UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to ________________________
Commission file number: 1-16739
VECTREN UTILITY HOLDINGS, INC.
------------------------------
(Exact name of registrant as specified in its charter)
INDIANA 35-2104850
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(State or other jurisdiction of incorporation (IRS Employer
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
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7 1/4% Senior Notes, due 10/15/2031 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Name of each exchange on which registered
- ---------------------------- -----------------------------------------
Common Stock - 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
28, 2002 was zero. All shares outstanding of the Registrant's common stock were
held by Vectren Corporation.
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 10 March 15, 2003
- ---------------------------------- ---------------- ------------------
Class Number of Shares Date
Documents Incorporated by Reference
Certain information in Vectren Corporation's Definitive Proxy Statement for the
2003 Annual Meeting of Stockholders, which was filed with the Securities and
Exchange Commission pursuant to Regulation 14A, on March 27, 2003, is
incorporated by reference in Part III of this Form 10-K.
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal
during construction units
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
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of PUCO: Public Utilities Commission
Environmental Management of Ohio
IURC: Indiana Utility Regulatory SFAS: Statement of Financial
Commission Accounting Standards
MCF / BCF: millions / billions USEPA: United States Environmental
of cubic feet Protection Agency
MDth / MMDth: thousands /millions Throughput: combined gas sales and
of dekatherms gas transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ............................................................1
2 Properties ..........................................................6
3 Legal Proceedings....................................................7.
4 Submission of Matters to Vote of Security Holders....................7
Part II
5 Market for the Company's Common Equity and Related
Stockholder Matters ...............................................8
6 Selected Financial Data..............................................9
7 Management's Discussion and Analysis of Results
of Operations and Financial Condition.............................10
7A Qualitative and Quantitative Disclosures About.
Market Risk......................................................29
8 Financial Statements and Supplementary Data.........................31
9 Change in and Disagreements with Accountants on
Accounting and Financial Disclosure...............................75
Part III
10 Directors and Executive Officers of the Registrant..................75
11 Executive Compensation..............................................76
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters........................78
13 Certain Relationships and Related Transactions......................80
Part IV
14 Controls and Procedures.............................................81
15 Exhibits, Financial Statement Schedules, and
Reports on Form 8-K...............................................81
Signatures..........................................................84
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge, including those of its wholly owned subsidiaries, through its
website at www.vectren.com, or by request, directed to Investor Relations at the
mailing address, phone number, or email address that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812) 491-4000 Steven M. Schein
Evansville, Indiana Vice President, Investor Relations
47702-0209 sschein@vectren.com
Explanatory Note
This Amendment No. 1 to Form 10-K filed on Form 10-K/A for the year ended
December 31, 2002, is being filed to reflect a transfer of net assets to Vectren
Utility Holdings, Inc. (the Company or VUHI) from Vectren Corporation (Vectren)
effective on January 1, 2003. The transfer requires the retroactive restatement
of VUHI's consolidated financial statements for all periods presented under
accounting rules governing combinations of entities under common control.
Accordingly the consolidated financial statements, included in Item 8 of Part
II, have been retroactively restated to reflect the combined financial position
and combined results of operations and cash flows for all periods presented,
giving effect to the transfer as if the combination had occurred at the
beginning of the earliest period presented. The effects of the transaction are
more fully described in Note 3 to the consolidated financial statements of Item
8 of Part II. This amendment also clarifies various disclosures in the Results
of Operations and Financial Condition sections of Item 7 of Part II and the
Consolidated Statements of Cash Flows and Notes 2, 3, 6, 10, 11, and 17 to the
consolidated financial statements of Item 8 of Part II. All other information
contained herein is as of February 26, 2003, and does not reflect any events or
changes in information that may have occurred subsequent to February 26, 2003.
For a discussion of events and developments relating to periods subsequent to
February 26, 2003, see the Company's reports filed with the Securities and
Exchange Commission for such subsequent periods, including the Company's
Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003.
PART I
ITEM 1. BUSINESS
Description of the Business
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the
Ohio operations. VUHI also has assets that provide information technology and
other services to the utilities.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO 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. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
Vectren is an energy and applied technology holding company headquartered in
Evansville, Indiana. The Company was organized on June 10, 1999 solely for the
purpose of effecting the merger of Indiana Energy and 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).
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.
Acquisition of the Gas Distribution Assets of The Dayton Power and Light Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.
The Company acquired the natural gas distribution assets as a tenancy in common
through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio,
Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana
Gas holds a 47% undivided ownership interest. VEDO is the operator of the
assets, and these operations are referred to as "the Ohio operations."
Narrative Description of the Business
The Company segregates its businesses into gas utility services, electric
utility services and other operations. The Gas Utility Services segment includes
the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes the operations of SIGECO's electric
transmission and distribution services, which provides electricity primarily to
southwestern Indiana, and SIGECO's power generating and power marketing
operations. Other Operations provide information technology and other support
services to those utility operations.
At December 31, 2002, the Company had $2.6 billion in total assets, with $1.5
billion (61%) attributed to the gas utility operations, $0.9 billion (33%)
attributed to the electric utility operations, and $0.2 billion (6%) attributed
to other operations. Net income for the year ended 2002 was $97.1 million with
$38.9 million attributed to gas utility operations, $55.6 million attributed to
electric utility operations, and $2.6 million to other operations. Net income,
as restated, for the year ended 2001 was $44.8 million. The year ending December
31, 2001 included nonrecurring charges with an after tax impact of $15.9
million. Nonrecurring items net of tax in 2001 included $7.7 million of merger
and integration costs, $9.3 million of restructuring costs, and a $1.1 million
gain resulting from a cumulative effect of change in accounting principle.
For further information refer to Note 3 regarding the restatement of previously
reported information, Note 14 regarding the segments' activities and assets,
Note 15 regarding special charges in 2001 and 2000, and Note 12 regarding the
cumulative effect of change in accounting principle included under Item 8
Financial Statements and Supplementary Data. Following is a more detailed
description of the gas and electric utility operations. The Company's other
operations are not significant.
Gas Utility Services
At December 31, 2002, the Company supplied natural gas service to 966,761
Indiana and Ohio customers, including 882,151 residential, 80,483 commercial,
and 4,127 industrial and other customers. This represents customer base growth
of 1.4% compared to 2001.
The Company's service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served include
automotive assembly, parts and accessories, feed, flour and grain processing,
metal castings, aluminum products, appliance manufacturing, polycarbonate resin
(Lexan) and plastic products, gypsum products, electrical equipment, metal
specialties, glass, steel finishing, pharmaceutical and nutritional products,
gasoline and oil products, and coal mining. The largest Indiana communities
served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and
Richmond. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2002, natural gas revenues were approximately
$909.0 million of which residential customers accounted for 67%, commercial 23%,
and industrial and other 10%, respectively.
The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) was 207,693 MDth for the year ended December 31, 2002. Transported
gas represented 44% of total throughput. Rates for transporting gas provide for
the same margins generally earned by selling gas under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company owns and operates seven
underground gas storage fields and six liquefied petroleum air-gas manufacturing
plants. The Company also contracts with ProLiance and other parties to ensure
availability of gas. Natural gas purchased from suppliers is injected into
storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately 909,500
MCF of gas per day can be withdrawn during peak demand periods from all sources
and for all utilities.
Gas Purchases
In 2002, the Company purchased natural gas from multiple suppliers including
ProLiance Energy, LLC (ProLiance). ProLiance is an unconsolidated, nonregulated,
energy marketing affiliate of Vectren and Citizens Gas and Coke Utility. (See
Note 5 in the Company's consolidated financial statements included in Item 8
Financial Statements and Supplementary Data regarding transactions with
ProLiance ). The Company purchased 120,764 MDth volumes of gas in 2002 at an
average cost of $4.57 per Dth, of which 94% was purchased from ProLiance. The
average cost of gas per Dth purchased for the last five years was; $4.57 in
2002; $5.83 in 2001; $5.60 in 2000; $3.58 in 1999; and $3.53 in 1998.
Regulatory and Environmental Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment and issues
involving manufactured gas plants.
Electric Utility Services
At December 31, 2002, the Company supplied electric service to 134,057 Indiana
customers, including 116,979 residential, 16,881 commercial, and 197 industrial
and other customers. This represents customer base growth of 0.6% compared to
2001. In addition, the Company is obligated to provide for firm power
commitments to several municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.
The principal industries served include polycarbonate resin (Lexan) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the year ended December 31, 2002, retail and firm wholesale electricity
sales totaled 6,187,132 MWh, resulting in revenues of approximately $305.3
million. Residential customers accounted for 35% of 2002 revenues; commercial
26%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 10,711,614 MWh through non-firm wholesale contracts in 2002 generating
revenue of $302.8 million.
Generating Capacity
Installed generating capacity as of December 31, 2002 was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and gas or oil-fired
turbines used for peaking or emergency conditions provide 295 MW. New peaking
capacity of 80 MW fueled by natural gas was added during 2002 and was available
for the summer peaking season.
In addition to its generating capacity, throughout 2002 the Company had 82MW
available under firm contracts and 95 MW available under interruptible
contracts. On January 1, 2003, a 50 MW firm contract expired and was no longer
required and therefore not renewed.
The Company has interconnections with Louisville Gas and Electric Company,
Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability may be impacted because the Company, as a
member of the Midwest Independent System Operator (MISO), has turned over
operational control over the interchange facilities and its own transmission
assets like many other Midwestern electric utilities to the MISO. See Item 7
Management's Discussion and Analysis of Results of Operations and Financial
Condition regarding the Company's participation in MISO.
Total load for each of the years 1998 through 2002 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
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Date of summer peak load 8/5/02 7/31/01 8/17/00 7/6/99 7/21/98
------ ------- ------- ------ -------
Total load at peak (1) 1,258 1,234 1,212 1,255 1,154
Generating capability 1,351 1,271 1,256 1,256 1,256
Firm purchase supply 82 82 75 - -
Interruptible contracts 95 95 95 95 85
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Total power supply capacity 1,528 1,448 1,426 1,351 1,341
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Reserve margin at peak 21% 17% 18% 8% 16%
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(1) The total load at peak is increased 25MW in 2002, 2001, 1999, and 1998 from
the total load actually experienced. The additional 25 MW represents load
that would have been incurred if summer cycler programs had not been
activated. The 25 MW is also included in the interruptible contract portion
of the Company's total power supply capacity. On the date of peak in 2000,
summer cycler programs were not activated.
The winter peak load of the 2001-2002 season of approximately 854 MW occurred on
March 4, 2002 and was 8% lower than the previous winter peak load of
approximately 925 MW which occurred on December 19, 2000.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO and supplies power requirements to the United States Department of
Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for, any
available power in excess of the DOE contract demand. At the present time, the
DOE contract demand is essentially zero. Because of this decreased demand, the
Company's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.
Fuel Costs and Purchased Power
Electric generation for 2002 was fueled by coal (97.5%) and natural gas (2.5%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of Vectren. Approximately 3.1 million tons of coal was purchased for
generating electricity during 2002. Of this amount, Vectren Fuels, Inc. supplied
2.7 million tons from its mines and third party purchases. The average cost of
coal consumed in generating electrical energy for the years 1998 through 2002
follows:
Year
--------------------------------------------------------------
Avg. Cost Per 2002 2001 2000 1999 1998
------- ------- ------- ------- -------
Ton $ 23.50 $ 22.48 $ 22.49 $ 21.88 $ 21.34
MWh 11.00 10.53 10.39 10.13 9.97
The Company will also purchase power as needed from the wholesale market to
supplement its generation capabilities in periods of peak demand; however, the
majority of power purchased through the wholesale market is used to optimize and
hedge the Company's sales to non-firm wholesale customers. Volumes purchased in
2002 totaled 10,362,196 MWh.
Regulatory and Environmental Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment, and a
discussion of the Company's Clean Air Act Compliance Plan, and the USEPA's
lawsuit against SIGECO for alleged violations of the Clean Air Act.
Competition
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding competition within the public utility industry for
the Company's regulated Indiana and Ohio operations.
Personnel
As of December 31, 2002, the Company and its consolidated subsidiaries had 1,581
employees, of which 896 are subject to collective bargaining arrangements.
In August 2001, the Company signed a new four-year labor agreement, ending in
September 2005 with Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The new agreement provides for annual wage increases of 3.25%, a new
401(k) savings plan and improvements in the areas of health insurance and
pension benefits.
Concurrent with the Company's purchase of the Ohio operations, VEDO and Local
Union 175, Utility Workers Union of America approved a labor agreement effective
November 2000, through October 2005. The agreement provides a 3.25% wage
increase each year, and the other terms and conditions are substantially the
same as the agreement reached between the Utility Workers Union and Dayton Power
and Light Company in August of 2000.
In July 2000, SIGECO signed a new four-year labor agreement with Local 702 of
the International Brotherhood of Electrical Workers, ending June 2004. The new
agreement provides a 3% wage increase for each year in addition to improvements
in health care coverage, retirement benefits and incentive pay.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four gas storage fields located in Indiana
covering 58,489 acres of land with an estimated ready delivery from storage
capability of 4.2 BCF of gas with delivery capabilities of 119,160 MCF per day.
Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas
manufacturing plants located in Indiana with the ability to store 1.5 million
gallons of propane and manufacture for delivery 31,000 MCF of manufactured gas
per day. In addition to its owned storage and manufacturing and daily delivery
capabilities, Indiana Gas contracts for a maximum of 17.2 BCF of gas
availability across various pipelines with a delivery capability of 283,298 MCF
per day. Indiana Gas' gas delivery system includes 11,590 miles of distribution
and transmission mains, all of which are in Indiana except for pipeline
facilities extending from points in northern Kentucky to points in southern
Indiana so that gas may be transported to Indiana and sold or transported by
Indiana Gas to ultimate customers in Indiana.
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 8.7 BCF of gas with delivery capabilities of 124,748 MCF per day.
In addition to its owned storage and daily delivery capabilities, SIGECO
contracts for a maximum of 0.5 BCF of gas availability across various pipelines
with a delivery capability of 18,753 MCF per day. SIGECO's gas delivery system
includes 2,996 miles of distribution and transmission mains, all of which are
located in Indiana.
The Ohio operations owns and operates three liquefied petroleum (propane)
air-gas manufacturing plants and one cavern for propane storage, all of which
are located in Ohio. The plants and cavern can store 3.7 million gallons of
propane, and the plants can manufacture for delivery 51,047 MCF of manufactured
gas per day. In addition to its owned storage and manufacturing and daily
delivery capabilities, the Ohio operations contracts for a maximum of 13.2 BCF
of gas availability across various pipelines with a delivery capability of
281,491 MCF per day. The Ohio operations' gas delivery system includes 5,176
miles of distribution and transmission mains, all of which are located in Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2002, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50MW and Broadway Avenue Unit 2,
65MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 829 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,221.2 megavolt amperes (Mva). The electric distribution
system includes 3,212 pole miles of lower voltage overhead lines and 275 trench
miles of conduit containing 1,541 miles of underground distribution cable. The
distribution system also includes 95 distribution substations with an installed
capacity of 1,939.5 Mva and 51,030 distribution transformers with an installed
capacity of 2,352.3 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture
dated as of April 1, 1932 between SIGECO and Bankers Trust Company, as Trustee,
and Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 10 of its consolidated
financial statements included in Item 8 Financial Statements and Supplementary
Data regarding the Clean Air Act and related legal proceedings. Legal
proceedings involving transactions with ProLiance were substantially resolved
during 2002. See Note 5 for a discussion of regulatory matters related to
ProLiance.
ITEM 4. Submission of Matters to Vote of Security Holders
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Common Stock
Market Price
All of the outstanding shares of VUHI's common stock are owned by Vectren.
VUHI's common stock is not traded.
There are no outstanding options or warrants to purchase VUHI's common equity or
securities convertible into VUHI's common equity. Additionally, VUHI has no
plans to publicly offer any of its common equity.
Dividends Paid to Parent
During 2002, VUHI paid dividends to its parent company of $17.9 million in each
of the first three quarters and $18.0 million in the fourth quarter.
During 2001, VUHI paid dividends to its parent company of $16.5 million, $14.3
million, $15.9 million, and $18.2 million in the first, second, third, and
fourth quarters, respectively.
On January 22, 2003, the board of directors declared a dividend $18.2 million,
payable to Vectren on March 3, 2003.
Dividends on shares of common stock are payable at the discretion of the board
of directors out of legally available funds. Future payments of dividends, and
the amounts of these dividends, will depend on the Company's financial
condition, results of operations, capital requirements, and other factors.
Debt Security
The Company's 7 1/4% Senior Notes, due October 15, 2031, trade on the New York
Stock Exchange under the symbol "AVU." The high and low sales prices for the
Company's publicly traded debt security since issuance in October 2001 as
reported on the New York Stock Exchange are shown in the following table for the
periods indicated.
Price Range
----------------------
2002 High Low
- ---- -------- --------
First Quarter $ 25.60 $ 24.50
Second Quarter 25.40 24.50
Third Quarter 25.95 24.80
Fourth Quarter 26.08 25.15
2001
Fourth Quarter $ 25.50 $ 24.95
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K/A. The
financial information as of and for the years ended December 31, 2001 and 2000
has been restated due to errors in previously reported financial statements.
Common shareholder's equity as of January 1, 2000 also reflects adjustments for
the restatement related to years prior to 2000. Effective January 1, 2003,
Vectren transferred certain information technology systems and related assets
and buildings from other entities within its consolidated group to VUHI. These
assets primarily support the operations of VUHI's subsidiaries. The transfer
required retroactive restatement of VUHI's consolidated financial statements for
all periods presented under accounting rules governing combinations of entities
under common control. The following selected financial data gives effect to the
transfer. See Note 3 to the consolidated financial statements included under
Item 8 Financial Statements and Supplementary Data for further information on
the restatement and the asset transfer.
Year Ended December 31
- ------------------------------------------------------------------------------------------
In millions 2002 2001 (1) 2000(2,3) 1999 1998
- ------------------------------------------------------------------------------------------
(As Restated)
Operating Data:
Operating revenues $1,517.4 $1,401.0 $1,155.1 $ 807.1 $ 785.1
Operating income $ 207.7 $ 131.4 $ 136.1 $ 109.0 $ 104.0
Income before cumulative effect
of change in accounting principle $ 97.1 $ 43.7 $ 55.9 $ 75.4 $ 69.3
Net income $ 97.1 $ 44.8 $ 55.9 $ 75.4 $ 69.3
Balance Sheet Data:
Total assets $2,570.4 $2,489.3 $2,509.0 $1,667.7 $1,612.5
Redeemable preferred stock $ 0.3 $ 0.5 $ 8.1 $ 8.2 $ 8.3
Long-term debt-net of current
maturities & debt subject to tender $ 841.2 $ 900.9 $ 572.6 $ 450.1 $ 351.7
Common shareholder's equity $ 768.6 $ 738.9 $ 624.3 $ 627.0 $ 609.9
(1) Merger and integration related costs incurred for the year ended December
31, 2001 totaled $2.8 million. These costs relate primarily to transaction
costs, severance and other merger and acquisition integration activities.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets
were shortened in 2000 to reflect this decision, resulting in additional
depreciation expense of $9.6 million for the year ended December 31, 2001.
In total, merger and integration related costs incurred for the year ended
December 31, 2001 were $12.4 million ($7.7 million after tax).
The Company incurred restructuring charges of $15.0 million, ($9.3 million
after tax) relating to employee severance, related benefits and other
employee related costs, lease termination fees related to duplicate
facilities, and consulting and other fees.
(2) Merger and integration related costs incurred for the year ended December
31, 2000 totaled $32.7 million. These costs relate primarily to transaction
costs, severance and other merger and acquisition integration activities.
As a result of merger integration activities, management identified certain
information systems to be retired in 2001. Accordingly, the useful lives of
these assets were shortened to reflect this decision, resulting in
additional depreciation expense of $11.4 million for the year ended
December 31, 2000. In total, merger and integration related costs incurred
for the year ended December 31, 2000 were $44.1 million ($31.6 million
after tax).
(3) Reflects two months of results of the Ohio operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto. As discussed in Note 3 in
the consolidated financial statements, subsequent to the issuance of the
Company's 2001 financial statements, the Company's management determined that
previously issued financial statements should be restated. As a result, the
Company has restated its 2001 and 2000 financial statements and has increased
reported retained earnings as of January 1, 2000 by $1.7 million. The
restatement had the effect of decreasing net income for 2001 by approximately
$10.6 million and increasing net income for 2000 by approximately $100,000. Note
3 to the consolidated financial statements includes a summary of the significant
effects of the restatement. The effect of the restatement on quarterly results,
including previously reported 2002 quarterly information, is discussed in Note
18.
Effective January 1, 2003, Vectren transferred certain information technology
systems and related assets and buildings from other entities within its
consolidated group to VUHI. These assets primarily support the operations of
VUHI's subsidiaries. The transfer required retroactive restatement of VUHI's
consolidated financial statements for all periods presented under accounting
rules governing combinations of entities under common control. The asset
transfer increased previously reported net income for 2001 by $4.7 million and
for 2000 by $3.4 million.
The following discussion and analysis gives effect to the restatement.
Consolidated Results of Operations
In 2002, consolidated net income was $97.1 million, an increase of $52.3 million
when compared to 2001, as restated. The year ended December 31, 2001 included
nonrecurring merger, integration, and restructuring costs and other nonrecurring
items totaling $15.9 million after tax. In addition to the nonrecurring 2001
items, the increase reflects improved margins and lower operating costs. These
resulted from favorable weather and a return to lower gas prices and the related
reduction in costs incurred in 2001. Weather increased utility earnings by an
estimated $11 million.
In 2001, consolidated net income of $44.8 million decreased $11.1 million when
compared to 2000. The year ended December 31, 2000 included nonrecurring merger
and integration costs totaling $31.6 million after tax. The decrease reflects
lower earnings resulting from extraordinarily high gas costs early in 2001 that
unfavorably impacted margins and operating costs including uncollectible
accounts expense, interest, and excise taxes; heating weather that was 9% warmer
than the prior year; and a weakened national economy.
Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.6 million after tax and other
adjustments, as described below, related to 2000 and prior periods. Adjustments
were also made to previously reported 2002 quarterly results. In addition to
adjustments affecting previously reported net income, other reclassifications
were made to the previously reported 2001 and 2000 results to conform with the
2002 presentation.
Previously Reported 2001 and 2000 Net Income Adjustments
The Company determined that $11.6 million ($7.2 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.
The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $5.6 million ($3.5 million after tax).
The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.
The Company identified reconciliation errors and other errors related to the
recording of estimates that were not significant, either individually or in the
aggregate. As a result of these additional items, 2001 earnings were reduced by
$2.2 million ($1.4 million after tax). Originally reflected in 2001, the
correction of the year 2000 overstatement of electric revenue totaling $2.4
million ($1.5 million after tax), now reflected in 2000 as discussed below,
significantly offset these additional items.
The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an understatement of gas revenue by
$1.8 million ($1.1 million after tax) and an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $0.8 million ($0.5 million after tax). The impact of
the restatement of results for the year ended 2000 is an increase to net income
of approximately $100,000.
Previously Reported 2002 Quarterly Net Income Adjustments
As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, management determined that the
accrual of such carrying costs was more appropriate in periods prior to 2000
when DSM program expenditures were made. Therefore, such carrying costs
originally reflected in 2002 quarterly results were reversed and reflected in
common shareholder's equity as of January 1, 2000. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $1.8 million and $1.1 million after tax,
respectively. The cumulative impact from of these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$2.1 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. As a result of these additional items, beginning
common shareholders' equity was reduced by $1.5 million. Accordingly, retained
earnings as of January 1, 2000 reflects a cumulative net increase of $1.7
million.
Other Balance Sheet Adjustments
Certain reclassifications were made to reflect separate Company prepaid and
accrued taxes that result in the consolidated tax position. This adjustment
added approximately $26.6 million to receivables due from other Vectren
companies and prepaid and other current assets with a corresponding increase in
payables due to other Vectren companies, accrued liabilities, and deferred taxes
as of December 31, 2001. The Company also reclassified all previously recorded
goodwill not included in rates to goodwill on the balance sheet. This adjustment
resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in
prepayments and other current assets and an $8.9 million increase in goodwill.
Transfer of Assets to VUHI
Effective January 1, 2003, Vectren transferred certain information technology
systems and related assets and buildings from other entities within its
consolidated group to VUHI. These assets primarily support the operations of
VUHI's subsidiaries. The transfer requires retroactive restatement of VUHI's
consolidated financial statements for all periods presented under accounting
rules governing combinations of entities under common control. The asset
transfer increased previously reported operating income and net income by $8.1
million and $4.7 million, respectively, in 2001 and by $6.2 million and $3.4
million, respectively, in 2000. As a result of the transfer, 2001 total assets
(primarily non-utility property), liabilities (primarily intercompany payables
and borrowings), and equity transferred increased $86.7 million, $51.9 million,
and $34.8 million, respectively. The years ended December 31, 2001 and 2000 have
been restated for this asset transfer, and the year ended December 31, 2002
reflects that asset transfer.
The Company has restated its financial statements to give effect to the matters
discussed above. A summary of the significant effects of the restatement on
previously reported financial position and results of operations is included in
Note 3 to the consolidated financial statements. The effects of the restatement
on 2001 quarterly results and on 2002 previously reported quarterly information,
is discussed in Note 18. The consolidated financial statements are included
under Item 8 Financial Statements and Supplementary Data.
Nonrecurring Items in 2001 and 2000
Merger & Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
Since March 31, 2000, $35.5 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$19.3 million. Of this amount, $5.5 million related to employee and executive
severance costs, $11.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. The remaining $16.2 million was expensed through
December 31, 2001 ($13.4 million in 2000 and $2.8 million in 2001) for
accounting fees resulting from merger related filing requirements, consulting
fees related to integration activities such as organization structure, employee
travel between company locations as part of integration activities, internal
labor of employees assigned to integration teams, investor relations
communications activities, and certain benefit costs.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets were
shortened in 2000 to reflect this decision, resulting in additional depreciation
expense of $9.6 million for the year ended December 31, 2001 and $11.4 million
for the year ended December 31, 2000.
In total, for the year ended December 31, 2001, merger and integration costs
totaled $12.4 million ($7.7 million after tax) compared to $44.1 million ($31.6
million after tax) in 2000.
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 $10.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $4.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $15.0 million, ($9.3 million after tax) in 2001. These charges were
comprised of $7.6 million for employee severance, related benefits and other
employee related costs, $4.0 million for lease termination fees related to
duplicate facilities and other facility costs, and $3.4 million for consulting
and other fees incurred through December 31, 2001. The restructuring program was
completed during 2001, except for the departure of certain employees impacted by
the restructuring which occurred during 2002 and the final settlement of the
lease obligation which has yet to occur. (See Note 15 for further information on
restructuring costs.)
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million after tax) recorded as a cumulative
effect of change in accounting principle in the Consolidated Statements of
Income.
Significant Fluctuations
Utility Margin
Gas Utility Margin
Gas Utility margin for the year ended December 31, 2002 of $337.2 million
increased $26.5 million, or 9%. The increase is primarily due to weather 7%
cooler for the year and 31% cooler in the fourth quarter. Rate recovery of
excise taxes in Ohio effective July 1, 2001, an increase in the Percent of
Income Payment Plan rider affecting Ohio customers, decreased gas costs, and
customer growth of over 1% also contributed. It is estimated that of the
increase in gas utility margin weather contributed $10 million, various rate
recovery riders in Ohio contributed $7 million, and other items, including the
impact of lower gas costs and customer growth, contributed $9 million. The
effects of cooler weather resulted in an overall 4% increase in total throughput
to 207.7 MMDth in 2002 from 199.3 MMDth in 2001. Total throughput in 2000 was
181.2 MMDth, which includes two months of throughput from the Ohio operations.
Gas Utility margin for the year ended December 31, 2001 of $310.7 million
increased $42.8 million, compared to 2000. Excluding the Ohio operations, gas
margin decreased by $15.7 million, or 6%. The primary factors contributing to
this decrease were weather that was 9% warmer than the prior year and the
unfavorable impact resulting from extraordinarily high gas costs early in 2001,
coupled with the effects of a weakened economy. These decreases were offset
somewhat by customer growth of nearly 1% compared to 2000.
Cost of gas sold was $571.8 million in 2002, $708.9 million in 2001, and $552.5
million in 2000. Cost of gas sold decreased $137.1 million, or 19%, during 2002
compared to 2001, primarily due to a return to lower gas prices somewhat offset
by an increase in retail volumes sold. Of the change in 2001 compared to 2000,
the Ohio operations contributed $179.4 million of the increase. Excluding the
Ohio operations, cost of gas sold decreased $23.0 million, or 4%, in 2001. The
decrease is primarily due to lower volumes sold due to the warmer weather and a
weakened economy, offset by an increase in gas prices. The total average cost
per dekatherm of gas purchased was $4.57 in 2002, $5.83 in 2001, and $5.60 in
2000. The price changes are due primarily to changing commodity costs in the
marketplace.
Electric Utility Margin
Electric Utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:
Year ended December 31,
- -------------------------------------------------------------------------
In millions 2002 2001 2000
- -------------------------------------------------------------------------
Retail & firm wholesale $ 215.3 $ 200.0 $ 201.2
Non-firm wholesale 14.9 19.9 21.1
- -------------------------------------------------------------------------
Total margin $ 230.2 $ 219.9 $ 222.3
=========================================================================
Non-firm wholesale margin:
Realized margin $ 18.5 $ 18.4 $ 21.1
Mark-to-market gains (losses) (3.6) 1.5 -
Electric Utility margin for the year ended December 31, 2002 increased $10.3
million, or 5%, when compared to 2001. The increases result primarily from the
effect on retail sales of cooling weather considerably warmer than the prior
year. Weather in 2002 was 27% warmer when compared to 2001 and 23% warmer than
normal. In addition to weather, 2002 was positively affected by increased
industrial and firm wholesale volumes and a cash return on NOx compliance
expenditures as the expenditures are made pursuant to a rate recovery rider
approved by the IURC in August 2001. As a result of warmer weather and increased
volumes sold, retail and firm wholesale volumes sold increased from 5.8 GWh in
2001 to 6.2 GWh in 2002. Volumes sold in 2000 were 5.9 GWh. It is estimated that
of the increase in electric utility margin weather contributed $7 million, and
the increased industrial and firm wholesale volumes and NOx recovery rider
contributed $8 million. The current year increase in margin from retail sales
was partially offset by $5 million in lower margins earned in the wholesale
energy market.
Electric Utility margin for the year ended December 31, 2001 decreased $2.4
million, or 1%, compared to 2000 primarily from decreased sales to firm
wholesale customers and decreased margin on non-firm wholesale activity. The
decreases were partially offset by a 3% increase in residential and commercial
sales due to cooling weather 7% warmer than the prior year and a 3% increase in
the number of residential and commercial customers.
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale transactions that expose the Company
to limited market risk. While volumes both sold and purchased in the wholesale
market have increased during 2002, margins softened as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $5.0 million during
2002 and $1.2 million during 2001. In 2002, volumes sold into the wholesale
market were 10.7 GWh compared to 3.4 GWh in 2001 and 1.6 GWh in 2000. Volumes
purchased from the wholesale market, some of which were utilized to serve retail
and firm wholesale customers, were 10.3 GWh in 2002 compared to 2.9 GWh in 2001
and 1.2 GWh in 2000.
Operating Expenses
Other Operating
Other operating expenses decreased $13.5 million for the year ended December 31,
2002 when compared to 2001. The decrease results primarily from a return to
lower gas prices and the related reduction in costs incurred in 2001. Specific
expenses affected by increased gas costs in 2001 were uncollectible accounts
expense of $3.4 million and contributions to low income heating assistance
programs of $2.0 million. Insurance recovery in 2002 of $2.8 million in certain
maintenance costs incurred in 2001 also contributed to the decrease.
Excluding $31.2 million in additional expenses related to the Ohio operations,
other operating expenses for the year ended December 31, 2001 decreased $0.3
million compared to 2000. The 2001 decrease results primarily from prior merger
synergies, offset by higher expenses resulting from increased gas costs.
Depreciation & Amortization
Depreciation and amortization decreased $7.2 million for the year ended December
31, 2002 when compared to 2001. The decrease results from a $9.6 million
decrease related to assets which had useful lives shortened as a result of the
merger and the discontinuance of goodwill amortization as required by SFAS 142,
which approximated $4.9 million in 2001.These decreases were offset somewhat by
depreciation of utility plant and non-utility property additions.
Depreciation and amortization increased $13.3 million in 2001 when compared to
2000. The increase is due to the inclusion of the Ohio operations and
depreciation of normal utility plant additions at Indiana Gas and SIGECO. For
the year ended December 31, 2001, the increase in utility depreciation and
amortization related to the Ohio operations was $12.9 million, including
amortization of goodwill of $4.9 million.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $0.9 million in 2002 compared to 2001 as
a result of lower revenues subject to gross receipts tax and increased $15.1
million in 2001 compared to 2000. The year ended December 31, 2001 includes
$15.3 million of additional expense related to the Ohio operations, primarily
state excise tax.
Other Income - Net
Other- net
Other income, net increased $1.5 million in 2002 when compared to 2001 and
amounts in 2001 were comparable to 2000. The increase in 2002 is primarily
attributable to gains recognized from the sale of excess emission allowances.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $1.3 million in 2002
and $0.5 million in 2001 principally due to increased losses and increased
ownership in a company that manufactures autoclaved aerated concrete products
from fly ash.
Interest Expense
Interest expense decreased $1.6 million in 2002 compared to 2001. The decrease
is attributable to lower average interest rates on adjustable rate debt.
Interest expense increased $24.3 million during the 2001 compared to 2000. The
increase is due primarily to interest related to financing the acquisition of
the Ohio operations and increased working capital requirements resulting from
higher natural gas prices.
Income Tax
Federal and state income taxes increased $25.5 million for the year ended
December 31, 2002 when compared to 2001. The increase results principally from
higher pre-tax earnings. The effective tax rate increased in 2002 due to
amortization of investment tax credits and higher pre-tax income.
Federal and state income taxes decreased $15.8 million in 2001 when compared to
2000. The 2001 decrease is due to lower pre-tax earnings. The effective tax rate
decreased in 2001 due primarily to the nondeductibility of certain merger and
integration costs incurred in 2000 and amortization of investment tax credits.
Competition
The utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressures faced by electric and gas
utility companies. Increased competition may create greater risks to the
stability of utility earnings generally and may in the future reduce earnings
from retail electric and gas sales. Currently, several states, including Ohio,
have passed legislation allowing electricity customers to choose their
electricity supplier in a competitive electricity market and several other
states are considering such legislation. At the present time, Indiana has not
adopted such legislation. Ohio regulation allows gas customers to choose their
commodity supplier. The Company implemented a choice program for its gas
customers in Ohio in January 2003. Indiana has not adopted any regulation
requiring gas choice; however, the Company operates under approved tariffs
permitting large volume customers to choose their commodity supplier.
Other Operating Matters
Midwest Independent System Operator
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The FERC has made regional transmission organizations a top priority to boost
competition and to provide more reliable power at lower rates. The Carmel,
Indiana, based MISO began some operations in December 2001 with control of
73,000 miles of transmission lines carrying up to 81,000 MW. More than 20 states
are included in the MISO from the Midwest and Plains states, to Texas, Arkansas,
and part of the Southeast. In December 2001, the IURC approved the Company's
request for authority to transfer operational control over its electric
transmission facilities to the MISO. That transfer occurred on February 1, 2002.
Issues pertaining to certain of MISO's tariff charges for its services remain to
be determined by the FERC. Given the outstanding tariff issues, as well as the
potential for additional growth in MISO participation, the Company is unable to
determine the future impact MISO participation may have on its operations.
Pursuant to an order from the IURC, certain MISO costs are deferred for future
recovery.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, may be impacted. Given the
nature of MISO's policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, it is difficult to predict the impact on operational
reliability. The potential need to expend capital for improvements to the
transmission system, both to SIGECO's facilities as well as to those facilities
of adjacent utilities, over the next several years will become more predictable
as MISO completes studies related to regional transmission planning and
improvements. Such expenditures may be significant.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxides (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible to comply with.
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 NOx emissions in
amounts that contributed to non-attainment with the ozone NAAQS in downwind
states. The USEPA required each state to revise its SIP to provide for further
NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's
final ruling, requires a 31% reduction in total NOx emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through December 31, 2002, $70.0 million has been expended.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. . SIGECO's suit is pending in the U.S. District Court for the
Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual, and
the plant continues to operate while the matter is being decided.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's Voluntary Remediation Program. In
response, SIGECO submitted to the IDEM the results of preliminary site
investigations conducted in the mid-1990's. These site investigations confirmed
that based upon the conditions known at the time, the sites posed no risk to
human health or the environment. Follow up reviews have recently been initiated
by the Company to confirm that the sites continue to pose no such risk.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of
service, accounting matters, issuance of securities, and certain other
operational matters specific to its Indiana customers are regulated by IURC. The
retail gas operations of the Ohio operations are subject to regulation by the
PUCO. Changes in prices for fuel for electric generation and purchased power are
determined primarily by energy markets.
Gas Costs Proceedings
Adjustments to rates and charges related to the cost of gas charged to Indiana
customers are made through gas cost adjustment (GCA) procedures established by
Indiana law and administered by the IURC. Similar adjustments to the cost of gas
charged to Ohio customers are made through gas cost recovery (GCR) procedures
established by Ohio law and administered by the PUCO. GCA and GCR procedures
involve scheduled quarterly filings and IURC and PUCO hearings to establish the
amount of price adjustments for a designated future quarter. The procedures also
provide for inclusion in later quarters any variances between the estimated cost
of gas and actual costs incurred. This reconciliation process with regard to
changes in the cost of gas sold closely matches revenues to expenses.
The IURC has also applied the statute authorizing GCA procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. Recovery of gas
costs is not allowed to the extent that net operating income for the longer of
(1) a 60-month period, including the twelve-month period provided in a gas cost
adjustment filing, or (2) the date of the last order establishing base rates and
charges exceeds the total net operating income authorized by the IURC. For the
recent past, the earnings test has not affected the Company's ability to recover
gas costs, and the Company does not anticipate the earnings test will restrict
the recovery of gas costs in the near future.
Rate structures for gas delivery operations do not include weather
normalization-type clauses that authorize the utility to recover gross margin on
sales established in its last general rate case, regardless of actual weather
patterns.
Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
the Company's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through these
commission-approved gas cost adjustment mechanisms, and margin on gas sales
should not be impacted. However, in 2001, the Company's utility subsidiaries
experienced 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.
In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.
Fuel & Purchased Power Costs
Adjustments to rates and charges related to the cost of fuel and the net energy
cost of purchased power charged to Indiana customers are made through fuel cost
adjustment procedures established by Indiana law and administered by the IURC.
Fuel cost adjustment procedures involve scheduled quarterly filings and IURC
hearings to establish the amount of price adjustments for future quarters. The
procedures also provide for inclusion in a later quarter of any variances
between the estimated cost of fuel and purchased power and actual costs
incurred. The order provides that any over-or-under-recovery caused by variances
between estimated and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor. This continuous reconciliation of
estimated incremental fuel costs billed with actual incremental fuel costs
incurred closely matches revenues to expenses.
An earnings test similar to the test restricting gas cost recovery is the
principal restriction to recovery of fuel cost increases. This earnings test has
not affected the Company's ability to recover fuel costs, and the Company does
not anticipate the earnings test will restrict the recovery of fuel costs in the
near future.
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
Transactions with ProLiance
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) and audit process
administered by the PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility.
However, with respect to the pricing of gas commodity purchased from ProLiance,
the price paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in a consolidated GCA proceeding involving Indiana Gas and
Citizens Gas.
On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other
consumer parties, entered into and filed with the IURC a settlement setting
forth the terms for resolution of all pending regulatory issues related to
ProLiance, including the three pricing issues. On July 23, 2002, the IURC
approved the settlement filed by the parties. The GCA proceeding has been
concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas,
and ProLiance have been approved and extended through March 31, 2007. ProLiance
will also have the opportunity, if it so elects, to participate in a "request
for proposal" process for service to the utilities after March 31, 2007.
For past services provided to Indiana Gas by ProLiance, the Company made refunds
to Indiana Gas' retail customers pursuant to the settlement totaling $6.4
million in the fourth quarter of 2002. A subsidiary of Vectren's nonregulated
operations has indemnified Indiana Gas for the amount of the refund as well as
any other amounts incurred as a result of the settlement. Accordingly, the
refund had no effect on operating margin or net income.
In addition to the above, the IURC order also provides that:
o A portion of the utilities' natural gas will be purchased through a
gas cost incentive mechanism that shares price risk and reward between
the utilities and customers;
o Beginning in 2004, ProLiance will provide the utilities with an
interstate pipeline transport and storage service price discount, thus
providing additional savings to customers;
o As ProLiance continues to provide the utilities with its supply
services, Citizens Gas and Vectren will together annually provide an
additional $2 million per year in customer benefits in 2003, 2004, and
2005.
Critical Accounting Policies
Management is required to make judgements, assumptions, and estimates that
affect the amounts reported in the consolidated financial statements and the
related disclosures that conform to accounting principles generally accepted in
the United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgement. These
include the estimates to perform goodwill and other asset impairments tests. The
Company makes other estimates in the course of accounting for unbilled revenue,
the effects of regulation, and intercompany allocations that are critical to the
Company's financial results but that are less likely to be impacted by near term
changes. Other estimates that significantly affect the Company's results, but
are not necessarily critical to operations, include depreciation of utility
plant, the valuation of derivative contracts, and the allowance for doubtful
accounts, among others. Actual results could differ from these estimates.
Goodwill
Pursuant to SFAS No. 142, the Company performed an initial impairment analysis
of its goodwill, all of which resides in the Gas Utility Services operating
segment. Also consistent with SFAS 142, goodwill is tested for impairment
annually at the beginning of the year and more frequently if events or
circumstances indicate that an impairment loss has been incurred. Impairment
tests are performed at the reporting unit level which the Company has determined
to be consistent with its Gas Utility Services operating segment as identified
in Note 14 to the consolidated financial statements. An impairment test
performed in accordance with SFAS 142 requires that a reporting unit's fair
value be estimated. The Company used a discounted cash flow model to estimate
the fair value of its Gas Utility Services operating segment, and that estimated
fair value was compared to its carrying amount, including goodwill. The
estimated fair value was in excess of the carrying amount and therefore resulted
in no impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgement in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also results in no impairment charge.
Impairment Review of Investments
The Company has investments in unconsolidated affiliates, including notes
receivable convertible into equity interests. On a periodic basis and when
events occur that may cause one of these investments to be impaired, the Company
performs an impairment analysis. An impairment analysis of notes receivable
usually involves the comparison of the investment's estimated free cash flows to
the stated terms of the note. An impairment analysis of investments in
unconsolidated affiliates involves comparison of the investment's estimated fair
value to its carrying amount. Fair value is estimated using primarily using
discounted cash flow analyses. Calculating free cash flows and fair value using
the above methods is subjective and requires significant judgement in growth
assumptions, longevity of cash flows, and discount rates (for fair value
calculations).
During 2002, the Company performed impairment tests on certain investments using
both free cash flows and discounted cash flows. No impairment charges resulted
from these analyses. For these impairment tests, a 100 basis point adverse
change in the discount rate used to estimate discounted cash flow or a 10%
adverse change in the cash flow growth assumption used to estimate free cash
flows would have resulted in no impairment charge.
Unbilled Revenues
To more closely match revenues and expenses, the Company records revenues for
all gas and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the month to
allocate unbilled units. Those allocated units are multiplied by rates in effect
during the month to calculate unbilled revenue at balance sheet dates. While
certain estimates are used in the calculation of unbilled revenue, these
estimates are not subject to near term changes.
Regulation
At each reporting date, the Company reviews current regulatory trends in the
markets in which it operates. This review involves judgement and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Based on the Company's current review, it believes its regulatory assets are
probable of recovery. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets. In the unlikely event of a change in the current regulatory
environment, such write-offs and impairment charges could be significant.
Intercompany Allocations
Support Services
Vectren and certain subsidiaries of Vectren provided corporate, 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. These costs are directly charged to individual
subsidiaries. Other components of costs (such interest cost from prior service
and asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Plan assets nor the FAS 87/106 liability is
allocated to individual subsidiaries since these assets and obligations are
derived from corporate level decisions. Further, Vectren satisfies the future
funding requirements of plans and the payment of benefits from general corporate
assets. Management believes these direct charges when combined with
benefit-related corporate charges discussed in "support services" above
approximate costs that would have been incurred if the Company accounted for
benefit plans on a stand-alone basis. Vectren annually measures its obligations
on September 30.
Vectren estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other things, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of pension and postretirement plans. Vectren used the
following weighted average assumptions to develop 2002 annual costs and the
ending benefit obligations recognized in the consolidated financial statements:
a discount rate of 6.75%, an expected return on plan assets before expenses of
9.00%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2002 declining to 5% in 2006. During 2002, Vectren reduced the
discount rate and rate of compensation increase by 50 basis points from those
assumptions used in 2001 due to the general decline in interest rates and other
market conditions that occurred in 2002. Future changes in health care costs,
work force demographics, interest rates, or plan changes could significantly
affect the estimated cost of these future benefits that are allocated to VUHI
and its subsidiaries.
Impact of Recently Issued Accounting Guidance on Future Operations
EITF 02-03
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
held for "trading purposes." The consensus rescinded EITF Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) as well as other decisions reached on energy trading
contracts at the EITF's June 2002 meeting.
The Company's non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
the definition of energy trading activities based upon the provisions in EITF
98-10. Currently, the Company uses a gross presentation to report the results of
these operations as described in Note 12 of the consolidated financial
statements. The Company has re-evaluated its portfolio of derivative contracts
and has determined gross presentation remains appropriate.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.
FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
Financial Condition
Within Vectren's consolidated group, VUHI funds short-term and long-term
financing needs of the regulated operations. Vectren does not guarantee VUHI's
debt. VUHI's currently outstanding long-term and short-term borrowing
arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and
VEDO. Prior to VUHI's formation, Indiana Gas and SIGECO funded their operations
separately, and therefore, have debt outstanding funded solely by their
operations. VUHI's operations have historically funded Vectren's common stock
dividends.
In November 2002, Moody's Investors Service (Moody's) downgraded the senior
unsecured debt of VUHI, Indiana Gas, and SIGECO (from A2 to Baa1) as well as
SIGECO's senior secured debt (from A1 to A3) and SIGECO's pollution control
revenue bonds (from VMIG 1 to VMIG 2). In addition, VUHI's commercial paper
program was also downgraded (from P-1 to P-2). The reasons cited for the
downgrades included weaker credit and fixed charge coverage measures compared to
A2 peers, resulting from the prior integration and restructuring costs and warm
winter of 2001 and 2002; and lack of weather normalization-type clauses that
authorize the utilities to recover gross margin on sales regardless of actual
weather patterns.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2002 are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's, respectively. SIGECO's credit ratings on
outstanding senior unsecured debt at December 31, 2002 are BBB+/Baa1. SIGECO's
credit ratings on outstanding secured debt at December 31, 2002 are A-/A3.
VUHI's commercial paper has a credit rating of A-2/P-2. Moody's current outlook
is stable while Standard and Poor's current outlook is negative. The ratings of
Standard and Poor's and Moody's are categorized as investment grade. A security
rating is not a recommendation to buy, sell, or hold securities. The rating is
subject to revision or withdrawal at any time, and each rating should be
evaluated independently of any other rating. Standard and Poor's and Moody's
lowest level investment grade rating is BBB- and Baa3, respectively.
The Company's consolidated equity capitalization objective is 40-55% of total
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, and seasonal
factors that affect the Company's operation. The Company's equity component was
46% and 45% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at December 31, 2002 and 2001,
respectively.
The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds. However, additional
permanent financing may be required due to significant capital expenditures for
NOx compliance equipment at SIGECO and plans to further strengthen the Company's
capital structure and the capital structures of its utility subsidiaries. These
plans may include the issuance of new equity to Vectren and debt and the calling
of certain long-term debt at SIGECO and Indiana Gas. Specific to the NOx
compliance project, the Company is authorized an 8 percent return on its capital
investments through approved rider mechanisms.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary and historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operations
increased during the year ended December 31, 2002 compared to 2001 by
$92.1million and increased $150.3 million in 2001 compared to 2000. The primary
reasons for the increases are due to favorable changes in working capital due to
a return to lower gas prices and increased earnings before non-cash charges.
Financing Cash Flow
Although working capital requirements are generally funded by cash flow from
operations, the Company uses short-term borrowings to supplement working capital
needs when accounts receivable balances are at their highest and gas storage is
refilled. Additionally short-term borrowings are required for capital projects
and investments until they are permanently financed.
Cash flow required for financing activities of $53.6million for the year ended
December 31, 2002 includes an increase in borrowings outstanding over 2001 of
$16.3 million and $69.7 million in dividends paid to Vectren compared to 2001.
Borrowings have increased due to the use of short-term borrowing for non-utility
property and NOx expenditures.
Cash flow from financing activities of $33.9 million for the year ended December
31, 2001 includes $38.1 million of reductions in borrowings and preferred stock
and $91.6 million in dividends paid to Vectren, offset by additional capital
contributions of $164.4 million. During 2001, $508.4 million of net proceeds
from debt issuances and capital contributions were utilized to pay down
short-term borrowings and strengthen VUHI's balance sheet.
Financing the Ohio Operations Purchase
On October 31, 2000, the acquisition of the Ohio operations was completed for a
purchase price of approximately $471 million. Commercial paper and $150.0
million in floating rate notes were issued to fund the purchase. During 2001,
the Company refinanced these interim borrowing arrangements with permanent
financing in the form of new equity and long-term debt, as described below.
In January 2001, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of 5.5 million shares of
new common stock. In February 2001, the registration became effective, and an
agreement was reached to sell approximately 6.3 million shares (the original 5.5
million shares, plus an over-allotment option of 0.8 million shares) to a group
of underwriters. The net proceeds from the sale of common stock totaled $129.4
million. These proceeds were contributed to VUHI as an additional capital
contribution.
In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission for $350.0 million aggregate principal amount of
unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with
an aggregate principal amount of $100.0 million and an interest rate of 7.25%
(the October Notes), and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.
These issues have no sinking fund requirements, and interest payments are due
quarterly for the October Notes and semi-annually for the December Notes. The
October Notes are due October 2031, but may be called by the Company, in whole
or in part, at any time after October 2006 at 100% of the principal amount plus
any accrued interest thereon. The December Notes are due December 2011, but may
be called by the Company, 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 the indenture, plus 25 basis points.
Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. These guarantees of VUHI's debt are full and
unconditional and joint and several. The net proceeds from the sale of the
senior notes and settlement of hedging arrangements totaled $344.0 million
Other Financing Transactions
In December 2001, Vectren contributed additional capital of $35.0 million. The
proceeds were used to repay short-term borrowings.
In September 2001, the Company notified holders of SIGECO's 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.
In December 2000, Indiana Gas issued $20.0 million of 15-Year Insured Quarterly
(IQ) Notes at an interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at
an interest rate of 7.45%. Indiana Gas has the option to redeem the 15-Year IQ
Notes, in whole or in part, from time to time on or after December 15, 2004 and
the option to redeem the 30-Year IQ Notes in whole or in part, from time to time
on or after December 15, 2005. The IQ notes have no sinking fund requirements.
The net proceeds totaling $67.9 million were used to repay outstanding
commercial paper.
Investing Cash Flow
Cash required for investing activities of $218.7 million for the year ended
December 31, 2002 includes $217.3 million of requirements for capital
expenditures. Investing activities for 2001 were $215.3 million. The $3.4
million increase in requirements occurring in 2002 is principally the result of
additional capital expenditures for NOx compliance and investments in deferred
compensation funding arrangements, offset by proceeds received from intercompany
notes receivable.
Cash required for investing activities for the year ended December 31, 2001
includes $202.8 million of requirements for capital expenditures. Investing
activities for the year ended December 31, 2000 were $595.0 million. The $379.7
million decrease occurring in 2001 is principally the result of the acquisition
of the Ohio operations in 2000, offset by increased capital expenditures for
utility plant and non-utility plant infrastructure.
Available Sources of Liquidity
At December 31, 2002, the Company has $330.0 million of short-term borrowing
capacity, of which approximately $90.9 million is available. Subsequent to
December 31, 2002, the Company increased its capacity $145.0 million to $475.0
million. Effective January 1, 2003, Vectren transferred certain assets that
primarily support the regulated operations from other wholly owned subsidiaries
to VUHI. This transfer of assets will take advantage of the greater borrowing
capacity available to VUHI.
Prior to 2001, Vectren purchased shares from the open market to satisfy
issuances of common stock pursuant to its dividend reinvestment plan and stock
option plans. In 2001, Vectren began issuing new shares to satisfy exercised
stock options and beginning in 2003 will issue new shares to satisfy dividend
reinvestment plan requirements. Management estimates these new equity issues
will add approximately $5 million per year that may be utilized to support
VUHI's operations.
Potential & Future Uses of Liquidity
The following is a summary of certain obligations and commitments at December
31, 2002:
- ---------------------------------------------------------------------------------------------
(In millions) 2003 2004 2005 2006 2007 Thereafter
- ---------------------------------------------------------------------------------------------
Short-term debt due to third parties $ 239.1 $ - $ - $ - $ - $ -
Short-term debt due to other Vectren
companies 86.9 - - - - -
Long-term debt (1) 16.0 15.0 - - 6.5 850.6
Long-term debt to be called (2) 23.8 - - - - -
Firm natural gas purchase commitments 89.5 21.3 3.6 - - -
- ----------------------------------------------------------------------------------------------
Total $ 455.3 $ 36.3 $ 3.6 $ - $ 6.5 $ 850.6
==============================================================================================
(1) Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow holders
to put debt back to the Company at face value or the Company to call debt
at face value or at a premium. Long-term debt subject to tender during the
years following 2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0
in 2005, $53.7 in 2006, $20.0 in 2007 and $120.0 thereafter.
(2) On January 15, 2003, the Company called the remaining $23.8 million of
Indiana Gas' 9.375% private placement notes originally due in 2021. Since
the proceeds to repay the notes were generated from short-term borrowings,
these notes are classified in current maturities of long-term debt at
December 31, 2002.
Planned Capital Expenditures & Investments
Capital expenditures for the five-year period 2003 - 2007 will require
significant investments and include expenditures for non-utility plant that will
primarily support utility operations and for NOx compliance. Capital
expenditures are estimated as follows:
- --------------------------------------------------------------------------------
In millions 2003 2004 2005 2006 2007
- --------------------------------------------------------------------------------
Capital expenditures
Utility plant (1) $ 204.8 $ 236.5 $ 184.9 $ 145.1 $ 135.4
Non-utility plant 22.3 27.8 10.5 16.4 11.3
- --------------------------------------------------------------------------------
Total capital expenditures $ 227.1 $ 264.3 $ 195.4 $ 161.5 $ 146.7
================================================================================
(1) Includes expenditures for NOx compliance of approximately $83.0 million in
2003, $79.0 million in 2004, $23.7 million in 2005, and $4.6 million in
2006.
Guarantees
Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $325.0 million commercial paper program, of which $239.1
million is outstanding at December 31, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at December 31, 2002. The guarantees are full and
unconditional and joint and several, and VUHI has no subsidiaries other than the
subsidiary guarantors.
Pension and Postretirement Funding Obligations
Vectren has not made significant contributions to its qualified pension plans in
recent years. Due to poor market performance during 2000-2002, it will be
necessary for Vectren to make contributions to benefits plans in the coming
years. Management currently estimates that the qualified pension plans will
require Company contributions of less than $1 million in 2003 and between $5
million and $10 million in 2004 and 2005. VUHI may be called upon to fund a
portion of these contributions.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in credit ratings, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee workforce factors including changes in key executives, collective
bargaining agreements with union employees, or work stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but not
limited to, those described in Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business risks associated with commodity
prices, interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company's risk management program includes, among other
things, the use of derivatives to mitigate risk.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.
Commodity Price Risk
The Company's 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 such purchases through natural gas and fuel
cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.
The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts.
The Company's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.
Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.
Market risk is measured by management as the potential impact on pre-tax
earnings resulting from a 10% adverse change in the forward price of commodity
prices on outstanding market sensitive financial instruments (all contracts not
expected to be settled by physical receipt or delivery). For the years ended
December 31, 2002 and 2001, a 10% adverse change in commodity forward prices on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $1.5 million and $2.0 million, respectively.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. At December 31, 2002, such obligations represented 26%
of the Company's total debt portfolio. To manage this exposure, the Company may
periodically use derivative financial instruments to reduce earnings
fluctuations caused by interest rate volatility.
Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility including bank notes, lines of credit, commercial
paper, and certain adjustable rate long-term debt instruments. At December 31,
2002 and 2001, the combined borrowings under these facilities totaled $319.5
million and $296.7 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2002 and 2001, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $2.3 million and $5.4 million, respectively. Of the 2001 exposure,
approximately $1.5 million would have been offset by an interest rate swap
designated to hedge such exposure.
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 and west
central Ohio. 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.
ITEM 8. Financial Statements and Supplementary Data
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Vectren Utility Holdings, Inc. (VUHI) is responsible for the
preparation of the consolidated 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 VUHI's parent company, Vectren Corporation, pursues
its responsibility for these financial statements through its audit committee,
which meets periodically with management, the internal auditors and the
independent auditors, to assure that each is carrying out its responsibilities.
Both the internal auditors and the independent auditors meet with the audit
committee of Vectren Corporation's board of directors, with and without
management representatives present, to discuss the scope and results of their
audits, their comments on the adequacy of internal accounting control and the
quality of financial reporting.
/S/ Niel C. Ellerbrook
Niel C. Ellerbrook
Chairman & Chief Executive Officer
February 26, 2003
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of Vectren Utility Holdings, Inc.:
We have audited the accompanying consolidated balance sheets of Vectren Utility
Holdings, Inc. and subsidiaries as of December 31, 2002 and 2001, and the
related consolidated statements of income, common shareholder's equity and cash
flows for each of the three years in the period ended December 31, 2002. Our
audits also included the financial statement schedules listed in the Table of
Contents at Item 15. These financial statements and financial statement
schedules are the responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements and financial statement
schedules 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 consolidated financial statements present fairly, in all
material respects, the financial position of Vectren Utility Holdings, Inc. and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic financial statements taken
as a whole, present fairly in all material respects the information set forth
therein.
As discussed in Note 2, effective January 1, 2002, the Company adopted Statement
of Financial Accounting Standards ("SFAS") 142, "Goodwill and Other
Intangibles." As discussed in Note 12, effective, January 1, 2001, the Company
adopted SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended.
As discussed in Note 3, the accompanying 2001 and 2000 financial statements have
been restated.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 26, 2003 (June 2, 2003 as to Notes 3 and 17)
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
- -------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------
(As Restated,
ASSETS See Note 3)
------ -------------
Current Assets
Cash & cash equivalents $ 10.5 $ 5.2
Accounts receivable-less reserves of $5.5 &
$5.1, respectively 131.9 123.1
Receivables due from other Vectren companies 56.3 86.3
Accrued unbilled revenues 112.7 77.1
Inventories 56.0 54.8
Recoverable fuel & natural gas costs 22.1 70.2
Prepayments & other current assets 86.5 82.8
- -------------------------------------------------------------------------------
Total current assets 476.0 499.5
- -------------------------------------------------------------------------------
Utility Plant
Original cost 3,037.2 2,906.1
Less: accumulated depreciation & amortization 1,389.0 1,308.2
- -------------------------------------------------------------------------------
Net utility plant 1,648.2 1,597.9
- -------------------------------------------------------------------------------
Investments in unconsolidated affiliates 2.4 3.5
Other investments 21.9 20.0
Non-utility property-net 139.2 85.0
Goodwill-net 202.2 201.5
Regulatory assets 75.2 67.8
Other assets 5.3 14.1
- -------------------------------------------------------------------------------
TOTAL ASSETS $ 2,570.4 $ 2,489.3
===============================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
- -------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------
(As Restated,
LIABILITIES & SHAREHOLDER'S EQUITY See Note 3)
---------------------------------- -------------
Current Liabilities
Accounts payable $ 74.8 $ 79.4
Accounts payable to affiliated companies 85.6 37.4
Payables due to other Vectren companies 69.8 51.6
Accrued liabilities 83.2 95.2
Short-term borrowings 239.1 274.2
Short-term borrowings due to other
Vectren companies 86.9 29.0
Current maturities of long-term debt 39.8 1.3
Long-term debt subject to tender 26.6 11.5
- -------------------------------------------------------------------------------
Total current liabilities 705.8 579.6
- --------------------------------------------------------------------------------
Long-Term Debt-Net of Current Maturities &
Debt Subject to Tender 841.2 900.9
Deferred Income Taxes & Other Liabilities
Deferred income taxes 172.3 176.5
Deferred credits & other liabilities 82.2 92.9
- -------------------------------------------------------------------------------
Total deferred credits & other liabilities 254.5 269.4
- -------------------------------------------------------------------------------
Commitments & Contingencies (Notes 9 - 11)
Cumulative, Redeemable Preferred Stock of
a Subsidiary 0.3 0.5
Common Shareholder's Equity
Common stock (no par value) 385.7 385.7
Retained earnings 382.4 355.0
Accumulated other comprehensive income (loss) 0.5 (1.8)
- -------------------------------------------------------------------------------
Total common shareholder's equity 768.6 738.9
- -------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 2,570.4 $ 2,489.3
===============================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
Year Ended December 31,
- ------------------------------------------------------------------------------
2002 2001 2000
- ------------------------------------------------------------------------------
OPERATING REVENUES (As Restated, See Note 3)
-------------------------
Gas utility $ 909.0 $1,019.6 $ 820.4
Electric utility 608.1 381.2 334.4
Other 0.3 0.2 0.3
- ------------------------------------------------------------------------------
Total operating revenues 1,517.4 1,401.0 1,155.1
- ------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 571.8 708.9 552.5
Fuel for electric generation 81.6 74.4 75.7
Purchased electric energy 296.3 86.9 36.4
Other operating 198.6 212.1 180.6
Merger & integration costs - 2.8 32.7
Restructuring costs - 15.0 -
Depreciation & amortization 110.7 117.9 104.6
Taxes other than income taxes 50.7 51.6 36.5
- ---------------------------------------------------------------------------
Total operating expenses 1,309.7 1,269.6 1,019.0
- ------------------------------------------------------------------------------
OPERATING INCOME 207.7 131.4 136.1
OTHER INCOME
Other - net 7.1 5.6 4.3
Equity in earnings of unconsolidated
affiliates (1.8) (0.5) -
- ------------------------------------------------------------------------------
Total other income 5.3 5.1 4.3
- ------------------------------------------------------------------------------
Interest expense 69.1 70.7 46.4
- ------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 143.9 65.8 94.0
- ------------------------------------------------------------------------------
Income taxes 46.8 21.3 37.1
Preferred dividend requirements of
subsidiary - 0.8 1.0
- ------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 97.1 43.7 55.9
- ------------------------------------------------------------------------------
Cumulative effect of change in accounting
principle - net of tax - 1.1 -
- ------------------------------------------------------------------------------
NET INCOME $ 97.1 $ 44.8 $ 55.9
==============================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31,
- ----------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES (As Restated, See Note 3)
-------------------------
Net income $ 97.1 $ 44.8 $ 55.9
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 110.7 117.9 104.6
Deferred income taxes & investment tax credits (23.4) (14.9) 12.9
Pension and post-retirement expense 6.5 5.7 8.8
Equity in earnings of unconsolidated affiliates 1.8 0.5 -
Net unrealized loss (gain) on derivative
instruments, including cumulative effect of
change in accounting principle 3.6 (3.3) -
Other non-cash charges- net 8.4 14.0 (1.2)
Changes in working capital accounts:
Accounts receivable, including to Vectren
companies & accrued unbilled revenue (28.1) 78.9 (231.0)
Inventories (1.2) 38.4 15.9
Recoverable fuel & natural gas costs 48.1 25.9 (82.3)
Prepayments & other current assets (9.4) (11.3) (36.8)
Accounts payable, including to Vectren
companies & affiliated companies 73.2 (87.7) 184.4
Accrued liabilities 0.1 (10.3) 0.7
Changes in noncurrent assets (1.2) (4.2) 2.5
Changes in noncurrent liabilities (8.6) (9.1) 0.7
- ----------------------------------------------------------------------------------------
Net cash flows from operating activities 277.6 185.3 35.1
- ----------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs - 344.0 67.9
Additional capital contribution - 164.4 -
Short-term notes payable - - 150.0
Other proceeds - - 1.6
Requirements for:
Dividends on common stock (69.7) (91.6) (60.6)
Retirement of long-term debt (6.5) (7.3) (0.7)
Redemption of preferred stock of subsidiary (0.2) (17.7) (2.0)
Retirement of short-term notes payable - (150.0) -
Dividends on preferred stock of subsidiary - (0.8) (1.0)
Net change in short-term borrowings, including
to other Vectren companies 22.8 (207.1) 405.2
- ----------------------------------------------------------------------------------------
Net cash flows (required for) from
financing activities (53.6) 33.9 560.4
- ----------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from other investing activities 10.4 1.5 -
Requirements for:
Capital expenditures, excluding AFUDC equity (217.3) (202.8) (118.7)
Acquisition of Ohio operations - (2.2) (469.2)
Other investments (11.8) (11.8) (7.1)
- ----------------------------------------------------------------------------------------
Net cash flows (required for) investing
activities (218.7) (215.3) (595.0)
- ----------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 5.3 3.9 0.5
Cash & cash equivalents at beginning of period 5.2 1.3 0.8
- ----------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 10.5 $ 5.2 $ 1.3
========================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(In millions)
Accumulated
Other
Common Retained Comprehensive
Stock Earnings Income (Loss) Total
- -------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Reported $ 221.3 $ 405.7 $ - $ 627.0
Restatement adjustment 1.7 1.7
- -------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Restated 221.3 407.4 - 628.7
- -------------------------------------------------------------------------------------------
Net income & comprehensive income, As Restated 55.9 55.9
Common stock dividends (60.6) (60.6)
Other 0.3 0.3
- -------------------------------------------------------------------------------------------
Balance at December 31, 2000, As Restated 221.3 403.0 - 624.3
- -------------------------------------------------------------------------------------------
Comprehensive income:
Net income, As Restated 44.8 44.8
Minimum pension liability adjustment
& other-net of tax (1.8) (1.8)
- -------------------------------------------------------------------------------------------
Total comprehensive income, As Restated 43.0
- -------------------------------------------------------------------------------------------
Common stock:
Additional capital contribution 164.4 164.4
Dividends (91.6) (91.6)
Loss on extinguishment of preferred stock (1.2) (1.2)
- -------------------------------------------------------------------------------------------
Balance at December 31, 2001, As Restated 385.7 355.0 (1.8) 738.9
- -------------------------------------------------------------------------------------------
Comprehensive income:
Net income 97.1 97.1
Minimum pension liability adjustments &
other - net of tax 2.3 2.3
- -------------------------------------------------------------------------------------------
Total comprehensive income 99.4
- -------------------------------------------------------------------------------------------
Common stock dividends (69.7) (69.7)
- -------------------------------------------------------------------------------------------
Balance at December 31, 2002 $ 385.7 $ 382.4 $ 0.5 $ 768.6
===========================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Overview
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the
Ohio operations. VUHI also has assets that provide information technology and
other services to the utilities.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO 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. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
Vectren is an energy and applied technology holding company headquartered in
Evansville, Indiana. The Company was organized on June 10, 1999 solely for the
purpose of effecting the merger of Indiana Energy and 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).
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.
Acquisition of the Natural Gas Distribution Assets of The Dayton Power and Light
Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.
The Company acquired the natural gas distribution assets as a tenancy in common
through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio,
Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana
Gas holds a 47% undivided ownership interest. VEDO is the operator of the
assets, and these operations are referred to as "the Ohio operations."
The purchase price was allocated to the assets and liabilities acquired based on
the fair value of those assets and liabilities as of the acquisition date.
Because of the regulatory environment in which the Ohio operations operate, the
book value of rate-regulated assets and liabilities is generally considered to
be fair value. Goodwill, in the amount of $202.5 million, was recognized for the
excess amount of the purchase price paid over the fair value of the net assets
acquired.
Had the acquisition of the Ohio operations occurred on January 1, 2000, pro
forma operating revenues and net income for the year ended December 31, 2000
would have been $1,339.1 million and $51.1 million, respectively. This pro forma
information is not necessarily indicative of the results that actually would
have occurred if the transaction had been consummated at the beginning of the
periods presented and is not intended to be a projection of future results.
2. Summary of Significant Accounting Policies
A. Principles of Consolidation
The accompanying consolidated financial statements for the period prior to March
31, 2000 reflect the Company on a historical basis as restated for the effects
of the combination of entities under common control whereby Indiana Gas and
SIGECO became subsidiaries of VUHI. The consolidated financial statements
include the accounts of the Company and its wholly owned and majority owned
subsidiaries, after elimination of intercompany transactions.
For the three months ended March 31, 2000, operating revenues and net income
contributed by the predecessor companies were $171.6 million and $8.8 million,
respectively, by Indiana Gas and $102.2 million and $4.0 million, respectively,
by SIGECO.
B. 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. Cash paid during the
periods reported for interest, income taxes, and acquired assets and liabilities
follows:
Year Ended December 31,
- -------------------------------------------------------------------------
In millions 2002 2001 2000
- -------------------------------------------------------------------------
Cash paid for
Interest $ 58.4 $ 63.5 $ 45.2
Income taxes 63.3 46.7 44.8
- -------------------------------------------------------------------------
Details of acquisition (Note 1)
Book value of assets acquired $ - $ 1.6 $ 275.2
Liabilities assumed - - 7.9
- -------------------------------------------------------------------------
Net assets acquired $ - $ 1.6 $ 267.3
=========================================================================
C. Inventories
Inventories consist of the following:
At December 31,
- -------------------------------------------------------------------------
In millions 2002 2001
- -------------------------------------------------------------------------
Gas in storage - at LIFO cost $ 25.4 $ 24.4
Materials & supplies 15.8 16.5
Fuel (coal & oil) for electric generation 10.0 9.5
Gas in storage - at average cost 3.3 0.8
Other 1.5 3.6
- -------------------------------------------------------------------------
Total inventories $ 56.0 $ 54.8
=========================================================================
Based on the average cost of gas purchased during December, the cost of
replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31,
2002 and 2001 by approximately $32.7 million and $17.9 million, respectively.
Gas in storage of the Indiana regulated operations is stated at LIFO. All other
inventories are carried at average cost.
D. 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 and For the Year Ended December 31,
- -------------------------------------------------------------------------------------------
In millions 2002 2001
- ----------------------------- ---------------------------- ----------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of Percent of
Original Cost Original Cost Original Cost Original Cost
- -------------------------------------------------------------------------------------------
Gas utility plant $1,622.0 3.8% $1,523.0 3.6%
Electric utility plant 1,211.1 3.3% 1,148.9 3.3%
Common utility plant 41.6 2.6% 41.3 2.6%
Construction work in progress 162.5 - 192.9 -
- -------------------------------------------------------------------------------------------
Total original cost $3,037.2 $2,906.1
===========================================================================================
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 Consolidated 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 millions 2002 2001 2000
- ---------------------------------------------------------------------------
AFUDC - borrowed funds $ 3.1 $ 2.1 $ 2.4
AFUDC - equity funds 2.2 2.5 2.6
- ---------------------------------------------------------------------------
Total AFUDC capitalized $ 5.3 $ 4.6 $ 5.0
===========================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced or
removed, the cost of such property is credited to utility plant, and such cost,
together with the cost of removal less salvage, is charged to accumulated
depreciation.
E. Non-Utility Property
The depreciation of non-utility property is charged against income over its
estimated useful life (ranging from 5 to 40 years), using the straight-line
method of depreciation. Repairs and maintenance, which are not considered
improvements and do not extend the useful life of the non-utility property, are
charged to expense as incurred. When non-utility property is retired, or
otherwise disposed of, the asset and accumulated depreciation are removed, and
the resulting gain or loss is reflected in income. Non-utility property is
presented net of accumulated depreciation and amortization totaling $83.8
million and $69.9 million as of December 31, 2002 and 2001, respectively.
Interest capitalized on non-utility projects approximated $0.2 million in 20021
and was not significant in 2002 or 2000.
F. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the
carrying amount may be impaired. This review is performed in accordance with
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144), which the Company adopted as required on January 1, 2002. SFAS 144
establishes one accounting model for all impaired long-lived assets and
long-lived assets to be disposed of by sale or otherwise. SFAS 144 replaced
authoritative guidance in SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and
certain aspects of APB Opinion No. 30, "Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
144 retains the framework of SFAS 121 and requires the evaluation for impairment
involve the comparison of an asset's carrying value to the estimated future cash
flows the asset is expected to generate over its remaining life. If this
evaluation were to conclude that the carrying value of the asset is impaired, an
impairment charge would be recorded based on the difference between the asset's
carrying amount and its fair value (less costs to sell for assets to be disposed
of by sale) as a charge to operations or discontinued operations.
G. Goodwill
Goodwill arising from past business combinations, such as the Company's
acquisition of the Ohio operations, is accounted for in accordance with SFAS No.
142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted SFAS
142, as required on January 1, 2002. SFAS 142 changed the accounting for
goodwill from an amortization approach to an impairment-only approach. Thus,
amortization of goodwill that was not included as an allowable cost for
rate-making purposes ceased upon SFAS 142's adoption.
Goodwill is to be tested for impairment at a reporting unit level at least
annually. The impairment review consists of a comparison of the fair value of a
reporting unit to its carrying amount. If the fair value of a reporting unit is
less than its carrying amount, an impairment loss is recognized in operations.
Prior to the adoption of SFAS 142, the Company amortized goodwill on a
straight-line basis over 40 years. SFAS 142 required an initial impairment
review of all goodwill within six months of the adoption date. Results of the
initial impairment review were to be treated as a change in accounting principle
in accordance with APB Opinion No. 20 "Accounting Changes."
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations ceased on January 1, 2002. In 2001, net income before
cumulative effect of change in accounting principle and net income would have
been $46.7 million and $47.8 million, respectively, had goodwill not been
amortized and in 2000, net income would have been $56.4 million had goodwill not
been amortized. 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. Following is a
reconciliation of reported net income to the adjusted net income disclosed above
for years ended December 31, 2001 and 2000:
In millions 2001 2000
- ------------------------------------------------ --------------------
Net Income, As Reported $44.8 $55.9
Add: goodwill amortization - net of tax 3.0 0.5
- ------------------------------------------------------------------------
Net Income, As Adjusted $47.8 $56.4
========================================================================
H. Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the IURC, and retail public utility operations affecting Ohio
customers are subject to regulation by the PUCO.
SFAS 71
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 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 millions 2002 2001
- --------------------------------------------------------------
Demand side management programs $ 32.1 $ 31.7
Unamortized debt issue costs 19.5 21.2
Regulatory income tax asset 15.8 10.3
Other 7.8 4.6
- --------------------------------------------------------------
Total regulatory assets $ 75.2 $ 67.8
==============================================================
As of December 31, 2002, regulatory assets totaling $42.6 million are reflected
in rates charged to customers, of which $17.2 million is earning a return. The
remaining $32.6 million, which is not yet included in rates, represents
primarily electric demand side management (DSM) costs incurred after 1993. The
Company has rate orders for all deferred costs not yet in rates and therefore
believes that future recovery is probable. At December 31, 2002, the weighted
average recovery period of regulatory assets, other than those arising from book
- - tax basis differences, included in rates is 16.0 years. Regulatory income tax
assets are recovered as deferred tax assets and liabilities discussed in Note 4
become payable or receivable.
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 typically contain a fuel adjustment clause that allows for adjustment in
charges for electric energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. Metered electric rates also allow recovery,
through a quarterly rate adjustment mechanism, for the margin on electric sales
lost due to the implementation of demand side management programs.
The Company records any under-or-over-recovery resulting from gas and fuel
adjustment clauses each month in revenues. A corresponding asset or liability is
recorded until the under-or-over-recovery is billed or refunded to utility
customers. The cost of gas sold is charged to operating expense as delivered to
customers, and the cost of fuel for electric generation is charged to operating
expense when consumed.
I. Comprehensive Income
Comprehensive income is a measure of all changes in equity that result from the
transactions or other economic events during the period from non-shareholder
transactions. This information is reported in the Consolidated Statements of
Common Shareholder's Equity. The principal transaction resulting in other
comprehensive income relates to a minimum pension liability adjustment which is
a loss of $3.8 million ($2.4 million after tax) in 2001. In 2002, all such
liabilities were transferred to Vectren. The remaining component of accumulated
other comprehensive income relates to a cash flow hedge discussed in Note 12.
J. 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.
K. Excise and Gross Receipts Taxes
Excise taxes and a portion of gross receipts taxes are included in rates charged
to customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $32.4 million in 2002, $26.6
million in 2001, and $16.6 million in 2000. Excise and gross receipts taxes paid
are recorded as a component of taxes other than income taxes.
L. Earnings Per Share
Earnings per share are not presented as VUHI's common stock is wholly owned by
Vectren.
M. Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 4) and derivatives (Note 12).
N. Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
3. Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.6 million after tax and other
adjustments, as described below, related to 2000 and prior periods. Adjustments
were also made to previously reported 2002 quarterly results. In addition to
adjustments affecting previously reported net income, other reclassifications
were made to the previously reported 2001 and 2000 results to conform with the
2002 presentation.
Previously Reported 2001 and 2000 Net Income Adjustments
The Company determined that $11.6 million ($7.2 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.
The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $5.6 million ($3.5 million after tax).
The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.
The Company identified reconciliation errors and other errors related to the
recording of estimates that were not significant, either individually or in the
aggregate. As a result of these additional items, 2001 earnings were reduced by
$2.2 million ($1.4 million after tax). Originally reflected in 2001, the
correction of the year 2000 overstatement of electric revenue totaling $2.4
million ($1.5 million after tax), now reflected in 2000 as discussed below,
significantly offset these additional items.
The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an understatement of gas revenue by
$1.8 million ($1.1 million after tax) and an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $0.8 million ($0.5 million after tax). The impact of
the restatement of results for the year ended 2000 is an increase to net income
of approximately $100,000.
Previously Reported 2002 Quarterly Net Income Adjustments
As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, management determined that the
accrual of such carrying costs was more appropriate in periods prior to 2000
when DSM program expenditures were made. Therefore, such carrying costs
originally reflected in 2002 quarterly results were reversed and reflected in
common shareholder's equity as of January 1, 2000. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $1.8 million and $1.1 million after tax,
respectively. The cumulative impact from of these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$2.1 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. As a result of these additional items, beginning
common shareholders' equity was reduced by $1.5 million. Accordingly, retained
earnings as of January 1, 2000 reflects a cumulative net increase of $1.7
million.
Other Balance Sheet Adjustments
Certain reclassifications were made to reflect separate Company prepaid and
accrued taxes that result in the consolidated tax position. This adjustment
added approximately $26.6 million to receivables due from other Vectren
companies and prepaid and other current assets with a corresponding increase in
payables due to other Vectren companies, accrued liabilities, and deferred taxes
as of December 31, 2001. The Company also reclassified all previously recorded
goodwill not included in rates to goodwill on the balance sheet. This adjustment
resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in
prepayments and other current assets and an $8.9 million increase in goodwill.
Transfer of Assets to VUHI
Effective January 1, 2003, Vectren transferred certain information technology
systems and related assets and buildings from other entities within its
consolidated group to VUHI. These assets primarily support the operations of
VUHI's subsidiaries and VUHI's subsidiaries receive a charge for their use that
is included in their other operating expenses. The transfer requires retroactive
restatement of VUHI's consolidated financial statements for all periods
presented under accounting rules governing combinations of entities under common
control.
The years ended December 31, 2001 and 2000, have been restated for this asset
transfer, and the year ended December 31, 2002 reflects that asset transfer. For
the year ended December 31, 2002, operating income and net income attributable
to the contributed assets were $8.5 million and $3.5 million, respectively. For
the year ended December 31, 2002, operating income and net income attributable
to VUHI's historical operations were $199.2 million and $93.6 million,
respectively. As of December 31, 2002, total assets attributable to the
contributed assets were $131.1 million, and total assets attributable to VUHI's
historical operations were $2,439.3 million.
The Company has restated its financial statements to give effect to the matters
discussed above. Following is a summary of the effects of the asset transfer and
restatement of previously reported results of operations for 2001 and 2000. The
effects of these events on 2001 quarterly results and on 2002 previously
reported quarterly information, is discussed in Note 18. Note 18 is unaudited.
The effects on the income statement for the year ending December 31, 2001
follow:
Adjustments for
---------------------------
As Reported Asset Transfer Restatement As Restated
----------- -------------- ----------- -----------
OPERATING REVENUES
Gas utility $ 1,031.5 $ - $ (11.9) $ 1,019.6
Electric utility 378.9 - 2.3 381.2
Other - 0.2 - 0.2
- --------------------------------------------------------------------------------------------------
Total operating revenues 1,410.4 0.2 (9.6) 1,401.0
- --------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 708.2 - 0.7 708.9
Fuel for electric generation 74.4 - - 74.4
Purchased electric energy 91.7 - (4.8) 86.9
Other operating 234.7 (29.0) 6.4 212.1
Merger & integration costs 2.8 - - 2.8
Restructuring costs 15.0 - - 15.0
Depreciation & amortization 96.9 20.7 0.3 117.9
Taxes other than income taxes 51.3 0.4 (0.1) 51.6
- --------------------------------------------------------------------------------------------------
Total operating expenses 1,275.0 (7.9) 2.5 1,269.6
- --------------------------------------------------------------------------------------------------
OPERATING INCOME 135.4 8.1 (12.1) 131.4
- --------------------------------------------------------------------------------------------------
OTHER INCOME
Other - net 5.0 0.1 0.5 5.6
Equity in earnings of unconsolidated
affiliates - - (0.5) (0.5)
- --------------------------------------------------------------------------------------------------
Total other income 5.0 0.1 - 5.1
- --------------------------------------------------------------------------------------------------
Interest expense 70.1 0.6 - 70.7
- --------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 70.3 7.6 (12.1) 65.8
- --------------------------------------------------------------------------------------------------
Income taxes 22.7 2.9 (4.3) 21.3
Preferred dividend requirements of
a subsidiary 0.8 - - 0.8
- --------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 46.8 4.7 (7.8) 43.7
- --------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting
principle - net of tax 3.9 - (2.8) 1.1
- --------------------------------------------------------------------------------------------------
NET INCOME $ 50.7 $ 4.7 $ (10.6) $ 44.8
==================================================================================================
The effects on the income statement for the year ending December 31, 2000
follow:
Adjustments for
---------------------------
As Reported Asset Transfer Restatement As Restated
----------- -------------- ----------- -----------
OPERATING REVENUES
Gas utility $ 818.8 $ - $ 1.6 $ 820.4
Electric utility 336.4 - (2.0) 334.4
Other - 0.3 - 0.3
- ----------------------------------------------------------------------------------------
Total operating revenues 1,155.2 0.3 (0.4) 1,155.1
- ----------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 552.5 - - 552.5
Fuel for electric generation 75.7 - - 75.7
Purchased electric energy 36.4 - - 36.4
Other operating 209.9 (28.4) (0.9) 180.6
Merger & integration costs 32.7 - - 32.7
Depreciation & amortization 82.4 22.2 - 104.6
Taxes other than income taxes 36.2 0.3 - 36.5
- ----------------------------------------------------------------------------------------
Total operating expenses 1,025.8 (5.9) (0.9) 1,019.0
- ----------------------------------------------------------------------------------------
OPERATING INCOME 129.4 6.2 0.5 136.1
Other income - net 5.0 (0.4) (0.3) 4.3
Interest expense 46.1 0.3 - 46.4
- ----------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 88.3 5.5 0.2 94.0
- ----------------------------------------------------------------------------------------
Income taxes 34.9 2.1 0.1 37.1
Preferred dividend requirements
of subsidiary 1.0 - - 1.0
- ----------------------------------------------------------------------------------------
NET INCOME $ 52.4 $ 3.4 $ 0.1 $ 55.9
========================================================================================
The effects on the balance sheet as of December 31, 2001 follow:
ASSETS Adjustments for
------ ---------------------------
As Reported Asset Transfer Restatement As Restated
----------- -------------- ----------- -----------
Current Assets
Cash & cash equivalents $ 7.2 $ 0.2 $ (2.2) $ 5.2
Accounts receivable-less reserves 125.3 - (2.2) 123.1
Receivables due from other Vectren
companies 26.6 - 59.7 86.3
Accrued unbilled revenues 78.3 - (1.2) 77.1
Inventories 55.3 - (0.5) 54.8
Recoverable fuel & natural gas costs 76.5 - (6.3) 70.2
Prepayments & other current assets 127.4 - (44.6) 82.8
- ---------------------------------------------------------------------------------------------------
Total current assets 496.6 0.2 2.7 499.5
- ---------------------------------------------------------------------------------------------------
Utility Plant
Original cost 2,903.2 - 2.9 2,906.1
Less: accumulated depreciation &
amortization 1,308.2 - - 1,308.2
- ---------------------------------------------------------------------------------------------------
Net utility plant 1,595.0 - 2.9 1,597.9
- ---------------------------------------------------------------------------------------------------
Investments in unconsolidated
affiliates 4.0 - (0.5) 3.5
Other investments 12.2 7.8 - 20.0
Non-utility property-net 6.3 78.7 - 85.0
Goodwill-net 193.1 - 8.4 201.5
Regulatory assets 61.4 - 6.4 67.8
Other assets 22.8 - (8.7) 14.1
- ---------------------------------------------------------------------------------------------------
TOTAL ASSETS $2,391.4 $ 86.7 $ 11.2 $ 2,489.3
====================================================================================================
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 79.0 $ - $ 0.4 $ 79.4
Accounts payable to affiliated companies 36.5 - 0.9 37.4
Payables due to other Vectren companies 11.5 22.4 17.7 51.6
Accrued liabilities 97.5 0.5 (2.8) 95.2
Short-term borrowings due to other
Vectren companies - 29.0 - 29.0
Short-term borrowings 274.2 - - 274.2
Long-term debt subject to tender 11.5 - - 11.5
Current maturities of long-term debt 1.3 - - 1.3
- ---------------------------------------------------------------------------------------------------
Total current liabilities 511.5 51.9 16.2 579.6
- ---------------------------------------------------------------------------------------------------
Long-Term Debt-Net of Current Maturities &
Debt Subject to Tender 900.9 - - 900.9
Deferred Income Taxes & Other Liabilities
Deferred income taxes 171.8 - 4.7 176.5
Deferred credits & other liabilities 93.7 - (0.8) 92.9
- ----------------------------------------------------------------------------------------------------
Total deferred credits & other
liabilities 265.5 - 3.9 269.4
- ---------------------------------------------------------------------------------------------------
Cumulative, Redeemable Preferred Stock
of a Subsidiary 0.5 - - 0.5
Common shareholder's equity
Common stock (no par value) 385.7 - - 385.7
Retained earnings 329.0 34.8 (8.8) 355.0
Accumulated other comprehensive loss (1.7) - (0.1) (1.8)
- ---------------------------------------------------------------------------------------------------
Total common shareholder's equity 713.0 34.8 (8.9) 738.9
- ---------------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S
EQUITY $2,391.4 $ 86.7 $ 11.2 $ 2,489.3
===================================================================================================
4. Transactions with Other Vectren Companies
Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, finance, tax, risk
management, human resources, which includes charges for restricted stock
compensation and for pension and other postretirement benefits not directly
charged to subsidiaries. These costs have been allocated using various
allocators, primarily number of employees, number of customers and/or revenues.
Allocations are based on cost. VUHI received corporate allocations totaling
$41.4 million, $49.4 million, and $36.8 million for the years ended December 31,
2002, 2001, and 2000, 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, 2002, 2001, and
2000, totaled $62.1 million, $58.4 million, and $25.7 million, respectively.
Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that
require accounting as described in SFAS No. 87 "Employers' Accounting for
Pensions and SFAS No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions," respectively. Subsequent to the merger forming Vectren, an
allocation of expense is determined by Vectren's actuaries, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date. These costs are directly charged to individual
subsidiaries. Other components of costs (such interest cost from prior service
and asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Plan assets nor the FAS 87/106 liability is
allocated to individual subsidiaries since these assets and obligations are
derived from corporate level decisions. Further, Vectren satisfies the future
funding requirements of plans and the payment of benefits from general corporate
assets. This allocation methodology is consistent with "multiemployer" benefit
accounting as described in SFAS 87 and 106.
For the years ended December 31, 2002 and 2001 pension expense totaling $5.5
million and $5.1 million, respectively, were directly charged by Vectren to the
Company. For the years ended December 31, 2002 and 2001other benefit expenses
totaling $1.0 million in both years were directly charged by Vectren to the
Company. In 2000, the Company recognized $8.8 million in charges for
participation in Vectren benefit plans. As of December 31, 2002 and 2001, $51.8
million and $53.3 million is included in other non-current liabilities and
represents expense directly charged to the Company that is yet to be funded to
Vectren, and $3.5 million and $4.8 million is included in other assets for
amounts funded in advance to Vectren.
Cash Management and Borrowing Arrangements
The Company participates in a centralized cash management program with Vectren,
other wholly owned subsidiaries, and banks which permits funding of checks as
they are presented.
Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $350.0 million commercial paper program, of which $239.1
million is outstanding at December 31, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at December 31, 2002. VUHI has no independent assets or
operations, the guarantees are full and unconditional and joint and several, and
VUHI has no subsidiaries other than the subsidiary guarantors.
Stock-Based Incentive Plans
VUHI does not have stock-based compensation plans separate from Vectren. An
insignificant number of VUHI's employees participate in Vectren's stock-based
compensation plans.
Income Taxes
Vectren and subsidiary companies file a consolidated federal income tax return.
For financial reporting purposes, VUHI'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 millions 2002 2001 2000
- ---------------------------------------------------------------------------
Current:
Federal $ 62.5 $ 32.2 $ 21.4
State 7.7 4.0 2.8
- ---------------------------------------------------------------------------
Total current taxes 70.2 36.2 24.2
- ---------------------------------------------------------------------------
Deferred:
Federal (16.2) (12.0) 13.8
State (4.9) (0.6) 1.5
- ---------------------------------------------------------------------------
Total deferred taxes (21.1) (12.6) 15.3
- ---------------------------------------------------------------------------
Amortization of investment tax credits (2.3) (2.3) (2.4)
- ---------------------------------------------------------------------------
Total income tax expense $ 46.8 $ 21.3 $ 37.1
===========================================================================
A reconciliation of the federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- -----------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 % 35.0 %
State and local taxes-net of federal benefit 1.3 3.3 3.6
Nondeductible merger costs - - 4.8
Amortization of investment tax credit (1.7) (4.0) (2.7)
All other-net (2.3) (2.2) (0.7)
- -----------------------------------------------------------------------------
Effective tax rate 32.3 % 32.1 % 40.0 %
=============================================================================
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 millions 2002 2001
- -------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences $ 189.8 $ 197.1
Regulatory assets recoverable through future rates 37.5 33.5
Regulatory liabilities to be settled through
future rates (21.7) (23.2)
Employee benefit obligations (30.2) (24.3)
Other - net (3.1) (6.6)
- -------------------------------------------------------------------------------
Net noncurrent deferred tax liability 172.3 176.5
- -------------------------------------------------------------------------------
Current deferred tax liabilities (assets):
Deferred fuel costs-net 7.7 21.1
LIFO inventory - (2.0)
- -------------------------------------------------------------------------------
Net current deferred tax liability 7.7 19.1
- -------------------------------------------------------------------------------
Net deferred tax liability $ 180.0 $ 195.6
===============================================================================
At December 31, 2002 and 2001, investment tax credits totaling $18.6 million and
$20.9 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,
2002. Alternative Minimum Tax credit carryforwards of approximately $5.2 million
were utilized in 2001.
5. 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 and Vectren Retail, LLC
(the Company's retail gas marketer) in 2002. ProLiance's primary business is
optimizing the gas portfolios of utilities and providing services to large end
use customers. Vectren continues to account for its investment in ProLiance
using the equity method of accounting.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) and audit process
administered by the PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility.
However, with respect to the pricing of gas commodity purchased from ProLiance,
the price paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in a consolidated GCA proceeding involving Indiana Gas and
Citizens Gas.
On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other
consumer parties, entered into and filed with the IURC a settlement setting
forth the terms for resolution of all pending regulatory issues related to
ProLiance, including the three pricing issues. On July 23, 2002, the IURC
approved the settlement filed by the parties. The GCA proceeding has been
concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas,
and ProLiance have been approved and extended through March 31, 2007. ProLiance
will also have the opportunity, if it so elects, to participate in a "request
for proposal" process for service to the utilities after March 31, 2007.
For past services provided to Indiana Gas by ProLiance, Indiana Gas made refunds
to retail customers pursuant to the settlement totaling $6.4 million in the
fourth quarter of 2002. A subsidiary of Vectren's nonregulated operations has
indemnified Indiana Gas for the amount of the refund as well as any other
amounts incurred as a result of the settlement. Accordingly, the refund had no
effect on operating margin or net income.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2002, 2001, and 2000 totaled $542.5 million, $610.6
million, and $478.9 million, respectively. Amounts owed to ProLiance at December
31, 2002 and 2001 for those purchases were $83.7 million and $36.1 million,
respectively, and are included in accounts payable to affiliated companies in
the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
Other Affiliate Transactions
The Company has ownership interests in other affiliated companies accounted for
using the equity method of accounting that provide materials management,
underground construction and repair, facilities locating, and meter reading
services to the Company. For the years ended December 31, 2002, 2001, and 2000,
fees for these services and construction-related expenditures totaled $38.3
million, $30.4 million, and $6.9 million, respectively. Amounts charged by these
affiliates are market based. Amounts owed to unconsolidated affiliates other
than ProLiance totaled $1.8 million and $1.3 million at December 31, 2002 and
2001, respectively, and are included in accounts payable to affiliated companies
in the Consolidated Balance Sheets.
6. Borrowing Arrangements
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term by subsidiary follow:
At December 31,
- ------------------------------------------------------------------------------
In millions 2002 2001
- ------------------------------------------------------------------------------
VUHI
Fixed Rate Senior Unsecured Notes
2011, 6.625% $ 250.0 $ 250.0
2031, 7.25% 100.0 100.0
- ------------------------------------------------------------------------------
Total VUHI 350.0 350.0
- ------------------------------------------------------------------------------
SIGECO
First Mortgage Bonds
Fixed Rate:
2003, Series B, 6.25%, tax exempt 1.0 1.0
2016, 1986 Series, 8.875% 13.0 13.0
2023, Series, 7.60% 45.0 45.0
2023, Series B, 6.00%, tax exempt 22.8 22.8
2025, 1993 Series, 7.625% 20.0 20.0
2029, 1999 Senior Notes, 6.72% 80.0 80.0
Adjustable Rate:
2015, Pollution Control Series A, presently 4.30%,
tax exempt, next rate adjustment: 2004 10.0 10.0
2025, Pollution Control Series A, presently 4.75%,
tax exempt, next rate adjustment: 2006 31.5 31.5
2024, Environmental Improvement Series A, tax
exempt, adjusts every 35 days, weighted average
for year: 1.80% 22.5 22.5
- ------------------------------------------------------------------------------
Total First Mortgage Bonds 245.8 245.8
- ------------------------------------------------------------------------------
Adjustable Rate Senior Unsecured Bonds
2020, Pollution Control Series B, presently 4.40%,
tax exempt, next rate adjustment: 2003 4.6 4.6
2030, Pollution Control Series B, presently 4.40%,
tax exempt, next rate adjustment: 2003 22.0 22.0
2030, Pollution Control Series C, presently 5.00%,
tax exempt, next rate adjustment: 2006 22.2 22.2
- ------------------------------------------------------------------------------
Total Adjustable Rate Senior Unsecured Bonds 48.8 48.8
- ------------------------------------------------------------------------------
Total SIGECO 294.6 294.6
- ------------------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------------------
In millions 2002 2001
- ------------------------------------------------------------------------------
Indiana Gas
Fixed Rate Senior Unsecured Notes
2003, Series F, 5.75% 15.0 15.0
2004, Series F, 6.36% 15.0 15.0
2007, Series E, 6.54% 6.5 6.5
2013, Series E, 6.69% 5.0 5.0
2015, Series E, 7.15% 5.0 5.0
2015, Insured Quarterly, 7.15% 20.0 20.0
2015, Series E, 6.69% 5.0 5.0
2015, Series E, 6.69% 10.0 10.0
2021, Private Placement, 9.375%,
$1.3 due annually in 2002 23.8 25.0
2025, Series E, 6.31% - 5.0
2025, Series E, 6.53% 10.0 10.0
2027, Series E, 6.42% 5.0 5.0
2027, Series E, 6.68% 3.5 3.5
2027, Series F, 6.34% 20.0 20.0
2028, Series F, 6.75% 13.6 13.8
2028, Series F, 6.36% 10.0 10.0
2028, Series F, 6.55% 20.0 20.0
2029, Series G, 7.08% 30.0 30.0
2030, Insured Quarterly, 7.45% 49.9 50.0
- ------------------------------------------------------------------------------
Total Indiana Gas 267.3 273.8
- ------------------------------------------------------------------------------
Total long-term debt outstanding 911.9 918.4
Less: Current maturities of long-term debt 39.8 1.3
Debt subject to tender 26.6 11.5
Unamortized debt premium & discount - net 4.3 4.7
- ------------------------------------------------------------------------------
Total long-term debt-net $ 841.2 $ 900.9
==============================================================================
VUHI
In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission for $350.0 million aggregate principal amount of
unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with
an aggregate principal amount of $100.0 million and an interest rate of 7.25%
(the October Notes), and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.
These issues have no sinking fund requirements, and interest payments are due
quarterly for the October Notes and semi-annually for the December Notes. The
October Notes are due October 2031, but may be called by the Company, in whole
or in part, at any time after October 2006 at 100% of the principal amount plus
any accrued interest thereon. The December Notes are due December 2011, but may
be called by the Company, 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 the indenture, plus 25 basis points.
The net proceeds from the sale of the senior notes and settlement of the hedging
arrangements (see Note 12) totaled $344.0 million.
Indiana Gas
In December 2000, $20.0 million of 15-Year Insured Quarterly (IQ) Notes at an
interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at an interest rate
of 7.45% were issued. Indiana Gas may call the 15-Year IQ Notes, in whole or in
part, from time to time on or after December 15, 2004 and has the option to
redeem the 30-Year IQ Notes in whole or in part, from time to time on or after
December 15, 2005. The IQ notes have no sinking fund requirements. The net
proceeds totaled $67.9 million. Both the quarterly interest payments and the
principal amount of the IQ Notes are insured by Ambac Assurance Corporation.
Long-Term Debt Put & Call Provisions
On January 15, 2003, the Company called the remaining $23.8 million of Indiana
Gas' 9.375% private placement notes originally due in 2021. Since the proceeds
to repay the notes were generated from short-term borrowings, these notes are
classified in current maturities of long-term debt at December 31, 2002.
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. Other than those described below
related to ratings triggers, 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 subject to tender during the years following
2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0 in 2005, $53.7 in
2006, $20.0 in 2007, and $120.0 thereafter. Debt that may be put to the Company
within one year is classified as debt subject to tender in current liabilities.
Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of
the greatest amount of bonds outstanding under the Mortgage Indenture. This
requirement may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2002 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2002 is excluded from
current liabilities in the Consolidated Balance Sheets. At December 31, 2002,
$342.8 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.
Consolidated maturities and sinking fund requirements on long-term debt,
including debt to be called, during the five years following 2002 (in millions)
are $39.8 in 2003, $15.0 in 2004, zero in 2005, zero in 2006, and $6.5 in 2007.
Short-Term Borrowings
At December 31, 2002, the Company has $330.0 million of short-term borrowing
capacity, of which approximately $90.9 million is available. Subsequent to
December 31, 2002, the Company increased its capacity $145.0 million to $475.0
million. See the table below for interest rates and outstanding balances.
Year ended December 31,
- -------------------------------------------------------------------------------
In millions 2002 2001 2000
- -------------------------------------------------------------------------------
Weighted average commercial paper and bank loans
outstanding during the year $ 155.7 $ 356.1 $ 190.0
Weighted average interest rates during the year
Bank loans 2.61% 4.39% 6.62%
Commercial paper 2.02% 5.77% 6.60%
At December 31,
- --------------------------------------------------------------------
In millions 2002 2001
- --------------------------------------------------------------------
Commercial paper $ 239.1 $ 273.3
Bank loans - 0.9
- --------------------------------------------------------------------
Total short-term borrowings $ 239.1 $ 274.2
====================================================================
Prior to the asset transfer discussed in Note 3, the operations integrated with
VUHI relied on the borrowing arrangements of Vectren Capital Corp, a wholly
owned subsidiary of Vectren, for its working capital needs. Borrowings
outstanding from Vectren Capital Corp at December 31, 2002 and 2001 were $86.9
million and $29.0 million, respectively. Interest expense incurred on these
borrowing arrangements for the years ended December 31, 2002, 2001, and 2000
totaled $3.0 million, $0.6 million, and $0.2 million, respectively.
Debt Guarantees
VUHI's currently outstanding long-term and short-term debt is guaranteed by
Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and
joint and several, and VUHI has no subsidiaries other than the subsidiary
guarantors. VUHI's long-term and short-term debt outstanding at December 31,
2002 totaled $350.0 million and $239.1 million, respectively.
Covenants
Both long-term and short-term borrowing arrangements contain customary default
provisions, restrictions on liens, sale leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2002, the Company was in
compliance with all financial covenants.
7. Cumulative Preferred Stock of a Subsidiary
Redemption of Preferred Stock of a Subsidiary
Nonredeemable preferred stock of a subsidiary 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 of a
subsidiary 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.
As both series of preferred stock redeemed was that of a subsidiary, 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, 2002 and
2001, there were 3,437 shares and 4,597 shares outstanding, respectively.
8. Common Shareholder's Equity
In February 2001, the Company received $129.4 million from an equity
contribution by Vectren. Vectren funded the contribution with the proceeds from
an offering of its common stock. In December 2001, Vectren made an additional
equity contribution of $35.0 million with proceeds received from dividends paid
by Vectren's nonregulated operations.
9. Commitments & Contingencies
Commitments
Firm commitments to purchase natural gas for years following December 31, 2002
totaled (in millions) $89.5 in 2003, $21.3 in 2004, and $3.6 million in 2005.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 10 regarding the Clean
Air Act.
10. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through December 31, 2002, $70.0 million has been expended.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit is pending in the U.S. District Court for the
Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled the IDEM's Voluntary Remediation Program. In response
SIGECO submitted to the IDEM the results of preliminary site investigations
conducted in the mid-1990's. These site investigations confirmed that based upon
the conditions known at the time, the sites posed no risk to human health or the
environment. Follow up reviews have recently been initiated by the Company to
confirm that the sites continue to pose no such risk.
11. Rate & Regulatory Matters
Gas Costs Proceedings
Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
Vectren's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through commission-approved gas
cost adjustment mechanisms.
In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.
Purchased Power Costs
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
12. Risk Management, Derivatives, & Other Financial Instruments
The Company is exposed to various business risks associated with commodity
prices, interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company's risk management program includes, among other
things, the use of derivatives to mitigate risk.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations, which subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.
The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts.
The Company's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.
Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. To manage this exposure, the Company may periodically
use derivative financial instruments to reduce earnings fluctuations caused by
interest rate volatility.
Other Risks
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages exposure to counter-party credit risk by entering into
contracts with companies that can be reasonably expected to fully perform under
the terms of the contract. Counter-party credit risk is monitored regularly and
positions are adjusted appropriately to manage risk. Further, tools such as
netting arrangements and requests for collateral are also used to manage credit
risk. Market risk is the adverse effect on the value of a financial instrument
that results from a change in commodity prices or interest rates. The Company
attempts to manage exposure to market risk associated with commodity contracts
and interest rates by establishing parameters and monitoring those parameters
that limit the types and degree of market risk that may be undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits or refunds
cash deposits based on that review.
Although the Company's regulated operations are exposed to limited commodity
price risk, volatile natural gas prices can result in higher working capital
requirements; increased expenses including unrecoverable interest costs,
uncollectible accounts expense, and unaccounted for gas; and some level of price
sensitive reduction in volumes sold.
Accounting for Derivatives & Other Contracts
When a derivative contract that is entered into in the normal course of
operations is probable of physical settlement, that contract is designated and
documented as a normal purchase or normal sale and is exempted from
mark-to-market accounting. Otherwise, derivative contracts are recorded at
market value as current or noncurrent assets or liabilities depending on their
value and on when the contracts are expected to be settled. Unless the contract
is a cash flow hedge that qualifies for hedge accounting treatment or is subject
to SFAS 71, that contract is marked to market through earnings. When hedge
accounting is appropriate, the Company assesses and documents hedging
relationships between its financial instruments, including commodity contracts
and interest rate swaps, and underlying risks as well as the investment's risk
management objectives and anticipated effectiveness. When the hedging
relationship is highly effective, derivatives are designated as hedges. The
market value of the effective portion of the hedge is marked to market in
accumulated other comprehensive income for cash flow hedges. The ineffective
portion of hedging arrangements is marked to market through earnings. Contracts
affected by SFAS 71 are marked to market as a regulatory asset or liability.
Market value is determined using quoted market prices from independent sources.
Non-Firm Wholesale Power Marketing Contracts
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale contracts that expose the Company to
limited market risk and are settled both financially and physically. These
operations do not meet the definition of energy trading activities based upon
the provisions in EITF Issue 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" (EITF 98-10).
Asset optimization sale contracts are reflected in electric utility revenues,
and purchase contracts are reflected in purchased electric energy. Contracts
with counter-parties subject to master netting arrangements are presented net in
the Consolidated Balance Sheets. Subsequent to the adoption of SFAS 133 as
described below, certain non-firm power marketing contracts that are
periodically financially settled are recorded at market value. Changes in market
value, which is a function of the normal decline in market value as earnings are
realized and the fluctuation in market value resulting from price volatility,
are recorded in purchased electric energy.
Power marketing contracts recorded at market value at December 31, 2002 totaled
$3.5 million of prepayments and other current assets and $4.2 million of accrued
liabilities, compared to $6.1 million of prepayments and other current assets
and $2.8 million of accrued liabilities at December 31, 2001. The change in the
net value of these contracts includes an unrealized loss of $3.6 million in 2002
and an unrealized gain of $1.5 million in 2001, respectively. Including these
unrealized changes in market value, overall margin (revenue net of purchased
power) from non-firm wholesale power marketing operations for the years ended
December 31, 2002 and 2001 was $14.9 million and $19.9 million, respectively.
Prior to the adoption of SFAS 133 and for the year ended December 31, 2000,
margin was $21.1 million.
Financial Contracts
In September 2001, the Company entered into several forward starting interest
rate swaps with a total notional amount of $200.0 million in anticipation of
VUHI's $250.0 million long-term debt issuance. Upon issuance of the debt in
December 2001, the swaps were settled resulting in the Company receiving $0.9
million. The value received is being amortized from accumulated other
comprehensive income to interest expense over the life of the debt.
In December 2000, the Company entered into an interest rate swap used to hedge
interest rate risk associated with variable rate short-term notes payable
totaling $150.0 million. The swap was entered into concurrently with the
issuance of the floating rate notes on December 28, 2000 and swapped the debt's
variable interest rate of three-month LIBOR plus 0.75% for a fixed rate of
6.64%. The swap expired on December 27, 2001, the date the debt agreement
expired.
Prior to the adoption of SFAS 133, instruments hedging interest rate risk were
accounted for upon settlement in interest expense. After adoption of SFAS 133,
hedging instruments are carried at market value, and changes in market value are
recorded in accumulated other comprehensive income, when effective, and are
recorded to interest expense as settled.
As of December 31, 2002 and 2001, no interest rate swaps are outstanding. At
December 31, 2002, approximately $0.8 million remains in accumulated other
comprehensive income related to future interest payments. Of that amount, $0.1
million will be reclassified to earnings in 2003 and $0.1 million was
reclassified to earnings during 2002.
Other Commodity-Related Operations
Other commodity contracts are generally settled by physical delivery or receipt
and are within the normal operations of the Company. Contracts entered into that
are probable of physical delivery or receipt receive accounting recognition upon
settlement. Firm wholesale electric contracts are recorded in electric utility
revenues. Certain contracts that purchase commodities for operational needs are
recorded when settled in other operating expenses.
Impact of Adoption of SFAS 133
In June 1998, the FASB issued SFAS 133, which required that every derivative
instrument be recorded on the balance sheet as an asset or liability measured at
its market value and that changes in the derivative's market value be recognized
currently in earnings unless specific hedge or regulatory accounting criteria
are met.
SFAS 133, as amended, required that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income, other comprehensive income, or regulatory assets or liabilities,
as appropriate. A change in earnings or other comprehensive income was reported
as a cumulative effect of a change in accounting principle in accordance with
APB Opinion No. 20, "Accounting Changes."
Resulting from the adoption of SFAS 133, certain non-firm wholesale power
marketing contracts that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million net of tax) recorded as a cumulative
effect of accounting change. SFAS 133 did not impact other commodity contracts
because they were normal purchases and sales specifically excluded from the
provisions of SFAS 133 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,
- -------------------------------------------------------------------------------------
2002 2001
-------------------- -------------------
Carrying Est. Fair Carrying Est. Fair
In millions Amount Value Amount Value
- ---------------------------------------- -------------------- -------------------
Long-term debt $ 911.9 $ 968.9 $ 918.4 $ 912.0
Short-term borrowings & notes payable 239.1 239.1 274.2 274.2
Short-term borrowings due to other
Vectren companies 86.9 86.9 29.0 29.0
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.
13. Additional Operational & Balance Sheet Information
Other - net in the Consolidated Statements of Income consists of the following:
Year ended December 31,
- ---------------------------------------------------------------------------
In millions 2002 2001 2000
- ---------------------------------------------------------------------------
AFUDC & capitalized interest $ 5.3 $ 4.8 $ 5.0
Interest income 0.8 0.2 1.2
Other income 3.3 8.0 2.1
Other expense (2.3) (7.4) (4.0)
- ---------------------------------------------------------------------------
Total other - net $ 7.1 $ 5.6 $ 4.3
===========================================================================
Other current assets in the Consolidated Balance Sheets consists of the
following:
At December 31,
- ---------------------------------------------------------------------------
In millions 2002 2001
- ---------------------------------------------------------------------------
Prepaid gas delivery service $ 70.3 $ 67.7
Prepaid taxes 4.8 8.7
Other prepayments & current assets 11.4 6.4
- ---------------------------------------------------------------------------
Total prepayments & other current assets $ 86.5 $ 82.8
===========================================================================
Accrued liabilities in the Consolidated Balance Sheets consists of the
following:
At December 31,
- --------------------------------------------------------------------------
In millions 2002 2001
- --------------------------------------------------------------------------
Accrued taxes $ 27.3 $ 34.9
Refunds to customers & customer deposits 21.0 18.7
Accrued interest 13.4 12.9
Deferred income taxes 7.7 19.1
Accrued salaries & other 13.8 9.6
- --------------------------------------------------------------------------
Total accrued liabilities $ 83.2 $ 95.2
==========================================================================
14. Segment Reporting
As discussed in Note 3, effective January 1, 2003, Vectren transferred certain
information technology systems and related assets and buildings from other
entities within its consolidated group to VUHI. These assets primarily support
the operations of VUHI's subsidiaries. The operations of these assets comprise
the Other Operations operating segment. The Company separates its operations
into three operating segments: Gas Utility Services, Electric Utility Services,
and Other Operations. The Company uses operating income as the measure of
profitability for its segments.
Gas Utility Services provides natural gas distribution and transportation
services in nearly two-thirds of Indiana and west central Ohio. Electric Utility
Services provides electricity primarily to southwestern Indiana, and includes
the Company's power generating and marketing operations. Other Operations
provide information technology and other support services to those utility
operations. Following is detailed information about the Company's operating
segments.
Year ended December 31,
- ------------------------------------------------------------------------------
In millions 2002 2001 2000
- ------------------------------------------------------------------------------
Operating Revenues
Gas Utility Services $ 909.0 $ 1,019.6 $ 820.4
Electric Utility Services 608.1 381.2 334.4
Other Operations 22.3 29.1 33.5
Intersegment Eliminations (22.0) (28.9) (33.2)
- ------------------------------------------------------------------------------
Total operating revenues $1,517.4 $ 1,401.0 $ 1,155.1
==============================================================================
Operating Income
Gas Utility Services $ 99.5 $ 44.9 $ 55.9
Electric Utility Services 100.1 77.6 74.0
Other Operations 8.1 8.9 6.2
- ------------------------------------------------------------------------------
Total operating income $ 207.7 $ 131.4 $ 136.1
==============================================================================
Depreciation & Amortization
Gas Utility Services $ 56.8 $ 58.5 $ 43.8
Electric Utility Services 40.0 38.7 38.6
Other Operations 13.9 20.7 22.2
- ------------------------------------------------------------------------------
Total depreciation & amortization $ 110.7 $ 117.9 $ 104.6
==============================================================================
Year ended December 31,
- ------------------------------------------------------------------------------
In millions 2002 2001 2000
- ------------------------------------------------------------------------------
Equity in Earnings of
Unconsolidated Affiliates
Gas Utility Services $ 0.1 $ 0.7 $ -
Electric Utility Services (1.9) (1.2) -
- ------------------------------------------------------------------------------
Total equity in earnings of
unconsolidated affiliates (1.8) $ (0.5) $ -
==============================================================================
Capital Expenditures
Gas Utility Services $ 63.0 $ 77.8 $ 73.1
Electric Utility Services 88.8 69.8 37.6
Other Operations 65.5 55.2 8.0
- ------------------------------------------------------------------------------
Total capital expenditures $ 217.3 $ 202.8 $ 118.7
==============================================================================
At December 31,
- -------------------------------------------------------------------
In millions 2002 2001
- ------------------------------------------------------------------
Identifiable Assets
Gas Utility Services $1,555.1 $ 1,563.2
Electric Utility Services 860.9 807.6
Other Operations 165.6 120.0
Eliminations (11.2) (1.5)
- ------------------------------------------------------------------
Total identifiable assets $2,570.4 $ 2,489.3
==================================================================
15. Special Charges for 2001 and 2000
Restructuring & Related Charges
As part of continued cost saving efforts, in June 2001, the Company'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 $10.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $4.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $15.0 million. These charges were comprised of $7.6 million for
employee severance, related benefits and other employee related costs, $4.0
million for lease termination fees related to duplicate facilities and other
facility costs, and $3.4 million for consulting and other fees.
The $7.6 million of severance and related costs includes $1.6 million of
deferred compensation payable at various times through 2016 and $0.8 million of
non-cash pension costs. The $4.0 million of lease termination fees includes $1.0
million of non-cash charges for impaired leasehold improvements. Restructuring
expenses were incurred by the Company's operating segments as follows: $10.2
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 100
employees. Employee separation benefits include severance, healthcare, and
outplacement services. As of December 31, 2001, approximately 80 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 and the final settlement of the lease obligation which has
yet to occur.
In June 2001, the Company established accruals totaling $8.2 million ($6.2
million for severance and $2.0 million for lease termination fees). Throughout
2001 additional expenses totaling $1.0 million for lease termination fees were
incurred. Cash payments in 2001 totaled $4.9 million, all of which related to
severance payments. As of December 31, 2001, the remaining accrual related to
the restructuring was $4.3 million. Of that amount, $1.3 million remained
accrued for severance, almost all of which relates to deferred compensation
arrangements, and $3.0 million remained for lease termination fees. During 2002,
the accrual for severance did not substantially change, and $1.0 million of
lease costs were paid. At December 31, 2002, the remaining accrual was $3.6
million ($1.6 million for severance and $2.0 million for lease termination
fees). The restructuring accrual is included in accrued liabilities.
Merger & Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
Since March 31, 2000, $35.5 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$19.3 million. Of this amount, $5.5 million related to employee and executive
severance costs, $11.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. The remaining $16.2 million was expensed through
December 31, 2001 ($13.4 million in 2000 and $2.8 million in 2001) for
accounting fees resulting from merger related filing requirements, consulting
fees related to integration activities such as organization structure, employee
travel between company locations as part of integration activities, internal
labor of employees assigned to integration teams, investor relations
communications activities, and certain benefit costs.
During the merger planning process, approximately 135 positions were identified
for elimination. As of December 31, 2001, all such identified positions were
vacated.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets were
shortened in 2000 to reflect this decision. These information system assets are
owned by a wholly owned subsidiary of Vectren, and the fees allocated by the
subsidiary for the use of these systems by the Company's subsidiaries are
reflected in other operating expenses. As a result of the shortened useful
lives, additional fees were incurred by the Company, resulting in additional
other operating expense of $9.6 million ($6.0 million after tax) for the year
ended December 31, 2001 and $11.4 million ($7.1 million after tax) for the year
ended December 31, 2000.
16. Impact of Recently Issued Accounting Guidance
EITF 02-03
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
held for "trading purposes." The consensus rescinded EITF Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) as well as other decisions reached on energy trading
contracts at the EITF's June 2002 meeting.
The Company's non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
the definition of energy trading activities based upon the provisions in EITF
98-10. Currently, the Company uses a gross presentation to report the results of
these operations as described in Note 12. The Company has re-evaluated its
portfolio of derivative contracts and has determined gross presentation remains
appropriate.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.
FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
17. Subsidiary Guarantor and Consolidating Information
The Company's three operating utility companies, SIGECO, Indiana Gas, and VEDO
are guarantors of VUHI's $325.0 million in short-term credit facilities and
VUHI's $350.0 million unsecured senior notes. As a result of the asset transfer
described in Note 3, VUHI has operations other than those of the subsidiary
guarantors. Pursuant to Article 3-10 of Regulation S-X, disclosure of the
results of operations and balance sheets of the subsidiary guarantors separate
from the parent company's operations is required. Following are consolidating
financial statements including information on the combined operations of the
subsidiary guarantors separate from the other operations of the parent company.
Consolidating Balance Sheet as of December 31, 2002:
ASSETS Subsidiary Parent
Guarantors Company Eliminations Consolidated
---------- -------- ------------ ------------
Current Assets
Cash & cash equivalents $ 10.2 $ 0.3 $ - $ 10.5
Accounts receivable-less reserves 130.8 1.1 - 131.9
Receivables due from other Vectren
companies 39.3 19.7 (2.7) 56.3
Accrued unbilled revenues 112.7 - - 112.7
Inventories 56.0 - - 56.0
Recoverable fuel & natural gas costs 22.1 - - 22.1
Prepayments & other current assets 86.2 0.3 - 86.5
- ---------------------------------------------------------------------------------------------
Total current assets 457.3 21.4 (2.7) 476.0
- ---------------------------------------------------------------------------------------------
Utility Plant
Original cost 3,037.2 - - 3,037.2
Less: accumulated depreciation
& amortization 1,389.0 - - 1,389.0
- ---------------------------------------------------------------------------------------------
Net utility plant 1,648.2 - - 1,648.2
- ---------------------------------------------------------------------------------------------
Investments in consolidated subsidiaries - 802.4 (802.4) -
Notes receivable from consolidated
subsidiaries 8.5 493.9 (502.4) -
Investments in unconsolidated affiliates 0.1 2.3 - 2.4
Other investments 13.1 8.8 - 21.9
Non-utility property-net 5.4 133.8 - 139.2
Goodwill-net 202.2 - - 202.2
Regulatory assets 70.3 4.9 - 75.2
Other assets 4.9 0.4 - 5.3
- ---------------------------------------------------------------------------------------------
TOTAL ASSETS $2,410.0 $ 1,467.9 $(1,307.5) $ 2,570.4
=============================================================================================
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 71.3 $ 3.5 $ - $ 74.8
Accounts payable to affiliated companies 85.2 0.4 - 85.6
Accounts payable due to other Vectren
companies 61.3 11.2 (2.7) 69.8
Accrued liabilities 83.8 1.7 (2.3) 83.2
Short-term borrowings - 239.1 - 239.1
Short-term borrowings due from
other Vectren companies 147.6 95.4 (156.1) 86.9
Current maturities of long-term debt 39.8 - - 39.8
Long-term debt subject to tender 26.6 - - 26.6
- ---------------------------------------------------------------------------------------------
Total current liabilities 515.6 351.3 (161.1) 705.8
- ---------------------------------------------------------------------------------------------
Long-Term Debt
Long-term debt-net of current maturities &
debt subject to tender 492.8 348.4 - 841.2
Long-term debt due to VUHI 344.0 - (344.0) -
- ---------------------------------------------------------------------------------------------
Total long-term debt-net 836.8 348.4 (344.0) 841.2
- ---------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 174.6 (2.3) - 172.3
Deferred credits & other liabilities 80.3 1.9 - 82.2
- ---------------------------------------------------------------------------------------------
Total deferred credits & other
liabilities 254.9 (0.4) - 254.5
- ---------------------------------------------------------------------------------------------
Cumulative, Redeemable Preferred
Stock of a Subsidiary 0.3 - - 0.3
Common Shareholder's Equity
Common stock (no par value) 461.3 385.7 (461.3) 385.7
Retained earnings 341.1 382.4 (341.1) 382.4
Accumulated other comprehensive income - 0.5 - 0.5
- ---------------------------------------------------------------------------------------------
Total common shareholder's equity 802.4 768.6 (802.4) 768.6
- ---------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S
EQUITY $2,410.0 $ 1,467.9 $(1,307.5) $ 2,570.4
=============================================================================================
Consolidating Balance Sheet as of December 31, 2001:
ASSETS Subsidiary Parent
Guarantors Company Eliminations Consolidated
---------- ------- ------------ ------------
Current Assets
Cash & cash equivalents $ 7.0 $ (1.8) $ - $ 5.2
Accounts receivable-less reserves 123.0 0.1 - 123.1
Receivables due from other Vectren
companies 56.0 31.8 (1.5) 86.3
Accrued unbilled revenues 77.1 - - 77.1
Inventories 54.8 - - 54.8
Recoverable fuel & natural gas costs 70.2 - - 70.2
Prepayments & other current assets 84.8 (2.0) - 82.8
- -------------------------------------------------------------------------------------------
Total current assets 472.9 28.1 (1.5) 499.5
- -------------------------------------------------------------------------------------------
Utility Plant
Original cost 2,906.1 - - 2,906.1
Less: accumulated depreciation
& amortization 1,308.2 - - 1,308.2
- -------------------------------------------------------------------------------------------
Net utility plant 1,597.9 - - 1,597.9
- -------------------------------------------------------------------------------------------
Investments in consolidated subsidiaries - 754.4 (754.4) -
Notes receivable from consolidated
subsidiaries - 544.3 (544.3) -
Investments in unconsolidated affiliates 0.2 3.3 - 3.5
Other investments 11.2 8.8 - 20.0
Non-utility property-net 6.3 78.7 - 85.0
Goodwill-net 201.5 - - 201.5
Regulatory assets 62.6 5.2 - 67.8
Other assets 13.9 0.2 - 14.1
- -------------------------------------------------------------------------------------------
TOTAL ASSETS $2,366.5 $1,423.0 $(1,300.2) $2,489.3
===========================================================================================
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 76.3 $ 3.1 $ - $ 79.4
Accounts payable to affiliated companies 37.4 - - 37.4
Accounts payable due to other Vectren
companies 29.1 24.0 (1.5) 51.6
Accrued liabilities 93.3 4.8 (2.9) 95.2
Short-term borrowings 0.9 273.3 - 274.2
Short-term borrowings due from
other Vectren companies 234.5 29.0 (234.5) 29.0
Current maturities of long-term debt 1.3 - - 1.3
Long-term debt subject to tender 11.5 - - 11.5
- -------------------------------------------------------------------------------------------
Total current liabilities 484.3 334.2 (238.9) 579.6
- -------------------------------------------------------------------------------------------
Long-Term Debt
Long-term debt-net of current maturities
& debt subject to tender 552.7 348.2 - 900.9
Long-term debt due to VUHI 306.9 - (306.9) -
- -------------------------------------------------------------------------------------------
Total long-term debt-net 859.6 348.2 (306.9) 900.9
- -------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 176.0 0.5 - 176.5
Deferred credits & other liabilities 91.7 1.2 - 92.9
- -------------------------------------------------------------------------------------------
Total deferred credits & other
liabilities 267.7 1.7 - 269.4
- -------------------------------------------------------------------------------------------
Cumulative, Redeemable Preferred
Stock of a Subsidiary 0.5 - - 0.5
Common Shareholder's Equity
Common stock (no par value) 436.3 385.7 (436.3) 385.7
Retained earnings 320.5 355.0 (320.5) 355.0
Accumulated other comprehensive income (2.4) (1.8) 2.4 (1.8)
- -------------------------------------------------------------------------------------------
Total common shareholder's equity 754.4 738.9 (754.4) 738.9
- -------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S
EQUITY $2,366.5 $1,423.0 $(1,300.2) $ 2,489.3
===========================================================================================
Consolidating Statement of Income for the year ended December 31, 2002:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ------------------------------------ ---------- ------- ------------ ------------
OPERATING REVENUES
Gas utility $ 909.0 $ - $ - $ 909.0
Electric utility 608.1 - - 608.1
Other - 22.3 (22.0) 0.3
- ----------------------------------------------------------------------------------------------
Total operating revenues 1,517.1 22.3 (22.0) 1,517.4
- ----------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 571.8 - - 571.8
Fuel for electric generation 81.6 - - 81.6
Purchased electric energy 296.3 - - 296.3
Other operating 220.2 0.4 (22.0) 198.6
Depreciation & amortization 96.8 13.9 - 110.7
Taxes other than income taxes 50.8 (0.1) - 50.7
- ----------------------------------------------------------------------------------------------
Total operating expenses 1,317.5 14.2 (22.0) 1,309.7
- ----------------------------------------------------------------------------------------------
OPERATING INCOME 199.6 8.1 - 207.7
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated
companies - 95.3 (95.3) -
Equity in losses of unconsolidated
affiliates - (1.8) - (1.8)
Other - net 5.0 27.6 (25.5) 7.1
- ----------------------------------------------------------------------------------------------
Total other income (expense) - net 5.0 121.1 (120.8) 5.3
- ----------------------------------------------------------------------------------------------
Interest expense 63.6 31.0 (25.5) 69.1
- --------------------------------------------------------------------------------- ----------
INCOME BEFORE INCOME TAXES 141.0 98.2 (95.3) 143.9
- ----------------------------------------------------------------------------------------------
Income taxes 45.7 1.1 - 46.8
- ----------------------------------------------------------------------------------------------
NET INCOME $ 95.3 $ 97.1 $(95.3) $ 97.1
==============================================================================================
Consolidating Statement of Income for the year ended December 31, 2001:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ------------------------------- ---------- ------- ------------ ------------
OPERATING REVENUES
Gas utility $1,019.6 $ - $ - $ 1,019.6
Electric utility 381.2 - - 381.2
Other - 29.1 (28.9) 0.2
- --------------------------------------------------------------------------------------------------
Total operating revenues 1,400.8 29.1 (28.9) 1,401.0
- --------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 708.9 - - 708.9
Fuel for electric generation 74.4 - - 74.4
Purchased electric energy 86.9 - - 86.9
Other operating 241.9 (0.9) (28.9) 212.1
Merger & integration costs 2.8 - - 2.8
Restructuring costs 15.0 - - 15.0
Depreciation & amortization 97.2 20.7 - 117.9
Taxes other than income taxes 51.2 0.4 - 51.6
- --------------------------------------------------------------------------------------------------
Total operating expenses 1,278.3 20.2 (28.9) 1,269.6
- --------------------------------------------------------------------------------------------------
OPERATING INCOME 122.5 8.9 - 131.4
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated companies - 40.1 (40.1) -
Equity in losses of unconsolidated affiliates - (0.5) - (0.5)
Other - net 4.9 23.0 (22.3) 5.6
- --------------------------------------------------------------------------------------------------
Total other income (expense) - net 4.9 62.6 (62.4) 5.1
- --------------------------------------------------------------------------------------------------
Interest expense 67.5 25.5 (22.3) 70.7
- --------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 59.9 46.0 (40.1) 65.8
- --------------------------------------------------------------------------------------------------
Income taxes 19.0 2.3 - 21.3
Preferred dividend requirements of subsidiary 1.9 - (1.1) 0.8
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 39.0 43.7 (39.0) 43.7
- --------------------------------------------------------------------------------------------------
Cumulative effect of change in accounting
principle - net of tax 1.1 - - 1.1
- --------------------------------------------------------------------------------------------------
NET INCOME $ 40.1 $ 43.7 $ (39.0) $ 44.8
==================================================================================================
Consolidating Statement of Income for the year ended December 31, 2000:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ------------------------------------- ---------- ------- ------------ ------------
OPERATING REVENUES
Gas utility $ 820.4 $ - $ - $ 820.4
Electric utility 334.4 - - 334.4
Other - 33.5 (33.2) 0.3
- -----------------------------------------------------------------------------------------
Total operating revenues 1,154.8 33.5 (33.2) 1,155.1
- -----------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 552.5 - - 552.5
Fuel for electric generation 75.7 - - 75.7
Purchased electric energy 36.4 - - 36.4
Other operating 209.0 4.8 (33.2) 180.6
Merger & integration costs 32.7 - - 32.7
Restructuring costs - - - -
Depreciation & amortization 82.4 22.2 - 104.6
Taxes other than income taxes 36.2 0.3 - 36.5
Total operating expenses 1,024.9 27.3 (33.2) 1,019.0
- -----------------------------------------------------------------------------------------
OPERATING INCOME 129.9 6.2 - 136.1
OTHER INCOME (EXPENSE) - NET
Equity in earnings of consolidated
companies - 52.5 (52.5) -
Equity in losses of unconsolidated
affiliates - - - -
Other - net 3.8 4.6 (4.1) 4.3
- -----------------------------------------------------------------------------------------
Total other income (expense)
- net 3.8 57.1 (56.6) 4.3
- -----------------------------------------------------------------------------------------
Interest expense 45.2 5.3 (4.1) 46.4
- -----------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 88.5 58.0 (52.5) 94.0
- -----------------------------------------------------------------------------------------
Income taxes 35.0 2.1 - 37.1
Preferred dividend requirements of
subsidiary 1.0 - - 1.0
- -----------------------------------------------------------------------------------------
NET INCOME $ 52.5 $ 55.9 $ (52.5) $ 55.9
=========================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2002:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ----------------------------------------------- ---------- ------- ------------ ------------
NET CASH FLOWS FROM OPERATING ACTIVITIES $ 269.4 $ 8.2 $ - $ 277.6
- ------------------------------------------------------------------------------------------------
CASH FLOWS REQUIRED FOR FINANCING ACTIVITIES
Proceeds from:
Capital contribution 25.0 - (25.0) -
Long-term debt 37.1 - (37.1) -
Requirements for:
Retirement of long-term debt,
including premiums paid (6.5) - - (6.5)
Dividends on common stock (74.7) (69.7) 74.7 (69.7)
Redemption of preferred stock of
subsidiary (0.2) - - (0.2)
Net change in short-term borrowings,
including to other Vectren companies (88.4) 32.2 79.0 22.8
- ------------------------------------------------------------------------------------------------
Net cash flows required for financing
activities (107.7) (37.5) 91.6 (53.6)
- ------------------------------------------------------------------------------------------------
CASH FLOW FROM (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from consolidated subsidiary
distributions
Consolidated subsidiary distributions - 74.7 (74.7) -
Other investing activities 1.5 8.9 - 10.4
Requirements for:
Capital expenditures, excluding
AFUDC-equity (147.6) (69.7) - (217.3)
Consolidated subsidiary investments - (25.0) 25.0 -
Other investing activities (3.9) (7.9) - (11.8)
Net change in notes receivable to other
Vectren companies (8.5) 50.4 (41.9) -
- ------------------------------------------------------------------------------------------------
Net cash flows from (required for)
investing activities (158.5) 31.4 (91.6) (218.7)
- ------------------------------------------------------------------------------------------------
Net increase in cash & cash equivalents 3.2 2.1 - 5.3
Cash & cash equivalents at beginning of period 7.0 (1.8) - 5.3
- ------------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 10.2 $ 0.3 $ - $ 10.6
================================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2001:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ------------------------------------------------ ---------- ------- ------------ ------------
NET CASH FLOWS FROM OPERATING ACTIVITIES $ 141.0 $ 44.3 $ - $ 185.3
- -----------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Capital contribution 214.7 164.4 (214.7) 164.4
Long-term debt 307.0 344.0 (307.0) 344.0
Requirements for:
Retirement of long-term debt, including
premiums paid (7.3) - - (7.3)
Retirement of short-term notes payable - (150.0) - (150.0)
Dividends on common stock (62.5) (91.6) 62.5 (91.6)
Redemption of preferred stock of subsidiary (17.7) - - (17.7)
Dividends on preferred stock of subsidiary (0.8) - - (0.8)
Net change in short-term borrowings, including
to other Vectren companies (414.3) (30.9) 238.1 (207.1)
- -----------------------------------------------------------------------------------------------------
Net cash flows from financing activities 19.1 235.9 (221.1) 33.9
- -----------------------------------------------------------------------------------------------------
CASH FLOWS REQUIRED FOR INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions - 62.5 (62.5) -
Other investing activities 1.5 - - 1.5
Requirements for:
Capital expenditures, excluding AFUDC-equity (154.4) (48.4) - (202.8)
Acquisition of the Ohio operations (2.2) - - (2.2)
Consolidated subsidiary investments - (214.7) 214.7 -
Other investing activities - (11.8) - (11.8)
Net change in notes receivable to other Vectren
companies - (68.9) 68.9 -
- -----------------------------------------------------------------------------------------------------
Net cash flows required for investing
activities (155.1) (281.3) 221.1 (215.3)
- -----------------------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 5.0 (1.1) - 3.9
Cash & cash equivalents at beginning of period 2.0 (0.7) - 1.3
- -----------------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 7.0 $ (1.8) $ - $ 5.2
=====================================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2000:
Subsidiary Parent
Guarantors Company Eliminations Consolidated
- ------------------------------------------------ ---------- ------- ------------ ------------
NET CASH FLOWS FROM OPERATING ACTIVITIES $ 23.2 $ 11.9 $ - $ 35.1
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Short-term notes payable - 150.0 - 150.0
Long-term debt 67.9 - - 67.9
Other proceeds 1.6 - - 1.6
Requirements for:
Retirement of long-term debt, including
premiums paid (0.7) - - (0.7)
Dividends on common stock (55.0) (60.6) 55.0 (60.6)
Redemption of preferred stock of
subsidiary (2.0) - - (2.0)
Dividends on preferred stock of
subsidiary (1.0) - - (1.0)
Net change in short-term borrowings,
including to other Vectren companies 547.4 333.2 (475.4) 405.2
- -------------------------------------------------------------------------------------------------------
Net cash flows from financing activities 558.2 422.6 (420.4) 560.4
- -------------------------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from consolidated subsidiary distributions - 55.0 (55.0) -
Requirements for:
Capital expenditures, excluding AFUDC-equity (103.9) (14.8) - (118.7)
Acquisition of the Ohio operations (469.2) - - (469.2)
Other investing activities (7.1) - - (7.1)
Net change in notes receivable to other Vectren
companies - (475.4) 475.4 -
- -------------------------------------------------------------------------------------------------------
Net cash flows (required for) investing
activities (580.2) (435.2) 420.4 (595.0)
- -------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 1.2 (0.7) - 0.5
Cash & cash equivalents at beginning of period 0.8 - - 0.8
- -------------------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 2.0 $ (0.7) $ - $ 1.3
=======================================================================================================
18. Quarterly Financial Data (Unaudited)
As more fully described in Note 3, the Company has restated the results for the
year ended December 31, 2001, including each quarter, as well as the first three
quarters of 2002 to appropriately account for certain errors and a transfer of
assets between entities under common control. Provided below is a comparison of
restated summarized quarterly financial data to summarized quarterly financial
data previously reported. Information in any one quarterly period is not
indicative of annual results due to the seasonal variations common to the
Company's utility operations.
Summarized quarterly financial data for 2002 follows:
- --------------------------------------------------------------------------------------------------
In millions Q1 Q2 (5) Q3 Q4
- ---------------------------- -------------------- -----------------------------------------------
As As As As As As As
2002 Operating data Reported Restated Reported Restated Reported Restated Reported
-------------------- ------------------------------ --------------------
Operating revenues $ 483.9 $485.0 $ 298.7 $299.1 $ 278.1 $278.1 $ 455.2
Operating income (6) 78.6 80.8 21.1 26.0 29.9 30.3 70.6
Net income 40.6 42.0 9.1 8.7 8.9 9.0 37.4
Summarized quarterly financial data for 2001 follows:
- ----------------------------------------------------------------------------------------------------------
In millions Q1 (1) Q2 (2) Q3 Q4 (4)
- --------------------------- ------------------ ------------------ ------------------ ------------------
As As As As As As As As
2001 Operating Data (3) Reported Restated Reported Restated Reported Restated Reported Restated
------------------ ------------------ ------------------ ------------------
Operating revenues $ 611.9 $614.8 $ 249.6 $248.5 $ 200.3 $196.7 $ 348.6 $ 341.0
Operating income (loss) (6) 70.2 77.2 (3.8) (1.5) 14.6 15.5 54.4 40.2
Income (loss) before
extraordinary loss &
cumulative effect of
change in accounting
principle 31.8 36.5 (12.9) (11.9) (0.5) (0.2) 28.4 19.3
Net income (loss) 35.7 37.6 (12.9) (11.9) (0.5) (0.2) 28.4 19.3
1. Q1 of 2001 includes charges for cumulative effect of changes in accounting
principle as described in Note 12.
2. Q2 of 2001 includes restructuring charges as described in Note 15.
3. 2001 includes merger and integration charges as described in Note 15.
4. The benefit clearing adjustment and primarily all of the inventory
adjustment discussed in Note 3 were recorded in Q4 of 2001.
5. In Q2 of 2002, the Company recorded $3.2 million of after tax carrying
costs for DSM programs pursuant to existing IURC orders. Management
determined that the accrual of such carrying costs was more appropriate in
periods prior to 2000 when DSM program expenditures were made. Therefore,
such carrying costs originally reflected in Q2 of 2002 were reversed and
reflected in common shareholder's equity as of January 1, 2000.
6. Operating income (loss) in the "As Reported" columns has been adjusted to
reflect the reclassification of income taxes which prior to Q4 of 2002 was
included as a component of operating income, consistent with traditional
regulated entity income statement presentation. The income statement
presentation was changed to the commercial and industrial presentation
described in Article 5 of Regulation S-X.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Disclosure with respect to this Item, has been previously provided on Form 8-K
originally filed with the SEC on March 26, 2002, as amended on Form 8-K/A filed
with the SEC on May 20, 2002.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Certain information required to be shown for Item 10, Directors and Executive
Officers of the Registrant, is incorporated by reference, with the exception of
the Compensation Committee Report and Performance Graph, from the Proxy
Statement of the registrant's parent company, Vectren Corporation. That report
was prepared and filed electronically with the Securities and Exchange
Commission on March 27, 2003, and is attached to this filing as Exhibit 99.1.
Directors
Niel C. Ellerbrook, age 54, has been a director of Indiana Energy or the Company
since 1991. Mr. Ellerbrook is Chairman of the Board and Chief Executive Officer
of the Company, having served in that capacity since March 2000. Mr. Ellerbrook
served as President and Chief Executive Officer of Indiana Energy from June 1999
to March 2000. Mr. Ellerbrook served as President and Chief Operating Officer of
Indiana Energy from October 1997 to March 2000. From January through October
1997, Mr. Ellerbrook served as Executive Vice President, Treasurer, and Chief
Financial Officer of Indiana Energy; and from 1986 to January 1997 as Vice
President, Treasurer, and Chief Financial Officer of Indiana Energy. Mr.
Ellerbrook is a director of Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., and Southern Indiana Gas and Electric Co. He is also a director of Old
National Bancorp and Deaconess Hospital of Evansville, Indiana.
Andrew E. Goebel, age 55, has been a director of SIGCORP or the Company since
1997. Mr. Goebel is President and Chief Operating Officer of the Company, having
served in that capacity since March 2000. Mr. Goebel was President and Chief
Operating Officer of SIGCORP from April 1999 to March 2000. From September 1997
through April 1999, Mr. Goebel served as Executive Vice President of SIGCORP;
and from 1996 to September 1997, he served as Secretary and Treasurer of
SIGCORP. Mr. Goebel is a director of Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., and Southern Indiana Gas and Electric Co. Mr. Goebel is also a
director of Old National Bancorp and Old National Bank. Mr. Goebel is retiring
from the Company effective April 30, 2003.
Jerome A. Benkert, Jr., age 44, has served as Executive Vice President and Chief
Financial Officer of the Company since March 2000 and as Treasurer of the
Company since October 2001 to April 2002. He was Executive Vice President and
Chief Operating Officer of Indiana Energy's administrative services company from
October 1997 to March 2000. Mr. Benkert has served as Controller and Vice
President of Indiana Gas. Mr. Benkert is a director of Vectren Utility Holdings,
Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Co., and
Fifth Third Bank, Indiana.
Ronald E. Christian, age 44, has served as Senior Vice President and Secretary
of the Company since March 2000. Mr. Christian served as Vice President and
General Counsel of Indiana Energy from July 1999 to March 2000. From June 1998
to July 1999, Mr. Christian was the Vice President, General Counsel and
Secretary of Michigan Consolidated Gas Company in Detroit, Michigan. He served
as the General Counsel and Secretary of Indiana Energy, Indiana Gas and Indiana
Energy Investments, Inc. from 1993 to June 1998. Mr. Christian is a director of
Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and Southern Indiana
Gas and Electric Co.
William S. Doty, age 52, has served as a director since June 2001. Mr. Doty has
also served as Senior Vice President-Energy Delivery of the Company since April
2001. Mr. Doty served as Senior Vice President of Customer Relationship
Management from January 2001 to April 2001. From January 1999 to January 2001,
Mr. Doty was Vice President of Energy Delivery for Southern Indiana Gas and
Electric Company and previous to January 1999, he was Director of Gas
Operations. Mr. Doty is a director of Southern Indiana Gas and Electric Company.
Other Executive Officer
Richard G. Lynch, age 51, has served as Senior Vice President-Human Resources
and Administration of the Company since March 2000. Mr. Lynch was Vice President
of Human Resources for SIGCORP from March 1999 to March 2000. Prior to joining
the Company, Mr. Lynch was the Director of Human Resources for the Mead Johnson
Division of Bristol Myers-Squibb in Evansville, Indiana.
ITEM 11. EXECUTIVE COMPENSATION
Certain information required to be shown for Item 11, Executive Compensation, is
incorporated by reference, with the exception of the Compensation Committee
Report and Performance Graph, from the Proxy Statement of the registrant's
parent company, Vectren Corporation. That report was prepared and filed
electronically with the Securities and Exchange Commission on March 27, 2003,
and is attached to this filing as Exhibit 99.1.
The compensation of Niel C. Ellerbrook, Andrew E. Goebel, Jerome A Benkert, Jr.,
and Ronald E. Christian is included in Exhibit 99.1 attached to this filing. In
addition to these named executive officers, the compensation of William S. Doty
is presented below. The compensation presented below and the compensation
included in Exhibit 99.1 represents each executive's Vectren-wide compensation,
not just the portion allocated to VUHI. The tables include a Summary
Compensation Table (Table I), a Summary of Option Grants in Last Fiscal year
(Table II), a table showing Aggregate Option Exercises in Last Fiscal Year and
Fiscal Year End Option Values (Table III) and a table showing the Long-Term
Incentive Plan Awards in Last Fiscal Year (Table IV).
TABLE I
SUMMARY COMPENSATION TABLE
(a) (b) (c) (d) (e) (g) (h) (i)
---------- ------- ------- -------- ------- --------
Annual Compensation Long-term Compensation Payouts
Other Other
Compen- Options LTIP Compen-
Name and Principal Bonus sation (# shares) Payouts sation
Position at VUHI Year Salary ($) ($) (1) ($) (2) (3) ($) (4) ($) (5)
---------------- ---- ---------- ------- ------- ------- ------- --------
William S. Doty 2002 189,654 61,737 5,931 15,000 - 10,739
Senior Vice President - 2001 174,608 10,500 5,709 22,000 - 12,836
Energy Delivery 2000 141,464 96,125 1,413 - - 18,079
Earnings are shown on a calendar year basis.
(1) The amounts shown in this column for 2002 and 2001 are exclusively payments
under the Company's At-Risk Compensation Plan, which is discussed above in
Part B, relating to "Annual Incentive Compensation," and Part B of the
Compensation and Benefits Committee Report in Exhibit 99.1.
The amounts shown in this column for 2000 include payments under the
Company's Executive Annual Incentive Plan and the SIGCORP Corporate
Performance Plan. Payments in 2000 attributable to the Company's Executive
Annual Incentive Plan for the performance period of April 1 to December 1,
2000 (Mr. Doty, $64,000). Also, at the close of the merger of Indiana
Energy and SIGCORP into the Company on March 31, 2000, the existing annual
incentive programs of the two companies were terminated and a "stub year"
payout was made based on the portion of the performance cycle that had
passed. For the SIGCORP Performance Plan, a prorated payout for three
months, January 1, 2000 to March 31, 2000 was made. For Mr. Doty, this stub
year bonus was $6,250. Also included in 2000 for Mr. Doty, ($25,875) is the
payment attributable to SIGCORP's performance for the period January 1 to
December 31, 1999.
(2) The amounts shown in this column are dividends paid on restricted shares
issued under the Vectren Corporation Executive Restricted Stock Plan
(formerly the Indiana Energy Executive Restricted Stock Plan), which was
adopted by the Company on March 31, 2000. No restricted shares were issued
to executives in 2001 and 2002. Mr. Doty did not participate in the Stock
Plan prior to March 31, 2000.
(3) The options shown were issued under the Company's At-Risk Compensation
Plan. For further information, see the discussion in Part B relating to
"Long-term Incentive Compensation," and Part C of the Compensation and
Benefits Committee Report in Exhibit 99.1.
(4) The amounts shown in this column represent the value of shares issued under
the Vectren Corporation Restricted Stock Plan and for which restrictions
were lifted in each year. At the time of the merger, Indiana Energy
executives had restricted stock performance grants relating to open
performance measurement periods. (Under normal circumstances, at the close
of each performance cycle, Indiana Energy's Total Shareholder Return would
have been compared to a peer group and the number of restricted shares
granted would have been adjusted in accordance with the plan.) The Board
concluded that it would be difficult, if not inappropriate, to use
Vectren's performance to make adjustments to the prior grants. Based upon
the frequency of past performance grants, the Board awarded 75 percent of
the present value of the potential performance grants. Mr. Doty did not
participate in the plan prior to March 31, 2000.
(5) The amount shown in this column represents several compensation elements.
For Mr. Doty, this column also contains income related to reimbursement
for taxable expenses (2002 -- $5,239; 2001 -- $5,680; 2000 -- $2,520),
imputed earnings from automobile usage (Mr. Doty: 2000 -- $1,167),
Company contributions to the retirement savings plan (2002 -- $5,500;
2001 -- $5,100; 2000 -- $5,100), and deferred compensation
contributions to restore contributions to the company Retirement
Savings Plan (2001 -- $2,056; 2000 -- $900). At the close of the
merger, officers coming from SIGCORP were no longer furnished with
company automobiles (Indiana Energy executives were not furnished with
company automobiles). As a result of the termination of this
perquisite, Mr. Doty was given a one-time automobile buyout of $8,392,
paid in 2000.
TABLE II
OPTION GRANTS IN LAST FISCAL YEAR
Number of % of Total
Shares Options
Underlying Granted to
Options/ Employees Exercise or
SARs in Fiscal Base Price Expiration Grant Date
Name Granted Year (Per Share) ($) Date Present Value
------------ ------- ------ --------------- ---------- -------------
(#) (1) ($)
W.S. Doty 15,000/0 3.29% 23.19 1/1/2013 $70,088
(1) On December 11, 2002, a total of 384,500 options were awarded effective as
of January 1, 2003 to all plan participants under the Vectren Corporation
At-Risk Compensation Plan. Stock options are exercisable upon vesting in
whole or in part and expire ten years from the date of grant. This grant
has a vesting schedule pursuant to which 34 percent vests at the end of the
first year, and 33 percent vests at the end of the second and third years.
(2) The assumptions used for the Model are as follows: Volatility -- 23.69
percent based on monthly stock prices for the period of January 1, 2000 to
December 31, 2002; Risk-free rate of return -- 4.54 percent; Dividend Yield
-- 4.78 percent over the period of January 1, 2000 to December 31, 2002;
and, a ten-year exercise term. A discount rate of .9412 was applied to
reflect a 3-year graduated vesting schedule. (Per a binomial model as
certified by an independent consultant retained by the Compensation and
Benefits committee.)
TABLE III
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
FROM 1/1/2001 TO 12/31/2001
Underlying
Shares Unexercised Number of Securities Value of Unexercised
Acquired On Value Underlying Unexercised In-the-Money
Name Exercise(#) Realized ($) Options at Year-End (#) (1) Options as of 12/31/01 ($)(1)
---- ----------- ------------ --------------------------- -----------------------------
Exercisable Unexercisable Exercisable Unexercisable
----------- ------------- ----------- -------------
W.S. Doty 1,631 14,033 30,657 28,200 99,965 6,072
(1) Includes grants authorized by the Compensation and Benefits Committee on
December 11, 2002 to be effective as of January 1, 2003.
TABLE IV
LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR
Estimated Future Payouts Under
Non-Stock Price-Based Plans
-------------------------------
(a) (b) (c) (d) (e) (f)
Performance
Number of or Other
Shares; Periods Until Threshold Target Maximum
Units or Maturation Number of Number of Number of
Other Rights (1) or Payout (2) Shares (3) Shares (4) Shares (5)
---------------- ------------- ---------- ---------- ----------
W.S. Doty 4,000 0 1,500 4,000 8,000
(1) This column reflects restricted stock grants awarded under the Vectren
Corporation At-Risk Compensation Plan by the Compensation and Benefits
Committee on December 11, 2002, to be effective January 1, 2003. The manner
for determining the awards, and other terms and conditions of the At-Risk
Plan, are discussed in the Compensation and Benefits Committee Report
relating to "Long-Term Incentive Compensation." The market value of the
shares on the date of grant is determined by the market price on the date
of grant or, if no trading occurs on that date, the market price on the
next trading day on which shares are traded. Dividends are paid directly to
the holders of the stock.
(2) As discussed in the Compensation and Benefits Committee Report relating to
"Long-Term Incentive Compensation" in Exhibit 99.1, for the grant
authorized on December 11, 2002 and granted on January 1, 2003, the
measurement period commenced on January 1, 2003 and will conclude on
December 31, 2005.
(3) The ultimate amount of the grant will be determined by the Company's
performance relative to its peer group. Performance at the 25th percentile
will result in a threshold payment equal to 0.375 of the initial grant
which is shown in column (b), and in column (e). Performance versus the
peer group which is below the 25th percentile will result in a complete
forfeiture.
(4) The total number of shares in column (b), and also set forth in column (e),
are subject to forfeiture as discussed in footnote (3). If the Company's
performance compared to the peer group during the measurement period places
it above 25% and below 90%, linear interpolation will be employed to
perform the award calculation. At target, the payment will be equal to the
initial grant which is shown in column (b).
(5) Under the At-Risk Plan, if the Company's performance compared to the peer
group during the measuring period places it in the 90th percentile, an
additional performance grant equal to the original grant will be made. In
that event, the shares shown in column (e) will be doubled.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Security ownership of certain beneficial owners
As of December 31, 2002, the following stockholder was known to the management
to be the beneficial owner of more than five percent of the outstanding shares
of any class of voting securities as set forth below.
Name and Address of Amount and Nature of
Title of Class Beneficial Owner Beneficial Ownership Percent of Class
- -------------- ------------------- -------------------- ----------------
Common Vectren Corporation 10 Shares 100 percent
20 N.W. Fourth Street Registered Owner
Evansville, IN 47708
Security ownership of management
The following table sets forth the beneficial ownership, as of December 31,
2002, of Vectren common stock, by each director and named executive officer in
Item 11 Executive Compensation. Also shown is the total ownership for such
persons as a group. Except as otherwise indicated, each individual has sole
voting and investment power with respect to the shares listed below.
Shares Owned
Name of Beneficial Owner Beneficially (1)
- ------------------------ ----------------
Niel C. Ellerbrook 210,837 (2) (3) (6) (8)
Andrew E. Goebel 187,976 (2) (3) (4) (5)
Jerome A. Benkert, Jr. 49,253 (2) (4) (5)
Ronald E. Christian 48,253 (2) (4) (5)
William S. Doty 43,047 (2) (4) (5)
All Directors and Named Executive Officers as a Group (5 Persons): 539,366 (1)
(1) No director, executive officer, or directors and executive officers as a
group owned beneficially as of December 31, 2002, more than 1 percent of
common stock of Vectren.
(2) This amount does not include derivative securities held under the Company's
Non-Qualified Deferred Compensation Plan. These derivative securities are
in the form of phantom stock units which are valued as if they were Company
Common Stock. The amounts shown for the following individuals include the
following amounts of phantom units:
Name of Individuals or Identity of Group Phantom Stock Units
---------------------------------------- -------------------
Niel C. Ellerbrook 53,837
Andrew E. Goebel 2,654
Jerome A. Benkert, Jr. 16,436
Ronald E. Christian 27,511
William S. Doty 677
All Directors and Executive Officers as a
Group (6 Persons) 101,115
(3) Includes shares held by spouse or jointly with spouse.
(4) Includes shares granted to executives under the Company's Executive
Restricted Stock Plan and restricted stock award granted to certain
executives on January 1, 2003 under the Company's At-Risk Compensation
Plan. These shares are subject to certain transferability restrictions and
forfeiture provisions.
(5) Includes shares which the named individual has the right to acquire as of
March 3, 2003, or within sixty (60) days thereafter, under the Vectren
Corporation Stock Option Plan.
Equity Compensation Plan Information
VUHI does not have equity compensation plans separate from Vectren. The
information with respect to common shares issuable under Vectren equity
compensation plans as of December 31, 2002 is included below.
- -------------------------------------------------------------------------------
(a) (b) (c)
- -------------------------------------------------------------------------------
Number of Number of securities
securities to be Weighted- remaining available
issued upon average for future issuance
exercise of exercise price under equity
outstanding of outstanding compensation
options, options, plans (excluding
warrants warrants and securities reflected
Plan category and rights rights in column (a)
- -------------------------------------------------------------------------------
Equity compensation 1,733,762 (2) $ 21.86 2,909,316 (3)
plans approved by
security holders (1)
- -------------------------------------------------------------------------------
Equity compensation 0 0 0
plans not approved by
security holders
- -------------------------------------------------------------------------------
Total 1,733,762 $ 21.86 2,909,316
===============================================================================
(1) Includes the following Vectren Corporation Plans: Vectren Corporation
At-Risk Compensation Plan, 1994 SIGCORP Stock Option Plan, Vectren
Corporation Executive Restricted Stock Plan, and Vectren Corporation
Directors Restricted Stock Plan.
(2) Includes a stock option grant approved by the Board of Directors'
Compensation Committee on December 11, 2002, effective January 1, 2003.
(3) Includes shares available for issuance under the Vectren Corporation
At-Risk Compensation Plan (2,678,027), of which up to 800,000 shares may be
issued in restricted stock, Vectren Corporation Executive Restricted Stock
Plan (186,098), and Vectren Corporation Directors Restricted Stock Plan
(45,191).
The SIGCORP stock option plan was approved by SIGCORP common shareholders prior
to the merger forming Vectren, and both the directors and executive restricted
stock plans were approved by Indiana Energy common shareholders prior to the
merger forming Vectren. The At-Risk Compensation plan was approved by Vectren
Corporation common shareholders after the merger forming Vectren.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with Vectren and Vectren Affiliates
Refer to Notes 4 and 5 to the Company's financial statements included in Item 8
Financial Statements and Supplementary Data for transactions with other Vectren
companies and Vectren affiliates.
Transactions with Directors and Officers
Andrew E. Goebel is a director and President of the Company and a director and
President and Chief Operating Officer of Vectren. During 2002 and 2001, Hasgoe
Cleaning Systems, a cleaning company owned by Mr. Goebel's brother's family,
performed certain cleaning services for the Company and is expected to perform
such services in 2003. During 2002, the cost of such services was $221,745,
which the Company believes to be a fair and reasonable price for the services
rendered.
PART IV
ITEM 14. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Within 90 days prior to the filing of the report, the Company carried out an
evaluation under the supervision and with the participation of the Chief
Executive Officer and Chief Financial Officer of the effectiveness and the
design and operation of the Company's disclosure controls and procedures. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
have concluded that the Company's disclosure controls and procedures are
effective in bringing to their attention on a timely basis material information
relating to the Company required to be disclosed by the Company in its filings
under the Securities Exchange Act of 1934 (Exchange Act).
Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-14(c) and 15d-14(c), are controls and other procedures of the Company that
are designed to ensure that information required to be disclosed by the Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC's rules and forms. "Disclosure controls and procedures" include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate to allow timely decisions regarding required
disclosure.
Changes in Internal Control
Since the evaluation of disclosure controls and procedures, there have been no
significant changes to the Company's internal controls and procedures or
significant changes in other factors that could significantly affect the
Company's internal controls and procedures. However, in Note 3 to the
consolidated financial statements (included in Item 8) which discusses the
restatement of 2001 and 2000 previously reported information, the Company
identified certain errors, the net effect of which, related primarily to gas
inventory accounting and the proper clearing of employee benefit related costs
routinely accumulated on the balance sheet. These errors resulted primarily from
insufficient account reconciliation procedures. The Company has taken steps to
improve these internal controls.
Internal control, as defined in American Institute of Certified Public
Accountants Codification of Statements on Auditing Standards (AU ss.319), is a
process, effected by an entity's board of directors, management, and other
personnel, designed to provide reasonable assurance regarding the achievement of
objectives in the following categories: (a) reliability of financial reporting,
(b) effectiveness and efficiency of operations and (c) compliance with
applicable laws and regulations.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
List Of Documents Filed As Part Of This Report
Consolidated Financial Statements
The consolidated 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/A.
Supplemental Schedules
For the years ended December 31, 2002, 2001, and 2000, the Company's Schedule II
- -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is presented on page 83. 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 Consolidated Financial Statements or related
notes in Item 8.
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified
below pursuant to Rule 12b-32 under the Exchange Act.
Exhibits for the Company are listed in the Index to Exhibits beginning
on page 85.
Exhibits for the Company attached to this filing filed electronically
with the SEC are listed on page 90.
Reports On Form 8-K During The Last Calendar Quarter
On October 25, 2002 Vectren Utility Holdings, Inc. filed a Current Report on
Form 8-K with respect to the release of financial information to the investment
community regarding Vectren Corporation's results of operations, financial
position and cash flows for the three, nine, and twelve month periods ended
September 30, 2002. The financial information was released to the public through
this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Third Quarter 2002 Vectren Corporation
Earnings
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995
On November 27, 2002, Vectren Utility Holdings, Inc. filed a Current Report on
Form 8-K with respect to a press release issued by Moody's Investors Service
that downgraded the credit ratings on various debt instruments issued by certain
of Vectren Corporation's wholly owned subsidiaries.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Moody's Investors Service
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995
SCHEDULE II
Vectren Utility Holdings, Inc. and Subsidiary Companies
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 millions)
VALUATION AND QUALIFYING ACCOUNTS:
AS RESTATED
Year 2002 - Accumulated provision for
uncollectible accounts $ 5.1 $ 11.7 $ - $ 11.3 $ 5.5
Year 2001 - Accumulated provision for
uncollectible accounts $ 5.1 $ 15.1 $ - $ 15.1 $ 5.1
Year 2000 - Accumulated provision for
uncollectible accounts $ 3.9 $ 6.6 $ 0.1 $ 5.5 $ 5.1
OTHER RESERVES:
Year 2002 - Reserve for merger and
integration charges $ 0.4 $ - $ - $ 0.4 $ -
Year 2001 - Reserve for merger and
integration charges $ 1.8 $ - $ - $ 1.4 $ 0.4
Year 2000 - Reserve for merger and
integration charges $ - $ 19.3 $ - $ 17.5 $ 1.8
Year 2002 - Reserve for restructuring
costs $ 4.3 $ - $ - $ 0.7 $ 3.6
Year 2001 - Reserve for restructuring
costs $ - $ 9.2 $ - $ 4.9 $ 4.3
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Amendment No. 1 on Form 10-K/A
to the Annual Report on Form 10-K to be signed on its behalf by the undersigned,
thereunto duly authorized.
VECTREN UTILITY HOLDINGS, INC.
Dated June 18, 2003
/S/ Niel C. Ellerbrook
----------------------------------------------
Niel C. Ellerbrook,
Chairman and Chief Executive Officer, Director
INDEX TO EXHIBITS
2. Plan Of Acquisition, Reorganization, Arrangement, Liquidation Or Succession
2.1 Asset Purchase Agreement dated December 14,1999 between Indiana Energy,
Inc. and The Dayton Power and Light Company and Number-3CHK with a
commitment letter for a 364-Day Credit Facility dated December 16,1999.
(Filed and designated in Current Report on Form 8-K dated December 28,
1999, File No. 1-9091, as Exhibit 2 and 99.1.)
3. Articles Of Incorporation And By-Laws
3.1 Articles of Incorporation of Vectren Utility Holdings, Inc. (Filed and
designated in Registration Statement on Amendment 3 to Form 10, File No.
1-16739, as Exhibit 3.1)
3.2 Bylaws of Vectren Utility Holdings, Inc. (Filed and designated in
Registration Statement on Amendment 3 to Form 10, File No. 1-16739, 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 February 1, 1991, between Indiana Gas and U.S. Bank Trust
National Association (formerly know as First Trust National Association,
which was formerly know as Bank of America Illinois, which was formerly
know as Continental Bank, National Association. Inc.'s. (Filed and
designated in Current Report on Form 8-K filed February 15, 1991, File No.
1-6494.); First Supplemental Indenture thereto dated as of February 15,
1991. (Filed and designated in Current Report on Form 8-K filed February
15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture
thereto dated as of September 15, 1991, (Filed and designated in Current
Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit
4(b).); Third supplemental Indenture thereto dated as of September 15, 1991
(Filed and designated in Current Report on Form 8-K filed September 25,
1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture
thereto dated as of December 2, 1992, (Filed and designated in Current
Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit
4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000,
(Filed and designated in Current Report on Form 8-K filed December 27,
2000, File No. 1-6494, as Exhibit 4.)
4.3 Indenture dated October 19, 2001, between Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated October 19, 2001,
File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated
October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed
and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, between Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1).
10. Material Contracts
10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power
Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern
Indiana Gas and Electric Company. (Filed and designated in Registration No.
2-29653 as Exhibit 4(d)-A.)
10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June
26, 1969, between Alcoa and Southern Indiana Gas and Electric Company.
(Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.)
10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-53005 as Exhibit 4(e)-4.)
10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-41209 as Exhibit 4(e)-1.)
10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and
Letter Agreement dated April 30, 1973 - First Supplement. (Filed and
designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as
Exhibit 1(e).)
10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.)
10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and
Electric Company and Alcoa, which amends Agreement for Sale in an Emergency
of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas
and Electric Company dated June 26, 1979. (Filed and designated in Form
10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.)
10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-3.)
10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as
Exhibit A-5.)
10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-6.)
10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power
Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and
Electric Company. (Filed and designated in Form 10-K for the fiscal year
1980, File No. 1-3553, as Exhibit (20)-1.)
10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power Generating
Inc. and Southern Indiana Gas and Electric Company. (Filed and designated
in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as
Exhibit 10.12.)
10.13 Summary description of Southern Indiana Gas and Electric Company's
nonqualified Supplemental Retirement Plan (Filed and designated in Form
10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.)
10.14 Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed
and designated in Southern Indiana Gas and Electric Company's Proxy
Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.15 Southern Indiana Gas and Electric Company's nonqualified Supplemental
Retirement Plan as amended, effective April 16, 1997. (Filed and designated
in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.)
10.16 Vectren Corporation Retirement Savings Plan (amended and restated
effective January 1, 2002). (Filed and designated in Form 10-Q for the
quarterly period ended September 30, 2002, File No. 1-15467, as Exhibit
10.1.)
10.17 Vectren Corporation Combined Non-Bargaining Retirement Plan. (Filed and
designated in Form 10-Q for the quarterly period ended September 30, 2000,
File No. 1-15467, as Exhibit 99.2.)
10.18 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.)
10.19 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.)
10.20 Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc.,
IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke
Utility, Citizens Energy Services Corporation and ProLiance Energy, LLC,
effective March 15, 1996. (Filed and designated in Form 10-Q for the
quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)
10.21 Gas Sales and Portfolio Administration Agreement between Indiana Gas
Company, Inc. and ProLiance Energy, LLC, effective March 15, 1996, for
services to begin April 1, 1996. (Filed and designated in Form 10-Q for the
quarterly period ended March 31, 1996, File No. 1-6494, as Exhibit 10-C.)
10.22 Amended appendices to the Gas Sales and Portfolio Administration Agreement
between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective
November 1, 1998. (Filed and designated in Form 10-Q for the quarterly
period ended March 31, 1999, File No. 1-6494, as Exhibit 10-A.)
10.23 Amended appendices to the Gas Sales and Portfolio Administration Agreement
between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective
November 1, 1999. (Filed and designated in Form 10-K for the fiscal year
ended September 30, 1999, File No. 1-6494, as Exhibit 10-V.)
10.24 Gas Sales and Portfolio Administration Agreement between Vectren Energy
Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000, for
services to begin November 1, 2000. (Filed and designated in Form 10-K, for
the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.)
10.25 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.)
10.26 Amendment to Indiana Energy, Inc. Executive Restricted Stock Plan
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.)
10.27 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.)
10.28 First Amendment to Indiana Energy, Inc. Directors' Restricted Stock Plan,
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.)
10.29 Second Amendment to Indiana Energy, Inc. Directors Restricted Stock Plan,
renamed the Vectren Corporation Directors Restricted Stock Plan effective
October 1, 2000. (Filed and designated in Form 10-K for the year ended
December 31, 2000, File No. 1-15467, as Exhibit 10-34.)
10.30 Third Amendment to Indiana Energy, Inc. Directors Restricted Stock Plan,
renamed the Vectren Corporation Directors Restricted Stock Plan 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.)
10.31 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.)
10.32 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.)
10.33 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.)
10.34 Vectren Corporation Employment Agreement between Vectren Corporation and
Andrew E. Goebel dated as of March 31, 2000 (Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.2.)
10.35 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.)
10.36 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.)
10.37 Vectren Corporation Employment Agreement between Vectren Corporation and
Timothy M. Hewitt dated as of March 31, 2000. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.6.)
10.38 Vectren Corporation Retirement Agreement between Vectren Corporation and
Timothy M. Hewitt dated as of May 31, 2001. (Filed and designated in Form
10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.39.)
10.39 Vectren Corporation Employment Agreement between Vectren Corporation and
J. Gordon Hurst dated as of March 31, 2000. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as
Exhibit 99.7.)
10.40 Vectren Corporation Retirement Agreement between Vectren Corporation and
J. Gordon Hurst dated as of May 31, 2001. (Filed and designated in Form
10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.41.)
10.41 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.)
10.42 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.)
10.43 Vectren Corporation Retirement Agreement between Vectren Corporation and
Thomas J. Zabor dated as of May 31, 2001. (Filed and designated in Form
10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.44.)
21. Subsidiaries Of The Company
The list of the Company's significant subsidiaries was filed and designated in
Annual Report on Form 10-K for the year ended December 31, 2002, File No.
1-16739, as Exhibit 21.1.
99. Additional Exhibits
99.1 Vectren Proxy Statement Pursuant to Section 14(a) of the Securities
Exchange Act of 1934, but not including the Compensation Committee Report
and Performance Graph. (Filed herewith.)
99.2 Agreement and Plan of Merger dated as of June 11,1999 among Indiana Energy,
Inc., SIGCORP, Inc. and Vectren Corporation (the "Merger Agreement ").
(Filed and designated in Form S-4 to (No. 333-90763) filed on November 12,
1999, File No. 1-15467, as Exhibit 2.)
99.3 Amendment No.1 to the Merger Agreement dated December 14, 1999 (Filed and
designated in Current Report on Form 8-K filed December 16, 1999, File No.
1-09091, as Exhibit 2.)
99.4 Amended and Restated Articles of Incorporation of Vectren Corporation
effective March 31, 2000. (Filed and designated in Current Report on Form
8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
99.5 Amended and Restated Code of By-Laws of Vectren Corporation as of February
26, 2003. (Filed and designated in Form 10-K for the year ended December
31, 2002, File No. 1-15467, as Exhibit 3.2
99.6 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren
Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and
designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No.
1-15467, as Exhibit 4.)
99.7 Certifications Pursuant to Section 906 of the Sarbanes-Oxlet Act of 2002.
(Filed Herewith.)
99.8 Chief Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. (Filed Herewith.)
99.9 Chief Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. (Filed Herewith.)
Vectren Utility Holdings, Inc.
2002 Form 10-K/A
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
See Page 85 of this amendment to the annual report on Form 10-K/A for a complete
list of exhibits.
Exhibit
Number Document
99.1 Vectren Proxy Statement Pursuant to Section 14(a) of the
Securities Exchange Act of 1934.
99.7 Certifications Pursuant to Section 906 of the Sarbanes-Oxlet Act
of 2002.
99.8 Chief Executive Officer Certification Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
99.9 Chief Financial Officer Certification Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.