UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 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
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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 Identification No.)
incorporation or organization)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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None None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Name of each exchange on which registered
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None None
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 if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes ___. No |X|.
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
28, 2002 was zero. All shares outstanding of the Registrant's common stock were
held by Vectren Corporation through its wholly owned subsidiary, Vectren Utility
Holdings, Inc.
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 20,785,007 March 15, 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 (I)(1)(a) and (b) of
Form 10-K and is therefore filing with the reduced disclosure format
contemplated thereby.
Definitions
AFUDC: allowance for funds used Mva: megavolt amperes
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force GWh: millions of megawatt hours
(gigawatt hour)
FASB: Financial Accounting Standards Board NOx: nitrogen oxide
IURC: Indiana Utility Regulatory Commission OUCC: Indiana Office of the Utility
Consumer Counselor
MCF / BCF: millions / billions of cubic feet SFAS: Statement of Financial
Accounting Standards
MMDth: millions of dekatherms USEPA: United States Environmental
Protection Agency
MMBTU: millions of British thermal units Throughput: combined gas sales and
gas transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business (A) .................................................... 1
2 Properties ...................................................... 1
3 Legal Proceedings................................................ 2
4 Submission of Matters to Vote of Security Holders (A)............ 2
Part II
5 Market for the Company's Common Equity and Related
Stockholder Matters ........................................... 2
6 Selected Financial Data (A)...................................... 3
7 Management's Discussion and Analysis of Results of
Operations and Financial Condition (A)......................... 3
7A Qualitative and Quantitative Disclosures
About Market Risk.............................................. 12
8 Financial Statements and Supplementary Data...................... 14
9 Change in and Disagreements with Accountants on
Accounting and Financial Disclosure............................ 45
Part III
10 Directors and Executive Officers of the Company (A).............. 45
11 Executive Compensation (A)....................................... 45
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters. (A)................ 45
13 Certain Relationships and Related Transactions (A)............... 45
Part IV
14 Controls and Procedures.......................................... 45
15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.................................................... 46
Signatures....................................................... 48
Certifications................................................... 49
(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 (I)(1)(a) and (b) of Form 10-K 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 47702-0209 Vice President, Investor
Relations
Sschein@vectren.com
PART I
ITEM 1. BUSINESS
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 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, 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.
The narrative description of the business, competition and personnel sections
were intentionally omitted. See the table of contents of this Annual Report on
Form 10-K for explanation.
ITEM 2. PROPERTIES
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2002, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50MW and Broadway Avenue Unit 2,
65MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 829 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,221.2 megavolt amperes (Mva). The electric distribution
system includes 3,212 pole miles of lower voltage overhead lines and 275 trench
miles of conduit containing 1,541 miles of underground distribution cable. The
distribution system also includes 95 distribution substations with an installed
capacity of 1,939.5 Mva and 50,030 distribution transformers with an installed
capacity of 2,352.3 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Gas Utility Services
The Company owns and operates three underground gas storage fields located in
Indiana covering 6,070 acres of land with an estimated ready delivery from
storage capability of 8.7 BCF of gas with delivery capabilities of 124,748 MCF
per day. In addition to its owned storage and daily delivery capabilities, the
Company contracts for a maximum of 0.5 BCF of gas availability across various
pipelines with a delivery capability of 18,753 MCF per day. The Company's gas
delivery system includes 2,996 miles of distribution and transmission mains, all
of which are located in Indiana.
Property Serving as Collateral
The Company's properties are subject to the lien of the First Mortgage Indenture
dated as of April 1, 1932 between the Company and Bankers Trust Company, as
Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various
supplemental indentures.
ITEM 3. 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 10 of its financial
statements included in Item 8 Financial Statements and Supplementary Data
regarding the Clean Air Act and related legal proceedings.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market Price
All of the outstanding shares of the Company's common stock are owned by VUHI at
December 31, 2002. The Company's common stock is not publicly traded.
As of December 31, 2002, there are no outstanding options or warrants to
purchase the Company's common stock or securities convertible into the Company's
common stock. Additionally, the Company has no plans to publicly offer any of
its common equity.
Dividends Paid to Parent
During 2002, the Company paid dividends to its parent company of $10.3 million,
$11.6 million, $11.6 million, and $11.6 million in the first, second, third, and
fourth quarters, respectively.
During 2001, the Company paid dividends to its parent company of $8.6 million,
$7.7 million, $7.7 million, and $14.9 million in the first, second, third, and
fourth quarters, respectively.
On January 29, 2003, the board of directors declared a dividend of $10.9
million, payable to its parent company on March 1, 2003.
Dividends on shares of common stock are payable at the discretion of the board
of directors out of legally available funds. Future payments of dividends, and
the amounts of these dividends, will depend on the Company's financial
condition, results of operations, capital requirements, and other factors.
ITEM 6. SELECTED FINANCIAL DATA
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Pursuant to General Instructions I(2)(a) of Form 10-K, 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.
The following discussion and analysis should be read in conjunction with the
financial statements and notes thereto. As discussed in Note 3 in the financial
statements, subsequent to the issuance of the Company's 2001 financial
statements, the Company's management determined that previously issued financial
statements should be restated. As a result, the Company has restated its 2001
and 2000 financial statements and has increased reported retained earnings as of
January 1, 2000 by $2.9 million. The restatement had the effect of decreasing
net income for 2001 and 2000 by approximately $1.8 million and $0.7 million,
respectively. Note 3 to the financial statements includes a summary of the
significant effects of the restatement. The effect of the restatement on
quarterly results, including previously reported 2002 quarterly information, is
discussed in Note 3 and Note 17. The following discussion and analysis gives
effect to the restatement.
Results of Operations
In 2002, net income applicable to common shareholder was $59.3 million, an
increase of $18.6 million when compared to 2001, as restated. The year ended
December 31, 2001 included nonrecurring merger, integration, and restructuring
costs and other nonrecurring items totaling $4.0 million after tax. In addition
to the nonrecurring 2001 items, the increase reflects improved margins and lower
operating costs. These resulted from favorable weather and a return to lower gas
prices and the related reduction in costs incurred in 2001.
In 2001, net income applicable to common shareholder was $40.7 million. Net
income applicable to common shareholder increased $1.3 million due primarily to
lower nonrecurring items incurred in 2001 compared to 2000. Nonrecurring merger
and integration costs in 2000 totaled $11.0 million after tax. Before non-
recurring items, net income applicable to common shareholders decreased $5.7
million primarily due to extra- ordinarily high gas costs early in 2001 that
unfavorably impacted margins and operating costs including uncollectible
accounts expense and interest; heating weather that was 10% warmer than the
prior year; and decreased margin from firm and non-firm wholesale customers,
reflecting a weakened national economy.
Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $1.8 million after tax, decreased
previously reported 2000 results by approximately $0.7 million after tax, and
increased retained earnings as of January 1, 2000 by $2.9 million after tax.
Adjustments were also made to previously reported 2002 quarterly results. In
addition to adjustments affecting previously reported net income, other
reclassifications were made to the previously reported 2001 and 2000 results to
conform with the 2002 presentation.
Previously Reported 2001 and 2000 Net Income Adjustments
The Company determined that $3.3 million ($2.0 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.
The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $1.5 million ($0.9 million after tax).
The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.
Originally reflected in 2001, the Company also reflected a correction of the
year 2000 overstatement of electric revenue totaling $2.4 million ($1.5 million
after tax), now reflected in 2000 as discussed below. The Company identified
other reconciliation errors and other errors related to the recording of
estimates that were not significant, either individually or in the aggregate. As
a result of these additional items, 2001 earnings were reduced by $0.6 million
($0.4 million after tax).
The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $1.3 million ($0.8 million after tax). The impact of
the restatement of results for the year ended 2000 is a reduction to pre-tax
income and net income of $1.1 million and $0.7 million, respectively.
Previously Reported 2002 Quarterly Net Income Adjustments
As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, 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. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $0.2 million and $0.1 million after tax,
respectively. The cumulative impact from these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$3.3 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000 resulting in a cumulative net increase of $2.9
million in retained earnings as of January 1, 2000.
Other Balance Sheet Adjustments
Certain reclassifications were made to reflect separate Company current and
deferred income taxes are included in Vectren's consolidated tax position. These
reclassifications are the principal adjustments to intercompany receivables and
payables as well as prepayments and other current assets and deferred income
taxes. The Company also reclassified all previously recorded goodwill not
included in rates to goodwill on the balance sheet. This adjustment resulted in
a $5.6 million decrease in other assets and a corresponding increase in
goodwill.
The Company has restated its financial statements to give effect to the matters
discussed above. A summary of the significant effects of the restatement on
previously reported financial position and results of operations is included in
Note 3 to the financial statements. The effects of the restatement on 2001
quarterly results and on 2002 previously reported quarterly information, is
discussed in Note 17. The financial statements are included under Item 8
Financial Statements and Supplementary Data.
Nonrecurring Items in 2001 and 2000
Merger and Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $0.6 million ($0.4 million after tax) and $14.1 million ($11.0 million
after tax), respectively. Merger and integration activities resulting from the
2000 merger were completed in 2001.
Since March 31, 2000, $14.7 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$7.4 million. Of this amount, $0.7 million related to employee and executive
severance costs and $6.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger. At December 31, 2001,
no accrual remains. The remaining $7.3 million was expensed ($6.7 million in
2000 and $0.6 million in 2001) for accounting fees resulting from merger related
filing requirements, consulting fees related to integration activities such as
organization structure, employee travel between company locations, internal
labor of employees assigned to integration teams, investor relations
communication activities, and certain benefit costs.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, Vectren's management and
board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $4.3 million were expensed in June 2001 as a direct result of
the restructuring plan. Additional charges of $1.5 million were incurred during
the remainder of 2001 primarily related to consulting fees and employee
relocation costs. In total, the Company has incurred restructuring charges of
$5.8 million, ($3.6 million after tax). These charges were comprised of $4.4
million for employee severance, related benefits and other employee related
costs and $1.4 million for consulting and other fees incurred through December
31, 2001. The restructuring program was completed during 2001, except for the
departure of certain employees impacted by the restructuring which occurred
during 2002. (See Note 15 for further information on restructuring costs.)
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million after tax) recorded as a cumulative
effect of change in accounting principle in the Statements of Income.
Loss on extinguishment of preferred stock
In September 2001, the Company notified holders of its 4.80%, 4.75%, and 6.50%
preferred stock of its intention to redeem the shares. The 4.80% preferred stock
was redeemed at $110.00 per share, plus $1.35 per share in accrued and unpaid
dividends. Prior to the redemption, there were 85,519 shares outstanding. The
4.75% preferred stock was redeemed at $101.00 per share, plus $0.97 per share in
accrued and unpaid dividends. Prior to the redemption, there were 3,000 shares
outstanding. The 6.50% preferred stock was redeemed at $104.23 per share, plus
$0.73 per share in accrued and unpaid dividends. Prior to the redemption, there
were 75,000 shares outstanding. The total redemption price was $17.7 million and
the loss on redemption totaled $1.2 million.
Significant Fluctuations
Utility 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:
Year ended December 31,
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In millions 2002 2001 2000
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Retail & firm wholesale $ 215.3 $ 200.0 $ 201.2
Non-firm wholesale 14.9 19.9 21.1
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Total margin $ 230.2 $ 219.9 $ 222.3
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Non-firm wholesale margin:
Realized margin $ 18.5 $ 18.4 $ 21.1
Mark-to-market gains (losses) (3.6) 1.5 -
Electric Utility margin for the year ended December 31, 2002 increased $10.3
million, or 5%, when compared to 2001. The increases result primarily from the
effect on retail sales of cooling weather considerably warmer than the prior
year. Weather in 2002 was 27% warmer when compared to 2001 and 23% warmer than
normal. In addition to weather, 2002 was positively affected by a cash return on
NOx compliance expenditures as the expenditures are made pursuant to a rate
recovery rider approved by the IURC in August 2001. As a result of warmer
weather, retail and firm wholesale volumes sold increased from 5.8 GWh in 2001
to 6.2 GWh in 2002. Volumes sold in 2000 were 5.9 GWh. The current year increase
in margin from retail sales was partially offset by lower margins earned in the
wholesale energy market.
Electric Utility margin for the year ended December 31, 2001 decreased $2.4
million, or 1%, compared to 2000 primarily from decreased sales to firm
wholesale customers and decreased margin on non-firm wholesale activity. The
decreases were partially offset by a 3% increase in residential and commercial
sales due to cooling weather 7% warmer than the prior year and a 3% increase in
the number of residential and commercial customers.
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. While volumes both sold and purchased in the wholesale
market have increased during 2002, margins softened as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $5.0 million during
2002 and $1.2 million during 2001. In 2002, volumes sold into the wholesale
market were 10.7 GWh compared to 3.4 GWh in 2001 and 1.6 GWh in 2000. Volumes
purchased from the wholesale market, some of which were utilized to serve retail
and firm wholesale customers, were 10.3 GWh in 2002 compared to 2.9 GWh in 2001
and 1.2 GWh in 2000.
Gas Utility Margin
Gas Utility margin for the year ended December 31, 2002 of $32.4 million
increased $6.5 million. The increase is primarily due to weather 4% cooler for
the year and 26% cooler in the fourth quarter and customer growth of almost 1%.
The Company's total throughput was 32.0 MMDth in 2002, 31.9 MMDth in 2001, and
35.6 MMDth in 2000. The change in throughput between 2002 and 2001 reflects a
10% increase in retail and commercial volumes sold offset by a decrease in
contract volumes that primarily represent transported volumes.
Gas Utility margin for the year ended December 31, 2001 of $25.9 million
decreased $4.4 million, compared to 2000. The primary factors contributing to
this decrease were weather that was 10% warmer than the prior year and the
unfavorable impact resulting from extraordinarily high gas costs early in 2001,
coupled with the effects of a weakened economy.
Cost of gas sold was $53.1 million in 2002, $72.7 million in 2001, and $78.9
million in 2000. Cost of gas sold decreased $19.6 million, or 27%, during 2002
compared to 2001, primarily due to a return to lower gas prices somewhat offset
by an increase in retail volumes sold. Cost of gas sold decreased $6.2 million,
or 8%, in 2001. The decrease is primarily due to lower volumes sold due to the
warmer weather, a weakened economy, and lower gas prices. The total average cost
per dekatherm of gas purchased was $4.20 in 2002, $5.20 in 2001, and $5.46 in
2000. The price changes are due primarily to changing commodity costs in the
marketplace.
Operating Expenses
Other Operating
Other operating expenses decreased $4.1 million for the year ended December 31,
2002 when compared to 2001. The decrease results primarily from insurance
recovery in 2002 of certain maintenance costs incurred in 2001, a return to
lower gas prices, and the related reduction in costs incurred in 2001. Specific
expenses affected by increased gas costs in 2001 were uncollectible accounts
expense and contributions to low income heating assistance programs.
Depreciation and Amortization
Depreciation and amortization increased $1.8 million for the year ended December
31, 2002 when compared to 2001. The increase results primarily from the
depreciation of additions to plant assets including an 80 MW gas turbine placed
into service in June 2002. Depreciation and amortization for 2001 was comparable
to 2000.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $1.3 million in 2002 compared to 2001 as
a result of lower revenues subject to gross receipts tax and were basically
unchanged in 2001 compared to 2000.
Interest Expense
Interest expense increased $2.2 million in 2002 compared to 2001. The increase
is attributable to higher outstanding borrowings during 2002 due to the funding
of NOx expenditures with short-term borrowing.
Interest expense increased $1.0 million during the 2001 compared to 2000. The
increase is due primarily to increased working capital requirements resulting
from higher natural gas prices.
Income Tax
Federal and state income taxes increased $9.0 million in 2002 compared to 2001
and decreased $2.8 million in 2001 compared to 2000. The changes in income taxes
result principally from fluctuations in pre-tax earnings. The effective tax rate
in 2000 was higher due to the nondeductibility of certain merger and integration
costs.
Critical Accounting Policies
Management is required to make judgements, assumptions, and estimates that
affect the amounts reported in the financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the financial statements describes the significant
accounting policies and methods used in the preparation of the financial
statements. Certain estimates used in the financial statements are subjective
and use variables that require judgement. These include the estimates to perform
goodwill asset impairment tests. The Company makes other estimates in the course
of accounting for unbilled revenue, the effects of regulation, and intercompany
allocations that are critical to the Company's financial results but that are
less likely to be impacted by near term changes. Other estimates that
significantly affect the Company's results, but are not necessarily critical to
operations, include depreciation of utility plant, the valuation of derivative
contracts and the allowance for doubtful accounts, among others. Actual results
could differ from these estimates.
Goodwill
Pursuant to SFAS No. 142, the Company performed an initial impairment analysis
of its goodwill, all of which resides in the Gas Utility Services operating
segment. Also consistent with SFAS 142, goodwill is tested for impairment
annually at the beginning of the year and more frequently if events or
circumstances indicate that an impairment loss has been incurred. Impairment
tests are performed at the reporting unit level which the Company has determined
to be consistent with its Gas Utility Services operating segment as identified
in Note 14 to the financial statements. An impairment test performed in
accordance with SFAS 142 requires that a reporting unit's fair value be
estimated. The Company used a discounted cash flow model to estimate the fair
value of its Gas Utility Services operating segment, and that estimated fair
value was compared to its carrying amount, including goodwill. The estimated
fair value was in excess of the carrying amount and therefore resulted in no
impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgement in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also results in no impairment charge.
Unbilled Revenues
To more closely match revenues and expenses, the Company records revenues for
all gas and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the month to
allocate unbilled units. Those allocated units are multiplied by rates in effect
during the month to calculate unbilled revenue at balance sheet dates. While
certain estimates are used in the calculation of unbilled revenue, these
estimates are not subject to near term changes.
Regulation
At each reporting date, the Company reviews current regulatory trends in the
markets in which it operates. This review involves judgement and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Based on the Company's current review, it believes its regulatory assets are
probable of recovery. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets. In the unlikely event of a change in the current regulatory
environment, such write-offs and impairment charges could be significant.
Intercompany Allocations
Support Services
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, finance, tax, risk
management, and 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. 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. In
addition, Vectren negotiates service and construction contracts on behalf of its
utilities to obtain those services at less cost than the utility may otherwise
be able to obtain on its own. The allocation methodology is not subject to near
term changes.
Pension and Other Postretirement Obligations
Vectren satisfies the future funding requirements of its pension and other
postretirement plans and the payment of benefits from general corporate assets.
An allocation of expense is determined by Vectren's actuaries, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date. These costs are directly charged to individual
subsidiaries. Other components of costs (such as interest cost from prior
service and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Plan assets nor the FAS 87/106
liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Further, Vectren
satisfies the future funding requirements of plans and the payment of benefits
from general corporate assets. Management believes these direct charges when
combined with benefit-related corporate charges discussed in "support services"
above approximate costs that would have been incurred if the Company accounted
for benefit plans on a stand-alone basis. Vectren annually measures its
obligations on September 30.
Vectren estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other things, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of pension and postretirement plans. Vectren used the
following weighted average assumptions to develop 2002 annual costs and the
ending benefit obligations recognized in its consolidated financial statements:
a discount rate of 6.75%, an expected return on plan assets before expenses of
9.00%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2002 declining to 5% in 2006. During 2002, Vectren reduced the
discount rate and rate of compensation increase by 50 basis points from those
assumptions used in 2001 due to the general decline in interest rates and other
market conditions that occurred in 2002. Future changes in health care costs,
work force demographics, interest rates, or plan changes could significantly
affect the estimated cost of these future benefits that are allocated to the
Company.
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 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 Issue 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 non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
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 as described in Note 12 of the financial statements. The
Company has re-evaluated its portfolio of derivative contracts and has
determined gross presentation remains appropriate.
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. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (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 obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.
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 and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 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.
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, including, but
not limited to Vectren's realization of net merger savings, are forward-looking
statements. Such statements are based on management's beliefs, as well as
assumptions made by and information currently available to management. When used
in this filing, the words "believe," "anticipate," "endeavor," "estimate,"
"expect," "objective," "projection," "forecast," "goal," and similar expressions
are intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company's actual
results to differ materially from those contemplated in any forward-looking
statements include, 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.
|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 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business 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. The Company's risk management program includes, among other
things, the use of derivatives to mitigate risk.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.
Commodity Price Risk
The Company's operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due to
current Indiana regulations, which subject to compliance with those regulations,
allow for recovery of such purchases through natural gas and fuel cost
adjustment mechanisms.
Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.
The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts.
The Company's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.
Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.
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 outstanding market sensitive financial instruments (all contracts not
expected to be settled by physical receipt or delivery). For the years ended
December 31, 2002 and 2001, a 10% adverse change in commodity forward prices on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $1.5 million and $2.0 million, respectively.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. At December 31, 2002, such obligations represented 10%
of the Company's total debt portfolio. To manage this exposure, the Company may
periodically use derivative financial instruments to reduce earnings
fluctuations caused by interest rate volatility.
Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility including bank notes, lines of credit, commercial
paper, and certain adjustable rate long-term debt instruments. At December 31,
2002 and 2001, the combined borrowings under these facilities totaled $61.9
million and $104.0 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2002 and 2001, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $0.9 million and $0.7 million, respectively.
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 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. Market risk is the adverse effect on the value of a financial instrument
that results from a change in commodity prices or interest rates. The Company
attempts to manage exposure to market risk associated with commodity contracts
and interest rates by establishing parameters and monitoring those 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. The
Company manages credit risk associated with its receivables by continually
reviewing creditworthiness and requests cash deposits or refunds cash deposits
based on that review.
Although the Company's operations are exposed to limited commodity price risk,
volatile natural gas prices can result in higher working capital
requirements; increased expenses including unrecoverable interest costs,
uncollectible accounts expense, and unaccounted for gas; and some level of price
sensitive reduction in volumes sold.
ITEM 8. Financial Statements and Supplementary Data
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Southern Indiana Gas and Electric Company (SIGECO) is
responsible for the preparation of the financial statements and the related
financial data contained in this report. The financial statements are prepared
in conformity with accounting principles generally accepted in the United States
and follow accounting policies and principles applicable to regulated public
utilities.
The integrity and objectivity of the data in this report, including required
estimates and judgments, is the responsibility of management. Management
maintains a system of internal control and utilizes an internal auditing program
to provide reasonable assurance of compliance with Company policies and
procedures and the safeguard of assets.
The board of directors of Vectren Corporation (Vectren), the parent company of
SIGECO, pursues its responsibility for these financial statements through its
audit committee, which meets periodically with management, the internal auditors
and the independent auditors, to assure that each is carrying out its
responsibilities. Both the internal auditors and the independent auditors meet
with the audit committee of Vectren's board of directors, with and without
management representatives present, to discuss the scope and results of their
audits, their comments on the adequacy of internal accounting control and the
quality of financial reporting.
/S/ Niel C. Ellerbrook
Niel C. Ellerbrook
Chairman & Chief Executive Officer
February 26, 2003
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of Southern Indiana Gas and Electric
Company:
We have audited the accompanying balance sheets of Southern Indiana Gas and
Electric Company as of December 31, 2002 and 2001, and the related statements of
income, common shareholder's equity and cash flows for each of the three years
in the period ended December 31, 2002. Our audits also included the financial
statement schedule listed in the Table of Contents at Item 15. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Southern Indiana Gas and Electric Company as
of December 31, 2002 and 2001, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As discussed in Note 12, effective, January 1, 2001, the Company adopted SFAS
133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
As discussed in Note 3, the accompanying 2001 and 2000 financial statements have
been restated.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 26, 2003
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
- -------------------------------------------------------------------------------------------
December 31, December 31,
2002 2001
- --------------------------------------------------- ------------- -------------
ASSETS (As Restated,
See Note 3)
Utility Plant
Original cost $ 1,526,094 $ 1,456,805
Less: Accumulated depreciation & amortization 728,768 690,344
- -------------------------------------------------------------------------------------------
Net utility plant 797,326 766,461
- -------------------------------------------------------------------------------------------
Current Assets
Cash & cash equivalents 2,145 1,556
Accounts receivable-less reserves of $3,662 &
$3,188, respectively 50,454 41,811
Receivables from other Vectren companies 18,015 19,625
Accrued unbilled revenues 33,027 17,013
Inventories 39,653 37,633
Recoverable fuel & natural gas costs 9,615 22,206
Prepayments & other current assets 5,926 6,238
- -------------------------------------------------------------------------------------------
Total current assets 158,835 146,082
- -------------------------------------------------------------------------------------------
Investments in unconsolidated affiliates 150 160
Other investments 10,019 9,242
Non-utility property-net 3,568 4,386
Goodwill-net 5,557 5,557
Regulatory assets 49,859 47,465
Other assets 344 539
- -------------------------------------------------------------------------------------------
TOTAL ASSETS $ 1,025,658 $ 979,892
===========================================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
- --------------------------------------------------------------------------------------------
December 31, December 31,
2002 2001
- ---------------------------------------------------- ------------ -------------
LIABILITIES & SHAREHOLDER'S EQUITY (As Restated,
See Note 3)
Capitalization
Common shareholder's equity
Common stock (no par value) $ 103,258 $ 78,258
Retained earnings 270,181 255,942
- --------------------------------------------------------------------------------------------
Total common shareholder's equity 373,439 334,200
- --------------------------------------------------------------------------------------------
Cumulative redeemable preferred stock 344 460
Long-term debt-net of current maturities & debt
subject to tender 264,238 291,702
Long-term debt due to VUHI 86,574 49,460
- --------------------------------------------------------------------------------------------
Total capitalization 724,595 675,822
- --------------------------------------------------------------------------------------------
Commitments & Contingencies (Notes 4-6)
Current Liabilities
Accounts payable 25,215 27,293
Accounts payable to affiliated companies 10,013 -
Payables to other Vectren companies 15,211 9,924
Accrued liabilities 30,713 30,677
Short-term borrowings - 874
Short-term borrowings due to VUHI 39,419 80,664
Long-term debt subject to tender 26,640 -
Current maturities of long-term debt 1,000 -
- --------------------------------------------------------------------------------------------
Total current liabilities 148,211 149,432
- --------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 112,004 115,523
Deferred credits & other liabilities 40,848 39,115
- --------------------------------------------------------------------------------------------
Total deferred income taxes & other liabilities 152,852 154,638
- --------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 1,025,658 $ 979,892
============================================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(In thousands)
Year Ended December 31,
- -------------------------------------------------------------------------------
2002 2001 2000
- ------------------------------------------------------------------------------
OPERATING REVENUES (As Restated, See Note 3)
-----------------------
Electric revenues $608,116 $381,233 $334,428
Gas revenues 85,461 98,580 109,142
- -----------------------------------------------------------------------------
Total operating revenues 693,577 479,813 443,570
- -----------------------------------------------------------------------------
COST OF OPERATING REVENUES
Fuel for electric generation 81,619 74,401 75,699
Purchased electric energy 296,267 86,928 36,394
Cost of gas sold 53,100 72,713 78,903
- -----------------------------------------------------------------------------
Total cost of operating revenues 430,986 234,042 190,996
- -----------------------------------------------------------------------------
TOTAL OPERATING MARGIN 262,591 245,771 252,574
OPERATING EXPENSES
Other operating 97,362 104,535 102,002
Merger & integration costs - 588 14,072
Restructuring costs - 5,825 -
Depreciation & amortization 45,098 43,287 43,214
Income taxes 30,637 21,648 24,425
Taxes other than income taxes 11,760 13,090 13,259
- -----------------------------------------------------------------------------
Total operating expenses 184,857 188,973 196,972
- -----------------------------------------------------------------------------
OPERATING INCOME 77,734 56,798 55,602
Other income - net 4,794 5,629 4,674
Interest expense 23,168 20,924 19,893
- -----------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 59,360 41,503 40,383
- -----------------------------------------------------------------------------
Cumulative effect of change in accounting
princIple-net of tax - 1,107 -
- -----------------------------------------------------------------------------
NET INCOME 59,360 42,610 40,383
Preferred stock dividends 33 758 1,017
Loss on extinguishment of preferred stock - 1,170 -
- -----------------------------------------------------------------------------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 59,327 $ 40,682 $ 39,366
=============================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
- ----------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES (As Restated, See Note 3)
------------------------
Net Income $ 59,360 $ 42,610 $ 40,383
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 45,098 43,287 43,214
Deferred income taxes & investment tax credits (6,461) 467 (8,613)
Net unrealized gain on derivative instruments,
including cumulative effect of change in
accounting principle 3,585 8,935 -
Other non-cash charges- net 3,167 864 2,579
Changes in working capital accounts:
Accounts receivable, including to Vectren
companies & accrued unbilled revenue (24,950) 19,633 (38,752)
Inventories (2,020) (6,578) 10,404
Recoverable fuel & natural gas costs 12,591 6,497 (23,118)
Prepayments & other current assets (5,419) (12,054) 4,994
Accounts payable, including to Vectren companies
& affiliated companies 34,332 (40,682) 43,011
Accrued liabilities (345) (18,784) 8,571
Other noncurrent assets & liabilities (3,134) 7 (16,352)
- ----------------------------------------------------------------------------------------------
Net cash flows from operating activities 115,804 44,202 66,321
- ----------------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt due to VUHI 37,114 49,460 -
Additional capital contribution 25,000 - -
Requirements for:
Dividends on common stock (45,088) (38,909) (28,639)
Redemption of preferred stock (116) (17,676) (2,000)
Dividends on preferred stock (33) (758) (1,017)
Net change in short-term borrowings, including
due to VUHI (42,119) 41,384 17,274
Proceeds from other financing activities - - 1,974
- ----------------------------------------------------------------------------------------------
Net cash flows (required for) from
financing activities (25,242) 33,501 (12,408)
- ----------------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from sale of investments and assets 1,400 - -
Requirements for:
Capital expenditures (89,747) (77,760) (51,119)
Other investments (1,626) - (1,630)
- ----------------------------------------------------------------------------------------------
Net cash flows (required for) investing
activities (89,973) (77,760) (52,749)
- --------------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 589 (57) 1,164
Cash & cash equivalents at beginning of period 1,556 1,613 449
- ----------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 2,145 $ 1,556 $ 1,613
==============================================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(In thousands)
Common Retained
Stock Earnings Total
- --------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Reported $ 78,258 $ 256,312 $ 334,570
Restatement adjustment - 2,923 2,923
- --------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Restated 78,258 259,235 337,493
Net income & comprehensive income, As Restated 40,383 40,383
Common stock dividends (28,639) (28,639)
Preferred stock dividends (1,017) (1,017)
Distribution of assets to parent (9,144) (9,144)
Other 317 317
- --------------------------------------------------------------------------------------------
Balance at December 31, 2000, As Restated 78,258 261,135 339,393
Net income & comprehensive income, As Restated 42,610 42,610
Common stock dividends (38,909) (38,909)
Preferred stock dividends (758) (758)
Distribution of assets to parent (6,966) (6,966)
Loss on redemption of preferred stock (1,170) (1,170)
- ---------------------------------------------------------------------------------------------
Balance at December 31, 2001, As Restated 78,258 255,942 334,200
Net income & comprehensive income 59,360 59,360
Common stock:
Additional capital contribution 25,000 25,000
Dividends (45,088) (45,088)
Preferred stock dividends (33) (33)
- ---------------------------------------------------------------------------------------------
Balance at December 31, 2002 $ 103,258 $ 270,181 $ 373,439
============================================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO THE FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Overview
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. Summary of Significant Accounting Policies
A. Cash and Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents. Cash paid during the
periods reported for interest and income taxes follows:
Year Ended December 31,
- ------------------------------------------------------------
In thousands 2002 2001 2000
- ------------------------------------------------------------
Cash paid during the year for
Interest (net of amount
capitalized) $ 20,598 $18,992 $17,506
Income taxes 41,441 47,960 21,627
- ------------------------------------------------------------
B. Inventories
Inventories consist of the following:
At December 31,
- ----------------------------------------------------------------------------
In thousands 2002 2001
- ----------------------------------------------------------------------------
Materials & supplies $ 15,836 $16,304
Gas in storage - at LIFO cost 12,880 10,542
Fuel (coal and oil) for electric
generation 10,030 9,513
Emission allowances 907 1,274
- ----------------------------------------------------------------------------
Total inventories $ 39,653 $37,633
============================================================================
Based on the average cost of gas purchased during December, the cost of
replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31,
2002 and 2001 by approximately $19.0 million and $15.8 million, respectively.
All other inventories are carried at average cost.
C. Utility Plant and Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation of
utility plant is provided using the straight-line method over the estimated
service lives of the depreciable assets. The original cost of utility plant,
together with depreciation rates expressed as a percentage of original cost,
follows:
At & For the Year Ended December 31,
- -----------------------------------------------------------------------------------------------
In thousands 2002 2001
- -------------------------------- ------------------------------ -----------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of Percent of
Original Cost Original Cost Original Cost Original Cost
- -----------------------------------------------------------------------------------------------
Electric utility plant $1,211,036 2.9% $ 1,148,887 3.3%
Gas utility plant 164,510 3.3% 155,051 3.0%
Common utility plant 41,621 2.6% 41,197 2.6%
Construction work in progress 108,927 - 111,670 -
- -----------------------------------------------------------------------------------------------
Total original cost $1,526,094 $ 1,456,805
===============================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction
purposes and is charged to construction work in progress during the construction
period and is included in other - net in the Statements of Income. The total
AFUDC capitalized into utility plant and the portion of which was computed on
borrowed and equity funds for all periods reported follows:
Year Ended December 31,
- -------------------------------------------------------------------------------
In thousands 2002 2001 2000
- -------------------------------------------------------------------------------
AFUDC - equity funds $ 1,746 $ 1,653 $ 2,051
AFUDC - borrowed funds 1,933 1,371 1,817
- -------------------------------------------------------------------------------
Total AFUDC capitalized $ 3,679 $ 3,024 $ 3,868
===============================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced or
removed, the cost of such property is credited to utility plant, and such cost,
together with the cost of removal less salvage, is charged to accumulated
depreciation.
D. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the
carrying amount may be impaired. This review is performed in accordance with
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144), which the Company adopted as required on January 1, 2002. SFAS 144
establishes one accounting model for all impaired long-lived assets and
long-lived assets to be disposed of by sale or otherwise. SFAS 144 replaced
authoritative guidance in SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and
certain aspects of APB Opinion No. 30, "Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
144 retains the framework of SFAS 121 and requires the evaluation for impairment
involve the comparison of an asset's carrying value to the estimated future cash
flows the asset is expected to generate over its remaining life. If this
evaluation were to conclude that the carrying value of the asset is impaired, an
impairment charge would be recorded based on the difference between the asset's
carrying amount and its fair value (less costs to sell for assets to be disposed
of by sale) as a charge to operations or discontinued operations.
E. Goodwill
Goodwill arising from past business combinations is accounted for in accordance
with SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The
Company adopted 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 was not included as an allowable
cost for rate-making purposes ceased upon SFAS 142's adoption.
Goodwill is to be tested for impairment at a reporting unit level at least
annually. The impairment review consists 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 is recognized in operations.
Prior to the adoption of SFAS 142, the Company amortized goodwill on a
straight-line basis over 40 years. SFAS 142 required an initial impairment
review of all goodwill within six months of the adoption date. 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."
As required by SFAS 142, amortization of goodwill ceased on January 1, 2002.
Amortization approximated $0.2 million ($0.1 million after tax) in both 2001 and
2000. The Company's goodwill is included in the Gas Utility Services operating
segment. Initial impairment reviews to be performed within six months of
adoption of SFAS 142 were completed and resulted in no impairment. The
impairment test is performed at the beginning of each year.
F. Regulation
SFAS 71
Retail public utility operations affecting Indiana customers are subject to
regulation by the IURC. The Company's accounting policies give recognition to
the rate-making and accounting practices of this agency and to accounting
principles generally accepted in the United States, including the provisions of
SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS
71). Regulatory assets represent probable future revenues associated with
certain incurred costs, which will be recovered from customers through the
rate-making process. Regulatory liabilities represent probable future reductions
in revenues associated with amounts that are to be credited to customers through
the rate-making process.
The Company assesses the recoverability of costs recognized as regulatory assets
and the ability to continue to account for its activities based on the criteria
set forth in SFAS 71. Based on current regulation, the Company believes such
accounting is appropriate. If all or part of the Company's operations cease to
meet the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulatory assets. Regulatory assets consist of the following:
At December 31,
- ---------------------------------------------------------
In thousands 2002 2001
- ---------------------------------------------------------
Demand side management programs $32,062 $31,667
Regulatory income tax asset 7,334 8,245
Unamortized debt discount & expenses 3,011 3,155
Other 7,452 4,398
- ---------------------------------------------------------
Total regulatory assets $49,859 $47,465
=========================================================
As of December 31, 2002, regulatory assets totaling $17.3 million are reflected
in rates charged to customers, of which $6.9 million is earning a return. The
remaining $32.6 million, which is not yet included in rates, represents
primarily electric demand side management (DSM) costs incurred after 1993. The
Company has rate orders for all deferred costs not yet in rates and therefore
believes that future recovery is probable. At December 31, 2002, the weighted
average recovery period of regulatory assets, other than those arising from
book-tax basis differences, included in rates is 8.3 years. Regulatory income
tax assets are recovered as deferred tax assets and liabilities discussed in
Note 5 become payable or receivable.
Refundable or Recoverable Gas Costs, Fuel for Electric Production and Purchased
Power
All metered gas rates contain a gas cost adjustment clause that allows the
Company to charge for changes in the cost of purchased gas. Metered electric
rates typically contain a fuel adjustment clause that allows for adjustment in
charges for electric energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. Metered electric rates also allow recovery,
through a quarterly rate adjustment mechanism, for the margin on electric sales
lost due to the implementation of demand side management programs.
The Company records any under-or-over-recovery resulting from gas and fuel
adjustment clauses each month in revenues. A corresponding asset or liability is
recorded until the under-or-over-recovery is billed or refunded to utility
customers. The cost of gas sold is charged to operating expense as delivered to
customers, and the cost of fuel for electric generation is charged to operating
expense when consumed.
G. Revenues
Revenues are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
H. Excise and Gross Receipts Taxes
Excise taxes and a portion of gross receipts taxes are included in rates charged
to customers. Accordingly, the Company records these taxes received as a
component of operating revenues. Excise and gross receipts taxes paid are
recorded as a component of taxes other than income taxes.
I. Earnings Per Share
Earnings per share are not presented as the Company's common stock is wholly
owned by Vectren Utility Holdings, Inc.
J. Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
3. Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $1.8 million after tax, decreased
previously reported 2000 results by approximately $0.7 million after tax, and
increased retained earnings as of January 1, 2000 by $2.9 million after tax.
Adjustments were also made to previously reported 2002 quarterly results. In
addition to adjustments affecting previously reported net income, other
reclassifications were made to the previously reported 2001 and 2000 results to
conform with the 2002 presentation.
Previously Reported 2001 and 2000 Net Income Adjustments
The Company determined that $3.3 million ($2.0 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.
The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $1.5 million ($0.9 million after tax).
The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.
Originally reflected in 2001, the Company also reflected a correction of the
year 2000 overstatement of electric revenue totaling $2.4 million ($1.5 million
after tax), now reflected in 2000 as discussed below. The Company identified
other reconciliation errors and other errors related to the recording of
estimates that were not significant, either individually or in the aggregate. As
a result of these additional items, 2001 earnings were reduced by $0.6 million
($0.4 million after tax).
The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $1.3 million ($0.8 million after tax). The impact of
the restatement of results for the year ended 2000 is a reduction to pre-tax
income and net income of $1.1 million and $0.7 million, respectively.
Previously Reported 2002 Quarterly Net Income Adjustments
As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, 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. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $0.2 million and $0.1 million after tax,
respectively. The cumulative impact from these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$3.3 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000 resulting in a cumulative net increase of $2.9
million in retained earnings as of January 1, 2000.
Other Balance Sheet Adjustments
Certain reclassifications were made to reflect separate Company current and
deferred income taxes are included in Vectren's consolidated tax position. These
reclassifications are the principal adjustments to intercompany receivables and
payables as well as prepayments and other current assets and deferred income
taxes. The Company also reclassified all previously recorded goodwill not
included in rates to goodwill on the balance sheet. This adjustment resulted in
a $5.6 million decrease in other assets and a corresponding increase in
goodwill.
The Company has restated its financial statements to give effect to the matters
discussed above. Following is a summary of the significant effects of the
restatement on previously reported financial position and results of operations.
The effects of the restatement on 2001 quarterly results and on 2002 previously
reported quarterly information, is discussed in Note 17. Note 17 is unaudited.
The effects on the income statement for the year ending December 31, 2001 ( in
thousands) follow:
- ------------------------------------------------------------------------------------------
As Reported Adjustments As Restated
- ------------------------------------------------------------------------------------------
OPERATING REVENUES
Electric revenues $ 378,867 $ 2,366 $ 381,233
Gas revenues 101,117 (2,537) 98,580
- ------------------------------------------------------------------------------------------
Total operating revenues 479,984 (171) 479,813
- ------------------------------------------------------------------------------------------
COST OF OPERATING REVENUES
Fuel for electric generation 74,402 (1) 74,401
Purchased electric energy 91,666 (4,738) 86,928
Cost of gas sold 72,829 (116) 72,713
- ------------------------------------------------------------------------------------------
Total cost of operating revenues 238,897 (4,855) 234,042
- ------------------------------------------------------------------------------------------
TOTAL OPERATING MARGIN 241,087 4,684 245,771
OPERATING EXPENSES
Other operating 101,868 2,667 104,535
Merger & integration costs 588 - 588
Restructuring costs 5,825 - 5,825
Depreciation & amortization 43,287 - 43,287
Income taxes 20,762 886 21,648
Taxes other than income taxes 13,090 - 13,090
- ------------------------------------------------------------------------------------------
Total operating expenses 185,420 3,553 188,973
- ------------------------------------------------------------------------------------------
OPERATING INCOME 55,667 1,131 56,798
Other income - net 5,778 (149) 5,629
Interest expense 20,993 (69) 20,924
- ------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 40,452 1,051 41,503
- ------------------------------------------------------------------------------------------
Cumulative effect of change in accounting
principle-net of tax 3,938 (2,831) 1,107
- ------------------------------------------------------------------------------------------
NET INCOME 44,390 (1,780) 42,610
Preferred stock dividends 758 - 758
Loss on extinguishment of preferred stock 1,170 - 1,170
- ------------------------------------------------------------------------------------------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 42,462 $ (1,780) $ 40,682
==========================================================================================
The effects on the income statement for the year ending December 31, 2000 (in
thousands) follow:
- ----------------------------------------------------------------------------------------
As Reported Adjustments As Restated
- ----------------------------------------------------------------------------------------
OPERATING REVENUES
Electric revenues $ 336,409 $ (1,981) $ 334,428
Gas revenues 109,284 (142) 109,142
- ----------------------------------------------------------------------------------------
Total operating revenues 445,693 (2,123) 443,570
- ----------------------------------------------------------------------------------------
COST OF OPERATING REVENUES
Fuel for electric generation 75,699 - 75,699
Purchased electric energy 36,394 - 36,394
Cost of gas sold 78,903 - 78,903
- ----------------------------------------------------------------------------------------
Total cost of operating revenues 190,996 - 190,996
- ----------------------------------------------------------------------------------------
TOTAL OPERATING MARGIN 254,697 (2,123) 252,574
OPERATING EXPENSES
Other operating 103,053 (1,051) 102,002
Merger & integration costs 14,072 - 14,072
Depreciation & amortization 43,214 - 43,214
Income taxes 24,832 (407) 24,425
Taxes other than income taxes 13,258 1 13,259
- ----------------------------------------------------------------------------------------
Total operating expenses 198,429 (1,457) 196,972
- ----------------------------------------------------------------------------------------
OPERATING INCOME 56,268 (666) 55,602
Other income - net 4,674 - 4,674
Interest expense 19,894 (1) 19,893
- ----------------------------------------------------------------------------------------
NET INCOME 41,048 (665) 40,383
Preferred stock dividends 1,017 - 1,017
- ----------------------------------------------------------------------------------------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 40,031 $ (665) $ 39,366
========================================================================================
The effects on the balance sheet as of December 31, 2001 (in thousands) follow:
- ---------------------------------------------------------------------------------------------------
ASSETS As Reported Adjustments As Restated
--------------------------------------
Utility Plant
Original cost $ 1,455,826 $ 979 $1,456,805
Less: Accumulated depreciation & amortization 690,344 - 690,344
- ---------------------------------------------------------------------------------------------------
Net utility plant 765,482 979 766,461
- ---------------------------------------------------------------------------------------------------
Current Assets
Cash & cash equivalents 2,451 (895) 1,556
Accounts receivable-less reserves 41,227 584 41,811
Receivables from other Vectren companies - 19,625 19,625
Accrued unbilled revenues 17,013 - 17,013
Inventories 38,322 (689) 37,633
Recoverable fuel & natural gas costs 22,132 74 22,206
Prepayments & other current assets 24,118 (17,880) 6,238
- ---------------------------------------------------------------------------------------------------
Total current assets 145,263 819 146,082
- ---------------------------------------------------------------------------------------------------
Investments in unconsolidated affiliates 160 - 160
Other investments 9,254 (12) 9,242
Non-utility property-net 4,386 - 4,386
Goodwill-net - 5,557 5,557
Regulatory assets 41,525 5,940 47,465
Other assets 7,152 (6,613) 539
- ---------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 973,222 $ 6,670 $ 979,892
===================================================================================================
LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 78,258 $ - $ 78,258
Retained earnings 255,464 478 255,942
Accumulated other comprehensive income 94 (94) -
- ---------------------------------------------------------------------------------------------------
Total common shareholder's equity 333,816 384 334,200
- ---------------------------------------------------------------------------------------------------
Cumulative redeemable preferred stock of subsidiary 460 - 460
Long-term debt-net of current maturities 291,702 - 291,702
Long-term debt due to VUHI 49,460 - 49,460
- ---------------------------------------------------------------------------------------------------
Total capitalization 675,438 384 675,822
- ---------------------------------------------------------------------------------------------------
Current Liabilities
Accounts payable 27,135 158 27,293
Payables to other Vectren companies 3,390 6,534 9,924
Accrued liabilities 33,545 (2,868) 30,677
Short-term borrowings 874 - 874
Short-term borrowings due to VUHI 80,664 - 80,664
- ---------------------------------------------------------------------------------------------------
Total current liabilities 145,608 3,824 149,432
- ---------------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 112,746 2,777 115,523
Deferred credits & other liabilities 39,430 (315) 39,115
- ---------------------------------------------------------------------------------------------------
Total deferred income taxes & other liabilities 152,176 2,462 154,638
- ---------------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 973,222 $ 6,670 $ 979,892
===================================================================================================
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, and 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. In addition, Vectren negotiates service and
construction contracts on behalf of its utilities to obtain those services at
less cost than the utility may otherwise be able to obtain on its own. For the
year ended December 31, 2002, 2001, and 2000, amounts billed by other wholly
owned subsidiaries of Vectren to the Company were $45.2 million, $43.5 million,
and $30.2 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 year ended December 31, 2002, 2001, and
2000 were $62.1 million, $58.4 million and $25.7 million, respectively.
Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that
require accounting as described in SFAS No. 87 "Employers' Accounting for
Pensions and SFAS No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions," respectively. Subsequent to the merger forming Vectren, an
allocation of expense is determined by Vectren's actuaries, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date. These costs are directly charged to individual
subsidiaries. Other components of costs (such as interest cost from prior
service and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Plan assets nor the FAS 87/106
liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Further, Vectren
satisfies the future funding requirements of plans and the payment of benefits
from general corporate assets. This allocation methodology is consistent with
"multiemployer" benefit accounting as described in SFAS 87 and 106.
For the years ended December 31, 2002 and 2001 pension expense totaling $2.6
million and $2.3 million, respectively, was directly charged by Vectren to the
Company. For the years ended December 31, 2002 and 2001 other benefit expenses
totaling $0.6 million and $0.5 million, respectively, were directly charged by
Vectren to the Company. In 2000, the Company recognized $3.5 million in charges
for participation in Vectren benefit plans. As of December 31, 2002 and 2001,
$24.1 million and $23.0 million is included in other non-current liabilities and
represents expense directly charged to the Company that is yet to be funded to
Vectren.
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.
See Note 7 regarding long and short-term intercompany borrowing arrangements.
Guarantees of Parent Company Debt
Vectren's three operating utility companies, SIGECO, VEDO, and Indiana Gas are
guarantors of VUHI's $350.0 million commercial paper program, of which
approximately $239.1 million is outstanding at December 31, 2002 and VUHI's
$350.0 million unsecured senior notes outstanding at December 31, 2002. VUHI has
no independent assets or operations, the guarantees are full and unconditional
and joint and several, and VUHI has no subsidiaries other than the subsidiary
guarantors.
Stock Based Incentive Plans
The Company does not have stock-based compensation plans separate from Vectren.
An insignificant number of the Company's employees participate in Vectren's
stock-based compensation plans.
Contribution of Assets
The Company contributed computer software and hardware with a book value of
approximately $6.2 million and $9.1 million to a wholly owned subsidiary of
Vectren (Vectren Resources, LLC) as a special dividend in 2001 and 2000,
respectively. Additionally in 2001, the Company contributed certain assets
totaling $0.8 million to VUHI. These contributions of assets are reflected as a
reduction of common shareholder's equity and resulted in no gain or loss and are
omitted from the Statement of Cash Flows.
5. Income Taxes
Vectren and subsidiary companies file a consolidated federal income tax return.
For financial reporting purposes, SIGECO's current and deferred tax expense is
computed on a separate company basis. The components of income tax expense and
utilization of investment tax credits follows:
Year Ended December 31,
- ------------------------------------------------------------------------------------------
In thousands 2002 2001 2000
- ------------------------------------------------------------------------------------------
Current:
Federal $ 30,300 $ 18,403 $29,788
State 5,766 2,999 3,274
- ------------------------------------------------------------------------------------------
Total current taxes 36,066 21,402 33,062
- ------------------------------------------------------------------------------------------
Deferred:
Federal (1,199) 1,640 (7,008)
State (3,916) 180 (177)
- ------------------------------------------------------------------------------------------
Total deferred taxes (5,115) 1,820 (7,185)
- ------------------------------------------------------------------------------------------
Amortization of investment tax credits (1,346) (1,353) (1,428)
- ------------------------------------------------------------------------------------------
Total income tax expense 29,605 21,869 24,449
Less: Income tax expense included in other-net (1,032) 221 24
- ------------------------------------------------------------------------------------------
Income tax expense in operating income $ 30,637 $ 21,648 $24,425
==========================================================================================
A reconciliation of the Federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- ------------------------------------------------------------------------------------
2002 2001 2000
- ------------------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 % 35.0 %
State & local taxes, net of federal benefit 2.2 2.9 3.5
Nondeductible merger costs - - 3.6
Amortization of investment tax credit (1.5) (2.2) (2.2)
All other-net (2.4) (0.8) (1.6)
- ------------------------------------------------------------------------------------
Effective tax rate 33.3 % 34.9 % 38.3 %
====================================================================================
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates.
Significant components of the net deferred tax liability follows:
At December 31,
- ------------------------------------------------------------------------------------------
In thousands 2002 2001
- ------------------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences $ 119,739 $ 117,549
Regulatory assets recoverable through future rates 23,352 24,647
Regulatory liabilities to be settled through future rates (16,018) (16,403)
Employee benefit obligations (13,585) (9,215)
Other - net (1,484) (1,055)
- ------------------------------------------------------------------------------------------
Net noncurrent deferred tax liability 112,004 115,523
- ------------------------------------------------------------------------------------------
Current deferred tax liabilities:
Deferred fuel costs, net 4,680 7,207
- ------------------------------------------------------------------------------------------
Net current deferred tax liability 4,680 7,207
- ------------------------------------------------------------------------------------------
Net deferred tax liability $ 116,684 $ 122,730
==========================================================================================
At December 31, 2002 and 2001, investment tax credits totaling $13.2 million and
$14.6 million, respectively, are included in deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments.
6. Transactions with Vectren Affiliates
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 business is
optimizing the gas portfolios of utilities and providing services to large end
use customers. Vectren continues to account for its investment in ProLiance
using the equity method of accounting. Purchases from ProLiance for resale and
for injections into storage for the years ended December 31, 2002 totaled $25.6
million. Amounts charged by ProLiance for gas supply services are established by
supply agreements. Amounts owed to ProLiance approximated $10.0 million at
December 31, 2002 and are included in accounts payable to affiliated companies
in the Balance Sheets. Prior to 2002, the Company paid suppliers directly for
its natural gas purchases.
7. Borrowing Arrangements
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term are as follows.
At December 31,
- -------------------------------------------------------------------------------------------
In thousands 2002 2001
- -------------------------------------------------------------------------------------------
Fixed Rate Senior Unsecured Note Payable to VUHI:
2011, 6.625% $ 86,574 $ 49,460
- -------------------------------------------------------------------------------------------
Total long-term debt to VUHI $ 86,574 $ 49,460
===========================================================================================
First Mortgage Bonds to Third Parties:
Fixed-Rate:
2003, 1978 Series B, 6.25%, tax exempt $ 1,000 $ 1,000
2016, 1986 Series, 8.875% 13,000 13,000
2023, 1993 Series, 7.60% 45,000 45,000
2023, 1993 Series B, 6.00% 22,800 22,800
2025, 1993 Series, 7.625% 20,000 20,000
2029, 1999 Senior Notes, 6.72% 80,000 80,000
Adjustable Rate:
2015, 1985 Pollution Control Series A, presently 4.30%,
tax exempt, next rate adjustment: 2004. 9,975 9,975
2025, 1998 Pollution Control Series A, presently 4.75%,
tax exempt, next rate adjustment: 2006. 31,500 31,500
2024, 2000 Environmental Improvement Series A,
presently 2.05%, tax exempt, adjusts every 35 days,
weighted average for year: 3.13%. 22,500 22,500
- -------------------------------------------------------------------------------------------
Total First Mortgage Bonds 245,775 245,775
- -------------------------------------------------------------------------------------------
Adjustable Rate Senior Unsecured Bonds to Third Parties:
2020, 1998 Pollution Control Series B, presently 4.40%,
tax exempt, next rate adjustment: 2003. 4,640 4,640
2030, 1998 Pollution Control Series B, presently 4.40%,
tax exempt, next rate adjustment: 2003. 22,000 22,000
2030, 1998 Pollution Control Series C, presently 5.00%,
tax exempt, next rate adjustment: 2006. 22,200 22,200
- -------------------------------------------------------------------------------------------
Total Adjustable Rate Senior Unsecured Bonds 48,840 48,840
- -------------------------------------------------------------------------------------------
Total long-term debt outstanding 294,615 294,615
Less: Debt subject to tender 26,640 -
Current maturies of long-term debt 1,000 -
Unamortized debt premium & discount, net 2,737 2,913
- -------------------------------------------------------------------------------------------
Total long-term debt-net $ 264,238 $ 291,702
===========================================================================================
Issuance Payable to VUHI
In 2001, the Company issued a note payable to VUHI for $49.5 million, and in
2002 issued a note payable to VUHI for $37.1 million. These two notes comprise
the $86.6 million of long-term debt due to VUHI at December 31, 2002.
The terms of these notes are identical to the terms of notes issued by VUHI in
December 2001 through a public offering (December Notes). The December Notes
have an aggregate principal amount of $250.0 million and an interest rate of
6.625%, priced at 99.302% to yield 6.69% to maturity. The December Notes have no
sinking fund requirements, and interest payments are due semi-annually. The
December Notes are due December 2011, but 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 of the notes to be redeemed 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.
Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow holders to
put debt back to the Company at face value or the Company to call debt at face
value or at a premium. Long-term debt subject to tender during the years
following 2002 (in millions) is $26.6 in 2003, $10.0 in 2004, zero in 2005,
$53.7 in 2006, zero in 2007, and $80.0 thereafter.
Long-Term Debt Sinking Fund Requirements and Maturities
The annual sinking fund requirement of the Company's first mortgage bonds is 1%
of the greatest amount of bonds outstanding under the Mortgage Indenture. This
requirement may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in the Mortgage
Indenture. The Company intends to meet the 2002 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2002 is excluded from
current liabilities in the Balance Sheets. At December 31, 2002, $342.8 million
of the Company's utility plant remained unfunded under the Company's Mortgage
Indenture.
Maturities and sinking fund requirements on long-term debt subject to mandatory
redemption during the five years following 2002 are $1.0 million in 2003, zero
in 2004, zero in 2005, zero in 2006, and zero in 2007.
Short-Term Borrowings
SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its
short-term working capital needs. Borrowings outstanding at December 31, 2002
were $39.4 million. The intercompany credit line totals $150.0 million, but is
limited to VUHI's available capacity ($85.9 million of additional capacity at
December 31, 2002) and is subject to the same terms and conditions as VUHI's
commercial paper program. At December 31, 2002, the Company has approximately $5
million of short-term borrowing capacity with third parties to supplement its
intercompany borrowing arrangements, of which all is available.
Year ended December 31,
- -------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------
Weighted average total outstanding during
the year payable to VUHI (in thousands) $ 68,034 $ 34,791 -
Weighted average total outstanding during
the year payable to third parties (in thousands) $ 1,875 $ 12,930 $ 20,026
Weighted average interest rates during the year:
VUHI 2.03% 5.24% N/A
Bank loans 2.56% 5.77% 6.24%
Covenants
Both long-term and short-term borrowing arrangements contain customary default
provisions, restrictions on liens, sale leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2002, the Company was in
compliance with all financial covenants.
8. Cumulative Preferred Stock
Redemption of Preferred Stock
Nonredeemable preferred stock contains call options that were exercised during
September 2001 for a total redemption price of $9.8 million. The 4.80%, $100 par
value preferred stock was redeemed at its stated call price of $110 per share,
plus accrued and unpaid dividends totaling $1.35 per share. The 4.75%, $100 par
value preferred stock was redeemed at its stated call price of $101 per share,
plus accrued and unpaid dividends totaling $0.97 per share. Prior to the
redemptions and as of December 31, 2000, there were 85,519 shares of the 4.80%
Series outstanding and 3,000 shares of the 4.75% Series outstanding.
In September 2001, the 6.50%, $100 par value preferred stock was redeemed for a
total redemption price of $7.9 million at $104.23 per share, plus $0.73 per
share in accrued and unpaid dividends. Prior to the redemption and as of
December 31, 2000, there were 75,000 shares outstanding.
The loss on redemption of $1.2 million is reflected as a reduction to reconcile
net income to net income applicable to common shareholder. The total redemption
price was $17.7 million.
Redeemable, Special
This series of redeemable preferred stock has a dividend rate of 8.50% and in
the event of involuntary liquidation the amount payable is $100 per share, plus
accrued dividends. This Series may be redeemed at $100 per share, plus accrued
dividends on any of its dividend payment dates and is also callable at the
Company's option at a rate of 1,160 shares per year. As of December 31, 2002 and
2001, there were 3,437 shares and 4,597 shares outstanding, respectively.
9. Commitments and Contingencies
Commitments
Firm commitments to purchase natural gas for years following December 31, 2002
totaled (in millions) $18.4 in 2003, $6.1 in 2004, and $1.2 in 2005.
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 10 regarding the Clean
Air Act.
10. 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.
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. 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 December 31, 2002, $70.0 million has been expended.
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. 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 January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) 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. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
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
complaint. 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 July 14, 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 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 the IDEM's Voluntary
Remediation Program. 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
recently been initiated by the Company to confirm that the sites continue to
pose no such risk.
11. Rate and Regulatory Matters
Gas Costs Proceedings
Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
Vectren's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through commission-approved gas
cost adjustment mechanisms.
In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.
Purchased Power Costs
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
12. Risk Management, Derivatives, and Other Financial Instruments
The Company is exposed to various business 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. The Company's risk management program includes, among other
things, the use of derivatives to mitigate risk.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for its retail customers
due to current Indiana and Ohio regulations, which subject to compliance with
those regulations, allow for recovery of such purchases through natural gas and
fuel cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.
The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts.
The Company's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.
Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. To manage this exposure, the Company may periodically
use derivative financial instruments to reduce earnings fluctuations caused by
interest rate volatility.
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 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. Market risk is the adverse effect on the value of a financial instrument
that results from a change in commodity prices or interest rates. The Company
attempts to manage exposure to market risk associated with commodity contracts
and interest rates by establishing parameters and monitoring those 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. The
Company manages credit risk associated with its receivables by continually
reviewing creditworthiness and requests cash deposits or refunds cash deposits
based on that review.
Although the Company's regulated operations are exposed to limited commodity
price risk, volatile natural gas prices can result in higher working capital
requirements; increased expenses including unrecoverable interest costs,
uncollectible accounts expense, and unaccounted for gas; and some level of price
sensitive reduction in volumes sold.
Accounting for Derivatives and Other Contracts
When a derivative contract that is entered into in the normal course of
operations is probable of physical settlement, that contract is designated and
documented as a normal purchase or normal sale and is exempted from
mark-to-market accounting. Otherwise, derivative contracts are recorded at
market value as current or noncurrent assets or liabilities depending on their
value and on when the contracts are expected to be settled. Unless the contract
is a cash flow hedge that qualifies for hedge accounting treatment or is subject
to SFAS 71, that contract is marked to market through earnings. When hedge
accounting is appropriate, the Company assesses and documents hedging
relationships between its financial instruments, including commodity contracts
and interest rate swaps, and underlying risks as well as the investment's risk
management objectives and anticipated effectiveness. When the hedging
relationship is highly effective, derivatives are designated as hedges. The
market value of the effective portion of the hedge is marked to market in
accumulated other comprehensive income for cash flow hedges. The ineffective
portion of hedging arrangements is marked to market through earnings. Contracts
affected by SFAS 71 are marked to market as a regulatory asset or liability.
Market value is determined using quoted market prices from independent sources.
Non-Firm Wholesale Power Marketing Contracts
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 contracts that expose the Company to
limited market risk and are settled both financially and physically. These
operations do not meet the definition of energy trading activities based upon
the provisions in EITF Issue 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" (EITF 98-10).
Asset optimization sale contracts are reflected in electric utility revenues,
and purchase contracts are reflected in purchased electric energy. Contracts
with counter-parties subject to master netting arrangements are presented net in
the Balance Sheets. Subsequent to the adoption of SFAS 133 as described below,
certain non-firm power marketing contracts that are periodically financially
settled are recorded at market value. Changes in market value, which is a
function of the normal decline in market value as earnings are realized and the
fluctuation in market value resulting from price volatility, are recorded in
purchased electric energy.
Power marketing contracts recorded at market value at December 31, 2002 totaled
$3.5 million of prepayments and other current assets and $4.2 million of accrued
liabilities, compared to $6.1 million of prepayments and other current assets
and $2.8 million of accrued liabilities at December 31, 2001. The change in the
net value of these contracts includes an unrealized loss of $3.6 million in 2002
and an unrealized gain of $1.5 million in 2001, respectively. Including these
unrealized changes in market value, overall margin (revenue net of purchased
power) from non-firm wholesale power marketing operations for the years ended
December 31, 2002 and 2001 was $14.9 million and $19.9 million, respectively.
Prior to the adoption of SFAS 133 and for the year ended December 31, 2000,
margin was $21.1 million.
Other Commodity-Related Operations
Other commodity contracts are generally settled by physical delivery or receipt
and are within the normal operations of the Company. Therefore, these contracts
receive accounting recognition upon settlement. Firm wholesale electric
contracts are recorded in electric utility revenues. Certain contracts that
purchase commodities for operational needs are recorded when settled in other
operating expenses.
Impact of Adoption of SFAS 133
In June 1998, the FASB issued SFAS 133, which required that every derivative
instrument be recorded on the balance sheet as an asset or liability measured at
its market value and that changes in the derivative's market value be recognized
currently in earnings unless specific hedge or regulatory accounting criteria
are met.
SFAS 133, as amended, required that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income, other comprehensive income, or regulatory assets or liabilities,
as appropriate. A change in earnings or other comprehensive income was reported
as a cumulative effect of a change in accounting principle in accordance with
APB Opinion No. 20, "Accounting Changes."
Resulting from the adoption of SFAS 133, certain non-firm wholesale power
marketing contracts that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million net of tax) recorded as a cumulative
effect of accounting change. SFAS 133 did not impact other commodity contracts
because they were normal purchases and sales specifically excluded from the
provisions of SFAS 133.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments follow:
At December 31,
- ---------------------------------------------------------------------------------------
2002 2001
-------------------- --------------------
In thousands Carrying Est. Fair Carrying Est. Fair
Amount Value Amount Value
- ---------------------------------------------------------------------------------------
Long term debt $ 294,615 $313,202 $294,615 $ 289,179
Long term debt due to VUHI 86,574 93,820 49,460 49,460
Short-term borrowings & notes payable - - 874 874
Short-term debt due to VUHI 39,419 39,419 80,664 80,664
- ---------------------------------------------------------------------------------------
Certain methods and assumptions must be used to estimate the fair value of
financial instruments. The fair value of the Company's other financial
instruments was estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to the Company for instruments
with similar characteristics. Because of the maturity dates and variable
interest rates of short-term borrowings, its carrying amount approximates its
fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term
debt are generally recovered in customer rates over the life of the refunding
issue. Accordingly, any reacquisition would not be expected to have a material
effect on the Company's financial position or results of operations.
13. Additional Operational and Balance Sheet Information
Other-net in the Statements of Income consists of the following:
Year ended December 31,
- --------------------------------------------------------------------------
In thousands 2002 2001 2000
- --------------------------------------------------------------------------
AFUDC $3,679 $ 3,024 $ 3,868
Other income 2,394 5,923 1,415
Other expense (1,279) (3,318) (609)
- --------------------------------------------------------------------------
Total other - net $4,794 $ 5,629 $ 4,674
==========================================================================
Accrued liabilities in the Balance Sheets consists of the following:
At December 31,
- -----------------------------------------------------------
In thousands 2002 2001
- -----------------------------------------------------------
Accrued taxes $8,707 $11,833
Deferred income taxes 4,680 7,207
Accrued interest 5,593 5,510
Refunds to customers & customer
deposits 4,576 3,470
Accrued salaries & other 7,157 2,657
- -----------------------------------------------------------
Total accrued liabilities $30,713 $30,677
===========================================================
14. 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. The
following tables provide information about business segments. The Company makes
decisions on finance and dividends at the corporate level.
Year ended December 31,
- --------------------------------------------------------------------------
In thousands 2002 2001 2000
- --------------------------------------------------------------------------
Operating Revenues
Electric Utility Services $ 608,116 $ 381,233 $ 334,428
Gas Utility Services 85,461 98,580 109,142
- --------------------------------------------------------------------------
Total operating revenues $ 693,577 $ 479,813 $ 443,570
==========================================================================
Interest Expense
Electric Utility Services $ 19,723 $ 17,813 $ 18,102
Gas Utility Services 3,445 3,111 1,791
- --------------------------------------------------------------------------
Total interest expense $ 23,168 $ 20,924 $ 19,893
==========================================================================
Year ended December 31,
- --------------------------------------------------------------------------
In thousands 2002 2001 2000
- --------------------------------------------------------------------------
Income Taxes
Electric Utility Services $ 28,508 $ 21,203 $ 23,386
Gas Utility Services 2,129 445 1,039
- --------------------------------------------------------------------------
Total income taxes $ 30,637 $ 21,648 $ 24,425
==========================================================================
Net Income applicable to
common shareholder
Electric Utility Services $ 56,408 $ 43,074 $ 36,811
Gas Utility Services 2,919 (2,392) 2,555
- --------------------------------------------------------------------------
Net income $ 59,327 $ 40,682 $ 39,366
==========================================================================
Depreciation & Amortization
Electric Utility Services $ 40,003 $ 38,691 $ 38,639
Gas Utility Services 5,095 4,596 4,575
- --------------------------------------------------------------------------
Total depreciation &
amortization $ 45,098 $ 43,287 $ 43,214
==========================================================================
Capital Expenditures
Electric Utility Services $ 87,544 $ 69,683 $ 43,520
Gas Utility Services 2,203 8,077 7,599
- --------------------------------------------------------------------------
Total capital expenditures $ 89,747 $ 77,760 $ 51,119
==========================================================================
At December 31,
- -------------------------------------------------------------
In thousands 2002 2001
- -------------------------------------------------------------
Identifiable Assets
Electric Utility Services $ 856,516 $ 804,867
Gas Utility Services 169,142 175,025
- -------------------------------------------------------------
Total identifiable assets $1,025,658 $ 979,892
=============================================================
15. Special Charges for 2001 and 2000
Restructuring and Related Charges
As part of continued cost saving efforts, in June 2001, Vectren's management and
board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $4.3 million were expensed in June 2001 as a direct result of
the restructuring plan. Additional charges of $1.5 million were incurred during
the remainder of 2001 primarily for consulting fees and employee relocation
costs. In total, the Company has incurred restructuring charges of $5.8 million.
These charges were comprised of $4.4 million for employee severance, related
benefits and other employee related costs, and $1.4 million for consulting and
other fees incurred through December 31, 2001.
The $4.4 million expensed for employee severance and related costs includes $0.8
million of noncash pension costs and is associated with approximately 40
employees. Employee separation benefits include severance, healthcare, and
outplacement services. As of December 31, 2001, 37 employees have exited the
business. Restructuring expenses were incurred by the Company's operating
segments as follows: $1.0 million by the Gas Utility Services segment and $4.8
million by the Electric Utility Services segment. The restructuring program was
completed during 2001, except for the departure of the remaining employees
impacted by the restructuring which occurred during 2002.
In June 2001, the Company established accruals totaling $2.7 million for
severance. Throughout 2001 additional expenses totaling $0.6 million for
severance were incurred. Cash payments in 2001 totaled $3.1 million. As of
December 31, 2001, the remaining accrual related to the restructuring was $0.2
million. Of that amount, almost all relates to structured compensation
arrangements payable through 2004. During 2002, the accrual for severance did
not substantially change.
Merger and Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $0.6 million and $14.1 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001. Merger costs
are reflected in the financial statements of the operating subsidiaries in which
merger savings are expected to be realized.
Since March 31, 2000, $14.7 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$7.4 million. Of this amount, $0.7 million related to employee and executive
severance costs and $6.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger. At December 31, 2001,
no accrual remains. The remaining $7.3 million was expensed ($6.7 million in
2000 and $0.6 million in 2001) for accounting fees resulting from merger related
filing requirements, consulting fees related to integration activities such as
organization structure, employee travel between company locations, internal
labor of employees assigned to integration teams, investor relations
communication activities, and certain benefit costs.
During the merger planning process, approximately 54 positions were identified
for elimination. As of December 31, 2001, all such identified positions have
been vacated.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
16. 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 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 Issue 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 non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
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 as described in Note 12. The Company has re-evaluated its
portfolio of derivative contracts and has determined gross presentation remains
appropriate.
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. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (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 obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.
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 and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 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.
17. Quarterly Financial Data (Unaudited)
As more fully described in Note 3, the Company has restated the results for the
year ended December 31, 2001, including each quarter, as well as the first three
quarters of 2002 to appropriately account for certain transactions. Provided
below is a comparison of restated summarized quarterly financial data to
summarized quarterly financial data previously reported. Information in any one
quarterly period is not indicative of annual results due to the seasonal
variations common to the Company's utility operations.
Summarized quarterly financial data for 2002 follows:
In thousands Q1 Q2 (5) Q3 Q4
- ----------------------------------------------- ------------------- ------------------- --------
As As As As As As As
2002 Operating data Reported Restated Reported Restated Reported Restated Reported
-------- --------- -------- -------- -------- -------- --------
Operating revenues $156,407 $156,407 $176,548 $176,548 $197,323 $197,018 $163,604
Operating margin 61,249 61,207 59,073 59,290 79,541 78,766 63,328
Operating income 15,830 15,738 11,002 13,225 27,628 27,015 21,756
Net income applicable to
common shareholder 11,137 11,435 12,384 9,439 22,826 22,212 16,241
Summarized quarterly financial data for 2001 follows:
In thousands Q1 (1) Q2 (2) Q3 Q4 (4)
- -------------------------------------------- ------------------- ------------------ ------------------
As As As As As As As As
2001 Operating Data (3) Reported Restated Reported Restated Reported Restated Reported Restated
-------- -------- -------- -------- -------- -------- -------- --------
Operating revenues $140,159 $141,305 $106,371 $106,867 $115,367 $116,289 $118,087 $115,352
Operating margin 67,564 71,054 50,323 52,112 65,865 69,627 57,335 52,978
Operating income 19,984 21,590 5,669 6,741 18,973 21,280 11,041 7,187
Income before
cumulative effect of
change in accounting
principle 15,587 17,120 1,480 2,447 14,692 16,961 8,693 4,975
Net income applicable to
common shareholder 19,287 17,989 1,238 2,205 13,248 15,523 8,689 4,965
1. Q1 of 2001 includes charges for cumulative effect of changes in accounting
principle as described in Note 12.
2. Q2 of 2001 includes restructuring charges as described in Note 15.
3. 2001 includes merger and integration charges as described in Note 15.
4. The benefit clearing adjustment and the inventory adjustment discussed in
Note 3 were recorded in Q4 of 2001.
5. In Q2 of 2002, the Company recorded $3.2 million of after tax carrying
costs for DSM programs pursuant to existing IURC orders. 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 Q2 of 2002 were reversed and
reflected in common shareholder's equity as of January 1, 2000.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
Disclosure with respect to this Item, has been previously provided on Form 8-K
originally filed with the SEC on March 26, 2002, as amended on Form 8-K/A filed
with the SEC on May 20, 2002.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
ITEM 11. EXECUTIVE COMPENSATION
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Intentionally omitted. See the table of contents of this Annual Report on Form
10-K for explanation.
PART IV
ITEM 14. 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 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 in bringing to their attention on a timely basis 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).
Disclosure controls and procedures, as defined by the Exchange Act 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 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 controls and procedures or
significant changes in other factors that could significantly affect the
Company's internal controls and procedures. However, in Note 3 to the financial
statements (included in Item 8) which discusses the restatement of 2001 and 2000
previously reported information, the Company identified certain errors, the net
effect of which, related primarily to gas inventory accounting and the proper
clearing of employee benefit related costs routinely accumulated on the balance
sheet. These errors resulted primarily from insufficient account reconciliation
procedures. The Company has taken steps to improve these internal controls.
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.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
List Of Documents Filed As Part Of This Report
Financial Statements
The financial statements and related notes, together with the report of Deloitte
& Touche LLP, appear in Part II Item 8 Financial Statements and Supplementary
Data of this Form 10-K.
Supplemental Schedules
For the years ended December 31, 2002, 2001, and 2000, the Company's Schedule II
- -- Valuation and Qualifying Accounts Financial Statement Schedules is presented
on page 47. The report of Deloitte & Touche LLP on the schedule may be found in
Item 8.
All other schedules are omitted as the required information is inapplicable or
the information is presented in the Financial Statements or related notes in
Item 8.
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified
below pursuant to Rule 12b-32 under the Exchange Act.
Exhibits for the Company are listed in the Index to Exhibits beginning on page
52.
Exhibits for the Company attached to this filing filed electronically with the
SEC are listed on page 57.
Reports On Form 8-K During The Last Calendar Quarter
On October 25, 2002, the Company filed a Current Report on Form 8-K with respect
to the release of financial information to the investment community regarding
Vectren Corporation's results of operations, financial position and cash flows
for the three, nine, and twelve month periods ended September 30, 2002. The
financial information was released to the public through this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Third 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
On November 27, 2002, the Company filed a Current Report on Form 8-K with
respect to a press release issued by Moody's Investor Services that downgraded
the credit ratings on various debt instruments issued by certain of Vectren
Corporation's (Vectren) wholly owned subsidiaries.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Moody's Investor's Services
99.2 - Cautionary Statement for Purposes of the "Safe
Harbor" Provisions of the Private Securities Litigation
Reform Act of 1995
SCHEDULE II
Southern Indiana Gas and Electric Company
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
- --------------------------------------------------------------------------------------------------
Additions
------------------
Balance at Charged Charged Deductions Balance at
Beginning to to Other from End of
Description Of Year Expenses Accounts Reserves, Net Year
- --------------------------------------------------------------------------------------------------
(In thousands)
VALUATION AND QUALIFYING ACCOUNTS:
Year 2002 - Accumulated provision for
uncollectible accounts $ 3,188 $ 2,500 $ - $ 2,026 $ 3,662
Year 2001 - Accumulated provision for
uncollectible accounts $ 2,639 $ 2,387 $ - $ 1,838 $ 3,188
Year 2000 - Accumulated provision for
uncollectible accounts $ 2,138 $ 1,189 $ - $ 688 $ 2,639
OTHER RESERVES:
Year 2001 - Reserve for merger and
integration charges $ 526 $ - $ - $ 526 $ -
Year 2000 - Reserve for merger and
integration charges $ - $ 7,400 $ - $ 6,874 $ 526
Year 2002 - Reserve for restructuring
costs $ 180 $ - $ 670 $ - $ 850
Year 2001 - Reserve for restructuring
costs $ - $ 3,321 $ - $ 3,141 $ 180
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SOUTHERN INDIANA GAS
AND ELECTRIC COMPANY
Dated February 26, 2003
/S/ Niel C. Ellerbrook
---------------------------
Niel C. Ellerbrook, Chairman and
Chief Executive Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in capacities and on the dates indicated.
Signature Title Date
/S/ Niel C. Ellerbrook Chairman & Chief Executive February 26, 2003
- ---------------------------- Officer, Director (Principal -------------------
Niel C. Ellerbrook Executive Officer)
/S/ Jerome A. Benkert, Jr. Executive Vice President, February 26, 2003
- ---------------------------- Chief Financial Officer, & -------------------
Jerome A. Benkert, Jr. Director (Principal Financial
Officer)
/S/ M. Susan Hardwick Vice President & Controller, February 26, 2003
- ---------------------------- Director (Principal -------------------
M. Susan Hardwick Accounting Officer)
/S/ Andrew E. Goebel Director February 26, 2003
- ---------------------------- -------------------
Andrew E. Goebel
/S/ Ronald E. Christian Director February 26, 2003
- ---------------------------- -------------------
Ronald E. Christian
/S/ William S. Doty Director February 26, 2003
- ---------------------------- -------------------
William S. Doty
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 annual report on Form 10-K of Southern Indiana Gas and
Electric Company;
2. Based on my knowledge, this annual 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 annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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 have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant is made known to us by
others within those entities, particularly during the period in which
this annual 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 annual report (the "Evaluation Date"); and
c) presented in this annual 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
functions):
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
annual report whether 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: February 26, 2003
/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 annual report on Form 10-K of Southern Indiana Gas and
Electric Company;
2. Based on my knowledge, this annual 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 annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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 have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant is made known to us by
others within those entities, particularly during the period in which
this annual 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 annual report (the "Evaluation Date"); and
c) presented in this annual 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
functions):
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
annual report whether 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: February 26, 2003
/s/ Jerome A. Benkert, Jr.
------------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Financial 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 26th day of February, 2003.
/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)
INDEX TO EXHIBITS
2. Plan Of Acquisition, Reorganization, Arrangement, Liquidation Or Succession
Not applicable.
3. Articles Of Incorporation And By-Laws
3.1 Amended and Restated Articles of Incorporation of Southern Indiana Gas and
Electric Company effective January 24, 2003. (Filed herewith.)
3.2 Amended and Restated Code of By-Laws of Southern Indiana Gas and Electric
Company as of January 16, 2003. (Filed herewith.)
4. Instruments Defining The Rights Of Security Holders, Including Indentures
4.1 Mortgage and Deed of Trust dated as of April 1, 1932 between Southern
Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and
Supplemental Indentures thereto dated August 31, 1936, October 1, 1937,
March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1,
1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966,
August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1,
1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January
20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984,
July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in
Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective
Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in
Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553,
dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as
Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit
(4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K,
for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15,
1986 and January 15, 1987. (Filed and designated in Form 10-K, for the
fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987.
(Filed and designated in Form 10-K, for the fiscal year 1987, File No.
1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form
10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1,
1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No.
1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K,
dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed
and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as
Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated
August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed
and designated in Form 10-K for the year ended December 31, 2001, File No.
1-15467, as Exhibit 4.1.)
4.2 Indenture dated October 19, 2001, between Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated October 19, 2001,
File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated
October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed
and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, between Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1).
4.3 Promissory Note for Long-Term Loans dated November 30, 2001, between
Southern Indiana Gas and Electric Company and Vectren Utility Holdings,
Inc. (Filed and designated in Form 10-K, for the year ended December 31,
2001, File No. 1-3553, as Exhibit 4.4).
4.4 Promissory Note for Long-Term Loans dated December 1, 2002, between
Southern Indiana Gas and Electric Company and Vectren Utility Holdings,
Inc. (Filed herewith.)
9. Voting Trust Agreement
Not applicable.
10. Material Contracts
10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power
Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern
Indiana Gas and Electric Company. (Filed and designated in Registration No.
2-29653 as Exhibit 4(d)-A.)
10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June
26, 1969, between Alcoa and Southern Indiana Gas and Electric Company.
(Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.)
10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-53005 as Exhibit 4(e)-4.)
10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-41209 as Exhibit 4(e)-1.)
10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and
Letter Agreement dated April 30, 1973 - First Supplement. (Filed and
designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as
Exhibit 1(e).)
10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.)
10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and
Electric Company and Alcoa, which amends Agreement for Sale in an Emergency
of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas
and Electric Company dated June 26, 1979. (Filed and designated in Form
10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.)
10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-3.)
10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as
Exhibit A-5.)
10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-6.)
10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power
Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and
Electric Company. (Filed and designated in Form 10-K for the fiscal year
1980, File No. 1-3553, as Exhibit (20)-1.)
10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power Generating
Inc. and Southern Indiana Gas and Electric Company. (Filed and designated
in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as
Exhibit 10.12.)
10.13 Summary description of Southern Indiana Gas and Electric Company's
nonqualified Supplemental Retirement Plan (Filed and designated in Form
10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.)
10.14 Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed
and designated in Southern Indiana Gas and Electric Company's Proxy
Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.15 Southern Indiana Gas and Electric Company's nonqualified Supplemental
Retirement Plan as amended, effective April 16, 1997. (Filed and designated
in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.)
10.16 Gas Sales and Portfolio Administration Agreement between Southern Indiana
Gas and Electric Company and ProLiance Energy, LLC, for services to begin
September 1, 2002. (Filed herewith).
10.17 Vectren Corporation Retirement Savings Plan. (Filed and designated in Form
10-Q for the quarterly period ended September 30, 2000, File No. 1-15467,
as Exhibit 99.1.)
10.18 Vectren Corporation Combined Non-Bargaining Retirement Plan. (Filed and
designated in Form 10-Q for the quarterly period ended September 30, 2000,
File No. 1-15467, as Exhibit 99.2.)
10.19 Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended
and restated effective January 1, 2001. (Filed and designated in Form 10-K
for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)
10.20 Vectren Corporation Employment Agreement between Vectren Corporation and
Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in
Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
as Exhibit 99.1.)
10.21 Vectren Corporation Employment Agreement between Vectren Corporation and
Andrew E. Goebel dated as of March 31, 2000(Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.2.)
10.22 Vectren Corporation Employment Agreement between Vectren Corporation and
Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in
Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
as Exhibit 99.3.)
10.23 Vectren Corporation Employment Agreement between Vectren Corporation and
Ronald E. Christian dated as of March 31, 2000. (Filed and designated in
Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
as Exhibit 99.5.)
10.24 Vectren Corporation Employment Agreement between Vectren Corporation and
J. Gordon Hurst dated as of March 31, 2000. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.7.)
10.25 Vectren Corporation Retirement Agreement between Vectren Corporation and
J. Gordon Hurst dated as of May 31, 2001. (Filed and designated in Form
10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.41.)
10.26 Vectren Corporation Employment Agreement between Vectren Corporation and
Richard G. Lynch dated as of March 31, 2000. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.8.)
10.27 Vectren Corporation Employment Agreement between Vectren Corporation and
William S. Doty dated as of April 30, 2001. (Filed and designated in Form
10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.43.)
11. Statement Re Computation Of Per Share Earnings
Not applicable.
12. Statements Re Computation Of Ratios
Not applicable.
13. Annual Report To Security Holders, Form 10-Q Or Quarterly Report To
Security Holders
Not applicable.
16. Letter Re Change In Certifying Accountant
Not applicable.
18. Letter Re Change In Accounting Principles
Not applicable.
21. Subsidiaries Of The Company
Not applicable.
22. Published Report Regarding Matters Submitted To Vote Of Security Holders
Not applicable.
23. Consents Of Experts And Counsel
Not applicable.
24. Power Of Attorney
Not applicable.
99. Additional Exhibits
99.1 Agreement and Plan of Merger dated as of June 11,1999 among Indiana Energy,
Inc., SIGCORP, Inc. and Vectren Corporation (the "Merger Agreement ").
(Filed and designated in Form S-4 to (No. 333-90763) filed on November 12,
1999, File No. 1-15467, as Exhibit 2.)
99.2 Amendment No.1 to the Merger Agreement dated December 14,1999 (Filed and
designated in Current Report on Form 8-K filed December 16, 1999, File No.
1-09091, as Exhibit 2.)
99.3 Amended and Restated Articles of Incorporation of Vectren Corporation
effective March 31,2000. (Filed and designated in Current Report on Form
8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
99.4 Amended and Restated Code of By-Laws of Vectren Corporation as of February
26, 2003. (Filed and designated in Form 10-K for the year ended December
31, 2002, File No. 1-15467, as Exhibit 3.2.
99.5 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren
Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and
designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No.
1-15467, as Exhibit 4.)
Southern Indiana Gas and Electric Company
2002 Form 10-K
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
See Page 52 of this Annual Report on Form 10-K for a complete list of exhibits.
Exhibit
Number Document
3.1 Amended and Restated Articles of Incorporation of Southern Indiana Gas
and Electric Company effective January 24, 2003.
3.2 Amended and Restated Code of By-Laws of Southern Indiana Gas and
Electric Company as of January 16, 2003.
4.4 Promissory Note for Long-Term Loans dated December 1, 2002, between
Southern Indiana Gas and Electric Company and Vectren Utility
Holdings, Inc.
10.16 Gas Sales and Portfolio Administration Agreement between Southern
Indiana Gas and Electric Company and ProLiance Energy, LLC, for
services to begin September 1, 2002.