 83,337 $ 11,709 $ 9,511
Actual return on plan assets 5,020 6,000 595 1,434
Employer contributions - - - 1,425
Transfers (48,058) - - -
Benefits paid (2,118) (3,286) (1,082) (661)
-------- -------- -------- --------
Fair value of plan assets at end of year $ 40,895 $ 86,051 $ 11,222 $ 11,709
======== ======== ======== ========
Funded Status Pension Benefits Other Benefits
-------------------- ---------------------
In thousands 2000 1999 2000 1999
-------- -------- ---------- ---------
Funded status $ 1,946 $ 4,349 $ (14,458) $(13,199)
Unrecognized transitional obligation (asset) (804) (1,398) 15,037 17,043
Unrecognized service cost 1,125 3,180 - -
Unrecognized net (gain) loss and other (8,577) (14,491) (14,633) (15,885)
-------- -------- ---------- ---------
Net amount recognized $ (6,310) $ (8,360) $ (14,054) $(12,041)
======== ======== ========== =========
The fair value of plan assets for pension plans with benefit obligations is in
excess of the benefit obligation as of December 31, 2000 and 1999.
Weighted-average assumptions used in the accounting for these plans were as
follows:
Year Ended December 31,
----------------------------------
Pension Benefits Other Benefits
---------------- -------------------
2000 1999 2000 1999
------ ------ ------- ------
Discount rate 7.75% 7.50% 7.75% 7.50%
Expected return on plan assets 8.50% 8.50% N/A N/A
Rate of compensation increase 5.00% 5.00% N/A N/A
CPI rate N/A N/A 7.00% 6.50%
As of December 31, 2000, the health care cost trend is 7 percent declining to 5
percent in 2004 and remaining level thereafter. The accrued health care cost
trend rate for 2001 is 7 percent. The estimated cost of these future benefits
could be significantly affected by future changes in health care costs, work
force demographics, interest rates or plan changes.
A 1 percent change in the assumed health care cost trend for the postretirement
health care plan would have the following effects:
In thousands 1% Increase 1% Decrease
--------- ----------
Effect on the aggregate of the service
and interest cost components $ 309 $ (242)
Effect on the postretirement benefit
obligation 2,549 (2,038)
SIGECO has adopted Voluntary Employee Beneficiary Association (VEBA) Trust
Agreements for the benefit of SIGECO employees for the funding of postretirement
health benefits for retirees and their eligible dependents and beneficiaries.
Annual funding is discretionary and is based on the projected cost over time of
benefits to be provided to cover persons consistent with acceptable actuarial
methods. To the extent these postretirement benefits are funded, the benefits
will not be shown as a liability on SIGECO's financial statements.
24
9. Fair Value of Financial Instruments
Except for the following financial instruments, fair value of SIGECO's financial
instruments is equivalent to carrying value due to their short-term nature.
At December 31 (in thousands) 2000 1999
---------------------- ---------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
--------- ---------- -------- ----------
Long-Term Debt (includes current maturities) $291,499 $326,653 $291,982 $316,535
Redeemable Preferred Stock 5,300 5,467 7,500 7,538
Certain methods and assumptions must be used to estimate the fair value of
financial instruments. Because of the short maturity of notes payable, the
carrying amounts approximate fair values for these financial instruments. The
fair value of SIGECO's long-term debt was estimated based on the quoted market
prices for the same or similar issues or on the current rates offered for debt
of the same remaining maturities. The fair value of redeemable preferred stock
was based on the current quoted market rate of long-term debt with similar
characteristics.
The market price used to value these transactions reflects management's best
estimate of market prices considering various factors, including published
prices for certain delivery locations, time value and volatility factors
underlying the commitments.
10. Stock-Based Compensation
SIGECO does not have stock-based compensation plans separate from Vectren.
SIGECO's employees, officers and directors participate in Vectren's stock-based
compensation plans that provide for awards of restricted stock and stock options
to purchase Vectren common stock at prices equal to the fair value of the
underlying shares at the date of grant. Consistent with Vectren, SIGECO accounts
for participation in these plans in accordance with Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" and related
interpretations in measuring compensation costs for its stock options and
discloses pro forma net income as if compensation costs had been determined
consistent with the SFAS No. 123, "Accounting for Stock-based Compensation."
Had compensation cost for stock options been determined consistent with SFAS No.
123 "Accounting for Stock-based Compensation," net income applicable to common
shareholder would not have been materially different than reported amounts.
Certain SIGECO employees held options to purchase SIGCORP common shares granted
under the 1994 SIGECO Stock Option Plan and other employee compensation benefits
arrangements. When the merger was consummated, each unexpired and unexercised
option to purchase SIGCORP common shares was automatically converted into an
option to purchase the number of Vectren common shares that could have been
purchased under the original option multiplied by 1.333 (the exchange ratio in
the merger between Indiana Energy, Inc. and SIGCORP). The exercise price per
Vectren common share under the new option is equal to the original per share
price divided by 1.333. The new Vectren options will otherwise be subject to the
same terms and conditions as the original SIGCORP options. The conversion
resulted in no compensation expense, as the requirements set forth in paragraph
82 of the FASB Interpretation No. 44, "Accounting for Certain Transactions
Involving Stock Compensation" were met.
11. Commitments and Contingencies
Vectren, through a wholly owned subsidiary, has entered into a contract to
purchase and construct an 80-megawatt combustion gas turbine generator which,
upon regulatory approval will be owned by SIGECO. The total capital cost of the
project is estimated to be $33 million during the 2001-2002 construction period.
SIGECO is party to various legal proceedings arising in the normal course of
business. In the opinion of management, with the exception of the litigation
matter related to the Clean Air Act (the Act), there are no legal proceedings
25
pending against SIGECO that are likely to have a material adverse effect on the
financial position or results of operations. Refer to Note 12 for litigation
matters concerning the Clean Air Act.
12. Environmental Matters
NOx SIP Call Matter. In October 1997, the United States Environmental Protection
Agency (USEPA) proposed a rulemaking that could require uniform nitrogen oxide
(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 (the Act). 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 (IDEM) 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. On September
20, 2000, petitioners filed a Petition of Writ of Certiori with the United
States Supreme Court requesting review of the D.C. Circuit Court's March 3, 2000
Order. The Court has not yet ruled on the Petition for Certiorari. The EPA
granted Section 126 Petitions filed by northeastern states that require named
sources in the eastern half of Indiana to achieve NOx reduction by May 1, 2003.
No SIGECO facilities are named in the Section 126 Petitions filed by
northeastern states, therefore the compliance date remains 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, pending finalization of state rule making, 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
26
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. No accrual
has been recorded by the company related to the NOx SIP Call matter. The rules
governing NOx emissions, once finalized, are to be applied prospectively.
Mercury Emissions. On December 14, 2000, the USEPA released a statement
announcing that reductions of mercury emissions from coal-fired plants will be
required in the near future. The USEPA will propose regulations by December 2003
and issue final rules by December 2004.
Under the Act, the USEPA is required to study emissions from power plants in
order to determine if additional regulations are necessary to protect public
health. The USEPA reported its study to Congress in February 1998. That study
concluded that of all toxic pollution examined, mercury posed the greatest
concern to public health. An earlier USEPA study concluded that the largest
source of human-made mercury pollution in the United States was coal-fired power
plants.
After completion of the study, the Act required the USEPA to determine whether
to proceed with the development of regulations. The USEPA announced that it had
affirmatively decided that mercury air emissions from power plants should be
regulated. Because rules governing mercury emissions are under development, the
determination of exposure, if any, is impossible as there are no standards or
rules by which compliance (or lack thereof) can be measured. Accordingly, no
accrual has been recorded by the company related to the Mercury Emissions
matter.
Culley Generating Station Investigation Matter. The USEPA initiated an
investigation under Section 114 of 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
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 to comply 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 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.
27
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
Act. Accordingly, no accrual has been recorded by the company, and SIGECO
anticipates at this time that the plant will continue to operate while the
matter is being decided.
Information Request. On January 23, 2001, SIGECO received an information request
from the USEPA under Section 114(a) of the Act for historical operational
information on the Warrick and A.B. Brown generating stations. SIGECO plans to
provide all information requested, and management believes that no significant
issues will arise from this request.
13. Rate and Regulatory Matters
As a result of the ongoing appeal of a generic order issued by the IURC in
August 1999 regarding guidelines for the recovery of purchased power costs,
SIGECO entered into a settlement agreement with the Indiana Office of Utility
Consumer Counselor (OUCC) that provides certain terms with respect to the
recoverability of such costs. The settlement, originally approved by the IURC on
August 9, 2000, has been extended by agreement through March 2002. Under the
settlement, SIGECO can recover the entire cost of purchased power up to an
established benchmark, and during forced outages, SIGECO will bear a limited
share of its purchased power costs regardless of the market costs at that time.
Based on this agreement, SIGECO believes it has significantly limited its
exposure to unrecoverable purchased power costs.
14. Affiliate Transactions
Vectren and certain subsidiaries of Vectren have provided certain corporate
general and administrative services to the company including legal, finance,
tax, risk management and human resources. The costs have been allocated to
SIGECO using various allocators, primarily number of employees, number of
customers and/or revenues. Allocations are based on cost. Management believes
that the allocation methodology is reasonable and approximates the costs that
would have been incurred had SIGECO secured those services on a stand-alone
basis. SIGECO received corporate allocations totaling $30.0 million for the year
ended December 31, 2000. No amounts were charged in 1999 and 1998 as such
services were provided by SIGECO personnel during those periods.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which SIGECO purchases fuel used for electric generation.
Amounts paid for such purchases for the years ended December 31, 2000, 1999 and
1998 totaled $25.7 million $20.5 million and $16.8 million, respectively.
Amounts charged by Vectren Fuels, Inc. are market based.
The Company incurred approximately $171,000 in 2000 for janitorial services
provided by an entity owned by a relative of a director of the Company.
As of December 31, Amounts owed to unconsolidated affiliates totaled $11.5
million and $0 at December 31, 2000 and 1999, respectively. Amounts due from
unconsolidated affiliates totaled $27.8 million and $1.2 million at December 31,
2000 and 1999, respectively.
15. Segment Reporting
SFAS No. 131 "Disclosures about Segments of an Enterprise and Related
Information" establishes standards for reporting information about operating
segments in financial statements and disclosures about products and services and
geographic areas. Operating segments are defined as components of an enterprise
for which separate financial information is available and is evaluated regularly
by the chief operating decision maker in deciding how to allocate resources and
in assessing performance.
During 2000, SIGECO had two operating segments: (1) Electric Utility Services
and (2) Gas Utility Services. The Electric Utility Services segment generates,
transmits, distributes and sells electricity to Evansville, Indiana, and 74
28
other cities, towns and communities, and adjacent rural areas; and in periods of
under utilized capacity, excess electricity is sold to other wholesale
customers, cities and municipalities. The Gas Utility Services segment
distributes, transports and sells natural gas to Evansville, Indiana and 64
communities in ten counties in southwestern Indiana. Certain financial
information relating to significant segments of business is presented below:
Year Ended December 31 (in thousands) 2000 1999 1998
--------- --------- ---------
Operating revenues:
Electric Utility Services $ 336,409 $ 307,569 $ 297,865
Gas Utility Services 109,284 68,212 66,801
--------- --------- ---------
Total $ 445,693 $ 375,781 $ 364,666
--------- --------- ---------
Interest expense:
Electric Utility Services $ 18,103 $ 18,031 $ 18,882
Gas Utility Services 1,791 1,735 1,799
--------- --------- ---------
Total $ 19,894 $ 19,766 $ 20,681
--------- --------- ---------
Income taxes:
Electric Utility Services $ 23,386 $ 24,331 $ 22,881
Gas Utility Services 1,446 2,097 2,154
--------- --------- ---------
Total $ 24,832 $ 26,428 $ 25,035
--------- --------- ---------
Net Income applicable to common shareholder:
Electric Utility Services $ 36,811 $ 41,820 $ 38,342
Gas Utility Services 3,220 3,870 4,105
--------- --------- ---------
Total $ 40,031 $ 45,690 $ 42,447
--------- --------- ---------
Depreciation and amortization:
Electric Utility Services $ 38,639 $ 40,829 $ 38,077
Gas Utility Services 4,575 4,039 4,324
--------- --------- ---------
Total $ 43,214 $ 44,868 $ 42,401
--------- --------- ---------
Capital Expenditures:
Electric Utility Services $ 43,520 $ 51,080 $ 47,114
Gas Utility Services 9,650 9,893 8,199
Equity component of AFUDC (2,051) (296)
--------- --------- ---------
Total $ 51,119 $ 60,677 $ 55,313
--------- --------- ---------
Identifiable assets:
Electric Utility Services $ 799,104 $ 751,598 $ 740,746
Gas Utility Services 152,210 143,161 141,174
--------- --------- ---------
Total assets $ 951,314 $ 894,759 $ 881,920
========= ========= =========
16. Other Income-Net
For the years ended December 31, 2000, 1999 and 1998, other income, net consists
of the following:
(In thousands) 2000 1999 1998
------- ------- -------
AFUDC $ 3,868 $ 2,804 $ 1,465
Other income 1,484 408 2,309
Other expense (678) (103) (1,553)
------- ------- -------
Other income, net $ 4,674 $ 3,109 $ 2,221
======= ======= =======
29
17. Selected Quarterly Financial Data (Unaudited) (1)
2000
- -------------
In thousands Q1 Q2 Q3 Q4
-------- -------- -------- --------
Operating revenues $102,217 $ 92,471 $112,675 $138,330
Operating income (2) 8,350 10,700 20,867 16,351
Net income (2) 3,998 6,459 16,782 12,792
1999
- -------------
In thousands Q1 Q2 Q3 Q4
-------- -------- -------- --------
Operating revenues $100,685 $ 84,318 $101,930 $ 88,848
Operating income 17,147 12,338 21,219 12,721
Net income 12,237 7,617 17,601 8,235
(1) Information in any one quarterly period is not indicative of annual results
due to seasonal variations common to the utility industry.
(2) Includes merger and integration charges. See Note 2.
30
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Southern Indiana Gas and Electric Company (SIGECO) is
responsible for the preparation of the financial statements and the related
financial data contained in this report. The financial statements are prepared
in conformity with accounting principles generally accepted in the United States
and follow accounting policies and principles applicable to regulated public
utilities.
The integrity and objectivity of the data in this report, including required
estimates and judgments, are the responsibility of management. Management
maintains a system of internal control and utilizes an internal auditing program
to provide reasonable assurance of compliance with company policies and
procedures and the safeguard of assets.
The board of directors of SIGECO's parent company, Vectren Corporation, pursues
its responsibility for these financial statements through its audit committee,
which meets periodically with management, the internal auditors and the
independent auditors, to assure that each is carrying out its responsibilities.
Both the internal auditors and the independent auditors meet with the audit
committee of Vectren's board of directors, with and without management
representatives present, to discuss the scope and results of their audits, their
comments on the adequacy of internal accounting control and the quality of
financial reporting.
/s/ J. Gordon Hurst
J. Gordon Hurst
President
January 24, 2001.
31
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholder and Board of Directors of Southern Indiana Gas and Electric
Company:
We have audited the accompanying balance sheets of Southern Indiana Gas and
Electric Company (an Indiana corporation) as of December 31, 2000 and 1999, and
the related statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 2000. These financial
statements and the schedule referred to below are the responsibility of Southern
Indiana Gas and Electric Company's management. Our responsibility is to express
an opinion on these financial statements and the schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Southern Indiana Gas and
Electric Company as of December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a) (2)
is presented for the purpose of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. The
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Indianapolis, Indiana,
January 24, 2001.
32
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) Financial Statements
Financial statements filed as part of this Form 10-K are included under Part II,
Item 8.
(a)(2) Financial Statement Schedules:
PAGES IN FORM 10-K/A
--------------------
Report of Independent Accountants 32
For the years ended December 31, 2000, 1999, and 1998:
Schedule II - Valuation and Qualifying Accounts 34
All other schedules are omitted as the required information is inapplicable or
the information is presented in the Financial Statements or related notes.
33
SCHEDULE II
Southern Indiana Gas And Electric Company
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
- -------- -------- ------------------ -------- --------
Additions
Balance Charged Charged Deductions Balance
Beginning to to Other from End of
Description of Year Expenses Accounts Reserves, Net Year
- ----------- -------- -------- -------- --------- ------
(in thousands)
VALUATION AND QUALIFYING
ACCOUNTS:
Year 2000 - Accumulated
Provision for uncollectible
Accounts $2,138 $1,189 $ - $ 688 $2,639
Year 1999 - Accumulated
Provision for uncollectible
Accounts $2,156 $ 604 $ - $ 622 $2,138
Year 1998 - Accumulated
Provision for uncollectible
Accounts $ 328 $2,797 $ - $ 969 $2,156
OTHER RESERVES:
Year 2000 - Reserve for
Merger and integration costs $ - $7,400 $ - $6,874 $ 526
Year 2000 - Reserve for
Injuries and damages $1,047 $ 351 $ - $ 374 $1,024
Year 1999 - Reserve for
Injuries and damages $ 782 $ 661 $ - $ 396 $1,047
Year 1998 - Reserve for
Injuries and damages $1,047 $ 68 $ 261 $ 594 $ 782
34
(a)(3) EXHIBITS
Exhibits for the company are listed in the Index to Exhibits beginning on page
37.
(b) REPORTS ON FORM 8-K
On December 15, 2000, Southern Indiana Gas and Electric Company filed a Current
Report on Form 8-K with respect to providing an update on potential impact of
Increased Gas Costs and Gas Cost Adjustment Proceedings. Items reported include:
Item 5. Other Events
35
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
Dated August 27, 2001
/S/ Niel C. Ellerbrook
--------------------------------
Niel C. Ellerbrook, Chairman and
Chief Executive Officer
36
INDEX TO EXHIBITS
EX - 3.1 Amended Articles of Incorporation as amended March 26, 1985.
(Filed and designated in Form 10-K, for the fiscal year 1985,
File No. 1-3553, as Exhibit 3-A.) Articles of Amendment of the
Amended Articles of Incorporation, dated March 24, 1987. (Filed
and designated in Form 10-K for the fiscal year 1987, File No.
1-3553, as Exhibit 3-A.) Articles of Amendment of the Amended
Articles of Incorporation, dated November 27, 1992. (Filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 3-A)
EX - 3.2 By-Laws as amended through December 18, 1990. (Filed in Form 10-K
for the fiscal year 1990, File No. 1-3553, as Exhibit 3-B.)
By-Laws as amended through September 22, 1993. (Filed and
designated in Form 10-K for the fiscal year 1993, File No.
1-3553, as EX-3 (b).) By-Laws as amended through January 1, 1995.
(Filed and designated in Form 10-K for the fiscal year 1995, File
No. 1-3553, as EX-3(b).)
EX - 4.1 Mortgage and Deed of Trust dated as of April 1, 1932 between
Southern Indiana Gas and Electric Company and Bankers Trust
Company, as Trustee, and Supplemental Indentures thereto dated
August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948,
June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954,
March 1, 1957, October 1, 1965, September 1, 1966, August 1,
1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1,
1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4,
1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1,
1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1,
1986. (Filed and designated in Registration No. 2-2536 as
Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to
Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration
No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553,
dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March
24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June
3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed
and designated in Form 10-K, for the fiscal year 1985, File No.
1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987.
(Filed and designated in Form 10-K, for the fiscal year 1986,
File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and
designated in Form 10-K, for the fiscal year 1987, File No.
1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated
in Form 10-K, for the fiscal year 1990, File No. 1-3553, as
Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K,
dated April 13, 1993, File 1-3553, as Exhibit 4.) June 1, 1993
(Filed and designated in Form 8-K, dated June 14, 1993, File
1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form
10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit
4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated
August 16, 1999, File 1-3553, as Exhibit 4(a).)
EX - 10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick
Power Plant of Alcoa Generating Corporation ("Alcoa"), between
Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-29653 as Exhibit 4(d)-A.)
EX - 10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement,
dated June 26, 1969, between Alcoa and Southern Indiana Gas and
Electric Company. (Filed and designated in Registration
No. 2-41209 as Exhibit 4(e)-2.)
EX - 10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April
30, 1973, between Alcoa and Southern Indiana Gas and Electric
Company. (Filed and designated in Registration No. 2-53005 as
Exhibit 4(e)-4.)
EX - 10.4 Electric Power Agreement (the "Power Agreement"), dated May 28,
1971, between Alcoa and Southern Indiana Gas and Electric
Company. (Filed and designated in Registration No. 2-41209 as
Exhibit 4(e)-1.)
EX - 10.5 Second Supplement, dated as of July 10, 1975, to the Power
Agreement and Letter Agreement dated April 30, 1973 - First
Supplement. (Filed and designated in Form 10-K for the fiscal
year 1975, File No. 1-3553, as Exhibit 1(e).)
EX - 10.6 Third Supplement, dated as of May 26, 1978, to the Power
Agreement. (Filed and designated in Form 10-K for the fiscal year
1978 as Exhibit A-1.)
37
EX - 10.7 Letter Agreement dated August 22, 1978 between Southern Indiana
Gas and Electric Company and Alcoa, which amends Agreement for
Sale in an Emergency of Electrical Power and Energy Generation by
Alcoa and Southern Indiana Gas and Electric Company dated June
26, 1979. (Filed and designated in Form 10-K for the fiscal year
1978, File No. 1-3553, as Exhibit A-2.)
EX - 10.8 Fifth Supplement, dated as of December 13, 1978, to the Power
Agreement. (Filed and designated in Form 10-K for the fiscal year
1979, File No. 1-3553, as Exhibit A-3.)
EX - 10.9 Sixth Supplement, dated as of July 1, 1979, to the Power
Agreement. (Filed and designated in Form 10-K for the fiscal year
1979, File No. 1-3553, as Exhibit A-5.)
EX - 10.10 Seventh Supplement, dated as of October 1, 1979, to the Power
Agreement. (Filed and designated in Form 10-K for the fiscal year
1979, File No. 1-3553, as Exhibit A-6.)
EX - 10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power
Agreement, dated May 28, 1971, between Alcoa and Southern Indiana
Gas and Electric Company. (Filed and designated in Form 10-K for
the fiscal year 1980, File No. 1-3553, as Exhibit (20)-1.)
EX - 10.12 Summary description of Southern Indiana Gas and Electric
Company's nonqualified Supplemental Retirement Plan (Filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 10-A-17.)
EX - 10.13 Supplemental Post Retirement Death Benefits Plan, dated October
10, 1984. (Filed and designated in Form 10-K for the fiscal year
1992, File No. 1-3553, as Exhibit 10-A-18.)
EX - 10.14 Summary description of Southern Indiana Gas and Electric
Company's Corporate Performance Incentive Plan. (Filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 10-A-19.)
EX - 10.15 Southern Indiana Gas and Electric Company's Corporate Performance
Incentive Plan as amended for the plan year beginning January 1,
1994. (Filed and designated in Form 10-K for the fiscal year
1993, File No. 1-3553, as Exhibit 10-A-20.)
EX - 10.16 Southern Indiana Gas and Electric Company 1994 Stock Option Plan
(Filed and designated in Southern Indiana Gas and Electric
Company's Proxy Statement dated February 22, 1994, File No.
1-3553, as Exhibit A.)
EX - 10.17 Summary description of Southern Indiana Gas and Electric
Company's Corporate Performance Incentive Plan as amended for the
plan year beginning January 1, 1997. (Filed and designated in the
SIGCORP, Inc. and Southern Indiana Gas and Electric Company's
Joint Proxy Statement dated March 23, 1998, File No. 1-11603 and
File No. 1-3553, under "Compensation Committee Report On
Executive Compensation", page 9.)
EX - 10.18 Southern Indiana Gas and Electric Company's nonqualified
Supplemental Retirement Plan as amended, effective April 16,
1997. (Filed and designated in Form 10-K for the fiscal year
1997, File No. 1-3553, as Exhibit 10.29.)
EX - 10.19 Agreement dated April 16, 1997 between Southern Indiana Gas and
Electric Company and Ronald G. Reherman regarding supplemental
pension and disability benefits, which supercedes such agreement
dated February 1, 1995. (Filed and designated in Form 10-K for
the fiscal year 1997, File No. 1-3553, as Exhibit 10.27.)
EX - 10.20 Southern Indiana Gas and Electric Company's nonqualified
Supplemental Retirement Plan as amended, effective April 16,
1997. (Filed and designated in Form 10-K for the fiscal year
1997, File No. 1-3553, as Exhibit 10.29.)
38
EX - 10.21 Indiana Energy, Inc. Director's Restricted Stock Plan as amended
and restated effective May 1, 1997. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 1997, File 1-9091,
as Exhibit 10-B.)
EX - 10.22 First Amendment to Indiana Energy, Inc. Director's Restricted
Stock Plan, effective December 1, 1998. (Filed and designated in
Form 10-Q for the quarterly period ended December 31, 1998, File
1-9091, as Exhibit 10-J.)
EX - 10.23 Second Amendment to Indiana Energy, Inc. Director's Restricted
Stock Plan, renamed the Vectren Corporation Directors Restricted
Stock Plan effective October 1, 2000. (Filed and designated in
Form 10-K for the year ended December 31, 2000, File No. 1-15467,
as Exhibit 10.34.)
EX - 10.24 Third Amendment to Indiana Energy, Inc. Director's Restricted
Stock Plan, renamed the Vectren Corporation Directors Restricted
Stock Plan effective March 28, 2000. (Filed and designated in
Form 10-K for the year ended December 31, 2000, File No. 1-15467,
as Exhibit 10.35.)
EX - 10.25 Vectren Corporation Retirement Savings Plan. (Filed and
designated in Form 10-Q for the quarterly period ended September
30, 2000, File 1-15467, as Exhibit 99.1.)
EX - 10.26 Vectren Corporation Combined Non-Bargaining Retirement Plan.
(Filed and designated in Form 10-Q for the quarterly period ended
September 30, 2000, File 1-15467, as Exhibit 99.2.)
EX - 10.27 Vectren Corporation Employment Agreement between Vectren
Corporation and Niel C. Ellerbrook dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File 1-15467, as Exhibit 99.1.)
EX - 10.28 Vectren Corporation Employment Agreement between Vectren
Corporation and Andrew E. Goebel dated as of March 31, 2000(Filed
and designated in Form 10-Q for the quarterly period ended June
30, 2000, File 1-15467, as Exhibit 99.2.)
EX - 10.29 Vectren Corporation Employment Agreement between Vectren
Corporation and Jerome A. Benkert, Jr. dated as of March 31,
2000. (Filed and designated in Form 10-Q for the quarterly period
ended June 30, 2000, File 1-15467, as Exhibit 99.3.)
EX - 10.30 Vectren Corporation Employment Agreement between Vectren
Corporation and Ronald E. Christian dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File 1-15467, as Exhibit 99.5.)
EX - 10.31 Vectren Corporation Employment Agreement between Vectren
Corporation and Timothy M. Hewitt dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File 1-15467, as Exhibit 99.6.)
EX - 10.32 Vectren Corporation Employment Agreement between Vectren
Corporation and J. Gordon Hurst dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File 1-15467, as Exhibit 99.7.)
EX - 10.33 Vectren Corporation Employment Agreement between Vectren
Corporation and Richard G. Lynch dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File 1-15467, as Exhibit 99.8.)
EX - 12 Ratio of Ratio of Earning to Fixed Charges. (Filed and designated
in Form 10-K for the year ended December 31, 2000, File 1-15467,
as Exhibit 12.)
EX - 99.1 Vectren Proxy Statement Pursuant to Section 14(a) of the
Securities Exchange Act of 1934, but not including the
Compensation Committee Report and Performance Graph. (Filed and
designated in Form 10-K for the year ended December 31, 2000,
File 1-15467, as Exhibit 99.1.)
39
EX - 99.2 Agreement and Plan of Merger dated as of June 11,1999 among
Indiana Energy, Inc., SIGCORP, Inc. and Vectren Corporation (the
"Merger Agreement "). (Filed and designated in Form S-4 to (No.
333-90763) filed on November 12, 1999, File 1-15467, as Exhibit
2.)
EX - 99.3 Amendment No. 1 to the Merger Agreement dated December 14,1999
(Filed and designated in Current Report on Form 8-K filed
December 16, 1999, File 1-09091, as Exhibit 2.)
EX - 99.4 Amended and Restated Articles of Incorporation of Vectren
Corporation effective March 31,2000. (Filed and designated in
Current Report on Form 8-K filed April 12, 2000, File 1-15467, as
Exhibit 4.1.)
EX - 99.5 Code of By-Laws of Vectren Corporation. (Filed and designated in
Form S-3 (No 333-5390) filed January 19, 2001, File 1-15467, as
Exhibit 4.2.)
EX - 99.6 Shareholders Rights Agreement dated as of October 21, 1999
between Vectren Corporation and Equiserve Trust Company, N.A., as
Rights Agent. (Filed and designated in Form S-4 to (No.
333-90763) filed on November 12, 1999, File 1-15467, as Exhibit
4.)