UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 2003
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
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(Exact name of registrant as specified in its charter)
INDIANA 35-0672570
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
20 N.W. 4th Street, Evansville, Indiana, 47708
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(Address of principal executive offices)
(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) has been subject to such filing
requirements for the past 90 days. Yes |X| No __
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes __ No |X|
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock-Without Par Value 25,815,188 October 31, 2003
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Class Number of Shares Date
Omission of Information by Certain Wholly Owned Subsidiaries
The Registrant is a wholly owned subsidiary of Vectren Utility Holdings, Inc.
and meets the conditions set forth in General Instructions (H)(1)(a) and (b) of
Form 10-Q and is therefore filing with the reduced disclosure format
contemplated thereby.
Table of Contents
Item Page
Number Number
PART I. FINANCIAL INFORMATION
1 Financial Statements (Unaudited)
Southern Indiana Gas and Electric Company
Condensed Balance Sheets 1-2
Condensed Statements of Income 3
Condensed Statements of Cash Flows 4
Notes to Unaudited Condensed Financial Statements 5-13
2 Management's Discussion and Analysis of Results of Operations 14-19
and Financial Condition (A)
3 Quantitative and Qualitative Disclosures About Market Risk (A) 19
4 Controls and Procedures 19
PART II. OTHER INFORMATION
1 Legal Proceedings 20
6 Exhibits and Reports on Form 8-K 20
Signatures 21
(A) Omitted or amended as the Registrant is a wholly-owned subsidiary of
Vectren Utility Holdings, Inc. and meets the conditions set forth in
General Instructions (H)(1)(a) and (b) of Form 10-Q and is therefore filing
with the reduced disclosure format contemplated thereby.
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge, including those of its wholly owned subsidiaries, through its
website at www.vectren.com, or by request, directed to Investor Relations at the
mailing address, phone number, or email address that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812) 491-4000 Steven M. Schein
Evansville, Indiana Vice President, Investor Relations
47702-0209 sschein@vectren.com
Definitions
AFUDC: allowance for funds used MMBTU: millions of British
during construction thermal units
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions
of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of SFAS: Statement of Financial
Environmental Management Accounting Standards
IURC: Indiana Utility Regulatory USEPA: United States Environmental
Commission Protection Agency
MCF / BCF: millions / billions of Throughput: combined gas sales and
cubic feet gas transportation volumes
MDth / MMDth: thousands / millions of
dekatherms
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited - In thousands)
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September 30, December 31,
2003 2002
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ASSETS
Utility Plant
Original cost $ 1,609,355 $ 1,526,094
Less: Accumulated depreciation & amortization 760,541 728,768
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Net utility plant 848,814 797,326
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Current Assets
Cash & cash equivalents 1,239 2,145
Accounts receivable-less reserves of $1,699 &
$3,662, respectively 39,902 50,454
Receivables from other Vectren companies 27 18,015
Accrued unbilled revenues 17,240 33,027
Inventories 34,745 39,653
Recoverable fuel & natural gas costs 7,946 9,615
Prepayments & other current assets 8,577 5,926
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Total current assets 109,676 158,835
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Investments in Unconsolidated Affiliates 150 150
Other Investments 10,141 10,019
Non-Utility Property - Net 3,819 3,568
Goodwill - Net 5,557 5,557
Regulatory Assets 56,950 49,859
Other Assets 634 344
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TOTAL ASSETS $ 1,035,741 $ 1,025,658
================================================================================
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited - In thousands)
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September 30, December 31,
2003 2002
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LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 128,258 $ 103,258
Retained earnings 272,678 270,181
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Total common shareholder's equity 400,936 373,439
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Cumulative redeemable preferred stock 228 344
Long-term debt-net of current maturities
& debt subject to tender 216,388 264,238
Long-term debt due to VUHI 148,484 86,574
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Total capitalization 766,036 724,595
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Commitments & Contingencies (Notes 4, 6, & 7)
Current Liabilities
Accounts payable 11,026 25,215
Accounts payable to affiliated companies 4,082 10,013
Payables to other Vectren companies 10,191 14,677
Accrued liabilities 33,501 31,247
Short-term borrowings 996 -
Short-term borrowings due to VUHI 42,126 39,419
Long-term debt subject to tender 9,975 26,640
Current maturities of long-term debt - 1,000
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Total current liabilities 111,897 148,211
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Deferred Income Taxes & Other Liabilities
Deferred income taxes 116,118 112,004
Deferred credits & other liabilities 41,690 40,848
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Total deferred income taxes & other liabilities 157,808 152,852
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TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 1,035,741 $ 1,025,658
================================================================================
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)
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Three Months Nine Months
Ended September 30, Ended September 30,
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2003 2002 2003 2002
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As Restated, As Restated,
See Note 3 See Note 3
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OPERATING REVENUES
Electric revenues $133,987 $189,550 $343,606 $475,274
Gas revenues 11,458 7,468 78,225 54,699
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Total operating revenues 145,445 197,018 421,831 529,973
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COST OF OPERATING REVENUES
Fuel for electric generation 24,954 22,872 66,320 59,731
Purchased electric energy 42,644 92,906 101,830 239,451
Cost of gas sold 6,519 2,474 57,343 31,528
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Total cost of operating revenues 74,117 118,252 225,493 330,710
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TOTAL OPERATING MARGIN 71,328 78,766 196,338 199,263
OPERATING EXPENSES
Other operating 24,668 24,419 77,381 75,877
Depreciation & amortization 11,843 11,370 35,117 33,411
Income taxes 10,495 12,307 22,895 24,022
Taxes other than income taxes 2,961 3,657 8,920 9,975
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Total operating expenses 49,967 51,753 144,313 143,285
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OPERATING INCOME 21,361 27,013 52,025 55,978
Other income - net 1,278 927 2,440 4,331
Interest expense 6,453 5,713 18,835 17,198
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NET INCOME 16,186 22,227 35,630 43,111
Preferred stock dividends 4 15 18 25
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NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 16,182 $ 22,212 $ 35,612 $ 43,086
=======================================================================================
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)
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Nine Months Ended
September 30,
-------------------------
2003 2002
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As Restated,
See Note 3
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NET CASH FLOWS FROM OPERATING ACTIVITIES $ 96,374 $ 92,216
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt issuance to VUHI 61,900 -
Common stock issuance to VUHI 25,000 -
Requirements for:
Dividends to VUHI (33,115) (33,541)
Retirement of long-term debt, including
premiums paid (68,438) -
Other financing costs (1,744) -
Redemption of preferred stock (116) (116)
Dividends on preferred stock (18) (25)
Net change in short-term borrowings, including
due to VUHI 3,703 3,528
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Net cash flows from financing activities (12,828) (30,154)
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CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (84,452) (62,817)
Proceeds from sale of assets - 1,400
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Net cash flows from investing activities (84,452) (61,417)
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Net (decrease) increase in cash & cash equivalents (906) 645
Cash & cash equivalents at beginning of period 2,145 1,556
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Cash & cash equivalents at end of period $ 1,239 $ 2,201
================================================================================
The accompanying notes are an integral part of these condensed financial
statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO 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 8 counties in southwestern Indiana, including counties surrounding
Evansville, and participates in the wholesale power market. The Company also
provides natural gas distribution and transportation services to 10 counties in
southwestern Indiana, including counties surrounding Evansville. SIGECO is a
direct subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct,
wholly owned subsidiary of Vectren Corporation (Vectren).
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 note
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, 2002, filed
on Form 10-K/A. 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.
3. Restatement of Previously Reported Information
Subsequent to the issuance of the Company's 2002 quarterly financial statements,
the Company's management determined that previously issued financial statements
should be restated. The restatement had the effect of decreasing net income for
the three and nine months ended September 30, 2002, by $0.6 million after tax
and $3.3 million after tax, respectively.
In the second quarter of 2002, the Company recorded $5.2 million ($3.2 million
after tax) of carrying costs for demand side management (DSM) programs pursuant
to existing IURC orders and based on an improved regulatory environment.
Subsequently, management determined that the accrual of such carrying costs was
more appropriate in periods prior to 2000 when DSM program expenditures were
made. Therefore, such carrying costs originally reflected in 2002 quarterly
results were reversed and reflected in common shareholder's equity as of January
1, 2000. The Company also identified other adjustments for various
reconciliation errors and other errors related primarily to the recording of
estimates. These adjustments were not significant, either individually or in the
aggregate, and decreased previously reported pre-tax and after tax earnings for
the three months ended September 30, 2002, by approximately $1.0 million and
$0.6 million, respectively, and decreased previously reported pre-tax and after
tax earnings for the nine months ended September 30, 2002, by less than $0.1
million.
Following is a summary of the effects of the restatement on previously reported
results of operations for the three months ended September 30, 2002.
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In thousands As Reported Adjustments As Restated
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OPERATING REVENUES
Electric revenues $ 189,935 $ (385) $ 189,550
Gas revenues 7,388 80 7,468
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Total operating revenues 197,323 (305) 197,018
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COST OF OPERATING REVENUES
Fuel for electric generation 22,872 - 22,872
Purchased electric energy 92,436 470 92,906
Cost of gas sold 2,474 - 2,474
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Total cost of operating revenues 117,782 470 118,252
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TOTAL OPERATING MARGIN 79,541 (775) 78,766
OPERATING EXPENSES
Other operating 24,205 214 24,419
Depreciation & amortization 11,370 - 11,370
Income taxes 12,681 (374) 12,307
Taxes other than income taxes 3,657 - 3,657
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Total operating expenses 51,913 (160) 51,753
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OPERATING INCOME 27,628 (615) 27,013
Other income - net 926 1 927
Interest expense 5,713 - 5,713
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NET INCOME 22,841 (614) 22,227
Preferred stock dividends 15 - 15
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NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 22,826 $ (614) $ 22,212
================================================================================
Following is a summary of the effects of the restatement on previously reported
results of operations for the nine months ended September 30, 2002.
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In thousands
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As Reported Adjustments As Restated
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OPERATING REVENUES
Electric revenues $ 475,659 $ (385) $ 475,274
Gas revenues 54,619 80 54,699
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Total operating revenues 530,278 (305) 529,973
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COST OF OPERATING REVENUES
Fuel for electric generation 59,731 - 59,731
Purchased electric energy 239,272 179 239,451
Cost of gas sold 31,412 116 31,528
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Total cost of operating revenues 330,415 295 330,710
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TOTAL OPERATING MARGIN 199,863 (600) 199,263
OPERATING EXPENSES
Other operating 76,003 (126) 75,877
Depreciation & amortization 33,411 - 33,411
Income taxes 26,014 (1,992) 24,022
Taxes other than income taxes 9,975 - 9,975
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Total operating expenses 145,403 (2,118) 143,285
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OPERATING INCOME 54,460 1,518 55,978
Other income - net 9,109 (4,778) 4,331
Interest expense 17,198 - 17,198
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NET INCOME 46,371 (3,260) 43,111
Preferred stock dividends 25 - 25
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NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 46,346 $ (3,260) $ 43,086
================================================================================
4. Transactions with Other Vectren Companies
Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, finance, tax, risk
management, human resources, which includes charges for restricted stock
compensation and for pension and other postretirement benefits not directly
charged to subsidiaries. These costs have been allocated using various
allocators, primarily number of employees, number of customers and/or revenues.
Allocations are based on cost. SIGECO received corporate allocations totaling
$10.6 million and $10.9 million, respectively, for the three months ended
September 30, 2003 and 2002,and $32.2 million and $35.2 million, respectively,
for the nine months ended September 30, 2003 and 2002.
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 three months ended September 30, 2003
and 2002, totaled $20.5 million and $17.3 million, respectively, and $58.7
million and $45.6, respectively, for the nine months ended September 30, 2003
and 2002.
Guarantees of Parent Company Debt
Vectren's three operating utility companies, VEDO, Indiana Gas, and SIGECO are
guarantors of VUHI's $346 million in short-term credit facilities, of which
$142.5 million is outstanding at September 30, 2003, and VUHI's $550.0 million
unsecured senior notes outstanding at September 30, 2003. The guarantees are
full and unconditional and joint and several, and VUHI has no subsidiaries other
than the subsidiary guarantors.
Stock-Based Incentive Plans
SIGECO does not have stock-based compensation plans separate from Vectren. An
insignificant number of SIGECO's employees participate in Vectren's stock-based
compensation plans.
5. Transactions with ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to Indiana Gas, the Ohio operations, Citizens Gas and
others. ProLiance also began providing service to SIGECO and Vectren Retail, LLC
(Vectren's retail gas marketer) in 2002. ProLiance's primary businesses include
gas marketing, gas portfolio optimization, and other portfolio and energy
management services.
Purchases from ProLiance for resale and for injections into storage for the
three months ended September 30, 2003 and 2002, totaled $10.6 million and zero,
respectively, and for the nine months ended September 30, 2003 and 2002, totaled
$49.2 million and zero, respectively. Amounts owed to ProLiance at September 30,
2003 and December 31, 2002, for those purchases were $4.0 million and $10.0
million, respectively, and are included in accounts payable to affiliated
companies. Amounts charged by ProLiance for gas supply services are established
by supply agreements with each utility.
6. Financing Transactions
During 2003, the Company called two first mortgage bonds. The first bond had a
principal amount of $45.0 million, an interest rate of 7.60%, was originally due
in 2023, and was redeemed at 103.745% of its stated principal amount. The second
bond had a principal amount of $20.0 million, an interest rate of 7.625%, was
originally due in 2025, and was redeemed at 103.763% of the stated principal
amount. Pursuant to regulatory authority, the premiums paid to retire the net
carrying value of these bonds totaling $2.4 million were deferred as a
regulatory asset. The proceeds to fund the early redemption were received from
VUHI in the form of new long-term debt totaling $61.9 million and $25 million in
additional equity. To generate the initial proceeds to fund these transactions,
in August 2003, VUHI completed a public offering of long-term debt netting
proceeds of approximately $203 million, and Vectren completed a public offering
of common stock netting proceeds of approximately $163 million. Additionally, in
January, 2003, SIGECO retired other debt totaling $1.0 million.
The $61.9 million of new long-term debt due to VUHI has terms identical to the
terms of notes issued by VUHI in August 2003 through the public offering. Those
notes have an interest rate of 5.75% priced at 99.177% to yield 5.80% to
maturity and are due August 2018. They have no sinking fund requirements, and
interest payments are due semi-annually. The notes may be called by VUHI, in
whole or in part, at any time for an amount equal to accrued and unpaid
interest, plus the greater of 100% of the principal amount or the sum of the
present values of the remaining scheduled payments of principal and interest,
discounted to the redemption date on a semi-annual basis at the Treasury Rate,
as defined in VUHI's indenture, plus 25 basis points.
7. Commitments & Contingencies
Legal Proceedings
The Company is party to various legal 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 8 regarding
environmental matters.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in Note 3 to these condensed financial statements and in
Note 3 to the 2002 financial statements filed on Form 10-K/A, the Company
restated its financial statements for 2000, 2001, and 2002 quarterly results.
The Company is cooperating with the SEC in an informal inquiry with respect to
this previously announced restatement, has met with the staff of the SEC, and
has provided information in response to their requests.
8. 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 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 1999 and 1998.
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.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months an 8 percent
return on its capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is in service.
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 is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
September 30, 2003, $117.1 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. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
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. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged 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 alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced a agreement that would resolve the lawsuit. The agreement was embodied
in a consent decree filed in U.S. District Court for the Southern District of
Indiana. The mandatory public comment period has expired, and no comments were
received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations
alleged in the government's complaint, and SIGECO continues to believe that it
acted in accordance with applicable regulations and conducted only routine
maintenance on the units. SIGECO has entered into this agreement to further its
continued commitment to improve air quality and avoid the cost and uncertainties
of litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxides, or cease
operation of the unit by December 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
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 October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's Voluntary Remediation Program (VRP). In
response SIGECO submitted to the IDEM the results of preliminary site
investigations conducted in the mid-1990's. These site investigations confirmed
that based upon the conditions known at the time, the sites posed no risk to
human health or the environment. Follow up reviews have been initiated by the
Company to confirm that the sites continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. At this time the Company
is unable to predict any outcome that may result from these SIGECO manufactured
gas plant sites.
9. Impact of Recently Issued Accounting Guidance
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. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
In accordance with regulatory treatment, the Company collects an estimated net
cost of removal of its utility plant in rates through normal depreciation. As of
September 30, 2003, and December 31, 2002, such removal costs approximated $130
million and $125 million, respectively, of accumulated depreciation as presented
in the condensed consolidated balance sheets based upon the Company's latest
depreciation studies.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133; (2) in connection with other projects dealing with financial
instruments; and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements, which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
financial statements
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments; obligations to repurchase the issuer's equity shares by
transferring assets; and certain obligations to issue a variable number of
shares. SFAS 150 is effective immediately for all financial instruments entered
into or modified after May 31, 2003. For all other instruments, SFAS 150 applies
to the Company's third quarter of 2003. SFAS 150's adoption did not affect the
Company's results of operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.
FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and, thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. FIN 46 currently applies to VIE's
created after January 31, 2003, and to VIE's in which an enterprise obtains an
interest after that date. For entities created prior to January 31, 2003, FIN 46
is to be adopted on December 31, 2003. Although management is still evaluating
the impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
EITF 03-11
The EITF has recently released guidance on when gross or net presentation on the
income statement for derivative instruments not held for trading purposes is
appropriate. The guidance is effective for the Company's fourth quarter, and the
Company is currently determining the impacts, if any, that will result from
implementing that guidance.
10. Segment Reporting
The Company has two operating segments: (1) Gas Utility Services and (2)
Electric Utility Services. The Gas Utility Services segment includes the
operations of the Company's natural gas distribution business and provides
natural gas distribution and transportation services in southwest Indiana. The
Electric Utility Services segment includes the operations of the Company's power
generating and marketing operations, and electric transmission and distribution
services, which provides electricity to primarily southwestern Indiana.
Following is detailed information about the Company's operating segments. The
Company uses pre-tax operating income as the measure of profitability for its
segments.
Following is information regarding the Company's segments' operating data.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------- --------------------
In thousands 2003 2002 2003 2002
- ------------------------------ --------- --------- --------- ---------
Operating Revenues
Electric Utility Services $ 133,987 $ 189,550 $ 343,606 $475,274
Gas Utility Services 11,458 7,468 78,225 54,699
- -------------------------------------------------------------------------------
Total operating revenues $ 145,445 $ 197,018 $ 421,831 $529,973
===============================================================================
Pre-tax Operating Income
Electric Utility Services $ 32,316 $ 39,847 $ 71,551 $ 74,624
Gas Utility Services (460) (527) 3,369 5,376
- -------------------------------------------------------------------------------
Total pre-tax operating
income $ 31,856 $ 39,320 $ 74,920 $ 80,000
===============================================================================
Following is information regarding the Company's segments' total assets.
September 30, December 31,
In thousands 2003 2002
- ----------------------------------------------------------
Identifiable Assets
Electric Utility Services $ 896,526 $ 856,516
Gas Utility Services 139,215 169,142
- ----------------------------------------------------------
Total identifiable assets $1,035,741 $1,025,658
==========================================================
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Pursuant to General Instructions H(2)(a) of Form 10-Q, the following analysis of
the results of operations is presented in lieu of Management's Discussion and
Analysis of Financial Condition and Results of Operations.
Results of Operations
The following discussion and analysis should be read in conjunction with the
unaudited financial statements and notes thereto. Subsequent to the issuance of
the Company's 2002 quarterly financial statements, the Company's management
determined that previously issued financial statements should be restated. The
restatement had the effect of decreasing net income for the three and nine
months ended September 30, 2002, by $0.6 million after tax and $3.3 million
after tax, respectively. Note 3 to the condensed financial statements includes a
summary of the effects of the restatement. The Company's results of operations
give effect to the restatement.
Net Income Applicable to Common Shareholder
For the three months ended September 30, 2003, net income applicable to common
shareholder was $16.2 million compared to $22.2 million, for the same period
last year. The primary contributors to the $6.0 million decline were milder
cooling weather, a slowly recovering economy, and lower non-firm wholesale power
margins.
For the nine months ended September 30, 2003, net income applicable to common
shareholder was $35.6 million compared to $43.1 million for the same period in
2002. The $7.5 million decrease was primarily driven by weather, a slowly
recovering economy, and increased operating expenses, partially offset by
increased wholesale power margins. It is estimated that the mild weather has
unfavorably impacted earnings by $3.5 million after tax.
Margin
Electric Utility Margin
Electric utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:
- ----------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
------------------ ------------------
In millions 2003 2002 2003 2002
- ----------------------------- ------------------ ------------------
Retail & firm wholesale $ 63.7 $ 70.0 $160.5 $169.2
Non-firm wholesale 2.8 3.8 15.0 6.9
- ----------------------------------------------------------------------------
Total electric margin $ 66.5 $ 73.8 $175.5 $176.1
============================================================================
Non-firm wholesale margin:
Realized margin $ 3.3 $ 4.0 $ 14.6 $ 10.0
Mark-to-market gains (losses) (0.5) (0.2) 0.4 (3.1)
Electric margins were $66.5 million, a decrease of $7.3 million compared to the
third quarter of 2002. The decrease in electric margin was due primarily to the
effect of milder cooling weather which was 7% cooler than normal and 26% cooler
than last year. The estimated quarter over quarter decrease as a result of the
milder weather was approximately $3.6 million. Impacts of the slowly recovering
economy on industrial sales and slightly lower non-firm wholesale power margins
further decreased non-weather related electric margin compared to the prior
year. As a result primarily of mild weather, volumes sold to retail and firm
wholesale customers decreased 8% from 1.87 GWh in 2002 to 1.72 GWh in 2003.
Electric margins were $175.5 million, a decrease of $0.6 million over the nine
months ended September 30, 2002. The decrease was primarily due to lower retail
sales due to milder cooling weather and the current quarter decrease in
industrial sales. As a result primarily of the mild weather which was 18% cooler
than normal and 33% cooler than last year, volumes sold to retail and firm
wholesale customers decreased 5% from 4.76 GWh in 2002 to 4.53 GWh in 2003 with
an estimated margin decrease of $6.5 million. The decrease was partially offset
by increased non-firm wholesale power margins resulting from price volatility.
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale transactions that expose the Company
to limited market risk. For the three months ended September 30, 2003, volumes
sold into the wholesale market were 1.01 GWh compared to 2.66 GWh in 2002 while
volumes purchased were 1.01 GWh in 2003 compared to 2.65 GWh in 2002. For the
nine months ended September 30, 2003, volumes sold into the wholesale market
were 3.04 GWh compared to 8.30 GWh in 2002 while volumes purchased were 3.49 GWh
in 2003 compared to 8.14 GWh in 2002. A portion of volumes purchased in the
wholesale market is used to serve retail and firm wholesale customers, and in
2003, greater amounts of purchased power have been required for native load due
to scheduled outages, which has reduced capacity available for optimization.
Additionally, both sold and purchased power were lower in 2003 due to a shorter
term focus in hedging and optimization strategies combined with a more selective
approach to counter-party relationships. While volumes both sold and purchased
in the wholesale market have decreased during 2003, which has resulted in
decreased electric revenues and purchased power, margins year-to-date have
increased primarily from price volatility. In the third quarter, margins
decreased because less capacity was available for optimization due to outages
for NOx control equipment installation and the wholesale power market was less
volatile.
Gas Utility Margin
Gas margins for the third quarter, a non-heating, base load usage quarter, were
$4.9 million, a decrease of 1% compared to the prior year period. While margin
was generally flat, overall usage decreased 11% primarily due to slowly
recovering economic conditions and high gas costs.
Gas utility margins were $20.9 million, a decrease of $2.3 million over the
first nine months of 2002. The decrease is primarily due to estimates for
unbilled revenue, the pricing of unaccounted for gas, and reduced consumption
per degree day per customer, all of which decreased margin by approximately $3.0
million. Management estimates that weather 17% colder than the prior year and 9%
colder than normal increased margin by approximately $0.7 million period over
period. The colder weather is the primary reason for the 3% increase in
throughput.
Operating Expenses
Other Operating
For the nine months ended September 30, 2003, other operating expenses increased
$1.5 million, compared to the prior year. The increased expenses were
principally due to the timing of electric plant maintenance expenditures and
other routine expenditures.
Depreciation & Amortization
For the three and nine months ended September 30, 2003, depreciation and
amortization increased $0.5 million and $1.7 million, respectively, due to a
full nine months depreciation on utility plant additions including a new
gas-fired peaker unit and other upgrades to existing transmission and
distribution facilities.
Income Tax
For the three and nine months ended September 30, 2003, federal and state income
taxes decreased $1.8 million and $1.1 million, respectively, when compared to
2002. The changes are primarily due to decreases in pre-tax income. Year to
date, the effective tax rate increased from 35.8% in 2002 to 39.1% in 2003
principally due to an increase in the Indiana state income tax rate from 4.5 %
to 8.5% that was effective January 1, 2003.
Taxes Other Than Income Taxes
For the three and nine months ended September 30, 2003, taxes other than income
taxes decreased $0.7 million and $1.1 million, respectively, when compared to
2002. The decreases are primarily attributable to lower property taxes.
Other Income - Net
For the three and nine months ended September 30, 2003, other income -net
increased $0.4 million and decreased $1.9 million, respectively, compared to the
prior year. The current quarter increase in other income -net was principally
the result of fluctuations in investments used to fund deferred compensation
plans. The year-to-date decrease is primarily the result of the current year
penalty associated with the Culley settlement of $0.6 million and sales of
emission allowances in the second quarter of 2002 totaling $0.6 million. In
addition, both the quarter and year to date 2003 periods have experienced less
AFUDC.
Interest Expense
For the three and nine months ended September 30, 2003, interest expense
increased $0.7 million and $1.6 million, respectively, when compared to the same
periods last year. The increase results from increased debt outstanding which is
due primarily to increased working capital requirements resulting from the
higher gas prices and NOx expenditures. Results also include permanent financing
transactions executed during the year whereby short term borrowings due to VUHI
and $65.0 million of higher coupon third party debt were replaced with $25
million in equity and $61.9 million in long term debt payable to VUHI.
Impact of Recently Issued Accounting Guidance
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. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133; (2) in connection with other projects dealing with financial
instruments; and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements, which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
financial statements
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments; obligations to repurchase the issuer's equity shares by
transferring assets; and certain obligations to issue a variable number of
shares. SFAS 150 is effective immediately for all financial instruments entered
into or modified after May 31, 2003. For all other instruments, SFAS 150 applies
to the Company's third quarter of 2003. SFAS 150's adoption did not affect the
Company's results of operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.
FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and, thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. FIN 46 currently applies to VIE's
created after January 31, 2003, and to VIE's in which an enterprise obtains an
interest after that date. For entities created prior to January 31, 2003, FIN 46
is to be adopted on December 31, 2003. Although management is still evaluating
the impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
EITF 03-11
The EITF has recently released guidance on when gross or net presentation on the
income statement for derivative instruments not held for trading purposes is
appropriate. The guidance is effective for the Company's fourth quarter, and the
Company is currently determining the impacts, if any, that will result from
implementing that guidance.
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 include, 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 electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
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
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in credit ratings, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other 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 Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o 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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Pursuant to General Instructions H(2)(c) of Form 10-Q, the following is
intentionally omitted.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of September 30, 2003, 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 and 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 at providing
reasonable assurance that material information relating to the Company required
to be disclosed by the Company in its filings under the Securities Exchange Act
of 1934 (Exchange Act) is brought to their attention on a timely basis.
Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-15(e) and 15d-15(e), 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 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 Over Financial Reporting
During the quarter ended September 30, 2003, there have been no significant
changes to the Company's internal control over financial reporting that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
Internal control over financial reporting is defined by the SEC in Final Rule:
Management's Reports on Internal Control Over Financial Reporting and
Certification of Disclosure in Exchange Act Periodic Reports. The final rule
defines internal control over financial reporting as a process designed by, or
under the supervision of, the registrant's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
registrant's board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that: (1) Pertain to the maintenance of records that in reasonable
detail accurately and fairly reflect the transactions and dispositions of the
assets of the registrant; (2) Provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the registrant are being made only in accordance with
authorizations of management and directors of the registrant; and (3) Provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the registrant's assets that could have a
material effect on the financial statements.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is party to various legal 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 8 of its unaudited
condensed financial statements included in Part 1 Item 1 Financial Statements
regarding the Clean Air Act and related legal proceedings.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
Certifications
31.1 Certification Pursuant To Section 302 Of The Sarbanes-Oxley Act Of 2002-
Chief Executive Officer
31.2 Certification Pursuant To Section 302 Of The Sarbanes-Oxley Act Of 2002-
Chief Financial Officer
32 Certification Pursuant To Section 906 Of The Sarbanes-Oxley Act Of 2002
Other Exhibits
None
(b) Reports On Form 8-K During The Last Calendar Quarter
On July 11, 2003, Vectren Corporation filed a Current Report on Form 8-K with
respect to adjust 2003 earnings guidance and to address recent announcements
related to the production of synthetic fuel. Portions of this information were
furnished to the SEC
Item 5. Other Events and Regulation FD Disclosure
Item 7. Exhibits
99.1 - Press Release - Vectren Corporation adjusts 2003
earnings guidance and addresses recent announcements
related to the production of synthetic fuel
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
Item 9. Regulation FD Disclosure and Item 12. Results of Operations
and Financial Condition
On July 23, 2003, Vectren Corporation furnished information to the SEC on a
Current Report on Form 8-K with respect to the release of financial information
to the investment community regarding the Company's results of operations, for
the three, six, and twelve month periods ended June 30, 2003. The financial
information was released to the public through this filing.
Item 7. Exhibits
99.1 - Press Release - Vectren Corporation Reports 2nd
Quarter 2003 Results
99.2 - Press Release - Vectren Corporation Declares Regular
Quarterly Dividend
99.3 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
Item 9. Regulation FD Disclosure and Item 12. Results of Operations
and Financial Condition
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHERN INDIANA GAS AND
ELECTRIC COMPANY
------------------------------------------------
Registrant
November 12, 2003 /s/ Jerome A. Benkert, Jr.
----------------------------
Jerome A. Benkert, Jr.
Executive Vice President &
Chief Financial Officer
(Principal Financial Officer)
/s/ M. Susan Hardwick
-----------------------------
M. Susan Hardwick
Vice President & Controller
(Principal Accounting Officer)