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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, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to ________________________
Commission file number: 1-3553
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
INDIANA 35-0672570
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
20 N.W. 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
- --------------------------- ------------------------------------------
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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Common - Without Par 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
30, 2003, 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 25,815,188 March 1, 2004
- -------------------------------- ---------- -------------
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 MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours/millions of
megawatt hours (gigawatt hour)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
IDEM: Indiana Department of OUCC: Indiana Office of the Utility
Environmental Management Consumer Counselor
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF/BCF: millions/billions of cubic USEPA: United States Environmental
feet Protection Agency
MDth/MMDth: thousands/millions of Throughput: combined gas sales and gas
dekatherms transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business (A) .......................................................4
2 Properties .........................................................4
3 Legal Proceedings...................................................5
4 Submission of Matters to Vote of Security Holders (A)...............5
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities (A)..............5
6 Selected Financial Data (A).........................................6
7 Management's Discussion and Analysis of Results of
Operations and Financial Condition (A)..............................6
7A Qualitative and Quantitative Disclosures About Market Risk.........16
8 Financial Statements and Supplementary Data........................18
9 Change in and Disagreements with Accountants on Accounting
and Financial Disclosure...........................................44
9A Controls and Procedures............................................44
and Procedures
Part III
10 Directors and Executive Officers of the Registrant (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
14 Principal Accountant Fees and Services............................46
Part IV
15 Exhibits (A), Financial Statement Schedules, and
Reports on Form 8-K................................................47
Signatures.........................................................54
(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 Vice President, Investor Relations
47702-0209 [email protected]
16
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, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI
is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO
generally does business as Vectren Energy Delivery of Indiana, Inc.
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" (APB 16).
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, Inc.
(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, 2003, 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, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80 MW 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 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution
system includes 3,224 pole miles of lower voltage overhead lines and 289 trench
miles of conduit containing 1,622 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed
capacity of 2,368.6 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
SIGECO 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 6.3 BCF of gas with maximum peak day delivery capabilities of
124,748 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 18,699 MCF per day. SIGECO has the ability to meet a
total annual demand, utilizing all of its assets across various pipelines, of
28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day.
SIGECO's gas delivery system includes 3,026 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 8 of its financial
statements included in "Item 8 Financial Statements and Supplementary Data"
regarding the Clean Air Act and related legal proceedings. Legal proceedings
regarding the Culley generating station's compliance with the Clean Air Act were
substantially resolved during 2003.
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 COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND
ISSUER PURCHASES OF EQUITY SECURITIES
All of the outstanding shares of the Company's common stock are owned by VUHI.
The Company's common stock is not traded. There are no outstanding options or
warrants to purchase the Company's common equity or securities convertible into
the Company's common equity. Additionally, the Company has no plans to publicly
offer any of its common equity.
Dividends Paid to Parent
During 2003, the Company paid dividends to its parent company of $10.9 million,
$10.9 million, $11.3 million, and $19.0 million in the first, second, third, and
fourth quarters, respectively.
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.
On January 28, 2004, the board of directors declared a $12.3 million dividend,
payable to its parent company on March 1, 2004.
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.
Executive Summary of Results of Operations
In 2003, net income applicable to common shareholder was $48.8 million, a
decrease of $10.5 million when compared to 2002. The decrease in 2003 compared
to 2002 was primarily driven by weather, a slowly recovering economy, and
increased operating expenses, partially offset by increased wholesale power
margins and retail electric rate recovery related to NOx compliance expenditures
and related operating expenses.
In 2002, net income applicable to common shareholder was $59.3 million, an
increase of $18.6 million when compared to 2001. 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 reflected 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.
The Company generates revenue primarily from the delivery of electric service
and natural gas service to its customers. The primary source of cash flow
results from the collection of customer bills and the payment for goods and
services procured for the delivery of electric and gas services. Results are
impacted by weather patterns in its service territory and general economic
conditions both in its service territory as well as nationally.
The Company has in place a disclosure committee that consists of senior
management as well as financial management. The committee is actively involved
in the preparation and review of the Company's SEC filings.
Nonrecurring Items in 2001
Merger & Integration Costs
Merger and integration related costs incurred during 2001 totaled $0.6 million
($0.4 million after tax). These costs relate primarily to transaction costs,
severance, and other merger and acquisition integration activities. 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. Merger and integration
activities resulting from the 2000 merger forming Vectren were completed in
2001.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, the Company'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 incurred restructuring charges of $5.8 million
($3.6 million after tax) in 2001. 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. The restructuring program was
completed during 2001, except for the departure of certain employees impacted by
the restructuring which occurred during 2002.
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
Operating Margin
Margin generated from the sale of electricity and natural gas to residential and
commercial customers is seasonal and impacted by weather patterns in its service
territory. Margin generated from sales to industrial and other contract
customers is impacted by overall economic conditions. In general, operating
margin is not sensitive to variations in fuel or gas costs. It is, however,
impacted by the collection of state mandated taxes which fluctuate with gas
costs and also some level of fluctuation in volumes sold. Electric generating
asset optimization activities are primarily affected by market conditions, the
level of excess generating capacity, and electric transmission availability.
Following is a discussion and analysis of margin generated from regulated
utility operations.
Electric Utility Margin
Electric Utility margin by revenue type follows:
Year Ended December 31,
- ----------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- ----------------------------------------------------------------------------
Residential & commercial $ 141,061 $ 145,667 $ 134,436
Industrial 53,533 54,874 49,590
Municipalities & other 20,174 16,962 16,773
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Total retail & firm wholesale 214,768 217,503 200,799
Asset optimization 18,277 12,727 19,105
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Total electric utility margin $ 233,045 $ 230,230 $ 219,904
============================================================================
Retail & Firm Wholesale Margin
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.8 million, a decrease of $2.7 million when compared
to 2002. It is estimated that summer weather 19% cooler than normal and 34%
cooler than last year caused an $8 million decrease in residential and
commercial margin. The estimated effect of weather was partially offset by a
$7.1 million increase in retail electric rates related to recovery of NOx
compliance expenditures and related operating expenses. A slowly recovering
economy continued to negatively impact industrial sales which decreased $1.3
million compared to 2002. As a result primarily of the mild weather and slow
economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90
GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh.
The current year decrease in native load and firm wholesale margin has been
offset by increased margin from asset optimization activities as more fully
described below.
For the year ended December 31, 2002, margin from serving native load and firm
wholesale customers increased $16.7 million or 8%, when compared to 2001. The
increase results primarily from the effect on residential and commercial sales
of cooling weather considerably warmer than the prior year. Weather in 2002 was
27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002
was positively affected by increased industrial and other wholesale volumes and
rate recovery related to 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 and increased volumes sold, native load and firm
wholesale volumes sold increased 6%. It is estimated that weather contributed $7
million to the increase in electric utility margin, and the increased industrial
and other wholesale volumes and the NOx recovery rider contributed $8 million.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of
these contracts are integrated with portfolio requirements around power supply
and delivery and are short-term purchase and sale transactions that expose the
Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
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(In thousands) 2003 2002 2001
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Beginning of Year Net Asset Optimization Position $ (718) $ 3,321 $ -
Statement of Income Activity
Cumulative effect at adoption of SFAS 133 - - 1,783
Mark-to-market gains (losses) recognized 654 (3,585) 1,537
Realized gains recognized 17,623 16,312 17,568
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Net activity in electric utility margin 18,277 12,727 19,105
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Net cash received & other adjustments (17,983) (16,766) (17,567)
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End of Year Net Asset Optimization Position $ (424) $ (718) $ 3,321
=========================================================================================
Included in:
Prepayments & other current assets $ 2,373 $ 3,506 $ 6,128
Accrued liabilities (2,797) (4,224) (2,807)
For the years ended December 31, 2003, 2002, and 2001, volumes sold into the
wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh, respectively, while
volumes purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A
portion of volumes purchased in the wholesale market is used to serve native
load and firm wholesale customers, and in 2003, greater amounts of purchased
power have been required for native load due to scheduled outages, which has
reduced capacity available for optimization. Additionally, volumes sold and
purchased were lower in 2003 compared to 2002 due to a shorter term focus in
hedging and optimization strategies. While volumes both sold and purchased in
the wholesale market have decreased during 2003, margin from optimization
activities has increased compared to 2002 due primarily to price volatility.
Despite the increased volumes in 2002, margins were lower in 2002 compared to
2001 due to reduced price volatility.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.
Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income.
Year Ended December 31,
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(In thousands) 2003 2002 2001
- -------------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152,795 $ 302,764 $ 101,418
Purchase contracts (126,969) (275,851) (74,311)
Mark-to-market gains (losses) 654 (3,585) 1,537
- -------------------------------------------------------------------------------
Net asset optimization revenue 26,480 23,328 28,644
- -------------------------------------------------------------------------------
Fuel for electric generation (8,203) (10,601) (9,539)
- -------------------------------------------------------------------------------
Asset optimization margin $ 18,277 $ 12,727 $ 19,105
===============================================================================
Gas Utility Margin
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- --------------------------------------------------------------------------------
Residential $ 18,989 $ 21,215 $ 18,614
Commercial 5,367 6,146 4,705
Contract 4,024 4,062 4,284
Other 929 938 (1,736)
- --------------------------------------------------------------------------------
Total gas utility margin $ 29,309 $ 32,361 $ 25,867
================================================================================
Volumes in MMDth:
Sold to residential & commercial customers 12,495 12,336 11,215
Sold & transported to contract customers 19,052 19,652 20,708
- --------------------------------------------------------------------------------
Total throughput 31,547 31,988 31,923
================================================================================
Gas Utility margin for the year ended December 31, 2003, of $29.3 million
decreased $3.1 million, or 9%, compared to 2002. The decrease is primarily due
to estimates for unbilled revenue, the pricing of unaccounted for gas, and
reduced consumption per degree day per customer, all of which decreased margin
by approximately $2.8 million. Utility receipts taxes collected from customers
also decreased margin $0.5 million. Furthermore, the negative effect of high gas
prices on customer usage contributed to the decrease. Weather near normal and 2%
cooler than the prior year increased margin an estimated $0.2 million.
Gas Utility margin for the year ended December 31, 2002, of $32.4 million
increased $6.5 million compared to 2001. The increase is primarily due to
weather 4% cooler for the year and 26% colder in the fourth quarter and customer
growth of almost 1%.
Gas cost fluctuations have impacted customer usage during the years ended
December 31, 2003, 2002, and 2001. The average cost per dekatherm of gas
purchased in those years was $5.78 in 2003, $4.20 in 2002, and $5.20 in 2001.
Operating Expenses
Other Operating
For the year ended December 31, 2003, other operating expenses increased $5.6
million compared to 2002. The increase is principally caused by increased
distribution, plant, and transmission operating expenses; power plant and other
maintenance; customer service initiative costs; higher insurance premiums; and
prior year insurance recoveries.
Other operating expenses decreased $7.2 million for the year ended December 31,
2002, when compared to 2001. The decrease results primarily from insurance
recovery in 2002 of $2.8 million of maintenance costs incurred in 2001, and a
return to lower gas prices in 2002 compared to 2001.
Depreciation & Amortization
For the year ended December 31, 2003, depreciation and amortization increased
$2.6 million in 2003 compared to 2002, and $1.8 million in 2002 compared to
2001. The increased depreciation expense reflects depreciation of utility plant
placed into service including a full year for a gas-fired peaker unit placed
into service in June 2002, customer system upgrades, and other upgrades to
existing transmission and distribution facilities.
Income Taxes
For the year ended December 31, 2003, federal and state income taxes were
comparable to 2002. The increase in the effective rate from 33.3% for 2002, to
38.6% for 2003, reflects an increase in the Indiana state income tax rate from
4.5 % to 8.5% and other changes in the effective tax rate recognized in 2002.
The $9.0 million increase in 2002 compared to 2001 is principally due to higher
pre-tax earnings.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $0.7 million in 2003 compared to 2002.
Utility plant additions have increased property values and as a result have
increased property taxes in 2003. The increase was partially offset by lower
utility receipts 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.
Interest Expense
Interest expense increased $1.6 million in 2003 compared to 2002 and increased
$2.2 million in 2002 compared to 2001. The 2003 increase results from increased
debt outstanding which is due primarily to increased working capital
requirements resulting from the higher gas prices and NOx expenditures. The 2003
increase also reflects the impact of permanent financing completed in the third
quarter of 2003 whereby short term borrowings from VUHI and $65 million of
higher coupon third party debt were replaced with $25 million in equity and
$61.9 in long-term debt payable to VUHI. The 2002 increase is attributable to
higher outstanding borrowings during 2002 due to the funding of NOx expenditures
with short-term borrowing.
Rate Case Proceedings
On March 12, 2004, SIGECO (d/b/a Vectren Energy Delivery of Indiana, Inc.) filed
a petition with the IURC to adjust its base rates and charges for its gas
distribution business in southwestern Indiana. If the filing is approved, SIGECO
expects to increase its base (non-gas cost) rates by approximately $5.7 million
to cover the ongoing cost of operating and maintaining the approximately
3,000-mile distribution and storage system used to serve more than 110,000
customers. If finalized by the OUCC and ultimately approved by the IURC, the
agreement in principle would result in about a 5 percent increase for the
typical SIGECO residential customer who uses natural gas to heat his/her home.
The proposal will not affect the electric portion of the Company's customer
bills.
The petition only addresses "non-gas" costs, which are incurred to build,
operate and maintain the pipes, other equipment and systems that are used to
deliver gas. The petition indicates that SIGECO has reached an agreement in
principle with the OUCC regarding the proposed changes to the rates and charges.
The agreement in principle further provides for SIGECO's recovery through a
tracking mechanism of costs required to comply with a new federal law dealing
with pipeline safety.
As required by the regulatory process, SIGECO will be required to submit
information substantiating the proposed adjustment to its base rates. During the
processing of the case by the IURC, there will also be one or more public
hearings conducted regarding the proposal. The timing and ultimate outcome of
this regulatory initiative is uncertain.
Critical Accounting Policies
Management is required to make judgments, 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 judgment. These include the estimates to perform goodwill and other
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 11 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 in both 2003 and 2002 and
therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgment 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 would have resulted in no impairment charge in 2003 or
2002.
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, the method
these estimates are derived from is 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 judgment 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 provide corporate, 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. 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, which occurs on September 30. These costs are directly
charged to individual subsidiaries. Other components of costs (such as interest
cost and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Neither 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 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 2003 periodic benefit cost: a
discount rate of 6.75%, an expected return on plan assets before expenses of
9.0%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2003 declining to 5% in 2006. During 2003, Vectren reduced the
discount rate and rate of compensation increase by 75 basis points to value 2003
ending pension and postretirement obligations due to a decline in benchmark
interest rates. The Company also lengthened to 2009 the time in which the health
care trend rate declines to 5% primarily due to increases in healthcare costs.
In addition, the Company reduced its 2004 expected return on plan assets 50
basis points from that used to estimate 2003 expense due to recent lower
investment returns and lower interest rates. 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 VUHI and its subsidiaries.
Impact of Recently Issued Accounting Guidance
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $48 million and $44 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
adoption of SFAS 150 on January 1, 2004, did not affect the Company's results of
operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. Although management is
still evaluating the impact of FIN 46 and related Staff Positions on its
financial position and results of operations, the adoption is not expected to
have a material effect.
Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 financial statements, the Company restated
its annual financial statements for 2000 and 2001, and its 2002 quarterly
results. The Company received an informal inquiry from the SEC with respect to
this restatement. In response, the Company met with the SEC staff and provided
information in response to their requests, with the most recent response
provided on July 26, 2003.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in our credit rating, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee or contractor workforce factors including changes in key
executives, collective bargaining agreements with union employees, or work
stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but not
limited to, those described in Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 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.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities to be used in operations and
optimizing its generation assets.
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 retail customers due
to current Indiana and Ohio regulations, which subject to compliance with those
regulations, allow for recovery of the cost of such purchases through natural
gas and fuel cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and electric sales to
certain municipalities and large industrial customers are exposed to commodity
price risk associated with fluctuating commodity prices.
The Company's wholesale power marketing activities include asset optimization
activities that manage the utilization of available electric generating capacity
by entering into energy 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 accounts for asset optimization contracts that
are derivatives at fair value with the offset marked to market through earnings.
Sales to certain municipalities and large industrial customers are executed to
meet customer demand. Price risk from forward positions obligating the Company
to deliver commodities is mitigated using generating capability, and offsetting
forward purchase contracts. These contracts are expected to be settled by
physical receipt or delivery of the commodity.
Market risk resulting from commodity contracts is measured by management using
the potential impact on pre-tax earnings caused by the effect a 10% adverse
change in forward commodity prices might have on market sensitive derivative
positions outstanding on specific dates. For the years ended December 31, 2003,
and 2002, a 10% adverse change in forward commodity prices would have decreased
earnings by $3.0 million and $1.7 million, respectively, based upon open
positions existing on the last day of those years.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The
Company's risk management objective is for between 20% and 30% of its total debt
to be exposed to short-term interest rate volatility. However, there are times
when this targeted range of interest rate exposure may not be attained. To
manage this exposure, the Company may use derivative financial instruments. At
December 31, 2003, such debt obligations represented 18% of the Company's total
debt portfolio.
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. During 2003 and 2002, the weighted average combined
borrowings under these arrangements were $49.8 million and $92.4 million,
respectively. At December 31, 2003, and 2002, combined borrowings under these
arrangements were $83.8 million and $61.9 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2003, and 2002, an increase of 100 basis points (one percentage point) in
the rates would have increased interest expense by $0.5 million and $0.9
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 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. The Company mitigates these risks by
executing derivative contracts that manage the price of forecasted natural gas
purchases. These contracts are subject to regulation, which allows for
reasonable and prudent hedging costs to be recovered through rates. When
regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
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 ultimate 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 12, 2004
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, 2003 and 2002, 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, 2003. Our audits also included the financial
statement schedule listed in the Index 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, 2003 and 2002, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2003, 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 2-F, effective January 1, 2003, the Company adopted
Statement of Financial Accounting Standards ("SFAS") 143, "Accounting for Asset
Retirement Obligations." As discussed in Note 2-E, effective January 1, 2002,
the Company adopted SFAS 142, "Goodwill and Other Intangibles." As discussed in
Note 10, effective January 1, 2001, the Company adopted SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended.
As discussed in Note 10, in 2003 the Company adopted EITF Issue No. 03-11,
"Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and "Not Held for Trading Purposes" as Defined in
Issue No. 02-3." Amounts for the years 2002 and 2001 have been reclassified in
the accompanying statements of income to conform to this new method of
presentation.
/s/ DELOITTE & TOUCHE LLP
- -----------------------------------------------
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 12, 2004
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
December 31,
- -------------------------------------------------------------------------------
2003 2002
- -------------------------------------------------------------------------------
ASSETS
Utility Plant
Original cost $ 1,659,527 $ 1,531,141
Less: Accumulated depreciation & amortization 719,787 684,832
- -------------------------------------------------------------------------------
Net utility plant 939,740 846,309
- -------------------------------------------------------------------------------
Current Assets
Cash & cash equivalents 3,675 2,145
Accounts receivable - less reserves
of $1,202 & $3,662, respectively 38,817 50,454
Receivables from other Vectren companies 76 18,015
Accrued unbilled revenues 28,162 33,027
Inventories 37,214 39,653
Recoverable fuel & natural gas costs 3,900 9,615
Prepayments & other current assets 4,875 5,926
- -------------------------------------------------------------------------------
Total current assets 116,719 158,835
- -------------------------------------------------------------------------------
Investments in unconsolidated affiliates 150 150
Other investments 10,474 10,019
Non-utility property - net 3,769 3,569
Goodwill - net 5,557 5,557
Regulatory assets 54,625 44,811
Other assets 688 344
- -------------------------------------------------------------------------------
TOTAL ASSETS $1,131,722 $ 1,069,594
===============================================================================
The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
December 31,
- -----------------------------------------------------------------------------------
2003 2002
- -----------------------------------------------------------------------------------
LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 128,258 $ 103,258
Retained earnings 266,911 270,181
- -----------------------------------------------------------------------------------
Total common shareholder's equity 395,169 373,439
- -----------------------------------------------------------------------------------
Cumulative redeemable preferred stock 228 344
Long-term debt payable to third parties -
net of current maturities & debt subject
to tender 216,330 264,238
Long-term debt payable to VUHI 148,484 86,574
- -----------------------------------------------------------------------------------
Total capitalization 760,211 724,595
- -----------------------------------------------------------------------------------
Commitments & Contingencies (Notes 3, 7, 8, & 9)
Current Liabilities
Accounts payable 18,437 25,215
Accounts payable to affiliated companies 8,312 10,013
Payables to other Vectren companies 11,456 14,677
Accrued liabilities 38,619 31,247
Short-term borrowings 830 -
Short-term borrowings from VUHI 82,929 39,419
Long-term debt subject to tender 9,975 26,640
Current maturities of long-term debt - 1,000
- -----------------------------------------------------------------------------------
Total current liabilities 170,558 148,211
- -----------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 109,951 112,004
Regulatory liabilities & other removal costs 48,153 43,936
Deferred credits & other liabilities 42,849 40,848
- -----------------------------------------------------------------------------------
Total deferred income taxes & other liabilities 200,953 196,788
- -----------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 1,131,722 $ 1,069,594
===================================================================================
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,
- ------------------------------------------------------------------------------
2003 2002 2001
- ------------------------------------------------------------------------------
OPERATING REVENUES
Electric utility $ 335,694 $ 328,620 $ 308,458
Gas utility 102,736 84,392 98,580
- ------------------------------------------------------------------------------
Total operating revenues 438,430 413,012 407,038
- ------------------------------------------------------------------------------
COST OF OPERATING REVENUES
Fuel for electric generation 86,477 81,559 74,401
Purchased electric energy 16,172 16,831 14,153
Cost of gas sold 73,427 52,031 72,713
- ------------------------------------------------------------------------------
Total cost of operating revenues 176,076 150,421 161,267
- ------------------------------------------------------------------------------
TOTAL OPERATING MARGIN 262,354 262,591 245,771
OPERATING EXPENSES
Other operating 102,994 97,362 104,535
Merger & integration costs - - 588
Restructuring costs - - 5,825
Depreciation & amortization 47,649 45,098 43,287
Income taxes 30,640 30,637 21,648
Taxes other than income taxes 12,448 11,760 13,090
- ------------------------------------------------------------------------------
Total operating expenses 193,731 184,857 188,973
- ------------------------------------------------------------------------------
OPERATING INCOME 68,623 77,734 56,798
Other income - net 5,048 4,794 5,629
Interest expense 24,814 23,168 20,924
- ------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 48,857 59,360 41,503
- ------------------------------------------------------------------------------
Cumulative effect of change in
accounting principle - net of tax - - 1,107
- ------------------------------------------------------------------------------
NET INCOME 48,857 59,360 42,610
Preferred stock dividends 23 33 758
Loss on extinguishment of preferred stock - - 1,170
- ------------------------------------------------------------------------------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 48,834 $ 59,327 $ 40,682
==============================================================================
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,
- -----------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 48,857 $ 59,360 $ 42,610
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 47,649 45,098 43,287
Deferred income taxes & investment tax credits (6,195) (6,461) 467
Pension & postretirement periodic benefit cost 2,896 3,128 2,841
Net unrealized (loss) gain on derivative
instruments, including cumulative effect of
change in accounting principle (654) 3,585 8,935
Other non-cash charges - net (1,521) 39 (1,936)
Changes in working capital accounts:
Accounts receivable, including to Vectren
companies & accrued unbilled revenue 33,538 (24,950) 19,633
Inventories 2,439 (2,020) (6,578)
Recoverable fuel & natural gas costs 5,715 12,591 6,497
Prepayments & other current assets 608 (5,419) (12,054)
Accounts payable, including to Vectren
companies & affiliated companies (11,700) 34,332 (40,682)
Accrued liabilities 9,458 (345) (18,784)
Changes in noncurrent assets (6,015) (3,085) (939)
Changes in noncurrent liabilities 60 (49) 905
- -----------------------------------------------------------------------------------------
Net cash flows from operating
activities 125,135 115,804 44,202
- -----------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt due to VUHI 61,900 37,114 49,460
Additional capital contribution 25,000 25,000 -
Requirements for:
Dividends to parent (52,104) (45,088) (38,909)
Retirement of long-term debt, including
premiums paid (68,438) - -
Redemption of preferred stock (116) (116) (17,676)
Dividends on preferred stock (23) (33) (758)
Net change in short-term borrowings,
including from VUHI 44,340 (42,119) 41,384
Other activity (1,744) - -
- -----------------------------------------------------------------------------------------
Net cash flows from financing
activities 8,815 (25,242) 33,501
- -----------------------------------------------------------------------------------------
CASH FLOWS INVESTING ACTIVITIES
Proceeds from sale of investments and assets - 1,400 -
Requirements for:
Capital expenditures (132,420) (89,747) (77,760)
Other investments - (1,626) -
- -----------------------------------------------------------------------------------------
Net cash flows from investing
activities (132,420) (89,973) (77,760)
- -----------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 1,530 589 (57)
Cash & cash equivalents at beginning of period 2,145 1,556 1,613
- -----------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 3,675 $ 2,145 $ 1,556
=========================================================================================
Cash paid during the year for:
Interest $ 24,512 $ 20,598 $ 18,992
Income taxes 30,595 41,441 47,960
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, 2001 $ 78,258 $ 261,135 $ 339,393
Net income & comprehensive income 42,610 42,610
Common stock dividends to parent (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 78,258 255,942 334,200
Net income & comprehensive income 59,360 59,360
Common stock:
Additional capital contribution 25,000 25,000
Dividends to parent (45,088) (45,088)
Preferred stock dividends (33) (33)
- --------------------------------------------------------------------------------
Balance at December 31, 2002 103,258 270,181 373,439
- --------------------------------------------------------------------------------
Net income & comprehensive income 48,857 48,857
Common stock:
Additional capital contribution 25,000 25,000
Dividends to parent (52,104) (52,104)
Preferred stock dividends (23) (23)
- --------------------------------------------------------------------------------
Balance at December 31, 2003 $ 128,258 $ 266,911 $ 395,169
================================================================================
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
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. SIGECO 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). SIGECO generally does
business as Vectren Energy Delivery of Indiana, Inc.
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 Accounting Principles Board (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, formerly a wholly
owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. 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 & Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents.
B. Inventories
Inventories consist of the following:
At December 31,
- --------------------------------------------------------------------------------
(In thousands) 2003 2002
- --------------------------------------------------------------------------------
Materials & supplies $ 17,304 $ 15,836
Gas in storage - at LIFO cost 8,599 12,880
Fuel (coal and oil) for electric generation 10,680 10,030
Emission allowances 631 907
- --------------------------------------------------------------------------------
Total inventories $ 37,214 $ 39,653
================================================================================
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,
2003, and 2002, by approximately $30.1 million and $19.0 million, respectively.
Gas in storage of the Indiana regulated operations is stated at LIFO. All other
inventories are carried at average cost.
C. Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation of
utility property 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) 2003 2002
- -------------------------------------------------------------------------------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of Percent of
Original Cost Original Cost Original Cost Original Cost
- -------------------------------------------------------------------------------------------------
Electric utility plant $ 1,322,365 3.4% $ 1,216,083 3.3%
Gas utility plant 170,865 3.0% 164,510 2.9%
Common utility plant 44,295 2.7% 41,621 2.6%
Construction work in progress 122,002 - 108,927 -
- -------------------------------------------------------------------------------------------------
Total original cost $ 1,659,527 $ 1,531,141
=================================================================================================
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) 2003 2002 2001
- -------------------------------------------------------------------------------
AFUDC - equity funds $ 2,863 $ 1,746 $ 1,653
AFUDC - borrowed funds 1,904 1,933 1,371
- -------------------------------------------------------------------------------
Total AFUDC capitalized $ 4,767 $ 3,679 $ 3,024
===============================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred unless deferral is authorized by a rate order. When property that
represents a retirement unit is replaced or removed, the cost of such property
is charged to Utility plant, with an offsetting charge to Accumulated
depreciation and Regulatory liabilities for the cost of removal.
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 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 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 business combinations is accounted for in accordance with
SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company
adopted SFAS 142 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.
As required by SFAS 142, amortization of goodwill ceased on January 1, 2002.
Amortization approximated $0.2 million ($0.1 million after tax) in 2001. 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 these agencies 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 expenditures by
the Company for removal costs or 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
regulated assets.
Regulatory assets consist of the following:
At December 31,
- -------------------------------------------------------------------------------
(In thousands) 2003 2002
- -------------------------------------------------------------------------------
Future amounts recoverable from ratepayers:
Income taxes $ 9,184 $ 7,334
Other 858 -
- -------------------------------------------------------------------------------
10,042 7,334
Amounts deferred for future recovery:
Demand side management programs 24,888 23,844
Other 5,347 3,713
- -------------------------------------------------------------------------------
30,235 27,557
Amounts currently recovered through base rates:
Unamortized debt issue costs 4,515 3,011
Premiums paid to reacquire debt 5,915 3,739
Demand side management programs 2,746 3,170
- -------------------------------------------------------------------------------
13,176 9,920
Amounts currently recovered through authorized
Indiana tracking mechanisms 1,172 -
- -------------------------------------------------------------------------------
Total regulatory assets $ 54,625 $ 44,811
===============================================================================
The $13.2 million currently being recovered through base rates is earning a
return with a weighted average recovery period of 15.4 years. The Company has
rate orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.
Regulatory liabilities & other removal costs consist of the following:
At December 31,
- -------------------------------------------------------------------------------
(In thousands) 2003 2002
- -------------------------------------------------------------------------------
Cost of removal $ 48,153 $ -
Other removal costs - 43,936
- -------------------------------------------------------------------------------
Total regulatory liabilities &
other removal costs $ 48,153 $ 43,936
===============================================================================
SFAS 143 & Other Removal Costs
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations.
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $48 million and $44 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.
Refundable or Recoverable Gas Costs, Fuel for Electric Production & 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 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 Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates
charged to customers. Accordingly, the Company records these taxes received as a
component of Operating revenues. Excise and utility 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 SIGECO's common stock is wholly owned by
Vectren Utility Holdings, Inc.
J. Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 3) and derivatives (Note 10).
K. 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.
L. Reclassification
Certain prior year amounts have been reclassified in the financial statements
and accompanying notes to conform to 2003 classifications.
3. Transactions with Other Vectren Companies
Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, finance, tax, risk
management, human resources, which includes charges for restricted stock
compensation and for pension and other postretirement benefits not directly
charged to subsidiaries. These costs have been allocated using various
allocators, primarily number of employees, number of customers and/or revenues.
Allocations are based on cost. SIGECO received corporate allocations totaling
$42.3 million, $45.2 million, and $43.5 million for the years ended December 31,
2003, 2002, and 2001, respectively.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which SIGECO purchases fuel used for electric generation.
Amounts paid for such purchases for the years ended December 31, 2003, 2002, and
2001, totaled $77.0 million, $62.1 million, and $58.4 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. 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 and asset returns) are charged to individual subsidiaries through
the corporate allocation process discussed above. Neither 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, 2003, 2002, and 2001, periodic pension costs
totaling $2.4 million, $2.6 million and $2.3 million, respectively, was directly
charged by Vectren to the Company. For the years ended December 31, 2003, 2002,
and 2001, other periodic postretirement benefit costs totaling $0.5 million,
$0.6 million, and $0.5 million, respectively, was directly charged by Vectren to
the Company. As of December 31, 2003, and 2002, $26.4 million and $24.1 million,
respectively, is included in Deferred credits & other liabilities and represents
expense directly charged to the Company that is yet to be funded to Vectren.
The recently enacted Medicare Prescription Drug, Improvement and Modernization
Act of 2003 (the Medicare Act) provides a prescription drug benefit as well as a
federal subsidy to sponsors of certain retiree health care benefit plans. As
allowed by FASB Staff Position No. 106-1 (FSP 106-1), Vectren has elected to
defer reflecting the effects of the Medicare Act on the accumulated benefit
obligation and net periodic postretirement benefit cost in its 2003 financial
statements. Vectren's deferral election expires upon the occurrence of any event
that triggers a required remeasurement of plan assets or obligations, or upon
the issuance of specific authoritative guidance on the accounting for the
federal subsidy. Such guidance is pending and when issued could require the
Company to adjust previously reported information. Upon expiration of Vectren's
deferral or the issuance of guidance, Vectren's implementation of the Medicare
Act may impact SIGECO's financial statements.
Cash Management 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 5 regarding long-term and short-term intercompany
borrowing arrangements.
Guarantees of Parent Company Debt
Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $346 million commercial paper program, of which
approximately $184.4 million is outstanding at December 31, 2003, and VUHI's
$550 million unsecured senior notes outstanding at December 31, 2003. The
guarantees are full and unconditional and joint and several, and VUHI has no
subsidiaries other than the subsidiary guarantors.
Equity-Based Incentive Plans
The Company does not have equity-based compensation plans separate from Vectren.
An insignificant number of the Company's employees participate in Vectren's
equity-based compensation plans.
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 follow:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- --------------------------------------------------------------------------------
Current:
Federal $ 27,440 $ 30,300 $ 18,403
State 9,447 5,766 2,999
- --------------------------------------------------------------------------------
Total current taxes 36,887 36,066 21,402
- --------------------------------------------------------------------------------
Deferred:
Federal (2,358) (1,199) 1,640
State (2,534) (3,916) 180
- --------------------------------------------------------------------------------
Total deferred taxes (4,892) (5,115) 1,820
- --------------------------------------------------------------------------------
Amortization of investment tax credits (1,303) (1,346) (1,353)
- --------------------------------------------------------------------------------
Total income tax expense 30,692 29,605 21,869
Less: Income tax expense included
in other - net 52 (1,032) 221
- --------------------------------------------------------------------------------
Total income tax expense in operating
income $ 30,640 $ 30,637 $ 21,648
================================================================================
A reconciliation of the federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- --------------------------------------------------------------------------------
2003 2002 2001
- --------------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 % 35.0 %
State & local taxes, net of federal benefit 5.6 2.2 2.9
Amortization of investment tax credit (1.6) (1.5) (2.2)
All other - net (0.4) (2.4) (0.8)
- --------------------------------------------------------------------------------
Effective tax rate 38.6 % 33.3 % 34.9 %
================================================================================
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 follow:
At December 31,
- ------------------------------------------------------------------------------
(In thousands) 2003 2002
- ------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing
differences $ 111,404 $ 119,739
Regulatory assets recoverable through
future rates 15,614 23,352
Regulatory liabilities to be settled
through future rates (6,430) (16,018)
Employee benefit obligations (10,371) (13,585)
Other - net (266) (1,484)
- ------------------------------------------------------------------------------
Net noncurrent deferred tax liability 109,951 112,004
- ------------------------------------------------------------------------------
Current deferred tax liability:
Deferred fuel costs - net 3,691 4,680
- ------------------------------------------------------------------------------
Net current deferred tax liability 3,691 4,680
- ------------------------------------------------------------------------------
Net deferred tax liability $ 113,642 $ 116,684
==============================================================================
At December 31, 2003, and 2002, investment tax credits totaling $11.9 million
and $13.2 million, respectively, are included in Deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments. The Company has no tax credit carryforwards at December 31,
2003.
4. Transactions with Vectren Affiliates
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to Indiana Gas, the Ohio operations, Citizens Gas and
others. ProLiance also began providing service to SIGECO in 2002. ProLiance's
primary business is optimizing the gas portfolios of utilities and providing
services to large end use customers.
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2003 and 2002, totaled $72.8 million and $25.6 million,
respectively. Amounts owed to ProLiance at December 31, 2003, and 2002, for
those purchases were $8.3 million and $10.0 million, respectively, and are
included in Accounts payable to affiliated companies in the Balance Sheets.
Amounts charged by ProLiance for gas supply services are established by supply
agreements with each utility.
Other Affiliate Transactions Vectren has ownership interests in other affiliated
companies accounted for using the equity method of accounting that perform
underground construction and repair, facilities locating, and meter reading
services to the Company. For the years ended December 31, 2003, 2002, and 2001,
fees for these services and construction-related expenditures paid by the
Company to Vectren affiliates totaled $0.3 million, less than $0.1 million, and
zero in 2001, respectively. Amounts charged by these affiliates are market
based. Amounts owed to unconsolidated affiliates other than ProLiance totaled
less than $0.1 million and zero at December 31, 2003, and 2002, respectively.
5. Borrowing Arrangements & Other Financing Transactions
Short-Term Borrowings SIGECO mainly relies on the short-term borrowing
arrangements of VUHI for its short-term working capital needs. Borrowings,
including third party borrowings, outstanding at December 31, 2003, and 2002,
were $83.8 million and $39.4 million, respectively. The intercompany credit line
totals $150 million, but periodically may be limited by VUHI's available
capacity ($162 million of additional capacity at December 31, 2003) and is
subject to the same terms and conditions as VUHI's commercial paper program.
Short-term borrowings bear interest at VUHI's weighted average daily cost of
short-term funds. Additionally, at December 31, 2003, the Company has
approximately $5 million of short-term borrowing capacity with third parties to
supplement its intercompany borrowing arrangements, of which $4.2 million is
available. See the table below for interest rates and outstanding balances:
Year ended December 31,
- -------------------------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------------------------
Weighted average total outstanding during
the year payable to VUHI (in thousands) $ 41,456 $ 68,034 $ 34,791
Weighted average total outstanding during
the year payable to third parties (in thousands) $ 928 $ 1,875 $ 12,930
Weighted average interest rates during the year:
VUHI 1.31% 2.03% 5.24%
Bank loans 1.86% 2.56% 5.77%
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term follow:
At December 31,
- -------------------------------------------------------------------------------
(In thousands) 2003 2002
- -------------------------------------------------------------------------------
Senior Unsecured Notes Payable to VUHI:
2011, 6.625% $ 86,584 $ 86,574
2018, 5.75% 61,900 -
- -------------------------------------------------------------------------------
Total long-term debt payable to VUHI $ 148,484 $ 86,574
===============================================================================
First Mortgage Bonds Payable to Third Parties:
2003, 1978 Series B, 6.25%, tax exempt $ - $ 1,000
2016, 1986 Series, 8.875% 13,000 13,000
2023, Series, 7.60% - 45,000
2023, Series B, 6.00%, tax exempt 22,800 22,800
2025, 1993 Series, 7.625% - 20,000
2029, 1999 Senior Notes, 6.72% 80,000 80,000
2015, 1985 Pollution Control Series A, adjustable
rate presently 4.30%, tax exempt,
next rate adjustment: 2004 9,975 9,975
2025, 1998 Pollution Control Series A, adjustable
rate presently 4.75%, tax exempt, next rate
adjustment: 2006 31,500 31,500
'2024, 2000 Environmental Improvement Series A,
fixed in April 2003 at 4.65%, tax exempt,
weighted average for year: 3.69% 22,500 22,500
- -------------------------------------------------------------------------------
Total first mortgage bonds 179,775 245,775
- -------------------------------------------------------------------------------
Senior Unsecured Bonds Payable to Third Parties:
2020, 1998 Pollution Control Series B, fixed in
April 2003 at 4.50%, tax exempt, weighted
average for year: 4.16% 4,640 4,640
2030, 1998 Pollution Control Series B, fixed in
April 2003 at 5.00%, tax exempt, weighted
average for year: 4.48% 22,000 22,000
2030, 1998 Pollution Control Series C, adjustable
rate presently 5.00%, tax exempt, next rate
adjustment: 2006 22,200 22,200
- -------------------------------------------------------------------------------
Total senior unsecured bonds 48,840 48,840
- -------------------------------------------------------------------------------
Total long-term debt outstanding payable
to third parties 228,615 294,615
Long-term debt subject to tender (9,975) (26,640)
Current maturities of long-term debt - (1,000)
Unamortized debt premium & discount
& other - net (2,310) (2,737)
- -------------------------------------------------------------------------------
Long-term debt payable to third parties - net of
current maturities & debt subject to tender $ 216,330 $ 264,238
===============================================================================
Issuance Payable to VUHI in 2003
In 2003, the Company issued $61.9 million of long-term debt payable to VUHI. The
note has terms identical to the terms of notes issued by VUHI in July 2003
through a public offering. Those notes have an interest rate of 5.75% priced at
99.177% to yield 5.80% to maturity and are due August 2018. They have no sinking
fund requirements, and interest payments are due semi-annually. The notes may be
called by VUHI, in whole or in part, at any time for an amount equal to accrued
and unpaid interest, plus the greater of 100% of the principal amount or the sum
of the present values of the remaining scheduled payments of principal and
interest, discounted to the redemption date on a semi-annual basis at the
Treasury Rate, as defined in VUHI's indenture, plus 25 basis points.
Issuances Payable to VUHI in 2001 and 2002
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.
Debt Call
During 2003, the Company called two first mortgage bonds. The first bond had a
principal amount of $45.0 million, an interest rate of 7.60%, was originally due
in 2023, and was redeemed at 103.745% of its stated principal amount. The second
bond had a principal amount of $20.0 million, an interest rate of 7.625%, was
originally due in 2025, and was redeemed at 103.763% of the stated principal
amount. Pursuant to regulatory authority, the premiums paid to retire the net
carrying value of these notes totaling $2.4 million were deferred in Regulatory
assets. The proceeds to fund the early redemption were received from VUHI in the
form of new long-term debt discussed above and $25 million in additional equity.
To generate the initial proceeds to fund these transactions, in July 2003, VUHI
completed a public offering of long-term debt netting proceeds of approximately
$203 million, and, in August 2003, Vectren completed a public offering of common
stock netting proceeds of approximately $163 million.
Other Financing Transactions
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.
Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.
Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is one
percent 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. SIGECO intends to meet the 2004 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2004 is excluded from
Current liabilities in the Balance Sheets. At December 31, 2003, $502.0 million
of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.
There are no maturities and/or sinking fund requirements on long-term debt
during the five years following 2003.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. The put or call provisions are not
triggered by specific events, but are based upon dates stated in the note
agreements, such as when notes are re-marketed. Debt which may be put to the
Company during the years following 2003 (in millions) is $10.0 in 2004, zero in
2005, $53.7 in 2006, zero in 2007, zero in 2008, and $80.0 thereafter. Debt that
may be put to the Company within one year is classified as Long-term debt
subject to tender in current liabilities.
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, 2003, the Company was in
compliance with all financial covenants.
6. Cumulative Preferred Stock
Redemption of Preferred Stock
Nonredeemable preferred stock containing call options was redeemed 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, 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 of redeemable 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, there
were 75,000 shares outstanding.
The loss on redemption of $1.2 million in 2001 is reflected in Retained
earnings.
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, 2003,
and 2002, there were 2,277 shares and 3,437 shares outstanding, respectively.
7. Commitments & Contingencies
Commitments
Firm purchase commitments for commodities total (in millions) $26.3 in 2004 and
$8.4 in 2005. Firm purchase commitment for utility and non-utility plant total
$98.4 million.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 financial statements, the Company restated
its annual financial statements for 2000 and 2001, and its 2002 quarterly
results. The Company received an informal inquiry from the SEC with respect to
this restatement. In response, the Company met with the SEC staff and provided
information in response to their requests, with the most recent response
provided on July 26, 2003.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 8 regarding
environmental matters.
8. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.
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 currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by
investing in clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an eight percent
return on its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits, (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology, and (3) failing to notify the USEPA of
the modifications. In addition, the lawsuit alleged that the modifications to
the Culley Generating Station required SIGECO to begin complying with federal
new source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations in the
government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO has entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2
and 3 for additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at
Culley Unit 3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested
with the most recent correspondence provided on March 26, 2001.
Manufactured Gas Plants
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other potentially responsible parties involvement and insurance recoveries, that
may be incurred in connection with further investigation, and if necessary,
remedial work at the four SIGECO sites cannot be determined at this time.
9. Rate & Regulatory Matters
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 2004,
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.
10. Derivatives & Other Financial Instruments
Accounting Policy for Derivatives
The Company executes derivative contracts in the normal course of operations
while buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk.
When an energy contract that is a derivative is designated and documented as a
normal purchase or normal sale, it is exempted from mark-to-market accounting.
Otherwise, energy contracts and financial contracts that are derivatives 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.
The offset resulting from carrying the derivative at fair value on the balance
sheet is charged to earnings unless it qualifies as a hedge or is subject to
SFAS 71. When hedge accounting is appropriate, the Company assesses and
documents hedging relationships between the derivative contract and underlying
risks as well as its 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 or as an
adjustment to the underlying's basis for fair value hedges. The ineffective
portion of hedging arrangements is marked-to-market through earnings. The offset
to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or
liability. Market value for all derivative contracts is determined using quoted
market prices from independent sources. Following is a more detailed discussion
of the Company's use of mark-to-market accounting in three primary areas: asset
optimization, natural gas procurement, and interest rate management.
Asset Optimization
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. Substantially all of these
contracts are integrated with portfolio requirements around power supply and
delivery and are primarily short-term purchase and sale contracts that expose
the Company to limited market risk. Contracts with counter-parties subject to
master netting arrangements are presented net in the Balance Sheets. Asset
optimization contracts 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 Electric utility revenues.
Asset optimization contracts recorded at market value at December 31, 2003,
totaled $2.4 million of Prepayments & other current assets and $2.8 million of
Accrued liabilities, compared to $3.5 million of Prepayments & other current
assets and $4.2 million of Accrued liabilities at December 31, 2002.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.
Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income:
Year Ended December 31,
- ----------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152,795 $ 302,764 $ 101,418
Purchase contracts (126,969) (275,851) (74,311)
Mark-to-market gains (losses) 654 (3,585) 1,537
- ----------------------------------------------------------------------------
Net asset optimization revenue 26,480 23,328 28,644
- ----------------------------------------------------------------------------
Fuel for electric generation (8,203) (10,601) (9,539)
- ----------------------------------------------------------------------------
Asset optimization margin $ 18,277 $ 12,727 $ 19,105
============================================================================
Natural Gas Procurement Activity
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. 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. The Company mitigates these risks by
executing derivative contracts that manage the price of forecasted natural gas
purchases. These contracts are subject to regulation which allows for reasonable
and prudent hedging costs to be recovered through rates. When regulation is
involved, SFAS 71 controls when the offset to mark-to-market accounting is
recognized in earnings. The market value of natural gas procurement derivative
contracts at December 31, 2003, was not significant.
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 a change in the derivative's market value be
recognized currently in earnings unless specific hedge 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 or other comprehensive income, as appropriate.
Resulting from the adoption of SFAS 133, certain asset optimization 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 and did not impact the Company's cash flow hedges because they had
no value on the date of adoption.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments follow:
At December 31,
- -------------------------------------------------------------------------------------
2003 2002
---------------------- ----------------------
Carrying Est. Fair Carrying Est. Fair
(In thousands) Amount Value Amount Value
- ----------------------------------- --------- --------- --------- ---------
Long term debt $ 228,615 $ 239,407 $ 294,615 $ 313,202
Long term debt payable to VUHI 148,484 159,927 86,574 93,820
Short-term borrowings 830 830 - -
Short-term borrowings from VUHI 82,929 82,929 39,419 39,419
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 or over a 15-year period. Accordingly, any reacquisition would not be
expected to have a material effect on the Company's financial position or
results of operations.
11. Segment Reporting
The Company has two operating segments: (1) Gas Utility Services and (2)
Electric Utility Services as defined by SFAS 131 "Disclosure About Segments of
an Enterprise and Related Information" (SFAS 131). Gas Utility Services provides
natural gas distribution and transportation services in southwestern Indiana,
including counties surrounding Evansville. Electric Utility Services provides
electricity primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. For its operations the Company uses after
tax operating income as a measure of profitability, consistent with regulatory
reporting requirements. The Company cross manages its margin, other operating
expenses, and capital expenditures as separated between Energy Delivery, which
includes the gas and electric transmission and distribution functions, and Power
Supply, which includes the power generating and marketing operations. The
Company makes decisions on finance and dividends at the corporate level.
Information related to the Company's business segments is summarized below:
Year Ended December 31,
- ------------------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- ------------------------------------------------------------------------------------
Revenues
Electric Utility Services $ 335,694 $ 328,620 $ 308,458
Gas Utility Services 102,736 84,392 98,580
- ------------------------------------------------------------------------------------
Total operating revenues $ 438,430 $ 413,012 $ 407,038
====================================================================================
Profitability Measure
Operating Income
Electric Utility Services $ 63,767 $ 73,152 $ 56,490
Gas Utility Services 4,856 4,582 308
- ------------------------------------------------------------------------------------
Total operating income $ 68,623 $ 77,734 $ 56,798
====================================================================================
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services $ 42,627 $ 40,003 $ 38,691
Gas Utility Services 5,022 5,095 4,596
- ------------------------------------------------------------------------------------
Total depreciation & amortization $ 47,649 $ 45,098 $ 43,287
====================================================================================
Income Taxes
Electric Utility Services $ 29,808 $ 27,500 $ 21,058
Gas Utility Services 832 3,137 590
- ------------------------------------------------------------------------------------
Total income taxes $ 30,640 $ 30,637 $ 21,648
====================================================================================
At December 31,
- -----------------------------------------------------------------------
(In thousands) 2003 2002
- -----------------------------------------------------------------------
Assets
Electric Utility Services $ 974,576 $ 891,612
Gas Utility Services 157,146 177,982
- -----------------------------------------------------------------------
Total assets $1,131,722 $1,069,594
=======================================================================
Year Ended December 31,
- ------------------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- ------------------------------------------------------------------------------------
Capital Expenditures
Electric Utility Services $ 124,058 $ 88,804 $ 69,833
Gas Utility Services 8,362 943 7,927
- ------------------------------------------------------------------------------------
Total capital expenditures $ 132,420 $ 89,747 $ 77,760
====================================================================================
12. Additional Operational & Balance Sheet Information
Other - net in the Statements of Income consists of the following:
Year ended December 31,
- ------------------------------------------------------------------------------------
(In thousands) 2003 2002 2001
- ------------------------------------------------------------------------------------
AFUDC $ 4,767 $ 3,679 $ 3,024
Other income 1,699 2,394 5,923
Other expense (1,418) (1,279) (3,318)
- ------------------------------------------------------------------------------------
Total other - net $ 5,048 $ 4,794 $ 5,629
====================================================================================
Accrued liabilities in the Balance Sheets consist of the following:
At December 31,
- -----------------------------------------------------------------------
(In thousands) 2003 2002
- -----------------------------------------------------------------------
Accrued taxes $ 15,979 $ 8,707
Deferred income taxes 3,691 4,680
Accrued interest 5,710 6,127
Refunds to customers & customer deposits 5,124 4,576
Accrued salaries & other 8,115 7,157
- -----------------------------------------------------------------------
Total accrued liabilities $ 38,619 $ 31,247
=======================================================================
13. Special Charges for 2001
Restructuring & Related Charges
As part of continued cost saving efforts, in June 2001, Vectren's management and
the 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 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.
The $4.4 million of severance and related costs included $0.8 million of
non-cash pension costs. 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.
Employee severance and related costs are associated with approximately 40
employees. Employee separation benefits include severance, healthcare, and
outplacement services. During 2001, 37 employees had exited the business. The
restructuring program was completed during 2001, except for the departure of the
remaining employees impacted by the restructuring which occurred during 2002.
At the beginning of 2002, 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 2003 and 2002, the accrual for
severance did not substantially change. At December 31, 2003, and 2002, the
restructuring accrual was $0.6 million and $0.9 million, respectively. The
restructuring accrual is included in Accrued liabilities.
Merger & Integration Costs
Merger and integration costs incurred for the year ended December 31, 2001,
totaled $0.6 million. Those costs related primarily to transaction costs,
severance, and other merger and acquisition integration activities. 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. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
14. Impact of Recently Issued Accounting Guidance
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
adoption of SFAS 150 on January 1, 2004, did not affect the Company's results of
operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. Although management is
still evaluating the impact of FIN 46 and related Staff Positions on its
financial position and results of operations, the adoption is not expected to
have a material effect.
Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.
15. Subsequent Event
On March 12, 2004, SIGECO (d/b/a Vectren Energy Delivery of Indiana, Inc.) filed
a petition with the IURC to adjust its base rates and charges for its gas
distribution business in southwestern Indiana. If the filing is approved, SIGECO
expects to increase its base (non-gas cost) rates by approximately $5.7 million
to cover the ongoing cost of operating and maintaining the approximately
3,000-mile distribution and storage system used to serve more than 110,000
customers. If finalized by the OUCC and ultimately approved by the IURC, the
agreement in principle would result in about a 5 percent increase for the
typical SIGECO residential customer who uses natural gas to heat his/her home.
The proposal will not affect the electric portion of the Company's customer
bills.
The petition only addresses "non-gas" costs, which are incurred to build,
operate and maintain the pipes, other equipment and systems that are used to
deliver gas. The petition indicates that SIGECO has reached an agreement in
principle with the OUCC regarding the proposed changes to the rates and charges.
The agreement in principle further provides for SIGECO's recovery through a
tracking mechanism of costs required to comply with a new federal law dealing
with pipeline safety.
As required by the regulatory process, SIGECO will be required to submit
information substantiating the proposed adjustment to its base rates. During the
processing of the case by the IURC, there will also be one or more public
hearings conducted regarding the proposal. The timing and ultimate outcome of
this regulatory initiative is uncertain.
16. Quarterly Financial Data (Unaudited)
Quarterly operating revenues presented below have been adjusted to reflect the
adoption of EITF 03-11. See Note 10 to the financial statements for further
information on the adoption of EITF 03-11. 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
2003 and 2002 follows:
- ----------------------------------------------------------------------------
(In thousands) Q1 Q2 Q3 Q4
- ----------------------------------------------------------------------------
2003
Results of Operations:
Operating revenues $135,067 $89,600 $106,257 $107,506
Operating margin 68,325 56,685 71,328 66,016
Operating income 17,883 12,781 21,361 16,598
Net income applicable to
common shareholder 13,381 6,050 16,182 13,221
2002
Results of Operations:
Operating revenues $ 99,945 $94,241 $108,636 $110,190
Operating margin 61,207 59,290 78,766 63,328
Operating income 15,739 13,225 27,013 21,757
Net income applicable to
common shareholder 11,435 9,439 22,212 16,241
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9a. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2003, the Company carried out an evaluation under the
supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer of the effectiveness and the design and operation of the
Company's disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective at providing
reasonable assurance that material information relating to the Company required
to be disclosed by the Company in its filings under the Securities Exchange Act
of 1934 (Exchange Act) is brought to their attention on a timely basis.
Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-15(e) and 15d-15(e), are controls and other procedures of the Company that
are designed to ensure that information required to be disclosed by the Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC's rules and forms. "Disclosure controls and procedures" include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate, to allow timely decisions regarding required
disclosure.
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2003, there have been no significant
changes to the Company's internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, the
Company's internal control over financial reporting.
Internal control over financial reporting is defined by the SEC in Final Rule:
Management's Reports on Internal Control Over Financial Reporting and
Certification of Disclosure in Exchange Act Periodic Reports. The final rule
defines internal control over financial reporting as a process designed by, or
under the supervision of, the registrant's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
registrant's board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that: (1) pertain to the maintenance of records that in reasonable
detail accurately and fairly reflect the transactions and dispositions of the
assets of the registrant, (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the registrant are being made only in accordance with
authorizations of management and directors of the registrant, and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the registrant's assets that could have a
material effect on the financial statements.
PART 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.
Vectren's Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Nominating and Corporate Governance Committees, and its Code of
Ethics covering Vectren's directors, officers and employees are available on
Vectren's website, www.vectren.com, and a copy will be mailed upon request to
Investor Relations, Attention: Steve Schein, 20 N.W. Fourth Street, Evansville,
Indiana 47708. Vectren intends to disclose any amendments to the Code of Ethics
or waivers of the Code of Ethics on behalf of its directors or officers
including, but not limited to, the principal executive officer, principal
financial officer, principal accounting officer or controller and persons
performing similar functions on Vectren's website at the Internet address set
forth above promptly following the date of such amendment or waiver and such
information will also be available by mail upon request to Investor Relations,
Attention: Steve Schein, 20 N.W. Fourth Street, Evansville, Indiana 47708.
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
AND RELATED STOCKHOLDER MATTERS
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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following tabulation shows the audit and non-audit fees paid to Deloitte &
Touche, LLP (Deloitte) for the years ending December 31, 2003, and December 31,
2002. The fees presented below represent total fees incurred by Vectren
Corporation, the ultimate parent of the Company. The fees represent amounts
applicable to audits and audit-related and tax services for all of Vectren
Corporation and its subsidiary companies.
- --------------------------------------------------------------------------
2003 2002
- --------------------------------------------------------------------------
Audit Fees(1) $ 1,187,950 $ 350,000
Audit-Related Fees(2) 234,000 135,555
Tax Fees(3) 92,000 73,625
All Other Fees(4) - -
- --------------------------------------------------------------------------
Total Fees Paid to Deloitte $ 1,513,950 $ 559,180
==========================================================================
(1) Aggregate fees incurred payable to Deloitte for professional services
rendered for the audit of Vectren's 2003 fiscal year annual financial
statements and the review of financial statements included in Vectren's
Forms 10-Q filed during Vectren's 2003 fiscal year. This includes fees
incurred for audit services related to certain of Vectren's subsidiaries in
connection with the audit of Vectren's financial statements. The amount
also includes fees paid to Deloitte for the audits of Vectren's 2000 and
2001 financial statements and the completion of the audit of the 2002
financial statements. The 2002 amount relates to the audit of Vectren's
2002 financial statements and reviews of Vectren's Forms 10-Q filed during
the 2002 fiscal year.
(2) Audit related fees consisted principally of consultation on various
accounting issues in 2003 and 2002, and reviews related to various
financing transactions completed during 2003.
(3) Tax fees consisted of fees paid to Deloitte for tax planning and
review of tax returns of Vectren.
(4) All Other Fees - None.
Pursuant to its charter, Vectren's Audit Committee is responsible for selecting,
approving professional fees, and overseeing the independence, qualifications and
performance of the independent auditors. The Audit Committee has adopted a
formal policy with respect to the pre-approval of audit and permissible
non-audit services provided by the independent auditors. Pre-approval is
assessed on a case-by-case basis. In assessing requests for services to be
provided by the independent auditors, the Audit committee considers whether such
services are consistent with the auditors' independence, whether the independent
auditors are likely to provide the most effective and efficient service based
upon their familiarity with Vectren, and whether the service could enhance
Vectren's ability to manage or control risk or improve audit quality. The
audit-related, tax, and other services provided by Deloitte in the last fiscal
year and related fees were approved by the Audit Committee in accordance with
this policy.
PART IV
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, 2003, 2002, and 2001, the Company's Schedule II
- -- Valuation and Qualifying Accounts Financial Statement Schedules is presented
on page 48. 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 attached to this filing filed
electronically with the SEC are listed on page 49.
Exhibits for the Company are listed in the Index to Exhibits
beginning on page 50.
Reports On Form 8-K During The Last Calendar Quarter
On October 22, 2003, 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, 2003. The
financial information was released to the public through this filing.
Item 7. Exhibits
99-1 - Press Release - Vectren Corporation Reports Third
Quarter 2003 Results
99-2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
Item 12. Results of Operations and Financial Condition
On December 11, 2003, the Company filed a Current Report on Form 8-K with
respect to an analyst meeting where a discussion of Vectren Corporation's
current financial and operating results and plans for the future will occur.
Item 9. Regulation FD Disclosure
Index to Exhibits
99-1 - Press Release - Vectren Corporation Provides 2004
Earnings Guidance
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 2003 - Accumulated provision for
uncollectible accounts $ 3,662 $ 903 $ - $ 3,363 $ 1,202
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
OTHER RESERVES:
Year 2001 - Reserve for merger and
integration charges $ 526 $ - $ - $ 526 $ -
Year 2003 - Reserve for restructuring
costs $ 850 $ - $ - $ 250 $ 600
Year 2002 - Reserve for restructuring
costs $ 180 $ - $ 670 $ - $ 850
Year 2001 - Reserve for restructuring
costs $ - $ 3,321 $ - $ 3,141 $ 180
Southern Indiana Gas and Electric Company
2003 Form 10-K
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
See Page 50 of this Annual Report on Form 10-K for a complete list of exhibits.
Exhibit
Number Document
4.5 Promissory Note for Long-Term Loans dated September 1, 2003, between
Southern Indiana Gas and Electric Company and Vectren Utility Holdings,
Inc.
31.1 Chief Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Chief Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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 and designated
in Form 10-K for the year ended December 31, 2002, File No. 1-3553, as
Exhibit 3.1.)
3.2 Amended and Restated Code of By-Laws of Southern Indiana Gas and
Electric Company as of January 16, 2003. (Filed and designated in Form
10-K for the year ended December 31, 2002, File No. 1-3553, as Exhibit
3.2.)
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, among 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, among 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); Third Supplemental Indenture, among 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 July 24, 2003, 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 and designated in Form 10-K for the year ended
December 31, 2002, File No. 1-3553, as Exhibit 4.4.)
4.5 Promissory Note for Long-Term Loans dated September 1, 2003, between
Southern Indiana Gas and Electric Company and Vectren Utility
Holdings, Inc. (Filed herewith.)
10. Material Contracts
10.1 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.) First Amendment, effective April 16, 1997 (Filed and
designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as
Exhibit 10.29.).
10.2 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.)
10.3 Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a
Select Group of Management Employees as amended and restated effective
December 1, 1998. (Filed and designated in Form 10-Q for the quarterly
period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.)
10.4 Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective
January 1, 1999. (Filed and designated in Form 10-Q for the quarterly
period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.)
10.5 Indiana Energy, Inc. Executive Restricted Stock Plan as amended and
restated effective October 1, 1998. (Filed and designated in Form 10-K
for the fiscal year ended September 30, 1998, File No. 1-9091, as
Exhibit 10-O.) First Amendment, effective December 1, 1998 (Filed and
designated in Form 10-Q for the quarterly period ended December 31,
1998, File No. 1-9091, as Exhibit 10-I.).
10.6 Indiana Energy, Inc. Director's Restricted Stock Plan as amended and
restated effective May 1, 1997. (Filed and designated in Form 10-Q for
the quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit
10-B.) First Amendment, effective December 1, 1998. (Filed and
designated in Form 10-Q for the quarterly period ended December 31,
1998, File No. 1-9091, as Exhibit 10-J.) Second Amendment, Plan
renamed the Vectren Corporation Directors Restricted Stock Plan
effective October 1, 2000. (Filed and designated in Form 10-K for the
year ended December 31, 2000, File No. 1-15467, as Exhibit 10-34.)
Third Amendment, effective March 28, 2001. (Filed and designated in
Form 10-K for the year ended December 31, 2000, File No. 1-15467, as
Exhibit 10-35.)
10.7 Vectren Corporation At Risk Compensation Plan effective May 1, 2001.
(Filed and designated in Vectren Corporation's Proxy Statement dated
March 16, 2001, File No. 1-15467, as Appendix B.)
10.8 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.)
10.9 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.)
10.10 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.)
10.11 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.)
10.12 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.)
10.13 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.)
10.14 Gas Sales and Portfolio Administration Agreement between Southern
Indiana Gas and Electric Company and ProLiance Energy, LLC, effective
September 1, 2002. (Filed and designated in Form 10-K, for the year
ended December 31, 2003, File No 1-1567, as Exhibit 10.16.)
10.15 Coal Supply Agreement for F.B. Culley Generating Station between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
dated December 17, 1997 and effective January 1, 1998. (Filed and
designated in Form 10-K, for the year ended December 31, 2003, File No
1-1567, as Exhibit 10.18.). Portions of the document has been omitted
pursuant to a request to a request for confidential treatment.
10.16 Amendment 1, effective January 1, 2003, to Coal Supply Agreement
between Southern Indiana Gas and Electric Company and Vectren Fuels,
Inc originally dated December 17, 1997. . (Filed and designated in
Form 10-K, for the year ended December 31, 2003, File No 1-1567, as
Exhibit 10.19.)
10.17 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick
County, Indiana, and West Franklin, Posey County, Indiana between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc.,
dated January 19, 2000. . (Filed and designated in Form 10-K, for the
year ended December 31, 2003, File No 1-1567, as Exhibit 10.20.)
10.18 Amendment 1, effective January 1, 2004, to Coal Supply Agreement
between Southern Indiana Gas and Electric Company and Vectren Fuels,
Inc originally dated January 19, 2000. . (Filed and designated in Form
10-K, for the year ended December 31, 2003, File No 1-1567, as Exhibit
10.21.)
10.19 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated October
1, 2003. . (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No 1-1567, as Exhibit 10.22.)
10.20 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January
1, 2004. . (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No 1-1567, as Exhibit 10.23.)
21. Subsidiaries of the Company
Not applicable.
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 Of The
Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1
Chief Financial Officer Certification Pursuant to Section 302 Of The
Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is
attached hereto as Exhibit 32.1
99. Additional Exhibits
99.1 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.)
99.2 Amended and Restated Code of By-Laws of Vectren Corporation as of
October 29, 2003. (Filed and designated in Quarterly Report on Form 10-Q
filed November 13, 2003, File No. 1-15467, as Exhibit 3.1.)
99.3 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.)
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 25, 2004
/s/ Niel C. Ellerbrook
-----------------------------------------------
Niel C. Ellerbrook,
Chairman, Chief Executive Officer, and Director
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 25, 2004
- -------------------------- Officer, & Director -----------------
Niel C. Ellerbrook (Principal Executive Officer)
/s/ Jerome A. Benkert, Jr. Executive Vice President, February 25, 2004
- -------------------------- Chief Financial Officer, & -----------------
Jerome A. Benkert, Jr. Director (Principal Financial
Officer)
/s/ M. Susan Hardwick Vice President, Controller & February 25, 2004
- -------------------------- Director (Principal Accounting -----------------
M. Susan Hardwick Officer)
/s/ Ronald E. Christian Director February 25, 2004
- -------------------------- -----------------
Ronald E. Christian
/s/ William S. Doty Director February 25, 2004
- -------------------------- -----------------
William S. Doty
/s/ Robert L. Goocher Director February 25, 2004
- -------------------------- -----------------
Robert L. Goocher