UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For quarterly period ended September 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________ to __________
Commission file number 1-3553
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
-----------------------------------------
(Exact name of registrant as specified in its charter)
INDIANA 35-0672570
- ---------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices and Zip Code)
(812) 491-4000
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(Registrant's telephone number, including area code)
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 [ ]
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Common Stock-Without Par Value 15,754,826 November 1, 2002
- ------------------------------- ---------- ----------------
Class Number of Shares Date
As of November 1, 2002, all shares outstanding of the Registrant's classes of
common stock were held by Vectren Corporation through its wholly owned
subsidiary, Vectren Utility Holdings, Inc.
Table of Contents
Item Page
Number Number
Part I. Financial Information
1 Financial Statements (Unaudited)
Condensed Balance Sheets......................................... 1-2
Condensed Statements of Income................................... 3
Condensed Statements of Cash Flows............................... 4
Notes to Condensed Unaudited Financial Statements................ 5-11
2 Management's Discussion and Analysis
of Results of Operations and Financial Condition................. 12-20
3 Qualitative and Quantitative Disclosures About Market Risk......... 21-22
4 Controls and Procedures............................................ 23
Part II. Other Information
1 Legal Proceedings.................................................. 24
6 Exhibits and Reports on Form 8-K................................... 24
Signatures......................................................... 25
Certifications..................................................... 26-28
Definitions
As discussed in this Form 10-Q, the abbreviations
AFUDC means allowance for funds used during construction
APB means Accounting Principles Board
EITF means Emerging Issues Task Force
FASB means Financial Accounting Standards Board
IDEM means Indiana Department of Environmental Management
IURC means Indiana Utility Regulatory Commission
MMDth means millions of dekatherms
MMBTU means millions of British thermal units
USEPA means United States Environmental Protection Agency
Throughput means combined gas sales and gas transportation volumes
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited- In thousands)
September 30, December 31,
2002 2001
----------- -----------
ASSETS
Utility Plant
Original cost $1,501,560 $1,455,826
Less: Accumulated depreciation & amortization 720,662 690,344
---------- ----------
Net utility plant 780,898 765,482
---------- ----------
Current Assets
Cash & cash equivalents 3,096 2,451
Accounts receivable-less reserves of $3,590 &
$3,241, respectively 49,907 41,227
Receivables from other Vectren companies 709 10,065
Accrued unbilled revenues 20,152 17,013
Inventories 41,086 38,322
Recoverable fuel & natural gas costs 10,173 22,132
Prepayments & other current assets 14,972 14,053
---------- ----------
Total current assets 140,095 145,263
---------- ----------
Investments in unconsolidated affiliates 160 160
Other investments 9,873 9,254
Non-utility property-net 3,789 4,386
Goodwill-net 5,557 5,557
Regulatory assets 55,477 41,525
Other assets 3,804 1,595
---------- ----------
TOTAL ASSETS $ 999,653 $ 973,222
========== ==========
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited - In thousands)
September 30, December 31,
2002 2001
------------ -----------
LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 78,258 $ 78,258
Retained earnings 268,300 255,464
Accumulated other comprehensive income - 94
-------- --------
Total common shareholder's equity 346,558 333,816
-------- --------
Cumulative redeemable preferred stock of subsidiary 344 460
Long-term debt-net of current maturities 290,838 291,702
Long-term debt due to VUHI 49,460 49,460
-------- --------
Total capitalization 687,200 675,438
-------- --------
Commitments & Contingencies (Notes 4-6)
Current Liabilities
Accounts payable 21,860 27,135
Payables to other Vectren companies 3,398 3,390
Accrued liabilities 38,609 33,545
Short-term borrowings 3,174 874
Short-term borrowings due to VUHI 81,892 80,664
Current maturities of long-term debt 1,000 -
-------- --------
Total current liabilities 149,933 145,608
-------- --------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 119,445 112,746
Deferred credits & other liabilities 43,075 39,430
-------- --------
Total deferred income taxes & other
liabilities 162,520 152,176
-------- --------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $999,653 $973,222
======== ========
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited - In thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- ---------------------
2002 2001 2002 2001
-------- -------- -------- --------
OPERATING REVENUES
Electric revenues $189,935 $104,335 $475,659 $287,564
Gas revenues 7,388 11,032 54,619 74,333
-------- -------- -------- --------
Total operating revenues 197,323 115,367 530,278 361,897
-------- -------- -------- --------
COST OF OPERATING REVENUES
Fuel for electric generation 22,872 21,011 59,731 56,852
Purchased electric energy 92,436 22,565 239,272 69,380
Cost of gas sold 2,474 5,926 31,412 51,913
-------- -------- -------- --------
Total cost of operating revenues 117,782 49,502 330,415 178,145
-------- -------- -------- --------
TOTAL OPERATING MARGIN 79,541 65,865 199,863 183,752
OPERATING EXPENSES
Other operating 24,205 23,659 76,003 72,550
Merger & integration costs - 286 - 588
Restructuring costs - 433 - 4,777
Depreciation & amortization 11,370 11,053 33,411 33,190
Income taxes 12,681 8,336 26,014 18,043
Taxes other than income taxes 3,657 3,125 9,975 9,978
-------- -------- -------- --------
Total operating expenses 51,913 46,892 145,403 139,126
-------- -------- -------- --------
OPERATING INCOME 27,628 18,973 54,460 44,626
Other income - net 926 766 9,109 2,553
Interest expense 5,713 5,047 17,198 15,420
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 22,841 14,692 46,371 31,759
-------- -------- -------- --------
Cumulative effect of change in accounting
principle-net of tax - - - 3,938
-------- -------- -------- --------
NET INCOME 22,841 14,692 46,371 35,697
-------- -------- -------- --------
Preferred stock dividends 15 268 25 748
Loss on extinguishment of preferred stock - 1,176 - 1,170
-------- -------- -------- --------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 22,826 $ 13,248 $ 46,346 $ 33,779
======== ======== ======== ========
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited - In thousands)
Nine Months Ended
September 30,
--------------------
2002 2001
-------- --------
NET CASH FLOWS FROM OPERATING ACTIVITIES $ 92,185 $ 61,528
-------- --------
CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
Requirements for:
Dividends on common stock (33,510) (24,006)
Redemption of preferred stock (116) (17,676)
Dividends on preferred stock (25) (748)
Net change in short-term borrowings, including
due to VUHI 3,528 25,912
-------- --------
Net cash flows (required for) financing
activities (30,123) (16,518)
-------- --------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from sale of investments and assets 1,400 1,119
Requirements for:
Capital expenditures (61,191) (44,747)
Other investments (1,626) -
-------- --------
Net cash flows (required for) investing
activities (61,417) (43,628)
-------- --------
Net increase in cash & cash equivalents 645 1,382
Cash & cash equivalents at beginning of period 2,451 1,613
-------- --------
Cash & cash equivalents at end of period $ 3,096 $ 2,995
======== ========
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana
corporation, provides electric generation, transmission, and distribution
services to Evansville, Indiana, and 74 other communities in 8 counties in
southwestern Indiana and participates in the wholesale power market. SIGECO also
provides natural gas distribution and transportation services to Evansville,
Indiana, and 64 communities in 10 counties in southwestern Indiana. SIGECO is a
direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI
is a direct, wholly owned subsidiary of Vectren Corporation (Vectren).
Vectren, an Indiana corporation, is an energy and applied technology holding
company headquartered in Evansville, Indiana. 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). On March 31, 2000, the merger of
Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free
exchange of shares and has been accounted for as a pooling-of-interests in
accordance with APB Opinion No. 16 "Business Combinations."
Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding
company for its three operating public utilities: Indiana Gas Company, Inc.
(Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, SIGECO,
formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations, a
utility jointly owned by Indiana Gas and Vectren Energy Delivery of Ohio, Inc.
(VEDO). Both Vectren and VUHI are exempt from registration pursuant to Section
3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
2. Basis of Presentation
The interim condensed financial statements included in this report have been
prepared by the Company, without audit, as provided in the rules and regulations
of the Securities and Exchange Commission. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
omitted as provided in such rules and regulations. The Company believes that the
information in this report reflects all adjustments necessary to fairly state
the results of the interim periods reported. These condensed financial
statements and related notes should be read in conjunction with the Company's
audited annual financial statements for the year ended December 31, 2001, filed
on Form 10-K. Because of the seasonal nature of the Company's utility
operations, the results shown on a quarterly basis are not necessarily
indicative of annual results.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the statements
and the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
Certain reclassifications have been made to prior period financial statements to
conform with the current year classification. These reclassifications have no
impact on previously reported net income.
3. Impact of Recently Issued Accounting Guidance
EITF 02-03
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133) should be shown net in the income statement,
whether or not settled physically, if the derivative instruments are held for
"trading purposes." The consensus rescinded EITF 98-10 "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well
as other decisions reached on energy trading contracts at the EITF's June 2002
meeting.
The Company's power marketing operations enter into contracts that are
derivatives as defined by SFAS 133, but these operations do not met the
definition of energy trading activities based upon the provisions in EITF 98-10.
Currently, the Company uses a gross presentation to report the results of these
operations. The Company will re-evaluate its portfolio of derivative contracts
to determine if any will be required to be reported net in accordance with the
provisions of the new consensus.
The consensus relating to the presentation of gains and losses on derivative
instruments held for "trading purposes" is effective for financial statements
issued for periods beginning after December 15, 2002 and requires the
reclassification of all periods presented. For the Company, the consensus is
effective beginning January 1, 2003. See Note 7 for additional information on
the Company's power marketing operations
SFAS 142
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS 142). The Company adopted the provisions of SFAS 142 as required,
on January 1, 2002. SFAS 142 changed the accounting for goodwill from an
amortization approach to an impairment-only approach. Thus, amortization of
goodwill that is not included as an allowable cost for rate-making purposes
ceased upon adoption of the statement. This includes goodwill recorded in past
business combinations. Goodwill is to be tested for impairment at a reporting
unit level at least annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any significant other
intangible assets.
The Company has goodwill included in its Gas Utility Services operating segment.
The amortization of this goodwill which approximated $0.2 million per year
ceased on January 1, 2002. Initial impairment reviews to be performed within six
months of adoption of SFAS 142 were completed and resulted in no impairment.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002, did not have a material impact on
operations.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
4. Transactions With Other Vectren Companies
Support Services & Purchases
Vectren and certain subsidiaries of Vectren have provided corporate, general and
administrative services to the Company including legal, finance, tax, risk
management and human resources. The costs have been allocated to the Company
using various allocators, primarily number of employees, number of customers
and/or revenues. Management believes that the allocation methodology is
reasonable and approximates the costs that would have been incurred had the
Company secured those services on a stand-alone basis. For the three months
ended September 30, 2002 and 2001, amounts billed by other wholly owned
subsidiaries of Vectren to the Company were $10.9 million and $9.1 million,
respectively. For the nine months ended September 30, 2002 and 2001, amounts
billed by other wholly owned subsidiaries of Vectren to the Company were $35.2
million and $30.6 million, respectively.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which the Company purchases fuel used for electric generation.
Amounts paid for such purchases for the three months ended September 30, 2002
and 2001 were $17.3 million and $7.3 million, respectively. Amounts paid for
such purchases for the nine months ended September 30, 2002 and 2001 were $45.6
million and $28.2 million, respectively.
Cash Management and Borrowing Arrangements
The Company participates in a centralized cash management program with Vectren,
other wholly owned subsidiaries, and banks which permits funding of checks as
they are presented.
Guarantees of Parent Company Debt
Vectren's three operating utility companies, SIGECO, VEDO, and Indiana Gas are
guarantors of VUHI's $325 million commercial paper program, of which $168.5
million is outstanding at September 30, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at September 30, 2002. These guarantees are full and
unconditional and joint and several. VUHI has no significant independent assets
or operations other than the assets and operations of these operating utility
companies.
5. Commitments & Contingencies
The Company is party to various legal and regulatory proceedings arising in the
normal course of business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position or results of operations. See Note 6
regarding environmental matters.
6. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the United States Environmental
Protection Agency (USEPA) finds a state's SIP inadequate to achieve the NAAQS,
the USEPA can call upon the state to revise its SIP (a SIP Call).
In October 1998, the 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). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1998 and 1999.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. Based on
the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through September 30, 2002,
$53.5 million has been expended. After the equipment is installed and
operational, related annual operating expenses, including depreciation expense,
are estimated to be between $24 million and $27 million. Such expenses would
commence in 2004 when the technology becomes operational. On October 22, 2002,
the Company filed a settlement agreement with the IURC that has been entered
into with the Indiana Office of Utility Consumer Counselor and an industrial
intervenor group relating to the ongoing NOx project. The agreement, if approved
by the IURC, will authorize additional capital cost investment and recovery on
those capital costs, as well as the recovery of future operating costs,
including depreciation and purchased emission allowances, through a rider
mechanism. A hearing is scheduled for November 15, 2002 to consider the
agreement. The settlement establishes a fixed return of 8 percent on the capital
investment.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, 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 review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. 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 an 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 1999 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: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
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 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 itself. Since the filing of this lawsuit, the USEPA has
voluntarily dismissed a majority of the claims brought in its original
compliant. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin March 31, 2003.
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
permitting requirements of new source review 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, the Company has recorded no accrual and
the plant continues 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 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
7. Energy Marketing Activities
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale transactions that expose the Company to limited market risk.
During 2002, the Company has increased its activity in the wholesale market.
With the exception of those contracts subject to the normal purchase and sale
exclusion, commodity contracts are accounted for at market value. As of
September 30, 2002, contracts had a no net asset value compared to a net asset
value of $3.2 million at December 31, 2001. The Company has determined these
power marketing contracts are derivatives within the scope of SFAS No. 133.
Contracts recorded at market value are recorded as current or noncurrent assets
or liabilities in the Condensed Balance Sheets depending on their value and on
when the contracts are expected to be settled. Changes in market value, which is
a function of the normal decline in fair value as earnings are realized and the
fluctuation in fair value resulting from price volatility, are recorded in
purchased electric energy in the Condensed Statements of Income. Market value is
determined using quoted market prices from independent sources.
Forward sale contracts, premiums received for written options, and proceeds
received from exercised options are recorded when settled as electric utility
revenues in the Condensed Statements of Income. Forward purchase contracts,
premiums paid for purchased options, and proceeds paid for exercising options
are recorded when settled in purchased electric energy in the Condensed
Statements of Income. Contracts with counter-parties subject to master netting
arrangements are presented net in the Condensed Balance Sheets.
Power marketing contracts at September 30, 2002 totaled $7.7 million of
prepayments and other current assets and $7.7 million of accrued liabilities,
compared to $5.2 million of prepayments and other current assets and $2.0
million of accrued liabilities at December 31, 2001. For the three months ended
September 30, 2002 and 2001, the change in the net value of these contracts
includes an unrealized gain of $0.2 million and an unrealized loss of $0.9
million, respectively. For the nine months ended September 30, 2002 and 2001,
the change in the net value of these contracts includes unrealized losses of
$3.0 million and $3.3 million, respectively. Including these unrealized changes
in fair value, overall margin (revenue net of purchased power) from power
marketing operations for the three months ended September 30, 2002 and 2001 was
$4.6 million and $4.1million, respectively, and for the nine months ended
September 30, 2002 and 2001 was $8.0 million and $10.9 million, respectively.
8. Segment Reporting
The Company had two operating segments during the three and nine months ended
September 30, 2002: (1) Gas Utility Services and (2) Electric Utility Services.
The Gas Utility Services segment provides natural gas distribution and
transportation services in southwestern Indiana. The Electric Utility Services
segment includes the operations of SIGECO's electric transmission and
distribution services, which provides electricity to primarily southwestern
Indiana, and SIGECO's power generating and power marketing operations. The
following tables provide information about business segments. The Company makes
decisions on finance and dividends at the corporate level.
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
In thousands 2002 2001 2002 2001
--------- --------- --------- ---------
Operating Revenues
Electric Utility Services $ 189,935 $ 104,335 $ 475,659 $ 287,564
Gas Utility Services 7,388 11,032 54,619 74,333
--------- --------- --------- ---------
Total operating revenues $ 197,323 $ 115,367 $ 530,278 $ 361,897
========= ========= ========= =========
Net Income Applicable to
Common Shareholder
Electric Utility Services $ 23,268 $ 11,380 $ 43,170 $ 31,526
Gas Utility Services (442) 1,868 3,176 2,253
--------- --------- --------- ---------
Net income applicable to
common shareholder $ 22,826 $ 13,248 $ 46,346 $ 33,779
========= ========= ========= =========
September 30, December 31,
In thousands 2002 2001
----------- -----------
Identifiable Assets
Electric Utility Services $ 842,629 $ 811,248
Gas Utility Services 157,024 161,974
--------- ---------
Total identifiable assets $ 999,653 $ 973,222
========= =========
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the Business
Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana
corporation, provides electric generation, transmission, and distribution
services to Evansville, Indiana, and 74 other communities in 8 counties in
southwestern Indiana and participates in the wholesale power market. SIGECO also
provides natural gas distribution and transportation services to Evansville,
Indiana, and 64 communities in 10 counties in southwestern Indiana. SIGECO is a
direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI
is a direct, wholly owned subsidiary of Vectren Corporation (Vectren).
Vectren, an Indiana corporation, is an energy and applied technology holding
company headquartered in Evansville, Indiana. 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). On March 31, 2000, the merger of
Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free
exchange of shares and has been accounted for as a pooling-of-interests in
accordance with APB Opinion No. 16 "Business Combinations."
Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding
company for its three operating public utilities: Indiana Gas Company, Inc.
(Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, SIGECO,
formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations, a
utility jointly owned by Indiana Gas and Vectren Energy Delivery of Ohio, Inc.
(VEDO). Both Vectren and VUHI are exempt from registration pursuant to Section
3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
Results of Operations
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Net income applicable to common shareholder,
as reported $ 22,826 $ 13,248 $ 46,346 $ 33,779
Merger, integration, & other costs-net of tax - 178 - 365
Restructuring costs-net of tax - 268 - 2,965
Cumulative effect of change in accounting
principle-net of tax - - - (3,938)
Loss on extinguishment of preferred stock - 1,176 - 1,170
-------- -------- -------- --------
Net income applicable to common shareholder before
nonrecurring items $ 22,826 $ 14,870 $ 46,346 $ 34,341
======== ======== ======== ========
Net Income Applicable to Common Shareholder
For the nine months ended September 30, 2002, net income applicable to common
shareholder was $46.3 million compared to $33.8 million for the same period in
2001. In addition to completion of merger and restructuring activities and
related costs and the extinguishment of preferred stock, the nine-month period
increase of $12.6 million was primarily the result of favorable cooling weather
during the second and third quarters, a return to lower gas prices and the
related reduction in costs incurred in 2001, and merger synergies. The accrual
of carrying costs on the Company's demand side management programs consistent
with an existing IURC rate order also contributed. These favorable impacts were
offset somewhat by the effects of warm weather during the heating season.
For the three months ended September 30, 2002, net income applicable to common
shareholder was $22.8 million compared to $13.2 million for the same period in
2001. Net income applicable to common shareholder increased primarily due to
increased margins, partly reflecting favorable cooling weather.
New Accounting Principles
EITF 02-03
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133) should be shown net in the income statement,
whether or not settled physically, if the derivative instruments are held for
"trading purposes." The consensus rescinded EITF 98-10 "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well
as other decisions reached on energy trading contracts at the EITF's June 2002
meeting.
The Company's power marketing operations enter into contracts that are
derivatives as defined by SFAS 133, but these operations do not met the
definition of energy trading activities based upon the provisions in EITF 98-10.
Currently, the Company uses a gross presentation to report the results of these
operations. The Company will re-evaluate its portfolio of derivative contracts
to determine if any will be required to be reported net in accordance with the
provisions of the new consensus.
The consensus relating to the presentation of gains and losses on derivative
instruments held for "trading purposes" is effective for financial statements
issued for periods beginning after December 15, 2002 and requires the
reclassification of all periods presented. For the Company, the consensus is
effective beginning January 1, 2003.
SFAS 142
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS 142). The Company adopted the provisions of SFAS 142, as required
on January 1, 2002. SFAS 142 changed the accounting for goodwill from an
amortization approach to an impairment-only approach. Thus, amortization of
goodwill that is not included as an allowable cost for rate-making purposes
ceased upon adoption of this statement. This includes goodwill recorded in past
business combinations. Goodwill is to be tested for impairment at a reporting
unit level at least annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any significant other
intangible assets.
The Company has goodwill included in its Gas Utility Services operating segment.
The amortization of this goodwill which approximated $0.2 million per year
ceased on January 1, 2002. Initial impairment reviews to be performed within six
months of adoption of SFAS 142 were completed and resulted in no impairment.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations are no longer
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002 did not materially impact
operations.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
Significant Fluctuations
Utility Margin (Operating Revenues Less Cost of Gas Sold, Fuel for Electric
Generation, & Purchased Electric Energy)
Electric Utility Margin
Electric Utility margin for the three and nine months ended September 30, 2002
and 2001 increased $14.0 million, or 23%, and $15.3 million, or 9%,
respectively. The increases result primarily from the effect on retail sales of
cooling weather considerably warmer than the prior year. Weather in 2002 was 31%
warmer for the quarter and 23% warmer for the nine-month period when compared to
2001. For the nine-month period, weather was 22% warmer than normal. In addition
to weather, both the quarter and the nine-month period were positively affected
by a cash return on NOx compliance expenditures pursuant to a rate recovery
rider approved by the IURC in August 2001. The year-to-date period, however, was
negatively affected by decreased margin from power marketing activities.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale transactions that expose the Company to limited market risk.
While volumes both sold and purchased in the wholesale market have increased
during 2002, margins have softened this year as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $2.9 million for
the year-to-date period. For the quarter, power marketing activities increased
margin by $0.5 million.
Gas Utility Margin
Gas Utility margin for the three months ended September 30, 2002 of $4.9 million
decreased $0.2 million, or 4%, compared to 2001. The decrease is primarily due
to warmer weather.
Gas Utility margin for the nine months ended September 30, 2002 of $23.2 million
increased $0.8 million, or 4%, compared to 2001. The increase is primarily due
to favorable changes in unaccounted for gas, customer growth, and other
adjustments. These increases were offset by weather warmer than the prior year
during the heating season and customer conservation. These offsets resulted in
an overall 6% decrease in total throughput from 23.7 MMDth in 2001 to 22.3 MMDth
in 2002.
Operating Expenses (excluding Cost of Gas Sold, Fuel for Electric Generation, &
Purchased Electric Energy)
Other Operating
Other operating expenses for the three months ended September 30, 2002 increased
$0.5 million, or 2%, and $3.5 million, or 5% for the nine months ended September
30, 2002 compared to 2001. The 2002 increase results primarily from charges for
the use of corporate assets offset by merger synergies and the timing of
maintenance expenditures.
Income Tax Expense
Federal and state income taxes increased $4.3 million and $8.0 million for the
three and nine months ended September 30, 2002, respectively. The increase
results principally from higher pretax earnings.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $0.5 million for the three months ended
September 30, 2002 when compared to the prior year period and were comparable
for the nine month periods. The increase during the quarter is attributable to
greater electric revenues that are subject to gross receipts tax than in the
prior period. For the nine-month period, the increase experienced during the
quarter was offset by a decrease in gross receipts and excise taxes as a result
of lower gas revenues due to lower gas prices.
Other income-net
Other income-net increased $0.2 million and $6.6 million for the three and nine
months ended September 30, 2002 as compared to the prior year periods. The
increases are attributable to the accrual of $5.2 million in carrying costs for
demand side management programs not currently in rates pursuant to an existing
IURC rate order and $0.6 million from the sale of excess emission allowances in
the second quarter of 2002. The remainder is principally increased AFUDC
throughout 2002 due to increased construction in progress balances for the NOx
compliance project.
Interest Expense
Interest expense increased $0.7 million and $1.8 million for the three and nine
months ended September 30, 2002. The increase was due primarily to increased
borrowings from VUHI resulting from NOx compliance capital expenditures.
Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the United States Environmental
Protection Agency (USEPA) finds a state's SIP inadequate to achieve the NAAQS,
the USEPA can call upon the state to revise its SIP (a SIP Call).
In October 1998, the 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). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1998 and 1999.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. Based on
the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through September 30, 2002,
$53.5 million has been expended. After the equipment is installed and
operational, related annual operating expenses, including depreciation expense,
are estimated to be between $24 million and $27 million. Such expenses would
commence in 2004 when the technology becomes operational. On October 22, 2002,
the Company filed a settlement agreement with the IURC that has been entered
into with the Indiana Office of Utility Consumer Counselor and an industrial
intervenor group relating to the ongoing NOx project. The agreement, if approved
by the IURC, will authorize additional capital cost investment and recovery on
those capital costs, as well as the recovery of future operating costs,
including depreciation and purchased emission allowances, through a rider
mechanism. A hearing is scheduled for November 15, 2002 to consider the
agreement. The settlement establishes a fixed return of 8 percent on the capital
investment.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, 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 review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. 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 an 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 1999 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: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
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 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 itself. Since the filing of this lawsuit, the USEPA has
voluntarily dismissed a majority of the claims brought in its original
compliant. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin March 31, 2003.
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
permitting requirements of new source review 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, the Company has recorded no accrual and
the plant continues 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 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
Financial Condition
The Company's equity capitalization objective is 40-55% of total capitalization.
This objective may have varied, and will vary, depending on particular business
opportunities and seasonal factors that affect the Company's operation. The
Company's equity component was 50% and 49% of total capitalization, including
current maturities of long-term debt, at September 30, 2002 and December 31,
2001, respectively.
Short-term cash working capital is required primarily to finance customer
accounts receivable, unbilled utility revenues resulting from cycle billing, gas
in underground storage, and capital expenditures. The Company expects the
majority of its capital expenditures and debt security redemptions to be
provided by internally generated funds; however, additional financing may be
required in future years due to significant capital expenditures for NOx
compliance equipment.
SIGECO's credit ratings on outstanding secured debt at September 30, 2002 are
A-/A1 as rated by Standard and Poor's and Moody's, respectively. On August 27,
2002, Moody's Investor Services issued a press release indicating its rating is
under review for a possible downgrade. Moody's raised several concerns including
the regulatory treatment of the significant NOx environmental expenditures. The
Company continues to work with Moody's to address these and other items
involving Vectren and other Vectren subsidiaries including the favorable NOx
settlement.
Cash Flow From Operations
The Company's primary source of liquidity to fund working capital requirements
has been cash generated from operations, which totaled approximately $92.2
million and $61.5 million, for the nine months ended September 30, 2002 and
2001, respectively.
Cash flow from operations increased during the nine months ended September 30,
2002 compared to 2001 by $30.7 million due primarily to favorable changes in
working capital accounts due to a return to lower gas prices and increased
earnings before non-cash charges.
Financing Activities
Sources & Uses of Liquidity
SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its
short-term working capital needs. The intercompany credit line totals $150
million, but is limited to VUHI's available capacity ($156.5 million at
September 30, 2002) and is subject to the same terms and conditions as VUHI's
commercial paper program. Borrowings outstanding at September 30, 2002 were
$81.9 million. At September 30, 2002, the Company had approximately $5 million
of short-term borrowing capacity with third parties to supplement its
intercompany borrowing arrangements of which $1.8 million was available.
Vectren's three operating utility companies, SIGECO, VEDO, and Indiana Gas are
guarantors of VUHI's $325 million commercial paper program, of which $168.5
million is outstanding at September 30, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at September 30, 2002. VUHI has no significant
independent assets or operations other than the assets and operations of these
operating utility companies. These guarantees are full and unconditional and
joint and several. Ratings triggers on VUHI's commercial paper backup facility
existing at December 31, 2001, were removed as the facility was renewed during
2002.
Financing Cash Flow
Cash flow required for financing activities of $30.1 million for the nine months
ended September 30, 2002 includes $33.5 million in common stock dividends and
$0.1 million paid for the redemption of preferred stock offset by $3.5 million
of increases in borrowings. In the prior year, the company retired $17.7 million
of preferred stock.
Other Financing Transactions
In January 2002, the Company redeemed 1,160 shares of SIGECO's 8.5% preferred
stock per its stated terms of $100 per share, plus accrued and unpaid dividends.
Prior to the redemption, there were 4,597 shares outstanding.
Capital Expenditures & Other Investment Activities
Cash required for investing activities of $61.4 million for the nine months
ended September 30, 2002 includes $61.2 million for capital expenditures.
Investing activities for the nine months ended September 30, 2001 were $43.6
million. The increase is attributable to NOx compliance expenditures.
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 statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition 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 the
Company's actual results to differ materially from those contemplated in any
forward-looking statements included, among others, the following:
|X| 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.
|X| Increased competition in the energy environment including effects of
industry restructuring and unbundling.
|X| 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.
|X| 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.
|X| Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
|X| Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but
not limited to, price, basis, credit, liquidity, volatility, capacity,
interest rate, and warranty risks.
|X| Availability or cost of capital, resulting from changes in the
Company, including its security ratings, changes in interest rates,
and/or changes in market perceptions of the utility industry and other
energy-related industries.
|X| Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages.
|X| Legal and regulatory delays and other obstacles associated with
mergers, acquisitions, and investments in joint ventures.
|X| Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but
not limited to, those described in Management's Discussion and
Analysis of Results of Operations and Financial Condition.
|X| Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company 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.
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electric energy for its retail
customers due to current Indiana regulations, which subject to compliance with
applicable state regulations, allow for recovery of such purchases through
natural gas and fuel cost adjustment mechanisms.
The Company does engage in limited wholesale power marketing operations that may
expose it to commodity price risk associated with fluctuating electric power
prices. The Company's wholesale power marketing operations manage the
utilization of its available electric generating capacity. These operations
enter into forward and option contracts that commit the Company to purchase and
sell electric power in the future.
Commodity price risk results from forward sale and option contracts that commit
the Company to deliver commodities on specified future dates. Power marketing
uses planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.
Open positions in terms of price, volume and specified delivery points may occur
to a limited extent and are managed using methods described above and frequent
management reporting.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale contracts that expose the Company to limited market risk.
During 2002, the Company has increased its activity in the wholesale market.
With the exception of those contracts subject to the normal purchase and sale
exclusion, commodity contracts are accounted for at market value. As of
September 30, 2002, contracts had no net asset value compared to a net asset
value of $3.2 million at December 31, 2001. The Company has determined these
power marketing contracts are derivatives within the scope of SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities."
Power marketing contracts at September 30, 2002 totaled $7.7 million of
prepayments and other current assets and $7.7 million of accrued liabilities,
compared to $5.2 million of prepayments and other current assets and $2.0
million of accrued liabilities at December 31, 2001. The change in the net value
of these contracts includes an unrealized gain of $0.2 million and an unrealized
loss of $3.0 million, respectively, for the three and nine months ended
September 30, 2002. For the three months ended September 30, 2002 and 2001, the
change in the net value of these contracts includes an unrealized gain of $0.2
million and an unrealized loss of $0.9 million, respectively. For the nine
months ended September 30, 2002 and 2001, the change in the net value of these
contracts includes unrealized losses of $3.0 million and $3.3 million,
respectively. Including these unrealized changes in fair value, overall margin
(revenue net of purchased power) from power marketing operations for the three
months ended September 30, 2002 and 2001 was $4.6 million and $4.1 million,
respectively, and for the nine months ended September 30, 2002 and 2001 was $8.0
million and $10.9 million, respectively.
Market risk is measured by management as the potential impact on pre-tax
earnings resulting from a 10% adverse change in the forward price of commodity
prices on market sensitive financial instruments (all contracts not expected to
be settled by physical receipt or delivery). For the three and nine months ended
September 30, 2002, a 10% adverse change in the forward prices of electricity on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $0.0 million and $1.4 million, respectively. For the three and
nine months ended September 30, 2001, a 10% adverse change in the forward prices
of electricity on market sensitive financial instruments would have decreased
pre-tax earnings by approximately $0.6 million and $2.0 million, respectively.
Interest Rate Risk
Interest rate risk is not significantly different from the information as set
forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk
included in the Company's 2001 Form 10-K and is therefore not presented herein.
Other Risks
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages this exposure to counter-party credit risk by entering
into contracts with companies that can be reasonably expected to fully perform
under the terms of the contract. Counter-party credit risk is monitored
regularly and positions are adjusted appropriately to manage risk. Further,
tools such as netting arrangements and requests for collateral are also used to
manage credit risk. The Company attempts to manage exposure to market risk
associated with commodity contracts and interest rates by establishing and
monitoring parameters that limit the types and degree of market risk that may be
undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits based on that
review. Credit risk associated with certain investments is also managed by a
review of creditworthiness and receipt of collateral.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures
Within 90 days prior to the filing of the report, the Company carried out an
evaluation under the supervision and with the participation of the Chief
Executive Officer and Chief Financial Officer of the effectiveness or the design
and operation of the Company's disclosure controls and procedures. Based on that
evaluation, the Chief Executive Officer and the Chief Financial Officer have
concluded that the Company's disclosure controls and procedures are effective in
bringing to their attention on timely basis material information relating to the
Company required to be disclosed by the Company in its Exchange Act reports.
Disclosure controls and procedures, as defined by the Securities Exchange Act of
1934 in Rules 13a-14(c) and 15d-14(c), are controls and other procedures of the
Company that are designed to ensure that information required to be disclosed by
the Company in the reports filed or submitted by it under the Securities and
Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and
reported, within the time periods specified in the SEC's rules and forms.
"Disclosure controls and procedures" include, without limitation, controls and
procedures designed to ensure that information required to be disclosed by the
Company in its Exchange Act reports is accumulated and communicated to the
Company's management, including its principal executive and financial officers,
as appropriate to allow timely decisions regarding required disclosure.
Changes in internal control
Since the evaluation of disclosure controls and procedures, there have been no
significant changes to the Company's internal control structure or significant
changes in other factors that could significantly affect the Company's internal
control environment. No material weaknesses or other significant deficiencies in
the design of internal control were noted by the Company during the most recent
disclosure control and procedure evaluation and through the filing of this Form
10-Q.
Internal control, as defined in American Institute of Certified Public
Accountants Codification of Statements on Auditing Standards (AU ss.319), is a
process, effected by an entity's board of directors, management, and other
personnel, designed to provide reasonable assurance regarding the achievement of
objectives in the following categories: (a) reliability of financial reporting,
(b) effectiveness and efficiency of operations and (c) compliance with
applicable laws and regulations.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is party to various legal and regulatory proceedings arising in the
normal course of business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position or results of operations. See Note 6
regarding environmental matters.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None
(b) Reports On Form 8-K During The Last Calendar Quarter
On July 23, 2002, SIGECO filed a Current Report on Form 8-K with respect to the
release of financial information to the investment community regarding Vectren's
results of operations for the three, six, and twelve month periods ended June
30, 2002. The financial information was released to the public through this
filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Second Quarter 2002 Vectren Corporation
Earnings
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995
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
-----------------------------------------
Registrant
November 13, 2002 /s/Jerome A. Benkert, Jr.
-------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/M. Susan Hardwick
-----------------------------
M. Susan Hardwick
Vice President and Controller
(Principal Accounting Officer)
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CHIEF EXECUTIVE OFFICER CERTIFICATION
I, Niel C. Ellerbrook, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southern Indiana Gas
and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 13, 2002
/s/ Niel C. Ellerbrook
---------------------------------
Niel C. Ellerbrook
Chairman and Chief Executive Officer
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CHIEF FINANCIAL OFFICER CERTIFICATION
I, Jerome A. Benkert, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southern Indiana Gas
and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 13, 2002
/s/ Jerome A. Benkert, Jr.
------------------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Executive Officer
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
By signing below, each of the undersigned officers hereby certifies pursuant to
18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, that, to his or her knowledge, (i) this report fully complies with the
requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
and (ii) the information contained in this report fairly presents, in all
material respects, the financial condition and results of operations of Southern
Indiana Gas and Electric Company.
Signed this 13th day of November 2002.
/s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook
- --------------------------------- -------------------------------------
(Signature of Authorized Officer) (Signature of Authorized Officer)
Jerome A. Benkert, Jr. Niel C. Ellerbrook
- --------------------------------- -------------------------------------
(Typed Name) (Typed Name)
Executive Vice President and
Chief Financial Officer Chairman and Chief Executive Officer
- --------------------------------- -------------------------------------
(Title) (Title)