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: 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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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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Common - Without Par New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: 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 |X|. No __.
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 $1,624,281,589.
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 68,011,649 February 15, 2003
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Class Number of Shares Date
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2003
Annual Meeting of Stockholders, which will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A, not later than 120 days after
the end of the fiscal year, is incorporated by reference in Part III of this
Form 10-K.
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions of
megawatt hours (gigawatt hour)
FASB: Financial Accounting Standards Board NOx: nitrogen oxide
FERC: Federal Energy Regulatory Commission OUCC: Indiana Office of the Utility Consumer Counselor
IDEM: Indiana Department of Environmental PUCO: Public Utilities Commission of Ohio
Management
IURC: Indiana Utility Regulatory Commission SFAS: Statement of Financial Accounting Standards
MCF/BCF: millions / billions of cubic feet USEPA: United States Environmental Protection Agency
MDth/MMDth: thousands /millions of Throughput: combined gas sales and gas
dekatherms transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ......................................................... 1
2 Properties ....................................................... 11
3 Legal Proceedings................................................. 12
4 Submission of Matters to Vote of Security Holders................. 12
Part II
5 Market for the Company's Common Equity and Related
Stockholder Matters ............................................ 12
6 Selected Financial Data........................................... 13
7 Management's Discussion and Analysis of Results of
Operations and Financial Condition.............................. 14
7A Qualitative and Quantitative Disclosures About Market Risk........ 40
8 Financial Statements and Supplementary Data....................... 42
9 Change in and Disagreements with Accountants on
Accounting and Financial Disclosure............................. 89
Part III
10 Directors and Executive Officers of the Registrant................ 89
11 Executive Compensation............................................ 90
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters...................... 90
13 Certain Relationships and Related Transactions.................... 91
Part IV
14 Controls and Procedures........................................... 91
15 Exhibits, Financial Statement Schedules, and
Reports on Form 8-K............................................. 92
Signatures........................................................ 94
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge 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 clarify various disclosures in the
Description of Business section of Item 1 of Part I, the Results of Operations
by Business Segments and Financial Condition sections of Item 7 of Part II and
the Consolidated Statements of Cash Flows and Notes 2, 7, 8, 14 and 16 to the
Consolidated Financial Statements of Item 8 of Part II. All 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
Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP) are the
predecessor companies to Vectren Corporation. Indiana Energy, incorporated under
Indiana law on October 24, 1985, was engaged in natural gas distribution, gas
portfolio administrative services, and marketing of natural gas, electric power
and related services. Indiana Energy had fourteen subsidiaries, including ten
nonregulated direct or indirect subsidiaries, a not-for-profit foundation and
three utility subsidiaries, as well as investments in four nonregulated joint
ventures. SIGCORP, incorporated under Indiana law on October 19, 1994, was
engaged in electric generation, transmission, and distribution, natural gas
distribution, coal mining, and broadband communication services. SIGCORP had
eleven wholly-owned subsidiaries, including ten nonregulated subsidiaries.
Vectren Corporation (the Company or Vectren), an Indiana corporation, 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).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. Both Vectren and VUHI are exempt from registration pursuant to
Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
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.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate and leveraged leases.
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, nonregulated, and corporate and other business segments. The
Company collectively refers to its gas and electric utility services segments as
its regulated operations. At December 31, 2002, the Company had $2.9 billion in
total assets, with $2.4 billion (83%) attributed to the regulated operations,
$0.4 billion (14%) attributed to the nonregulated operations, and $0.1 billion
(3%) attributed to the corporate and other group. Net income for the year ended
2002 was $114.0 million, or $1.69 per share of common stock, with $93.6 million
attributed to regulated, $19.0 million attributed to nonregulated, and $1.4
million attributed to corporate and other. Net income, as restated, for the year
ended 2001 was $52.7 million, or $0.79 per share of common stock. The year
ending December 31, 2001 included nonrecurring charges with an after tax impact
of $26.4 million. Nonrecurring items net of tax in 2001 included $8.0 million of
merger and integration costs, $11.8 million of restructuring costs, $7.7 million
of extraordinary loss, 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 18 regarding the segments' activities and assets,
Note 19 regarding special charges in 2001 and 2000, Note 5 regarding the
extraordinary loss, and Note 16 regarding the cumulative effect of change in
accounting principle in the Company's consolidated financial statements included
under Item 8 Financial Statements and Supplementary Data.
Following is a more detailed description of the regulated and nonregulated
business segments. The operations of the corporate and other business segment,
which include primarily information technology services, are not significant.
Regulated Business Segments
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. 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.
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 4 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.
Date of summer peak load 8/5/02 7/31/01 8/17/00 7/6/99 7/21/98
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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 the Company. 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
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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.
Nonregulated Business Segment
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband.
Energy Marketing and Services
The Energy Marketing and Services group relies heavily upon a customer focused,
value added strategy. The group provides natural gas and fuel supply management
services to a broad range of municipalities, utilities, industrial operations,
schools, and healthcare institutions through ProLiance. ProLiance is a
significant gas supplier to the Company's regulated operations. The group also
focuses on performance-based energy contracting through Energy Systems Group,
LLC. This service helps schools, hospitals, and other governmental and private
institutions reduce their energy and maintenance costs by upgrading their
facilities with energy-efficient equipment.
ProLiance is an unconsolidated affiliate of the Company and Citizens Gas and
Coke Utility (Citizens Gas). Energy Systems Group, LLC is a consolidated venture
between the Company and Citizens Gas, with the Company owning two-thirds.
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001 Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member. Since
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
At December 31, 2002, the Energy Marketing and Services group's natural gas
marketing operations had 1,060 customers, up from 984 in 2001. The collective
revenue of ProLiance and SES exceeded $1.7 billion in 2002.
Coal Mining
The Coal Mining group provides the mining and sale of coal to the Company's
utility operations and to other third parties through its wholly owned
subsidiary Vectren Fuels, Inc. The Coal Mining group also generates income tax
credits through IRS Code Section 29 investment tax credits relating to the
production of coal-based synthetic fuels through its 8.3% ownership in Pace
Carbon Synfuels, LP. The Company's two coal mines produced 3.5 million tons in
2002, up from 3.3 million in 2001. The Company's investment in Pace Carbon is
accounted for using the equity method of accounting.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water,
electric, and telecommunications companies as well as facilities locating and
meter reading services through its investment in Reliant Services, LLC
(Reliant). Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting.
In December 2000, Reliant purchased the common stock of Miller Pipeline
Corporation (Miller) from NiSource, Inc. for approximately $68.3 million.
Vectren and Cinergy Corp. each contributed $16.0 million of equity, and the
remaining $36.3 million was funded with 7-year intermediate bank loans. The
acquisition combines Reliant's utility services of underground facility
locating, contract meter reading, and installation of telecommunications
infrastructure with Miller's underground pipeline construction, replacement, and
repair services. Miller is one of the nation's premier natural gas distribution
contractors with over 50 years of experience in the construction industry,
currently providing such services to Indiana Gas, among other customers.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Broadband group provides telecommunications services to approximately 26,800
residential and commercial customers (an increase of 7.9% from 2001) in the
greater Evansville area in southwestern Indiana. The present customer base has
yielded approximately 78,000 residential revenue generating units (up from
approximately 70,000 at the end of 2001) indicating multiple services being
utilized by the same residential customer.
The Company has an approximate 1% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of
bundled communication services focusing on last mile delivery to residential and
commercial customers. The Company also has an 18.9% equity interest in SIGECOM
Holdings, Inc., which was formed by Utilicom to hold interests in SIGECOM, LLC
(SIGECOM). SIGECOM provides broadband services to the greater Evansville,
Indiana, area.
Utilicom also plans to provide services to Indianapolis, Indiana, and Dayton,
Ohio. However, the funding of these projects has been delayed due to the
continued difficult environment within the telecommunication capital markets,
which has prevented Utilicom from obtaining debt financing on terms it considers
acceptable. While the existing investors remain interested in the Indianapolis
and Dayton projects, the Company is not required to make further investments and
does not intend to proceed unless commitments are obtained to fully fund these
projects. Franchising agreements have been extended in both locations.
The convertible subordinated debt investment totals $30.7 million, of which
$28.6 million is convertible into Utilicom ownership at the Company's option or
upon the event of a public offering of stock by Utilicom and $2.1 million is
convertible into common equity interests in the Indianapolis and Dayton ventures
at the Company's option. Upon conversion, the Company would have up to a 12%
interest in Utilicom, assuming completion of all required funding and up to a
31% interest in the Indianapolis and Dayton ventures.
Other Businesses
In addition to the nonregulated business groups previously discussed, the Other
Businesses group invests in a portfolio of interests in gas and power storage,
distributed generation projects, and similar energy-related businesses.
Additional activities include:
o A utility services business, which supplies utilities with a number of
important services ranging from supply chain management to
environmental compliance testing.
o A retail unit, providing natural gas and other related products and
services primarily in Ohio serving customers opting for choice among
energy providers.
o A broadband consulting business.
Major investments include Haddington Energy Partnerships, two partnerships both
approximately 40% owned; CIGMA, LLC, a 50% owned strategic alliance with an
affiliate of Citizens Gas; and the wholly owned subsidiaries Southern Indiana
Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC, Vectren
Communication Services, Inc., and IEI Financial Services, LLC.
Personnel
As of December 31, 2002, the Company and its consolidated subsidiaries had 1,876
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.
Nonregulated Services
Subsidiaries other than the utility operations have no significant properties
other than the ownership and operation of coal mining property in Indiana and
investments in real estate partnerships, leveraged leases, and notes receivable.
The assets of the coal mining operations comprise approximately 3 percent of
total assets.
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 14 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 4 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
The Company's common stock trades on the New York Stock Exchange under the
symbol "VVC." For each quarter in 2002 and 2001, the high and low sales prices
for the Company's common stock as reported on the New York Stock Exchange and
dividends paid are shown in the following table.
Common Stock Price Range
Cash -------------------------
2002 Dividend High Low
-------- ------- -------
First Quarter $ 0.265 $ 25.95 $ 22.45
Second Quarter 0.265 26.10 23.10
Third Quarter 0.265 25.44 17.95
Fourth Quarter 0.275 25.00 21.05
2001
First Quarter $ 0.255 $ 24.44 $ 21.00
Second Quarter 0.255 23.90 20.38
Third Quarter 0.255 22.46 19.76
Fourth Quarter 0.265 24.07 21.05
On January 22, 2003, the board of directors declared a dividend of $0.275 per
share, payable on March 3, 2003, to common shareholders of record on February
14, 2003.
As of January 31, 2003, there were 13,460 shareholders of record of the
Company's common stock.
Dividends on shares of common stock are payable at the discretion of the board
of directors out of legally available funds. Future payments of dividends, and
the amounts of these dividends, will depend on the Company's financial
condition, results of operations, capital requirements, and other factors.
ITEM 6. SELECTED FINANCIAL DATA
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. The
financial information as of and for the years ended December 31, 2001 and 2000
has been restated. Common shareholders' equity as of January 1, 2000 also
reflects adjustments related to years prior to 2000. See Note 3 to the
consolidated financial statements included under Item 8 Financial Statements and
Supplementary Data for further information on the restatement.
Year Ended December 31
------------------------------------------------------------------------------------------------------
In millions, except per share data 2002 2001 (1) 2000(2,3) 1999 1998
------------------------------------------------------------------------------------------------------
(As Restated)
--------------------
Operating Data:
Operating revenues $ 1,804.3 $ 2,081.8 $ 1,632.8 $ 1,068.4 $ 997.7
Operating income $ 211.3 $ 127.9 $ 131.7 $ 160.8 $ 148.5
Income before extraordinary loss &
cumulative effect of change in
accounting principle $ 114.0 $ 59.3 $ 72.0 $ 90.7 $ 86.6
Net income $ 114.0 $ 52.7 $ 72.0 $ 90.7 $ 86.6
Average common shares outstanding 67.6 66.7 61.3 61.3 61.6
Fully diluted common shares
outstanding 67.9 66.9 61.4 61.4 61.8
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.69 $ 0.89 $ 1.18 $ 1.48 $ 1.41
Basic earnings per share
on common stock $ 1.69 $ 0.79 $ 1.18 $ 1.48 $ 1.41
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.68 $ 0.89 $ 1.17 $ 1.48 $ 1.40
Diluted earnings per share
on common stock $ 1.68 $ 0.79 $ 1.17 $ 1.48 $ 1.40
Dividends per share on common stock 1.07 $ 1.03 $ 0.98 $ 0.94 $ 0.90
Balance Sheet Data:
Total assets $ 2,926.5 $ 2,878.7 $ 2,943.7 $ 1,980.5 $ 1,798.8
Long-term debt, net $ 954.2 $ 1,014.0 $ 632.0 $ 486.7 $ 388.9
Redeemable preferred stock $ 0.3 $ 0.5 $ 8.1 $ 8.2 $ 8.3
Common shareholders' equity $ 869.9 $ 839.3 $ 733.4 $ 709.8 $ 677.9
(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 to reflect this decision, resulting in additional
depreciation expense of approximately $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 ($8.0 million after
tax).
The Company incurred restructuring charges of $19.0 million, ($11.8 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 $41.1 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 approximately $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 $52.5 million ($36.8
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 and 2000 by $10.9
million and $48,000, respectively. Note 3 in 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 21. The following discussion
and analysis gives effect to the restatement.
Consolidated Results of Operations
Year Ended December 31,
----------------------------------------------------------------------------
In millions, except per share amounts 2002 2001 2000
----------------------------------------------------------------------------
(As Restated)
---------------------
Net income $114.0 $ 52.7 $ 72.0
Attributed to:
Regulated $ 93.6 $ 40.1 $ 52.5
Nonregulated 19.0 12.1 21.8
Corporate & other 1.4 0.5 (2.3)
----------------------------------------------------------------------------
Basic earnings per share $ 1.69 $ 0.79 $ 1.18
Attributed to:
Regulated $ 1.39 $ 0.60 $ 0.85
Nonregulated 0.28 0.18 0.36
Corporate & other 0.02 0.01 (0.03)
In 2002, consolidated net income increased $61.3 million, or $0.90 per share,
when compared to 2001, as restated. The year ended December 31, 2001 included
nonrecurring merger, integration, and restructuring costs and other nonrecurring
items totaling $26.4 million after tax, or $0.40 per share. 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. Also contributing to
the increase was increased earnings from the Energy Marketing and Services Group
and a smaller loss in the Other Businesses Group, both of which are components
of nonregulated operations.
In 2001, consolidated net income decreased $19.3 million, or $0.39 per share,
compared to 2000. The year ended December 31, 2000 included nonrecurring merger,
integration, and restructuring costs net of other nonrecurring items totaling
$31.9 million after tax, or $0.52 per share. The decrease reflects lower
regulated earnings resulting from extraordinarily high gas costs early in 2001
that unfavorably impacted margins and operating costs, warmer heating weather,
especially during late 2001, and a weakened national economy. This reduction was
offset somewhat by increased earnings from the Energy Marketing and Services and
Coal Mining Groups, both of which are components of nonregulated operations, and
a decrease in nonrecurring items.
Dividends
In November 2002, the Company's board of directors increased its quarterly
dividend to $0.275 per share from $0.265 per share. Dividends declared for the
year ended December 31, 2002 were $1.07 per share, compared to $1.03 per share
and $0.98 per share for the same periods in 2001 and 2000, respectively.
Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.9 million after tax, or $0.16 per
share, 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
$2.6 million ($1.6 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 $0.6 million ($0.3 million after tax). The impact of
the restatement of results for the year ended 2000 is a reduction to net income
of less than $100,000.
In addition, the Company also reduced previously reported revenues and cost of
sales by $78.1 million in 2001 and $15.5 million in 2000 to adopt EITF Issue No.
99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" and to
properly eliminate certain transactions in consolidation.
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 shareholders' 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 $1.4 million and $0.9 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
$2.3 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. 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 $46.4 million of prepaid and other current assets with a
corresponding increase in accrued liabilities 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.
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 discussed in
Note 3. The effects of the restatement on 2001 quarterly results and on 2002
previously reported quarterly information, is discussed in Note 21. 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 $41.1 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
Since March 31, 2000, $43.9 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$20.7 million. Of this amount, $5.5 million related to employee and executive
severance costs, $13.1 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 $23.2 million was expensed ($20.4 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, internal labor of employees assigned to integration teams, investor
relations communication activities, and certain benefit costs.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
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 approximately $9.6 million and $11.4 million for the years ended
December 31, 2001 and 2000, respectively.
In total, for the year ended December 31, 2001, merger and integration costs
totaled $12.4 million ($8.0 million after tax), or $0.12 on a basic earnings per
share basis compared to $52.5 million ($36.8 million after tax), or $0.60 on a
basic earnings per share basis 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 $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 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 $19.0 million, ($11.8 million after tax), or $0.18 on a basic
earnings per share basis in 2001. These charges were comprised of $10.9 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 $4.1 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 19 for further information on restructuring costs.)
Extraordinary Loss
In June 2001, the Company sold certain leveraged lease investments with a net
book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax),
or $0.12 on a basic earnings per share basis. Because of the transaction's
significance and because the transaction occurred within two years of the
effective date of the merger of Indiana Energy and SIGCORP, which was accounted
for as a pooling-of-interests, APB 16 requires the loss on disposition of these
investments to be treated as extraordinary. Proceeds from the sale of $46.7
million were used to retire short-term borrowings.
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations and gas 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), or $0.02 on a basic earnings per share basis, recorded as a cumulative
effect of change in accounting principle in the Consolidated Statements of
Income. The majority of this gain results from the Company's power marketing
operations.
Gain on Restructuring of a Nonregulated Investment
In January 2000, the Company restructured its investment in SIGECOM, LLC
(SIGECOM). Affiliates of The Blackstone Group acquired a majority ownership
interest in Utilicom. In connection with The Blackstone Group investment, the
Company exchanged its 49% preferred equity interest in SIGECOM for $16.5 million
of convertible subordinated debt of Utilicom Networks LLC and an 18.9% common
equity interest in SIGECOM Holdings, Inc, which was valued at $6.5 million. The
carrying value of the Company's 49% preferred equity interest was $15.0 million
prior to the exchange. The Company received consideration in the exchange based
upon an investment bank analysis of the fair value of SIGECOM at the transaction
date. The investment restructuring resulted in a pre-tax gain of $8.0 million
($4.9 million after tax), or $0.08 on a basic earnings per share basis, which is
classified in equity in earnings of unconsolidated affiliates in the
Consolidated Statements of Income. Refer to Note 4 for more information on the
Company's investment in Utilicom-related entities.
Results of Operations by Business Segment
Following is a more detailed discussion of the results of operations of the
Company's regulated and nonregulated businesses. The detailed results of
operations for the regulated businesses and nonregulated businesses are
discussed and analyzed before the reclassification and elimination of certain
intersegment transactions necessary to consolidate those results into the
Company's Consolidated Statements of Income. The operations of the Corporate and
Other business segment, which include primarily information technology services,
are not significant.
Results of Operations of the Regulated Businesses
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. 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. The results of regulated operations before certain intersegment
eliminations and reclassifications for the years ended December 31, 2002, 2001,
and 2000 follows:
In millions, except per share amounts 2002 2001 2000
---------------------------------------------------------------------------
OPERATING REVENUES (As Restated)
--------------------
Gas revenues $ 909.0 $ 1,019.6 $ 820.4
Electric revenues 608.1 381.2 334.4
---------------------------------------------------------------------------
Total operating revenues 1,517.1 1,400.8 1,154.8
---------------------------------------------------------------------------
COST OF OPERATING REVENUES
Cost of gas 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
---------------------------------------------------------------------------
Total cost of operating revenues 949.7 870.2 664.6
---------------------------------------------------------------------------
TOTAL OPERATING MARGIN 567.4 530.6 490.2
OPERATING EXPENSES
Other operating 220.6 241.1 209.0
Merger & integration costs - 2.8 32.7
Restructuring costs - 15.0 -
Depreciation & amortization 96.8 97.2 82.4
Taxes other than income taxes 50.8 51.2 36.2
---------------------------------------------------------------------------
Total expenses 368.2 407.3 360.3
---------------------------------------------------------------------------
OPERATING INCOME 199.2 123.3 129.9
OTHER INCOME
Other - net 6.9 5.5 4.7
Equity in earnings of
unconsolidated affiliates (1.8) (0.5) -
---------------------------------------------------------------------------
Total other income 5.1 5.0 4.7
---------------------------------------------------------------------------
Interest expense 66.1 70.1 46.1
---------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 138.2 58.2 88.5
---------------------------------------------------------------------------
Income tax 44.6 18.4 35.0
Preferred dividend requirement of
subsidiary - 0.8 1.0
---------------------------------------------------------------------------
Income before cumulative effect of
change in accounting principle 93.6 39.0 52.5
Cumulative effect of change in accounting
principle - net of tax - 1.1 -
---------------------------------------------------------------------------
NET INCOME $ 93.6 $ 40.1 $ 52.5
===========================================================================
BASIC EARNINGS PER SHARE $ 1.39 $ 0.60 $ 0.85
===========================================================================
Utility operations contributed net income of $93.6 million, or $1.39 per share,
for the year ended December 31, 2002 compared to $40.1 million, or $0.60 per
share, in 2001. The year ended December 31, 2001 included nonrecurring merger,
integration, and restructuring costs and other nonrecurring items totaling $15.9
million after tax, or $0.24 per share. In addition to the nonrecurring 2001
items, the increase of $53.5 million, or $0.79 per share, was primarily the
result of improved margins and lower operating expense. 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.
For 2001 compared to 2000, net income decreased $12.4 million, or $0.25 per
share. The year ended December 31, 2000 included nonrecurring merger and
integration costs totaling $31.6 million, or $0.51 per share. The decrease is
due to extraordinarily high gas costs early in 2001 that unfavorably impacted
margins and operating costs, including uncollectible accounts expense, interest,
and excise taxes; and heating weather that was 9% warmer than the prior year.
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.
Utility Operating Expenses
Utility Other Operating
Utility other operating expenses decreased $20.5 million for the year ended
December 31, 2002 when compared to 2001. The decrease results primarily from
$9.6 million in lower charges for the use of corporate assets which had useful
lives shortened as a result of the merger and 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 maintenance costs incurred in 2001
was the primary component of the remaining decrease.
Excluding $33.2 million in additional expenses related to the Ohio operations,
utility other operating expenses for the year ended December 31, 2001 decreased
$1.1 million compared to 2000. The 2001 decrease results primarily from prior
merger synergies, offset by higher expenses resulting from increased gas costs.
Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.4 million for the year ended
December 31, 2002 when compared to 2001. The decrease results from the
discontinuance of goodwill amortization as required by SFAS 142, which
approximated $4.9 million in 2001, offset somewhat by depreciation of plant
additions.
Utility depreciation and amortization increased $14.8 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.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes decreased $0.4 million in 2002 compared to
2001 as a result of lower revenues subject to gross receipts tax and increased
$15.0 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.
Utility Other Income - Net
Other- net
Utility other income, net increased $1.4 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.
Utility Interest Expense
Utility interest expense decreased $4.0 million in 2002 compared to 2001. The
decrease is attributable to lower outstanding borrowings during 2002 and lower
average interest rates on adjustable rate debt.
Utility interest expense increased $24.0 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.
Utility Income Tax
Federal and state income taxes related to utility operations increased $26.2
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 from 31.6% in 2001 to 32.3% in 2002 due to amortization of investment
tax credits and higher pre-tax income.
Federal and state income taxes related to utility operations decreased $16.6
million in 2001 when compared to 2000. The 2001 decrease is due to lower pre-tax
earnings. The effective tax rate decreased from 39.5% in 2000 to 31.6% in 2001.
This decrease results primarily from 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.
For additional information on regulatory matters affecting the utilities, refer
to Nonregulated Section's discussion of transactions with ProLiance.
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.
Results of Operations of the Nonregulated Businesses
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates IRS Code Section 29 investment tax credits relating
to the production of coal-based synthetic fuels. Utility Infrastructure Services
provides underground construction and repair, facilities locating, and meter
reading services. Broadband invests in broadband communication services such as
analog and digital cable television, high-speed Internet and data services, and
advanced local and long distance phone services. In addition, the nonregulated
group has investments in other businesses that invest in energy-related
opportunities and provides utility services, municipal broadband consulting,
retail, and real estate and leveraged leases. The results of nonregulated
operations for the years ended December 31, 2002, 2001, and 2000 follows:
In millions, except per share amounts 2002 2001 2000
-------------------------------------------------------------------------
(As Restated)
----------------
Energy services & other revenues $ 287.2 $ 681.0 $ 478.0
Cost of energy services & other revenues 249.4 640.9 453.2
-------------------------------------------------------------------------
TOTAL OPERATING MARGIN 37.8 40.1 24.8
Intersegment revenues, net of costs 3.0 2.6 1.9
Expenses:
Operating expenses 36.1 36.3 20.3
Merger & integration costs - - 1.6
Restructuring costs - 3.5 -
-------------------------------------------------------------------------
Total expenses 36.1 39.8 21.9
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OPERATING INCOME 4.7 2.9 4.8
Other income:
Equity in earnings of
unconsolidated affiliates 10.9 13.9 9.8
Other - net 6.1 11.4 18.5
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Total other income 17.0 25.3 28.3
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Interest expense 9.1 12.5 9.6
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INCOME BEFORE TAXES 12.6 15.7 23.5
Income tax (6.9) (4.7) 0.6
Minority interest 0.5 0.6 1.1
-------------------------------------------------------------------------
Income before extraordinary loss 19.0 19.8 21.8
Extraordinary loss - net of tax - (7.7) -
-------------------------------------------------------------------------
NET INCOME $ 19.0 $ 12.1 $ 21.8
=========================================================================
BASIC EARNINGS PER SHARE $ 0.28 $ 0.18 $ 0.36
=========================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 15.0 $ 11.3 $ 7.2
Coal Mining 12.2 13.6 4.6
Utility Infrastructure (1.2) (0.6) 0.2
Broadband 0.4 (0.1) 4.4
Other Businesses (7.4) (12.1) 5.4
For the year ended December 31, 2002, earnings from nonregulated operations
increased $6.9 million, or $0.10 per share, when compared to 2001. The increase
is primarily due to increased earnings from Energy Marketing and Services and a
smaller loss incurred by the Company's broadband consulting operations which are
part of the Other Businesses Group. The year ended December 31, 2001 included
$2.2 million after tax, or $0.04 per share, in nonrecurring restructuring costs
and $7.7 million after tax, or $0.12 per share, related to an extraordinary loss
from the divestiture of certain assets. In addition, 2001 benefited from gains
recognized upon sale of investments by an unconsolidated affiliate in the first
and third quarters, and 2002 was negatively affected by a change in Indiana
corporate income tax laws enacted in June 2002, which required the recalculation
of deferred tax obligations and earnings from leveraged lease investments at the
date of enactment of the law.
For 2001 compared to 2000, net income decreased $9.7 million due primarily to
nonrecurring items incurred in 2001 and 2000. Nonrecurring items in 2000 added
earnings of $3.9 million, or $0.06 per share, and included a gain from
restructuring the Company's investment in SIGECOM, offset by merger and
integration costs. Before nonrecurring items, 2001 earnings increased $4.1
million primarily due to expanded natural gas marketing and coal mining
operations, partially offset by losses incurred by the Company's broadband
consulting operations.
Energy Marketing & Services
Energy Marketing and Services includes the Company's investment in ProLiance, a
nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke
Utility (Citizens Gas). ProLiance provides natural gas and related services to
Indiana Gas, the Ohio operations, Citizens Gas, and others and 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. In addition,
Energy Marketing and Services includes the operations of Energy Systems Group,
LLC (ESG), which provides energy performance contracting and facility upgrades
through its design and installation of energy-efficient equipment. ESG is a
consolidated venture between the Company and Citizens Gas, with the Company
owning two-thirds. ESG had no significant impact on the Company's financial
results in 2002, 2001, or 2000.
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001 Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member. Since
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. SES' revenues and expenses were
the primary component of nonregulated revenues and cost of revenues. Therefore,
the integration significantly decreased revenues and costs of revenues over $400
million in 2002 compared to 2001. The Company's operating expenses also
decreased $4.8 million in 2002 as a result of the integration. The transfer of
net assets was accounted for at book value consistent with joint venture
accounting and did not result in any gain or loss.
Pre-tax income of $19.1 million, $12.8 million and $5.4 million was recognized
as ProLiance's contribution to earnings for the years ended December 31, 2002,
2001, and 2000, respectively. Pre-tax earnings have increased primarily as a
result of increased operations at ProLiance and the Company's increased
ownership. Earnings recognized from ProLiance are included in equity in earnings
of unconsolidated affiliates.
In 2001 compared to 2000, the significant increase in the Company's nonregulated
revenues and costs of revenues was primarily attributable to SES' operations
reflecting higher prices for natural gas and increased volumes. SES' increased
activity was also a contributing factor to the increase in 2001 margin and
operating expenses when compared to 2000.
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, the Company made refunds
to Indiana Gas' retail customers pursuant to the settlement totaling $6.4
million and reimbursed other costs to parties involved in the settlement
totaling $1.1 million. Payments were made in the fourth quarter of 2002. At
December 31, 2001, the Company had established a reserve specific to this GCA
proceeding totaling $5.2 million which was recorded throughout the GCA
proceeding as a reduction of ProLiance's contribution to the Company's earnings.
The amount of the settlement in excess of that accrued prior to 2002 totaling
$2.3 million was reflected as a reduction of ProLiance's contribution to
earnings in 2002.
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.
Coal Mining
Coal Mining provides the mining and sale of coal to the Company's utility
operations and to other third parties through its wholly owned subsidiary
Vectren Fuels, Inc (Fuels). The group also generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels
through its investment in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon is
an unconsolidated affiliate accounted for using the equity method.
Earnings from Fuels were $6.2 million in 2002, $9.3 million in 2001, and $2.5
million in 2000. In 2002 compared to 2001, net income and operating income
decreased $3.3 million and $4.9 million, respectively, as a result of lower
market prices on third party coal sales and a somewhat lower yield per ton mined
in 2002. In 2001 compared to 2000, net income and operating income increased
$7.0 million and $11.1 million, respectively, as a result of the Company's
second mine starting operations in mid-2001. The new mine was also a
contributing factor to increased operating expenses in 2002 and 2001. Fuels'
operating expenses increased $0.8 million in 2002 and $6.9 million in 2001.
The investment in Pace Carbon resulted in losses reflected in equity in earnings
of unconsolidated affiliates totaling $6.8 million, $4.5 million, and $2.4
million in 2002, 2001, and 2000, respectively. Losses have increased as a result
of increased production of synthetic fuels and higher production costs. The
production of synthetic fuel generates IRS Code Section 29 investment tax
credits that are reflected in income taxes. These credits have also increased in
recent years consistent with increased synthetic fuel production. Net income,
including the losses, tax benefits, and tax credits, generated from the
investment in Pace Carbon totaled $6.0 million in 2002, $4.3 million in 2001,
and $2.1 million in 2000.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water,
electric, and telecommunications companies as well as facilities locating and
meter reading services through its investment in Reliant Services, LLC
(Reliant). Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting. The
investment in Reliant had no significant impact on the Company's results in
2002, 2001, or 2000.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Company has a minority interest and a convertible subordinated debt investment
in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of bundled
communication services focusing on last mile delivery to residential and
commercial customers. The Company also has a minority interest in SIGECOM
Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in
SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater
Evansville, Indiana, area.
The equity investments in Utilicom and Holdings are accounted for using the cost
method of accounting. As a result, Broadband had no significant impact on the
Company's financial results with the exception of the one-time gain recorded in
2000 upon the restructuring of the Company's investment in SIGECOM previously
discussed. The $4.9 million gain is included in equity in earnings of
unconsolidated affiliates.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana, and Dayton, Ohio, markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
remain interested in the Indianapolis and Dayton projects, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
Other Businesses
The Other Businesses Group includes a variety of wholly owned operations and
investments. The significant activities that affected the nonregulated results
of operations during 2002, 2001, and 2000 are the wholly owned operations of
Vectren Communication Services, Inc. (VCS), Vectren Retail LLC (Vectren Retail),
and Southern Indiana Properties, Inc.(SIPI) and the Company's investment in the
Haddington partnerships (Haddington), which are accounted for using the equity
method of accounting.
VCS is a wholly owned broadband consulting company that incurred charges in 2002
and 2001 related to the settlement of construction contracts and the
reorganization of its operations, allowing it to focus on consulting services.
As a result, VCS incurred net losses of $2.8 million in 2002 and $8.0 million in
2001 compared to net income of $0.2 million in 2000. The majority of the costs
incurred in 2001 and 2002 are included in cost of energy services and other
revenues and are therefore a component of the change in margin in 2002 compared
to 2001 and 2001 compared to 2000.
Vectren Retail provides natural gas and other related products and services
primarily in Ohio serving customers opting for choice among energy providers.
Vectren Retail began operations in 2001 and has incurred startup costs which
increased operating expenses $1.5 million in 2002 and $0.9 million in 2001. Due
to increased activity, these operations added margin of $1.3 million in 2002
compared to 2001.
SIPI has various investments in leveraged leases, notes receivable, and
unconsolidated affiliates. The Company divested of notes receivable and
leveraged lease investments in the second and fourth quarters of 2001. These
divestitures resulted in the $7.7 million extraordinary loss previously
discussed and less leveraged lease and interest income in 2002 compared to 2001
and in 2001 compared to 2000. The decrease in leveraged lease and interest
income is the primary contributing factor to the change in other-net in 2002 and
2001. The dispositions of these assets generated cash flow of approximately $67
million.
The Haddington partnerships are equity method investments that invest in
energy-related opportunities. During 2001, these partnerships sold investments
resulting in gains reflected by the Company totaling $6.2 million. Such gains
are included in equity in earnings of unconsolidated affiliates. The most
significant portion of these earnings was derived from Haddington's sale of Bear
Paw Investments, LLC (Bear Paw). In March 2001, Haddington sold its investment
in Bear Paw in exchange for a combination of cash and securities. The cost of
Haddington's Bear Paw investment approximated $5.1 million, and the net proceeds
received totaled $18.1 million, resulting in a gain of $13.0 million. The
Company recognized its portion of the pre-tax gain totaling $3.9 million in
March 2001. Later in 2001 as the securities received were sold, the Company
recognized its portion of the additional earnings totaling $1.0 million.
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 and
to determine pension and postretirement benefit obligations. The Company makes
other estimates in the course of accounting for unbilled revenue and the effects
of regulation 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 and non-utility plant, the valuation
of derivative contracts, and the allowance for doubtful accounts, among others.
Actual results could differ from these estimates.
Impairment Review of Investments
The Company has investments in notes receivable, entities accounted for using
the cost method of accounting, and entities accounted for using the equity
method of accounting. 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, or for notes that are collateral dependent, a comparison of the
collateral's fair value to the carrying amount of the note. An impairment
analysis of cost method and equity method investments involves comparison of the
investment's estimated fair value to its carrying amount. Fair value is
estimated using market comparisons, appraisals, and/or 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 an impairment analysis on its
Utilicom-related investments. The Company used market comparisons to estimate
fair value for the cost method portion of the Utilicom investment and a free
cash flow analysis to estimate fair value for the note receivable portion of the
Utilicom investment. No impairment charge was recorded as a result of these
tests. However, a 10% decrease in the fair value that was estimated using market
comparables would have resulted in a $0.3 million impairment charge to the cost
method investment. A 10% decrease in the cash flow growth assumption utilized to
calculate Utilicom's free cash flows would have resulted in no impairment charge
to the notes receivable.
Impairment tests on other investments were also conducted using appraisals and
discounted cash flow models to estimate fair value. No impairment charges
resulted from these analyses. For the other impairment tests performed during
2002, a 10% adverse change in the calculated or appraised fair value of
collateral or a 100 basis point adverse change in the discount rate used to
estimate fair value would have resulted in a $2.6 million impairment charge.
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 18 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.
Pension and Other Postretirement Obligations
The Company 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 the Company's pension and postretirement plans. The
Company annually measures its obligations on September 30. The Company 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, the Company 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.
For the year ended December 31, 2002, a 1% adverse change in the assumed health
care cost trend rate for the postretirement health care plans would have
decreased pre-tax income by approximately $0.4 million and would have increased
the postretirement liability by approximately $5.6 million.
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.
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 16 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.
The incremental disclosure requirements are included in the consolidated
financial statements included in Item 8, Note 13. 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, and Vectren Capital Corp (Cap Corp)
funds short-term and long-term financing needs of the nonregulated and corporate
operations. Vectren Corporation guarantees Cap Corp's debt, but 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.
Regulated operations have historically funded the Company's common stock
dividends. Nonregulated operations have demonstrated sustained profitability,
and the ability to generate cash flows. These cash flows are ordinarily
reinvested in other nonregulated ventures. In the future, nonregulated cash
flows could be used to fund a small portion of the Company's dividend
requirement.
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. Cap Corp's senior
unsecured debt is rated BBB+/Baa2. 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 40-50% 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, investments, 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 VUHI
and its utility subsidiaries. These plans may include the issuance of new equity
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 historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities increased during the year ended December 31, 2002 compared to 2001 by
$104.2 million and increased $141.5 million in 2001 compared to 2000. The
primary reasons for the increases are favorable changes in working capital
accounts 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 $57.6 million for the year ended
December 31, 2002 includes an increase in borrowings outstanding over 2001 of
$13.8 million and increased common stock dividends compared to 2001. Borrowings
have increased due to financing a portion of capital expenditures for NOx
compliance temporarily with short-term borrowings.
Cash flow required for financing activities of $2.7 million for the year ended
December 31, 2001 includes $59.5 million of reductions in borrowings and
preferred stock and $69.5 million in common stock dividends, offset by the
issuance of $129.4 million of common stock. During 2001, $473.4 million of net
proceeds from equity and debt issuances were utilized to pay down short-term
borrowings.
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, the Company 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.
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 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, Cap Corp issued $78.0 million of private placement unsecured
senior notes to three institutional investors. The issues and terms are $38.0
million at 7.67%, due December 2005; $17.5 million at 7.83%, due December 2007;
and $22.5 million at 7.98%, due December 2010. These notes are guaranteed by
Vectren Corporation. The issues have no sinking fund requirements. The net
proceeds totaling $77.4 million were used to repay outstanding short-term
borrowings.
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 $234.6 million for the year ended
December 31, 2002 includes $218.7 million of requirements for capital
expenditures. Investing activities for 2001 were $175.6 million. The $59.0
million increase occurring in 2002 is principally the result of the sale of
leveraged lease and notes receivable investments in 2001.
Cash required for investing activities for the year ended December 31, 2001
includes $239.7 million of requirements for capital expenditures offset by $53.8
million of proceeds from the sale of leveraged leases. Investing activities for
the years ended December 31, 2000 were $687.5 million. The $511.9 million
decrease occurring in 2001 is principally the result of the acquisition of the
Ohio operations and proceeds received from the sale of assets in 2001.
Available Sources of Liquidity
At December 31, 2002, the Company has $510.0 million of short-term borrowing
capacity, including $330.0 million for its regulated operations and $180.0
million for its wholly owned nonregulated and corporate operations, of which
approximately $90.9 million is available for regulated operations and $17.0
million is available for wholly owned nonregulated and corporate operations. The
availability of short-term borrowing is reduced by outstanding letters of credit
totaling $5.2 million, collateralizing nonregulated activities. Subsequent to
December 31, 2002, the Company increased its regulated capacity $145.0 million
to $475.0 million. Effective January 1, 2003, the Company 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 the regulated segment and will make the
nonregulated and corporate capacity available for those operations.
Prior to 2001, the Company purchased shares from the open market to satisfy
issuances of common stock pursuant to its dividend reinvestment plan and stock
option plans. In 2001, the Company 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 in additional liquidity.
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 $ 399.5 $ - $ - $ - $ - $ -
Long-term debt (1) 16.0 15.0 38.0 - 24.0 908.1
Long-term debt to be called (2) 23.8 - - - - -
Operating leases (3) 6.8 6.3 5.0 4.5 4.0 4.7
Firm natural gas purchase commitments 89.5 21.3 3.6 - - -
----------------------------------------------------------------------------------------
Total $ 535.6 $ 42.6 $ 46.6 $ 4.5 $ 28.0 $ 912.8
========================================================================================
(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.
(3) Included in rental commitments is a synthetic lease involving a
transportation asset. A synthetic lease allows the Company to keep certain
assets and corresponding debt off balance sheet while keeping the asset on
the balance sheet for tax purposes. If the Company were to consolidate the
special purpose entity that owns the asset, the Company would record
additional assets and debt both totaling approximately $4.5 million.
Planned Capital Expenditures & Investments
Capital expenditures and investments in nonregulated unconsolidated affiliates
for the five-year period 2003 - 2007 are estimated as follows:
In millions 2003 2004 2005 2006 2007
----------------------------------------------------------------------------
Capital expenditures
Regulated (1) $ 204.8 $ 236.5 $ 184.9 $ 145.1 $ 135.4
Nonregulated 7.8 6.5 5.7 6.9 7.3
Corporate & other 22.3 27.8 10.5 16.4 11.3
----------------------------------------------------------------------------
Total capital expenditures $ 234.9 $ 270.8 $ 201.1 $ 168.4 $ 154.0
============================================================================
Investments in unconsolidated
affiliates $ 14.6 $ 15.9 $ 18.8 $ 11.0 $ 12.2
============================================================================
(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.
Ratings Triggers
At December 31, 2002, $113.0 million of Cap Corp's senior unsecured notes were
subject to cross-default and ratings trigger provisions that would provide that
the full balance outstanding is subject to prepayment if the ratings of Indiana
Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a make
whole amount based on the discounted value of the remaining payments due on the
notes would also become payable. Ratings triggers on Cap Corp's bank loans and
VUHI's commercial paper back up facility existing at December 31, 2001 were
removed as facilities were renewed during 2002. As previously discussed under
Financial Condition above, Indiana Gas and SIGECO ratings were downgraded to
Baa1 by Moody's and remain at one level above the ratings trigger. Effective
January 1, 2003, the Company transferred assets which primarily related to its
regulated operations to VUHI in order to make approximately $60 million of
additional nonregulated and corporate capacity available and is currently
exploring expanding unutilized capacity under its nonregulated short-term
borrowing facilities for additional liquidity protection.
Guarantees and Letters of Credit
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees may include posted letters of credit, debt and leasing guarantees,
performance guarantees, and energy saving guarantees and may periodically
include the debt of and performance obligations of unconsolidated affiliates.
The Company estimates these guarantees totaled approximately $117 million at
December 31, 2002, including outstanding letters of credit. The Company's most
significant guarantee approximating $60 million represents two-thirds of Energy
Systems Group, LLC's (ESG) surety bonds, performance guarantees, and energy
savings guarantees. ESG is a two-thirds owned consolidated subsidiary. The
guarantees relate to amounts due to various insurance companies for surety bonds
should ESG default on obligations to complete construction, pay vendors or
subcontractors, or to achieve energy guarantees. Through December 31, 2002, the
Company has not been called upon to satisfy any obligations pursuant to its
guarantees.
Vectren guarantees the outstanding long-term and short-term debt of Cap Corp,
which totaled $113.0 million and $157.8 million, respectively, at December 31,
2002. VUHI's currently outstanding long-term and short-term debt is jointly and
severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and
short-term debt outstanding at December 31, 2002 totaled $350.0 million and
$239.1 million, respectively.
Pension and Postretirement Funding Obligations
The Company 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 the Company 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.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements included, among others, the following:
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 The performance of projects undertaken by the Company's nonregulated
businesses and the success of efforts to invest in and develop new
opportunities, including but not limited to, the realization of Section 29
income tax credits and the Company's coal mining, gas marketing, and
broadband strategies.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in our credit rating, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee 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, natural gas, coal, and other commodity prices. Other
commodity operations include sales of electricity to certain municipalities and
large industrial customers and nonregulated retail gas marketing and coal mining
operations.
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, natural gas, and coal, to meet customer
demands and operational needs. These operations also enter into forward and
option 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 stored inventory, insurance contracts, and
offsetting forward purchase contracts. In addition, price risk also results from
forward contracts to purchase commodities to fulfill forecasted sales
transactions that may, or may not, occur.
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.
Commodity Price Risk from Unconsolidated Affiliate
ProLiance, a nonregulated energy marketing affiliate, engages in energy hedging
activities to manage pricing decisions, minimize the risk of price volatility,
and minimize price risk exposure in the energy markets. ProLiance's market
exposure arises from storage inventory, imbalances, and fixed-price forward
purchase and sale contracts, which are entered into to support its operating
activities. Currently, ProLiance buys and sells physical commodities and
utilizes financial instruments to hedge its market exposure. However, net open
positions in terms of price, volume and specified delivery point do occur.
ProLiance manages open positions with policies which limit its exposure to
market risk and require reporting potential financial exposure to its management
and its members. As a result of ProLiance's risk management policies, management
believes that ProLiance's exposure to market risk will not result in material
earnings or cash flow loss to the Company.
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 30%
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 $419.4
million and $403.0 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2002 and 2001, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $3.1 million and $6.2 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. Credit risk associated with certain
investments is also managed by a review of creditworthiness and receipt of
collateral.
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 Corporation 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 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 Shareholders and Board of Directors of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren
Corporation and subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of income, shareholders' 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 Corporation 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 16, 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
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
-----------------------------------------------------------------------------
2002 2001
-----------------------------------------------------------------------------
(As Restated,
ASSETS See Note 3)
Current Assets
Cash & cash equivalents $ 25.1 $ 25.0
Accounts receivable-less reserves of
$5.5 & $5.3, respectively 154.4 208.3
Accrued unbilled revenues 116.1 76.7
Inventories 62.8 70.9
Recoverable fuel & natural gas costs 22.1 70.2
Prepayments & other current assets 93.0 131.0
-----------------------------------------------------------------------------
Total current assets 473.5 582.1
-----------------------------------------------------------------------------
Utility Plant
Original cost 3,037.1 2,906.1
Less: accumulated depreciation
& amortization 1,389.0 1,308.2
-----------------------------------------------------------------------------
Net utility plant 1,648.1 1,597.9
-----------------------------------------------------------------------------
Investments in unconsolidated affiliates 153.3 128.6
Other investments 124.3 99.8
Non-utility property-net 228.0 182.8
Goodwill-net 202.2 201.5
Regulatory assets 75.2 67.8
Other assets 21.9 18.2
-----------------------------------------------------------------------------
TOTAL ASSETS $ 2,926.5 $ 2,878.7
=============================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
--------------------------------------------------------------------------------
2002 2001
--------------------------------------------------------------------------------
(As Restated,
LIABILITIES & SHAREHOLDERS' EQUITY See Note 3)
Current Liabilities
Accounts payable $ 101.7 $ 145.2
Accounts payable to affiliated companies 86.4 38.1
Accrued liabilities 119.9 118.5
Short-term borrowings 399.5 383.3
Current maturities of long-term debt 39.8 1.3
Long-term debt subject to tender 26.6 11.5
--------------------------------------------------------------------------------
Total current liabilities 773.9 697.9
--------------------------------------------------------------------------------
Long-term Debt-Net of Current Maturities &
Debt Subject to Tender 954.2 1,014.0
Deferred Income Taxes & Other Liabilities
Deferred income taxes 195.5 216.3
Deferred credits & other liabilities 130.8 109.3
--------------------------------------------------------------------------------
Total deferred credits & other liabilities 326.3 325.6
--------------------------------------------------------------------------------
Minority Interest in Subsidiary 1.9 1.4
Commitments & Contingencies (Notes 4, 13-15)
Cumulative, Redeemable Preferred Stock of
a Subsidiary 0.3 0.5
Common Shareholders' Equity
Common stock (no par value) - issued &
outstanding 67.9 and 67.7, respectively 350.0 346.1
Retained earnings 530.4 489.1
Accumulated other comprehensive income (10.5) 4.1
--------------------------------------------------------------------------------
Total common shareholders' equity 869.9 839.3
--------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,926.5 $ 2,878.7
================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
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
Energy services & other 287.2 681.0 478.0
--------------------------------------------------------------------------------------
Total operating revenues 1,804.3 2,081.8 1,632.8
--------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 571.2 708.9 552.5
Fuel for electric generation 81.6 74.4 75.7
Purchased electric energy 296.3 86.9 36.4
Cost of energy services & other 249.4 640.9 453.2
Other operating 223.0 243.2 198.5
Merger & integration costs - 2.8 41.1
Restructuring costs - 19.0 -
Depreciation & amortization 119.6 124.1 105.7
Taxes other than income taxes 51.9 53.7 38.0
--------------------------------------------------------------------------------------
Total operating expenses 1,593.0 1,953.9 1,501.1
--------------------------------------------------------------------------------------
OPERATING INCOME 211.3 127.9 131.7
OTHER INCOME
Equity in earnings of unconsolidated affiliates 9.1 13.4 9.8
Other - net 11.5 16.7 23.1
--------------------------------------------------------------------------------------
Total other income 20.6 30.1 32.9
--------------------------------------------------------------------------------------
Interest expense 78.5 83.2 56.4
--------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 153.4 74.8 108.2
--------------------------------------------------------------------------------------
Income taxes 38.9 14.1 34.2
Minority interest in & preferred dividend
requirements of subsidiaries 0.5 1.4 2.0
--------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 114.0 59.3 72.0
--------------------------------------------------------------------------------------
Extraordinary loss - net of tax - (7.7) -
Cumulative effect of change in accounting
principle - net of tax - 1.1 -
--------------------------------------------------------------------------------------
NET INCOME $ 114.0 $ 52.7 $ 72.0
======================================================================================
AVERAGE COMMON SHARES OUTSTANDING 67.6 66.7 61.3
DILUTED COMMON SHARES OUTSTANDING 67.9 66.9 61.4
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.69 $ 0.89 $ 1.18
Extraordinary loss - net of tax - (0.12) -
Cumulative effect of change in accounting
principle - net of tax - 0.02 -
--------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.69 $ 0.79 $ 1.18
======================================================================================
DILUTED
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.68 $ 0.89 $ 1.17
Extraordinary loss - net of tax - (0.12) -
Cumulative effect of change in accounting
principle - net of tax - 0.02 -
--------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.68 $ 0.79 $ 1.17
======================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000
--------------------------------------------------------------------------------------
(As Restated,
CASH FLOWS FROM OPERATING ACTIVITIES See Note 3)
------------------
Net income $ 114.0 $ 52.7 $ 72.0
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 119.6 124.1 105.7
Deferred income taxes & investment tax credits (28.5) 12.4 (5.8)
Equity in earnings of unconsolidated affiliates (9.1) (13.4) (9.8)
Net unrealized loss (gain) on derivative
instruments, including cumulative effect
of change in accounting principle 3.6 (3.3) -
Extraordinary loss on sale of leveraged
leases - net of tax - 7.7 -
Pension and postretirement expense 13.2 8.5 9.8
Other non-cash charges- net 7.5 13.1 (0.4)
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue (42.0) 135.5 (255.8)
Inventories 0.4 24.2 17.8
Recoverable fuel & natural gas costs 48.1 25.9 (82.3)
Prepayments & other current assets 31.2 (70.3) (3.4)
Accounts payable, including to affiliated
companies 40.7 (120.6) 208.2
Accrued liabilities 11.7 (7.0) (2.4)
Changes in noncurrent assets (6.0) 4.6 1.2
Changes in noncurrent liabilities (12.1) (6.0) (8.2)
--------------------------------------------------------------------------------------
Net cash flows from operating activities 292.3 188.1 46.6
--------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs - 344.0 145.3
Common stock - net of issuance costs - 129.4 -
Short-term notes payable - - 150.0
Requirements for:
Dividends on common stock (72.3) (69.5) (60.0)
Retirement of long-term debt (6.5) (7.6) (3.3)
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 20.3 (228.2) 402.3
Proceeds (payments) from exercise of stock
options & other 1.1 (2.3) 7.4
--------------------------------------------------------------------------------------
Net cash flows (required for) from
financing activitiesS (57.6) (2.7) 638.7
--------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from:
Unconsolidated affiliate distributions 7.4 22.5 7.0
Sale of leveraged lease investments - 53.8 -
Notes receivable & other collections 3.9 16.6 9.0
Requirements for:
Capital expenditures, excluding AFUDC-equity (218.7) (239.7) (164.3)
Unconsolidated affiliate investments (12.5) (22.7) (29.4)
Acquisition of Ohio operations - (2.2) (469.2)
Notes receivable & other investments (14.7) (3.9) (40.6)
--------------------------------------------------------------------------------------
Net cash flows (required for) investing
activities (234.6) (175.6) (687.5)
--------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents 0.1 9.8 (2.2)
Cash & cash equivalents at beginning of period 25.0 15.2 17.4
--------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 25.1 $ 25.0 $ 15.2
======================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)
Common Stock
-------------------------
Accumulated
Restricted Other
Stock Retained Comprehensive
Shares Amount Grants Earnings Income (Loss) Total
----------------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Reported 61.3 $ 217.5 $ (1.5) $ 493.9 $ (0.1) $ 709.8
Restatement adjustment 1.7 1.7
----------------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Restated 61.3 217.5 (1.5) 495.6 (0.1) 711.5
----------------------------------------------------------------------------------------------------
Comprehensive income:
Net income 72.0 72.0
Minimum pension liability adjustments &
other - net of tax 0.1 0.1
Comprehensive income of unconsolidated
affiliates - net of tax 7.5 7.5
----------------------------------------------------------------------------------------------------
Total comprehensive income (As Restated) 79.6
----------------------------------------------------------------------------------------------------
Common stock dividends ($0.98 per share) (60.0) (60.0)
Other 0.1 1.8 0.5 2.3
----------------------------------------------------------------------------------------------------
Balance at December 31, 2000, As Restated 61.4 219.3 (1.5) 508.1 7.5 733.4
----------------------------------------------------------------------------------------------------
Comprehensive income:
Net income (As Restated, See Note 3) 52.7 52.7
Minimum pension liability adjustments &
other - net of tax (1.8) (1.8)
Comprehensive income of unconsolidated
affiliates - net of tax (1.6) (1.6)
----------------------------------------------------------------------------------------------------
Total comprehensive income, (As Restated) 49.3
----------------------------------------------------------------------------------------------------
Common stock:
Issuance - net of $5.1 issuance costs 6.3 129.4 129.4
Dividends ($1.03 per share) (69.5) (69.5)
Other (0.1) (1.0) (2.2) (3.3)
----------------------------------------------------------------------------------------------------
Balance at December 31, 2001, As Restated 67.7 348.6 (2.5) 489.1 4.1 839.3
----------------------------------------------------------------------------------------------------
Comprehensive income:
Net income 114.0 114.0
Minimum pension liability adjustments &
other - net of tax (9.3) (9.3)
Comprehensive income of unconsolidated
affiliates - net of tax (5.3) (5.3)
----------------------------------------------------------------------------------------------------
Total comprehensive income 99.4
----------------------------------------------------------------------------------------------------
Common stock dividends ($1.07 per share) (72.3) (72.3)
Other 0.2 3.7 0.2 (0.4) 3.5
----------------------------------------------------------------------------------------------------
Balance at December 31, 2002 67.9 $ 352.3 $ (2.3) $ 530.4 $(10.5) $ 869.9
====================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Overview
Vectren Corporation (the Company or Vectren), an Indiana corporation, 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, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. Both Vectren and VUHI are exempt from registration pursuant to
Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
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.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate and leveraged leases.
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, has been 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, net income, and basic and diluted earnings per share
for the year ended December 31, 2000 would have been $1,817.2 million, $72.0
million, $1.18, and $1.17, 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 results of the Company on a historical basis as restated
for the effects of the pooling-of-interests transaction completed on March 31,
2000 between Indiana Energy and SIGCORP. 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 $172.0 million and $22.1 million,
respectively, by Indiana Energy and $187.4 million and $19.3 million,
respectively, by SIGCORP.
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 $ 67.1 $ 74.9 $ 55.7
Income taxes 16.5 38.0 53.5
-----------------------------------------------------------------------------
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 19.7 21.0
Fuel (coal & oil) for electric generation 11.3 10.3
Gas in storage - at average cost 3.2 11.6
Other 3.2 3.6
---------------------------------------------------------------------------
Total inventories $ 62.8 $ 70.9
===========================================================================
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
Original Percent of Original Percent of
Cost Original Cost Cost Original Cost
-------------------------------------------------------------------------------
Gas utility plant $1,622.0 3.8% $1,523.0 3.6%
Electric utility plant 1,211.0 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 $3,037.1 $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
Non-utility property, net of accumulated depreciation
and amortization, by operating segment follows:
At December 31,
-------------------------------------------------------------------------
In millions 2002 2001
-------------------------------------------------------------------------
Corporate & Other $ 140.5 $ 103.1
Nonregulated Operations 78.8 73.4
Electric & Gas Utility Services 8.7 6.3
-------------------------------------------------------------------------
Non-utility property-net $ 228.0 $ 182.8
=========================================================================
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 or units-of-production method of amortization. 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 $104.7 million and $83.0 million as of
December 31, 2002 and 2001, respectively. For the years ended December 31, 2002,
2001, and 2000, the Company capitalized interest totaling $0.4 million, $1.7
million, and $1.5 million, respectively, on non-utility plant construction
projects.
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
extraordinary loss and cumulative effect of change in accounting principle and
net income would have been $62.3 million and $55.7 million, respectively, had
goodwill not been amortized and in 2000, net income would have been $72.5
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 and earnings per
share to the adjusted net income disclosed above and related earnings per share
for years ended December 31, 2001 and 2000:
Net Income Basic EPS Diluted EPS
-------------- -------------- --------------
In millions (except per share amounts) 2001 2000 2001 2000 2001 2000
---------------------------------------- -------------- -------------- --------------
As Reported $52.7 $72.0 $0.79 $1.18 $0.79 $1.17
Add: goodwill amortization - net of tax 3.0 0.5 0.05 0.01 0.05 0.01
----------------------------------------------------------------------------------------------
As adjusted $55.7 $72.5 $0.84 $1.19 $0.84 $1.18
==============================================================================================
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 6
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 Shareholders' Equity.
A summary of the components of and changes in accumulated other comprehensive
income for the past three years follows:
2000 2001 2002
--------------------------- --------------- ----------------
Beginning Changes End Changes End Changes End
of Year During of Year During of Year During of Year
In millions Balance Year Balance Year Balance Year Balance
-------------------------- --------- ------- ------- ------- ------- ------- -------
Unconsolidated affiliates $ - $ 7.5 $ 7.5 $ (1.6) $ 5.9 $ (5.3) $ 0.6
Minimum pension liability
adjustments & other (0.01) 0.01 - (1.8) (1.8) (9.3) (11.1)
-----------------------------------------------------------------------------------------
Accumulated other
comprehensive income $ (0.1) $ 7.6 $ 7.5 $ (3.4) $ 4.1 $(14.6) $(10.5)
=========================================================================================
Accumulated other comprehensive income arising from unconsolidated affiliates is
the Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's
accumulated comprehensive income related to its adoption of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS133) and
continued use of cash flow hedges, including commodity contracts and interest
rate swaps, and the Company's portion of Haddington Energy Partners, LP's
accumulated comprehensive income related to unrealized gains and losses of
"available for sale securities." (See Note 4 for more information on
unconsolidated affiliates.)
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. Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
investments in unconsolidated affiliates (Note 4), income taxes (Note 6),
earnings per share (Note 11), and derivatives (Note 16).
As more fully described in Note 12, the Company applies the intrinsic method
prescribed in APB Opinion 25, "Accounting for Stock Issued to Employees" (APB25)
and related interpretations when measuring compensation expense for its
stock-based compensation plans. The exercise price of stock options awarded
under the Company's stock option plans is equal to the fair market value of the
underlying common stock on the date of grant. Accordingly, no compensation
expense has been recognized for stock option plans. The Company also maintains
restricted stock and phantom stock plans for executives and non-employee
directors that result in stock-based compensation expense recognized in reported
net income. The amount of expense recorded in net income is consistent with
expense that would have been recognized if the Company used the fair value based
method prescribed in SFAS No. 123 "Accounting for Stock-Based Compensation"
(SFAS 123).
Following is the effect on net income and earnings per share as if the fair
value based method prescribed in SFAS 123, as amended by SFAS 148 "Accounting
for Stock-Based Compensation - Transition and Disclosure" had been applied to
the Company's stock- based compensation plans:
Year Ended December 31,
-----------------------------------------------------------------------------------
In millions, except per share amounts 2002 2001 2000
-----------------------------------------------------------------------------------
Net Income:
As reported $ 114.0 $ 52.7 $ 72.0
Add: Stock-based employee compensation included
in reported net income- net of tax 1.3 1.7 1.8
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards- net of tax 2.1 2.8 2.2
-----------------------------------------------------------------------------------
Pro forma $ 113.2 $ 51.6 $ 71.6
===================================================================================
Basic Earnings Per Share:
As reported $ 1.69 $ 0.79 $ 1.18
Pro forma 1.68 0.77 1.17
Diluted Earnings Per Share:
As reported $ 1.68 $ 0.79 $ 1.17
Pro forma 1.67 0.77 1.16
M. 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 $10.9 million after tax, or $0.16 per
share, 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
$2.6 million ($1.6 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 $0.6 million ($0.3 million after tax). The impact of
the restatement of results for the year ended 2000 is a reduction to net income
of less than $100,000.
In addition, the Company also reduced previously reported revenues and cost of
sales by $78.1 million in 2001 and $15.5 million in 2000 to adopt EITF Issue No.
99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" and to
properly eliminate certain transactions in consolidation.
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 shareholders' 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 $1.4 million and $0.9 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
$2.3 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. 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 $46.4 million of prepaid and other current assets with a
corresponding increase in accrued liabilities 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.
The Company has restated its financial statements to give effect to the matters
discussed above. Following is a summary of the significant effects of the
restatement on previously reported financial position and results of operations.
The effects of the restatement on 2001 quarterly results and on 2002 previously
reported quarterly information, is discussed in Note 21. Note 21 is unaudited.
The effects on the income statement for the year ending December 31, 2001
follow:
As Reported Adjustments As Restated
-----------------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $ 1,031.5 $ (11.9) $ 1,019.6
Electric utility 378.9 2.3 381.2
Energy services & other 759.6 (78.6) 681.0
----------------------------------------------------------------------------------
Total operating revenues 2,170.0 (88.2) 2,081.8
----------------------------------------------------------------------------------
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
Cost of energy services & other 720.2 (79.3) 640.9
Other operating 236.9 6.3 243.2
Merger & integration costs 2.8 - 2.8
Restructuring costs 19.0 - 19.0
Depreciation & amortization 123.7 0.4 124.1
Taxes other than income taxes 53.5 0.2 53.7
----------------------------------------------------------------------------------
Total operating expenses 2,030.4 (76.5) 1,953.9
----------------------------------------------------------------------------------
OPERATING INCOME 139.6 (11.7) 127.9
----------------------------------------------------------------------------------
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 14.1 (0.7) 13.4
Other - net 16.3 0.4 16.7
----------------------------------------------------------------------------------
Total other income 30.4 (0.3) 30.1
----------------------------------------------------------------------------------
Interest expense 82.6 0.6 83.2
----------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 87.4 (12.6) 74.8
----------------------------------------------------------------------------------
Income taxes 18.6 (4.5) 14.1
Minority interest in and preferred dividend
requirement of subsidiaries 1.4 - 1.4
----------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 67.4 (8.1) 59.3
----------------------------------------------------------------------------------
Extraordinary loss - net of tax (7.7) - (7.7)
Cumulative effect of change in accounting
principle - net of tax 3.9 (2.8) 1.1
----------------------------------------------------------------------------------
NET INCOME $ 63.6 $ (10.9) $ 52.7
==================================================================================
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ (0.12) $ 0.89
Extraordinary loss - net of tax (0.12) - (0.12)
Cumulative effect of change in accounting
principle - net of tax 0.06 (0.04) 0.02
----------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ (0.16) $ 0.79
==================================================================================
DILUTED
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ (0.12) $ 0.89
Extraordinary loss - net of tax (0.12) - (0.12)
Cumulative effect of change in accounting
principle - net of tax 0.06 (0.04) 0.02
----------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ (0.16) $ 0.79
==================================================================================
The effects on the income statement for the year ending December 31, 2000
follow:
As Reported Adjustments As Restated
------------------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $ 818.8 $ 1.6 $ 820.4
Electric utility 336.4 (2.0) 334.4
Energy services & other 493.5 (15.5) 478.0
------------------------------------------------------------------------------------
Total operating revenues 1,648.7 (15.9) 1,632.8
------------------------------------------------------------------------------------
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
Cost of energy services & other 468.8 (15.6) 453.2
Other operating 199.4 (0.9) 198.5
Merger & integration costs 41.1 - 41.1
Depreciation & amortization 105.7 - 105.7
Taxes other than income taxes 38.0 - 38.0
------------------------------------------------------------------------------------
Total operating expenses 1,517.6 (16.5) 1,501.1
------------------------------------------------------------------------------------
OPERATING INCOME 131.1 0.6 131.7
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 9.8 - 9.8
Other - net 23.7 (0.6) 23.1
------------------------------------------------------------------------------------
Total other income 33.5 (0.6) 32.9
------------------------------------------------------------------------------------
Interest expense 56.4 - 56.4
------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 108.2 - 108.2
------------------------------------------------------------------------------------
Income taxes 34.2 - 34.2
Minority interest in & preferred dividend
requirements of subsidiaries 2.0 - 2.0
------------------------------------------------------------------------------------
NET INCOME $ 72.0 $ - $ 72.0
====================================================================================
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.18 $ - $ 1.18
====================================================================================
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.17 $ - $ 1.17
====================================================================================
The effects on the balance sheet as of December 31, 2001 follow:
ASSETS As Reported Adjustments As Restated
----------- ----------- -----------
Current Assets
Cash & cash equivalents $ 27.2 $ (2.2) $ 25.0
Accounts receivable-less reserves 213.8 (5.5) 208.3
Accrued unbilled revenues 78.4 (1.7) 76.7
Inventories 71.4 (0.5) 70.9
Recoverable fuel & natural gas costs 76.5 (6.3) 70.2
Prepayments & other current assets 103.4 27.6 131.0
----------------------------------------------------------------------------------
Total current assets 570.7 11.4 582.1
----------------------------------------------------------------------------------
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 127.7 0.9 128.6
Other investments 100.3 (0.5) 99.8
Non-utility property-net 181.7 1.1 182.8
Goodwill-net 193.1 8.4 201.5
Regulatory assets 61.4 6.4 67.8
Other assets 26.9 (8.7) 18.2
----------------------------------------------------------------------------------
TOTAL ASSETS $2,856.8 $ 21.9 $ 2,878.7
==================================================================================
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 144.4 $ 0.8 $ 145.2
Accounts payable to affiliated companies 37.2 0.9 38.1
Accrued liabilities 101.4 17.1 118.5
Short-term borrowings 381.7 1.6 383.3
Current maturities of long-term debt 1.3 - 1.3
Long-term debt subject to tender 11.5 - 11.5
----------------------------------------------------------------------------------
Total current liabilities 677.5 20.4 697.9
----------------------------------------------------------------------------------
Long-term Debt-Net of Current Maturities &
Debt Subject to Tender 1,014.0 - 1,014.0
Deferred Income Taxes & Other Liabilities
Deferred income taxes 206.7 9.6 216.3
Deferred credits & other liabilities 108.1 1.2 109.3
----------------------------------------------------------------------------------
Total deferred credits & other
liabilities 314.8 10.8 325.6
----------------------------------------------------------------------------------
Minority Interest in Subsidiary 1.4 - 1.4
Cumulative, Redeemable Preferred Stock
of a Subsidiary 0.5 - 0.5
Common Shareholders' Equity
Common stock (no par value) 346.1 - 346.1
Retained earnings 498.3 (9.2) 489.1
Accumulated other comprehensive income 4.2 (0.1) 4.1
----------------------------------------------------------------------------------
Total common shareholders' equity 848.6 (9.3) 839.3
----------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $2,856.8 $ 21.9 $ 2,878.7
==================================================================================
4. Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates where the Company has significant
influence are accounted for using the equity method of accounting. The Company's
share of net income or loss from these investments is recorded in equity in
earnings of unconsolidated affiliates. Dividends are recorded as a reduction of
the carrying value of the investment when received. Investments in
unconsolidated affiliates where the Company does not have significant influence
are accounted for using the cost method of accounting less write-downs for
declines in value judged to be other than temporary. Dividends are recorded as
other-net when received. Investments in unconsolidated affiliates consist of the
following:
At December 31,
-------------------------------------------------------------------------------
In millions 2002 2001
-------------------------------------------------------------------------------
ProLiance Energy, LLC $ 61.4 $ 25.6
Haddington Energy Partnerships 19.7 26.8
Reliant Services, LLC 18.4 20.6
Utilicom Networks, LLC & related entities 15.4 14.5
Pace Carbon Synfuels, LP 6.8 7.2
Other partnerships & corporations 31.6 33.9
-------------------------------------------------------------------------------
Total investments in unconsolidated affiliates $ 153.3 $ 128.6
===============================================================================
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.
Pre-tax income of $19.1 million, $12.8 million and $5.4 million was recognized
as ProLiance's contribution to earnings for the years ended December 31, 2002,
2001, and 2000, respectively. Earnings recognized from ProLiance are included in
equity in earnings of unconsolidated affiliates.
Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001 Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member. Since
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. The transfer of net assets was
accounted for at book value consistent with joint venture accounting and did not
result in any gain or loss. Additionally, the non-cash component of the transfer
totaling $17.2 million is excluded from the Consolidated Statement of Cash
Flows.
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, the Company made refunds
to Indiana Gas' retail customers pursuant to the settlement totaling $6.4
million and reimbursed other costs to parties involved in the settlement
totaling $1.1 million. Payments were made in the fourth quarter of 2002. At
December 31, 2001, the Company had established a reserve specific to this GCA
proceeding totaling $5.2 million which was recorded throughout the GCA
proceeding as a reduction of ProLiance's contribution to the Company's earnings.
The amount of the settlement in excess of that accrued prior to 2002 totaling
$2.3 million was reflected as a reduction of ProLiance's contribution to
earnings in 2002.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2002, 2001, and 2000 totaled $544.1 million, $610.6
million, and $478.9 million, respectively. Amounts owed to ProLiance at December
31, 2002 and 2001 for those purchases were $84.6 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.
Summarized Financial Information
For the year ended December 31, 2002, revenues, margin, operating income, and
net income were (in millions) $1,534.5, $61.1, $36.5, and $37.4, respectively.
For the year ended December 31, 2001, revenues, margin, operating income, and
net income were (in millions) $1,599.5, $40.9, $26.1, and $27.7, respectively.
For the year ended December 31, 2000, revenues, margin, operating income, and
net income were (in millions) $945.8, $21.1, $10.4, and $12.1, respectively. As
of December 31, 2002, current assets, noncurrent assets, current liabilities,
and non current liabilities were (in millions) $301.6, $22.8, $228.8, and $1.2,
respectively. As of December 31, 2001, current assets, noncurrent assets,
current liabilities, and noncurrent liabilities were (in millions) $206.8,
$24.3, $180.8, and zero, respectively.
Haddington Energy Partnerships
The Company has an approximate 40% ownership interest in Haddington Energy
Partners, LP (Haddington I). Haddington I raised $27.0 million to invest in
energy projects. In July 2000, the Company made a commitment to fund an
additional $20.0 million in Haddington Energy Partners II, LP (Haddington II),
which raised a total of $47.0 million in firm commitments. Haddington II
provides additional capital for Haddington I portfolio companies and made
investments in new areas, such as distributed generation, power backup and
quality devices, and emerging technologies such as microturbines and
photovoltaics. At December 31, 2002, $11.0 million of the additional $20.0
million commitment remains. The Company has an approximate 40% ownership
interest in Haddington II. Both Haddington ventures are investment companies
accounted for using the equity method of accounting. For the year ended December
31, 2001, the partnerships' contribution to the Company's pre-tax earnings was
$6.2 million. In 2000 and 2002, the earnings contribution was not significant.
The following is summarized financial information as to the assets, liabilities,
and results of operations of the Haddington Partnerships. For the year ended
December 31, 2002 revenues, operating income, and net income were (in millions)
zero, ($0.9), and ($0.9), respectively. For the year ended December 31, 2001
revenues, operating income, and net income were (in millions) $23.6, $22.5, and
$22.5, respectively. For the year ended December 31, 2000 revenues, operating
income, and net income were (in millions) zero, ($0.9), and ($0.9),
respectively. As of December 31, 2002, investments, other assets, and
liabilities were (in millions) $49.6, $0.3, and zero, respectively. As of
December 31, 2001, investments, other assets, and liabilities were (in millions)
$79.1, $5.0, and $0.2, respectively.
Utilicom Networks, LLC & Related Entities
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has a minority interest and a convertible
subordinated debt investment in Utilicom. The Company also has a minority
interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to
hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for its
investments in Utilicom and Holdings using the cost method of accounting.
SIGECOM provides broadband services to the greater Evansville, Indiana, area.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana, and Dayton, Ohio, markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
are still interested in the Indianapolis and Dayton markets, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
In January 2000, the Company restructured its investment in SIGECOM. Affiliates
of The Blackstone Group acquired a majority ownership interest in Utilicom. In
connection with The Blackstone Group investment, the Company exchanged its 49%
preferred equity interest in SIGECOM for $16.5 million of convertible
subordinated debt of Utilicom and an 18.9% common equity interest in Holdings,
which was valued at $6.5 million. The carrying value of the Company's 49%
preferred equity interest was $15.0 million prior to the exchange. The Company
received consideration in the exchange based upon an investment bank analysis of
the fair value of SIGECOM at the transaction date. The investment restructuring
resulted in a pre-tax gain of $8.0 million, which is classified in equity in
earnings in unconsolidated affiliates in the accompanying Consolidated
Statements of Income.
At December 31, 2002, the Company has $30.7 million of notes receivable from
Utilicom-related entities which are convertible into equity interests. Notes
receivable totaling $28.6 million are convertible into Utilicom ownership at the
Company's option or upon the event of a public offering of stock by Utilicom,
and $2.1 million are convertible into common equity interests in the
Indianapolis and Dayton ventures at the Company's option. Upon conversion, the
Company would have up to a 12% interest in Utilicom, assuming completion of all
required funding and up to a 31% interest in the Indianapolis and Dayton
ventures. Investments in convertible notes receivable are included in other
investments.
At December 31, 2002 and 2001, the Company's combined investment in equity and
debt securities of Utilicom-related entities totaled $46.1 million and $39.3
million, respectively. Other than the $8.0 million gain discussed above, these
investments had no significant impact on the Company's financial results in
2002, 2001, or 2000.
Pace Carbon Synfuels, LP
Pace Carbon Synfuels, LP (Pace Carbon) is a limited partnership formed to
develop, own, and operate four projects to produce and sell coal-based synthetic
fuel. The Company has an 8.3% interest in Pace Carbon which is accounted for
using the equity method of accounting. Additional investments in Pace Carbon
will be made to the extent Pace Carbon generates Federal tax credits, with any
such additional investments to be funded by these credits. The investment in
Pace Carbon resulted in losses reflected in equity in earnings of unconsolidated
affiliates totaling $6.8 million, $4.5 million, and $2.4 million in 2002, 2001,
and 2000, respectively. The production of synthetic fuel generates IRS Code
Section 29 investment tax credits that are reflected in income taxes. Net
income, including the losses, tax benefits, and tax credits, generated from the
investment in Pace Carbon totaled $6.0 million in 2002, $4.3 million in 2001,
and $2.1 million in 2000.
The following is summarized financial information as to the assets, liabilities,
and results of operations of Pace Carbon. For the year ended December 31, 2002,
revenues, margin, operating income, and earnings were (in millions) $125.6,
($53.1), ($72.6), and ($73.4), respectively. For the year ended December 31,
2001, revenues, margin, operating income, and earnings were (in millions) $86.2,
($25.1), ($44.1), and ($44.8), respectively. For the year ended December 31,
2000, revenues, margin, operating income, and earnings were (in millions) $35.8,
($24.3), ($33.6), and ($34.1), respectively. As of December 31, 2002, current
assets, noncurrent assets, current liabilities, and noncurrent liabilities were
(in millions) $32.7, $44.8, $45.9 and $4.3, respectively. As of December 31,
2001, current assets, noncurrent assets, current liabilities, and noncurrent
liabilities were (in millions) $22.5, $42.0, $18.2, and $8.4, respectively.
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, $37.9 million, and $20.9 million, respectively. Amounts charged by
these affiliates are market based. Amounts owed to unconsolidated affiliates
other than ProLiance totaled $1.8 million and $2.0 million at December 31, 2002
and 2001, respectively, and are included in accounts payable to affiliated
companies in the Consolidated Balance Sheets. Amounts due from unconsolidated
affiliates included in accounts receivable totaled $0.6 million and $0.3
million, respectively, at December 31, 2002 and 2001.
5. Other Investments
Other investments consist of the following:
At December 31,
-----------------------------------------------------------------------------
In millions 2002 2001
-----------------------------------------------------------------------------
Notes receivable:
Utilicom Networks, LLC & related entities $ 30.7 $ 24.8
Other notes receivable 41.8 31.3
-----------------------------------------------------------------------------
Total notes receivable 72.5 56.1
-----------------------------------------------------------------------------
Leveraged leases 30.5 29.7
Other investments 21.3 14.0
-----------------------------------------------------------------------------
Total other investments $ 124.3 $ 99.8
=============================================================================
Notes Receivable
Interest rates on the above notes receivable range from fixed rates of 5% to 12%
or variable rates based on prime and are due at various times through 2017.
Generally, first or second mortgages and/or capital stock or partnership units
serve as collateral for the notes. (See Note 4 regarding the convertibility of
the Utilicom-related notes into equity interests.)
Leveraged Leases
The Company is a lessor in several leveraged lease agreements under which real
estate or equipment is leased to third parties. The economic lives and lease
terms vary with the leases. The total equipment and facilities cost was
approximately $76.2 million at both December 31, 2002 and 2001. The cost of the
equipment and facilities was partially financed by non-recourse debt provided by
lenders, who have been granted an assignment of rentals due under the leases and
a security interest in the leased property, which they accepted as their sole
remedy in the event of default by the lessee. Such debt amounted to
approximately $51.7 million and $54.3 million at December 31, 2002 and 2001,
respectively. The Company's net investment in leveraged leases follows:
At December 31,
------------------------------------------------------------------------------
In millions 2002 2001
------------------------------------------------------------------------------
Minimum lease payments receivable $ 48.6 $ 48.9
Estimated residual value 22.0 22.1
Less: Unearned income 40.1 41.3
------------------------------------------------------------------------------
Leveraged lease investments 30.5 29.7
Less: Deferred taxes arising from leveraged leases 26.3 25.4
------------------------------------------------------------------------------
Net investment in leveraged leases $ 4.2 $ 4.3
==============================================================================
In June 2001, the Company sold certain leveraged lease investments with a net
book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax).
Because of the transaction's significance and because the transaction occurred
within two years of the effective date of the merger of Indiana Energy and
SIGCORP, which was accounted for as a pooling-of-interests, APB 16 requires the
loss on disposition of these investments to be treated as extraordinary.
Proceeds from the sale totaled $46.7 million.
6. Income Taxes
The components of income tax expense and utilization of investment tax credits
follow:
Year Ended December 31,
------------------------------------------------------------------------------
In millions 2002 2001 2000
------------------------------------------------------------------------------
Current:
Federal $ 62.2 $ (2.2) $ 37.1
State 5.2 3.9 2.9
------------------------------------------------------------------------------
Total current taxes 67.4 1.7 40.0
------------------------------------------------------------------------------
Deferred:
Federal (26.2) 14.9 (5.5)
State - (0.2) 2.1
------------------------------------------------------------------------------
Total deferred taxes (26.2) 14.7 (3.4)
------------------------------------------------------------------------------
Amortization of investment tax credits (2.3) (2.3) (2.4)
------------------------------------------------------------------------------
Total income tax expense $ 38.9 $ 14.1 $ 34.2
==============================================================================
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 3.0 3.1
Increase in state income tax rate 1.1 - -
Nondeductible merger costs - - 4.0
Section 29 tax credits (7.0) (9.5) (3.3)
Amortization of investment tax credit (1.5) (3.1) (2.2)
Other tax credits (1.1) (3.6) (3.8)
All other-net (2.4) (2.6) (0.4)
--------------------------------------------------------------------------
Effective tax rate 25.4 % 19.2 % 32.4 %
==========================================================================
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 $ 197.9 $ 215.0
Leveraged leases 26.3 25.4
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 (45.9) (31.3)
Other - net 1.4 (3.1)
----------------------------------------------------------------------------------------
Net noncurrent deferred tax liability 195.5 216.3
----------------------------------------------------------------------------------------
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 $ 203.2 $ 235.4
========================================================================================
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. Through certain of its nonregulated subsidiaries and investments, the
Company also realizes federal income tax credits associated with affordable
housing projects and the production of synthetic fuels. During 2001, tax credit
carryforwards from these operations totaling $5.5 million were utilized.
7. Retirement Plans & Other Postretirement Benefits
Effective July 1, 2000, the SIGCORP and Indiana Energy defined benefit pension
plans, defined contribution retirement savings plans, and postretirement health
care plans and life insurance plans for employees not covered by a collective
bargaining agreement were merged. The merged plans became Vectren plans, and as
a result, the respective plan assets and plan obligations were transferred to
Vectren through cash payment for assets and cash receipt for obligations. These
transfers resulted in no gain or loss.
The defined benefit pension and other postretirement benefit plans which cover
eligible full-time regular employees are primarily noncontributory. The
postretirement health care and life insurance plans are a combination of
self-insured and fully insured plans.
The detailed disclosures of benefit components that follow are based on an
actuarial valuation using a measurement date as of September 30.
A summary of the components of net periodic benefit cost for the three years
ended December 31, 2002 follows:
Pension Benefits Other Benefits
----------------------- ----------------------
In millions 2002 2001 2000 2002 2001 2000
------------------------------------ ----------------------- ----------------------
Service cost $ 5.9 $ 5.9 $ 4.3 $ 1.0 $ 1.0 $ 1.3
Interest cost 13.9 13.6 11.7 6.0 5.8 5.9
Expected return on plan assets (15.7) (16.3) (15.9) (0.7) (0.8) (0.8)
Amortization of prior service cost 0.8 0.8 0.2 - - -
Amortization of transitional
obligation (asset) (0.5) (0.6) (0.7) 2.9 3.0 3.7
Amortization of actuarial loss (gain) 0.1 (0.9) (1.1) (0.5) (1.0) (1.5)
Settlement, curtailment, & other
charges (credits) - (1.4) 2.7 - (0.6) -
----------------------------------------------------------------------------------------
Net periodic benefit cost $ 4.5 $ 1.1 $ 1.2 $ 8.7 $ 7.4 $ 8.6
========================================================================================
To calculate the expected return on plan assets, the Company uses an expected
long-term rate of return and the plan assets' market-related value. The fair
market value of the assets at the measurement date is adjusted to a
market-related value by recognizing the change in fair value experienced in a
given year ratably over a five year period.
A reconciliation of the plans' benefit obligations, fair value of plan assets,
funded status, and amounts recognized in the Consolidated Balance Sheets at
December 31, 2002 and 2001 follows:
Pension Benefits Other Benefits
---------------- ---------------
In millions 2002 2001 2002 2001
---------------------------------------------- --------------- ---------------
Benefit Obligation
Benefit obligation at beginning of year $191.3 $167.0 $ 83.6 $ 77.4
Service cost - benefits earned during the year 5.9 5.9 1.0 1.0
Interest cost on projected benefit obligation 13.9 13.6 6.0 5.8
Plan amendments (0.1) 9.5 - -
Settlements & (curtailments) - (1.5) - (0.6)
Benefits paid (12.1) (13.5) (8.7) (1.7)
Actuarial (gain) loss 3.0 10.3 (0.4) 1.7
-----------------------------------------------------------------------------------
Benefit obligation at end of year $201.9 $191.3 $ 81.5 $ 83.6
===================================================================================
Fair Value of Plan Assets
Plan assets at fair value at beginning of year $160.1 $193.8 $ 8.8 $ 11.2
Actual return on plan assets (10.1) (20.9) (0.5) (1.6)
Employer contributions 0.7 0.7 7.8 0.9
Benefits paid (12.1) (13.5) (8.7) (1.7)
-----------------------------------------------------------------------------------
Fair value of plan assets at end of year $138.6 $160.1 $ 7.4 $ 8.8
===================================================================================
Funded status $(63.3) $(31.2) $(74.1) $(74.8)
Company contributions after measurement date 0.2 - 1.5 -
Unrecognized transitional obligation (asset) (0.4) (0.8) 32.0 34.9
Unrecognized service cost 11.0 12.0 - -
Unrecognized net (gain) loss and other 42.2 13.4 (11.6) (13.0)
-----------------------------------------------------------------------------------
Net amount recognized $(10.3) $ (6.6) $(52.2) $(52.9)
===================================================================================
Net amount recognized included in:
Deferred credits & other liabilities $(15.2) $(13.0) $(52.2) $(52.9)
Other assets 4.9 6.4 - -
In addition to the pension liability above, at December 31, 2002 and 2001, the
Company incurred additional minimum pension liabilities totaling $30.0 million
and $7.3 million, respectively, which are also included in deferred credits and
other liabilities. These liabilities are offset by intangible assets totaling
$10.5 and $3.5 million, respectively, which are included in other noncurrent
assets, and accumulated other comprehensive income totaling $19.5 ($11.6 million
after tax) and $3.8 million ($2.4 million after tax).
As of December 31, 2002 and 2001, pension plans with accumulated benefit
obligations in excess of plan assets had projected benefit obligations of $201.9
million and $96.7 million, respectively. Those plans had accumulated benefit
obligations of $179.1 million and $84.5 million, respectively. The fair value of
plan assets for such pension plans as of December 31, 2002 and 2001 was $138.6
million and $73.9 million, respectively.
Weighted-average assumptions used to develop annual costs and the benefit
obligation for these plans are as follows:
At & Year Ended December 31,
------------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------- -------------------
2002 2001 2002 2001
-------------------------------- ---------------- -------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets
before expenses 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase 4.25% 4.75% 4.25% 4.75%
CPI rate N/A N/A 10.00% 12.00%
------------------------------------------------------------------------------
As of December 31, 2002, the health care cost trend rate is 10% declining to 5%
in 2006 and remaining level thereafter. Future changes in health care costs,
work force demographics, interest rates, or plan changes could significantly
affect the estimated cost of these future benefits.
A 1% change in the assumed health care cost trend rate for the postretirement
health care plans would have the following effects as of and for the year ended
December 31, 2002:
In millions 1% Increase 1% Decrease
-------------------------------------------------------------------------------
Effect on the aggregate of the service &
interest cost components $ 0.5 $ (0.4)
Effect on the postretirement benefit
obligation 5.6 (4.7)
-------------------------------------------------------------------------------
The Company has adopted Voluntary Employee Beneficiary Association Trust
Agreements for the partial funding of postretirement health benefits for
retirees and their eligible dependents and beneficiaries. Annual funding is
discretionary and is based on the projected cost over time of benefits to be
provided to covered persons consistent with acceptable actuarial methods. To the
extent these postretirement benefits are funded, the benefits are not
liabilities in these consolidated financial statements.
The Company also has defined contribution retirement savings plans that are
qualified under sections 401(a) and 401(k) of the Internal Revenue Code. During
2002, 2001, and 2000, the Company made contributions to these plans of $3.0
million, $3.4 million, and $1.6 million, respectively.
8. 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
-------------------------------------------------------------------------------
Vectren Capital Corp.
Private Placement Fixed Rate Senior Unsecured Notes
2005, 7.67% 38.0 38.0
2007, 7.83% 17.5 17.5
2010, 7.98% 22.5 22.5
2012, 7.43% 35.0 35.0
-------------------------------------------------------------------------------
Total Vectren Capital Corp. 113.0 113.0
-------------------------------------------------------------------------------
Total long-term debt outstanding 1,024.9 1,031.4
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 4.6
-------------------------------------------------------------------------------
Total long-term debt-net $ 954.2 $1,014.0
===============================================================================
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 16) totaled $344.0 million.
Vectren Capital Corp.
In December 2000, Vectren Capital Corp (Cap Corp), a wholly owned consolidated
subsidiary that provides financing for the Company's nonregulated operations and
investments, issued $78.0 million of private placement unsecured senior notes to
three institutional investors. The issues and terms are $38.0 million at 7.67%,
due December 2005; $17.5 million at 7.83%, due December 2007; and $22.5 million
at 7.98%, due December 2010. The issues have no sinking fund requirements. The
net proceeds totaled $77.4 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 which may be put to the Company 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, $38.0 in 2005, zero in 2006, and $24.0 in
2007.
Short-Term Borrowings
At December 31, 2002, the Company has $510.0 million of short-term borrowing
capacity, including $330.0 million for its regulated operations and $180.0
million for its wholly owned nonregulated and corporate operations, of which
approximately $90.9 million is available for regulated operations and $17.0
million is available for wholly owned nonregulated and corporate operations. The
availability of short-term borrowing is reduced by outstanding letters of credit
totaling $5.2 million, collateralizing nonregulated activities. Subsequent to
December 31, 2002, the Company increased its regulated 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 $ 288.8 $ 447.0 $ 316.7
Weighted average interest rates during the year
Bank loans 2.52% 6.77% 6.98%
Commercial paper 2.02% 4.39% 6.53%
At December 31,
---------------------------------------------------------------------
In millions 2002 2001
---------------------------------------------------------------------
Bank loans $ 157.8 $ 107.2
Commercial paper 239.1 273.3
Other 2.6 2.8
---------------------------------------------------------------------
Total short-term borrowings $ 399.5 $ 383.3
=====================================================================
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.
Ratings Triggers
Cap Corp's $113.0 million senior unsecured notes are subject to ratings trigger
provisions that would provide that the full balance outstanding is subject to
prepayment if the ratings of Indiana Gas or SIGECO declined to BBB/Baa2. In
addition, accrued interest and a make whole amount based on the discounted value
of the remaining payments due on the notes would also become payable. Ratings
triggers on Cap Corp's bank loans and VUHI's commercial paper back up facility
existing at December 31, 2001 were removed as facilities were renewed during
2002. Effective January 1, 2003, the Company transferred certain assets that
primarily support the regulated operations from other wholly owned subsidiaries
to VUHI. This transfer of assets will take advantage of greater borrowing
capacity available to the regulated segment and will make the nonregulated and
corporate capacity available to support those operations. The Company is
currently exploring expanding unutilized capacity under its nonregulated
short-term borrowing facilities for additional liquidity protection.
Debt Guarantees
Vectren Corporation guarantees Cap Corp's long-term and short-term debt, which
totaled $113.0 million and $157.8 million, respectively, at December 31, 2002.
VUHI's currently outstanding long-term and short-term debt is jointly and
severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and
short-term debt outstanding at December 31, 2002 totaled $350.0 million and
$239.1 million, respectively.
9. Cumulative Preferred Stock of 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.
10. Common Shareholders' Equity
In March 2000, the merger of Indiana Energy and SIGCORP with and into Vectren
was consummated with a tax-free exchange of shares and has been accounted for as
a pooling of interests. The common shareholders of SIGCORP received 1.333 shares
of Vectren common stock for each SIGCORP common share and the common
shareholders of Indiana Energy received one share of Vectren common stock for
each Indiana Energy common share, resulting in the issuance of 61.3 million
shares of Vectren common stock.
In January 2001, the Company 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 totaled 129.4 million.
Authorized, Reserved Common and Preferred Shares
At December 31, 2002 and 2001 the Company was authorized to issue 480.0 million
shares of common stock and 20.0 million shares of preferred stock. Of the
authorized common shares, approximately 7.3 million shares at December 31, 2002
and 7.5 million shares at December 31, 2001 were reserved by the Board of
Directors for issuance through the Company's stock-based incentive plans and
benefit plans. At both December 31, 2002 and 2001 there were 404.8 million
authorized shares of common stock and all authorized preferred stock available
for a variety of general corporate purposes, including future public offerings
to raise additional capital and for facilitating acquisitions.
Shareholder Rights Agreement
The Company's board of directors has adopted a Shareholder Rights Agreement
(Rights Agreement). As part of the Rights Agreement, the board of directors
declared a dividend distribution of one right for each outstanding Vectren
common share. Each right entitles the holder to purchase from Vectren one share
of common stock at a price of $65.00 per share (subject to adjustment to prevent
dilution). The rights become exercisable 10 days following a public announcement
that a person or group of affiliated or associated persons (Vectren Acquiring
Person) has acquired beneficial ownership of 15% or more of the outstanding
Vectren common shares (or a 10% acquirer who is determined by the board of
directors to be an adverse person), or 10 days following the announcement of an
intention to make a tender offer or exchange offer the consummation of which
would result in any person or group becoming a Vectren Acquiring Person. The
Vectren Shareholder Rights Agreement expires October 21, 2009.
11. Earnings Per Share
Basic earnings per share is computed by dividing net income available to common
shareholders by the weighted-average number of common shares outstanding for the
period. Diluted earnings per share assumes the conversion of stock options into
common shares and the lifting of restrictions on issued restricted shares using
the treasury stock method to the extent the effect would be dilutive. The
following table illustrates the basic and dilutive earnings per share
calculations for the three years ended December 31, 2002:
2002 2001 2000
---------------------- ---------------------- ----------------------
Per Per Per
In millions, except Share Share Share
per share amounts Income Shares Amount Income Shares Amount Income Shares Amount
------------------- ------ ------ ------ ------ ------ ------ ------ ------ ------
Basic EPS $114.0 67.6 $ 1.69 $52.7 66.7 $0.79 $72.0 61.3 $ 1.18
Effect of dilutive
stock equivalents 0.3 0.2 0.1
--------------------------------------------------------------------------------------------
Diluted EPS $114.0 67.9 $ 1.68 $52.7 66.9 $0.79 $72.0 61.4 $ 1.17
============================================================================================
Options to purchase 87,963 shares of common stock for the year ended December
31, 2002, 836,688 shares of common stock for the year ended December 31, 2001,
and 526,469 shares of common stock for the year ended December 31, 2000 were not
included in the computation of dilutive earnings per share because the options'
exercise price was greater than the average market price of a share of common
stock during the period. Exercise prices for options excluded from the
computation ranged from $24.05 to $25.59 in 2002; $22.54 to $24.05 in 2001; and
$19.83 to $24.05 in 2000.
12. Stock-Based Incentive Plans
The Company has various stock-based incentive plans to encourage employees and
non-employee directors to remain with the Company and to more closely align
their interest with those of the Company's shareholders.
Stock Option Plans
A summary of the status of the Company's stock option plans for the past three
years follows:
Wtd. Avg.
Exercise
Options Price
-------------------------------------------------------------------------
Outstanding at January 1, 2000 931,004 $ 18.33
Cancelled (30,955) 19.04
Exercised (40,608) 15.92
--------------------------------------------------------------------------
Outstanding at December 31, 2000 859,441 18.41
Granted 783,999 22.54
Cancelled (92,953) 21.84
Exercised (122,709) 16.05
-------------------------------------------------------------------------
Outstanding at December 31, 2001 1,427,778 20.67
Granted 71,374 23.51
Cancelled (3,000) 22.54
Exercised (146,890) 14.51
--------------------------------------------------------------------------
Outstanding at December 31, 2002 1,349,262 21.48
==========================================================================
In January 2003, 384,500 options to purchase shares of common stock at an
exercise price of $23.19 were issued to management. The grant vests over three
years.
Certain SIGCORP employees held options to purchase SIGCORP common shares. When
the merger of SIGCORP and Indiana Energy was consummated, each granted and
outstanding option to purchase SIGCORP common shares was converted into an
option to purchase the number of Vectren common shares that could have been
purchased under the original option multiplied by one and one-third. The
exercise price per Vectren common share under the new option is equal to the
original per share price divided by one and one-third. The new Vectren options
are otherwise subject to the same terms and conditions as the original SIGCORP
options. Accordingly, the conversion resulted in no compensation expense.
Stock options granted in 2001 and 2002 become fully vested and exercisable at
the end of five years for stock options issued to employees and one year for
non-employee directors. Stock options granted prior to 2001 generally vest and
become exercisable between one and three years in equal annual installments
beginning one year after the grant date and are all vested as of December 31,
2002. Options granted both before and after 2001 generally expire ten years from
the date of grant.
The fair value of each option granted used to determine pro forma net income as
disclosed in Note 2, is estimated as of the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for grants in the years ended December 31, 2002 and 2001:
risk-free rate of return of 3.80% and 5.65%, respectively; expected option term
of 8 years for both years; expected volatility of 26.44% and 26.56%,
respectively; and dividend yield of 4.65% and 4.42%, respectively. The weighted
average fair value of options granted in 2002 and 2001 were $4.33 and $5.21,
respectively. No options were granted in 2000.
The following table summarizes information about stock options outstanding and
exercisable at December 31, 2002:
Outstanding Exercisable
---------------------------------------- ---------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Range of Remaining Exercise Exercise
Exercise Prices # of Options Contractual Life Price # of Options Price
----------------------------------------------------- -------------------------
$13.82 - $17.44 109,934 2.5 $ 15.46 109,934 $ 15.46
$19.83 - $20.26 336,266 5.8 20.09 336,266 20.09
$22.54 - $25.59 903,062 8.2 22.73 246,088 22.94
-------------------------------------------------------------------------------
Total 1,349,262 7.1 21.48 692,288 20.37
==============================================================================-
As of December 31, 2001 and 2000, stock options that are exercisable and those
options' weighted average exercise prices are 658,221 and $18.47 in 2001; and
781,415 and $18.41 in 2000.
Other Plans
Indiana Energy had a performance-based Executive Restricted Stock Plan for its
principal officers and a Directors' Restricted Stock Plan through which
non-employee directors received a portion of their director fees. Upon
consummation of the merger, the restrictions on each outstanding share of
restricted stock lapsed, and all shares that were issued as restricted stock
were treated as unrestricted shares in the merger exchange. In 2000, the Company
adopted these plans.
A summary of outstanding restricted stock issued through these plans since the
merger and through December 31, 2002 follows:
------------------------------------------------------------------------
Grants in & outstanding at December 31, 2000 194,884
------------------------------------------------------------------------
Grants 4,257
Forfeitures (19,726)
Vested (1,302)
------------------------------------------------------------------------
Outstanding at December 31, 2001 178,113
------------------------------------------------------------------------
Grants 66,831
Vested (4,257)
------------------------------------------------------------------------
Outstanding at December 31, 2002 240,687
========================================================================
For the years ended December 31, 2002, 2001, and 2000, the weighted average fair
value per share of restricted stock granted was $23.10, $22.54, and $19.90,
respectively. In January 2003, 93,000 restricted shares with a fair value per
share of $23.19 were issued to management. Those shares vest in 2006.
Executives and non-employee directors may defer certain portions of their
salary, annual bonus, incentive compensation, and earned stock-based incentives
into phantom stock units. Such units are vested when granted.
Compensation expense associated with the restricted stock and phantom stock
plans for the years ended December 31, 2002, 2001, and 2000 was $2.1 million,
$2.8 million, and $2.9 million, respectively. Approximately $2.3 million of
compensation expense for the year ended December 31, 2000 is for the lifting of
restrictions triggered by the merger transaction.
13. Commitments & Contingencies
Commitments
Future minimum lease payments required under operating leases that have initial
or remaining noncancelable lease terms in excess of one year during the five
years following 2002 and thereafter (in millions) are $6.8 in 2003, $6.3 in
2004, $5.0 in 2005, $4.5 in 2006, $4.0 in 2007, and $4.7 thereafter. Total lease
expense (in millions) was $7.3 in 2002, $6.2 in 2001, and $3.4 in 2000.
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.
Other Guarantees
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees may include posted letters of credit, debt and leasing guarantees,
performance guarantees, and energy saving guarantees and may periodically
include the debt of and performance obligations of unconsolidated affiliates.
The Company estimates these guarantees totaled approximately $117 million at
December 31, 2002, including outstanding letters of credit discussed in Note 8.
The Company's most significant guarantee approximating $60 million represents
two-thirds of Energy Systems Group, LLC's (ESG) surety bonds, performance
guarantees, and energy savings guarantees. ESG is a two-thirds owned
consolidated subsidiary. The guarantees relate to amounts due to various
insurance companies for surety bonds should ESG default on obligations to
complete construction, pay vendors or subcontractors, or to achieve energy
guarantees. Through December 31, 2002, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
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 14 regarding the Clean
Air Act.
14. 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.
15. 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.
16. 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, natural gas, coal, and other commodity prices. Other
commodity operations include sales of electricity to certain municipalities and
large industrial customers and nonregulated retail gas marketing and coal mining
operations.
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, natural gas, and coal, to meet customer
demands and operational needs. These operations also enter into forward and
option 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 stored inventory, insurance contracts, and
offsetting forward purchase contracts. In addition, price risk also results from
forward contracts to purchase commodities to fulfill forecasted sales
transactions that may, or may not, occur.
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. Credit risk associated with certain
investments is also managed by a review of creditworthiness and receipt of
collateral.
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. Contracts recorded by nonregulated operations related to the delivery
or receipt of natural gas or coal are included in energy services and other
revenues or cost of energy services and other revenues, as appropriate. Certain
contracts that purchase commodities for operational needs are recorded when
settled in other operating expenses.
The Company enters into other derivative contracts to hedge certain physical
natural gas positions used in nonregulated operations that are not probable of
physical delivery or receipt. Prior to the adoption of SFAS 133, instruments
hedging commodity price risk were accounted for upon settlement in cost of
energy services and other. 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 recorded to cost of energy
services and other when the underlying transaction occurs. Occasionally,
contracts required to be recorded at market value do not qualify for hedge
accounting and are required to be marked to market directly to cost of energy
services and other. For the years ended December 31, 2002 and 2001, derivative
instruments involving the purchase and sale of other commodities that were not
subject to the "normal" exception as described in SFAS 133 had no significant
impact on the Company's results or financial condition.
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 and other commodity 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. The majority of this
gain results from the Company's non-firm wholesale power marketing operations.
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 $1,024.9 $1,095.3 $ 1,031.4 $ 1,022.4
Short-term borrowings & notes payable 399.5 399.5 383.3 383.3
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.
Periodically, the Company tests its cost method investments and notes receivable
for impairment, which may require their fair value to be estimated. Because of
the customized nature of these investments and lack of a readily available
market, it is not practicable to estimate the fair value of these financial
instruments at specific dates without considerable effort and costs. At December
31, 2002 and 2001, fair value for these financial instruments has not been
estimated.
17. 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 $ 5.7 $ 6.3 $ 6.5
Interest income 4.7 5.7 8.6
Leveraged lease investment income 1.1 4.6 7.7
Other income 4.5 8.9 5.9
Other expense (4.5) (8.8) (5.6)
--------------------------------------------------------------------------
Total other - net $11.5 $16.7 $23.1
==========================================================================
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 46.4
Other prepayments & current assets 17.9 16.9
-------------------------------------------------------------------------
Total prepayments & other current assets $ 93.0 $ 131.0
=========================================================================
Accrued liabilities in the Consolidated Balance Sheets consists of the
following:
At December 31,
--------------------------------------------------------------------------
In millions 2002 2001
--------------------------------------------------------------------------
Accrued taxes $ 47.2 $ 34.0
Refunds to customers & customer deposits 21.0 18.7
Accrued interest 14.0 13.2
Deferred income taxes 7.7 19.1
Accrued salaries & other 30.0 33.5
--------------------------------------------------------------------------
Total accrued liabilities $119.9 $ 118.5
==========================================================================
18. Segment Reporting
The Company had four operating segments during 2002: 1) Gas Utility Services,
(2) Electric Utility Services, (3) Nonregulated Operations, and (4) Corporate
and Other. The Gas Utility Services segment provides natural gas distribution
and transportation services in 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. The Company collectively refers to its gas and electric
utility services segments as its Regulated Operations. The Nonregulated
Operations segment is comprised of various subsidiaries and affiliates offering
and investing in energy marketing and services, coal mining, utility
infrastructure services, and broadband communications among other energy-related
opportunities. The Corporate and Other segment, among other activities, provides
general and administrative support and assets, including computer hardware and
software, to the Company's other operating segments. The Company makes decisions
on finance and dividends at the corporate level. Investments in unconsolidated
affiliates, earnings of those unconsolidated affiliates, and the extraordinary
item recognized in 2001 are primarily within the Nonregulated Operations
segment.
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
------------------------------------------------------------------------------
Total Regulated 1,517.1 1,400.8 1,154.8
------------------------------------------------------------------------------
Nonregulated Operations 352.3 741.8 503.8
Corporate & Other 23.3 29.7 33.6
Intersegment Eliminations (88.4) (90.5) (59.4)
-------------------------------------------------------------------------------
Total operating revenues $1,804.3 $ 2,081.8 $1,632.8
==============================================================================
Interest Expense
Gas Utility Services $ 45.6 $ 51.6 $ 28.0
Electric Utility Services 20.5 18.5 18.1
------------------------------------------------------------------------------
Total Regulated 66.1 70.1 46.1
------------------------------------------------------------------------------
Nonregulated Operations 9.1 12.5 9.6
Corporate & Other 3.5 1.5 1.3
Intersegment Eliminations (0.2) (0.9) (0.6)
------------------------------------------------------------------------------
Total interest expense $ 78.5 $ 83.2 $ 56.4
==============================================================================
Income Taxes
Gas Utility Services $ 18.0 $ (2.0) $ 11.5
Electric Utility Services 26.6 20.4 23.5
------------------------------------------------------------------------------
Total Regulated 44.6 18.4 35.0
------------------------------------------------------------------------------
Nonregulated Operations (6.9) (4.7) 0.6
Corporate & Other 1.2 0.4 (1.4)
------------------------------------------------------------------------------
Total income taxes $ 38.9 $ 14.1 $ 34.2
==============================================================================
Equity in Earnings of
Unconsolidated Affiliates
Gas Utility Services $ 0.1 $ 0.7 $ -
Electric Utility Services (1.9) (1.2) -
------------------------------------------------------------------------------
Total Regulated (1.8) (0.5) -
------------------------------------------------------------------------------
Nonregulated Operations 10.9 13.9 9.8
------------------------------------------------------------------------------
Total equity in earnings of
unconsolidated affiliates $ 9.1 $ 13.4 $ 9.8
==============================================================================
Net Income
Gas Utility Services $ 39.0 $ (2.6) $ 15.7
Electric Utility Services 54.6 42.7 36.8
------------------------------------------------------------------------------
Total Regulated 93.6 40.1 52.5
------------------------------------------------------------------------------
Nonregulated Operations 19.0 12.1 21.8
Corporate & Other 1.4 0.5 (2.3)
------------------------------------------------------------------------------
Net income $ 114.0 $ 52.7 $ 72.0
==============================================================================
Year ended December 31,
------------------------------------------------------------------------------
In millions 2002 2001 2000
------------------------------------------------------------------------------
Depreciation & Amortization
Gas Utility Services $ 56.8 $ 58.5 $ 43.8
Electric Utility Services 40.0 38.7 38.6
------------------------------------------------------------------------------
Total Regulated 96.8 97.2 82.4
------------------------------------------------------------------------------
Nonregulated Operations 8.6 5.9 1.1
Corporate & Other 14.2 21.0 22.2
------------------------------------------------------------------------------
Total depreciation &
amortization $ 119.6 $ 124.1 $ 105.7
==============================================================================
Capital Expenditures
Gas Utility Services $ 63.0 $ 77.8 $ 73.1
Electric Utility Services 88.9 69.8 37.6
------------------------------------------------------------------------------
Total Regulated 151.9 147.6 110.7
------------------------------------------------------------------------------
Nonregulated Operations 28.0 35.0 27.3
Corporate & Other 38.8 57.1 26.3
------------------------------------------------------------------------------
Total capital expenditures $ 218.7 $ 239.7 $ 164.3
==============================================================================
At December 31,
------------------------------------------------------------
In millions 2002 2001
------------------------------------------------------------
Identifiable Assets
Gas Utility Services $1,570.1 $ 1,582.5
Electric Utility Services 869.2 818.4
------------------------------------------------------------
Total Regulated 2,439.3 2,400.9
------------------------------------------------------------
Nonregulated Operations 419.6 466.5
Corporate & Other 393.3 331.9
Intersegment Eliminations (325.7) (320.6)
------------------------------------------------------------
Total identifiable assets $2,926.5 $ 2,878.7
============================================================
19. 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 $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 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 $19.0 million. These charges were comprised of $10.9 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 $4.1 million for consulting and other fees.
The $10.9 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: $10.3
million by the Gas Utility Services segment; $4.8 million by the Electric
Utility Services segment; and $3.9 million by the Nonregulated 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 $8.8 million ($6.8
million for severance and $2.0 million for lease termination fees). Throughout
2001 additional expenses totaling $3.1 million ($2.1 million for severance and
$1.0 million for lease termination fees) were incurred. Cash payments in 2001
totaled $6.8 million, all of which related to severance payments. As of December
31, 2001, the remaining accrual related to the restructuring was $5.1 million.
Of that amount, $2.1 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 $4.2 million ($2.2 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 $41.1 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
Since March 31, 2000, $43.9 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$20.7 million. Of this amount, $5.5 million related to employee and executive
severance costs, $13.1 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. At December 31, 2001, the remaining accrual related to
employee severance was not significant and was entirely utilized in 2002. The
remaining $23.2 million was expensed ($20.4 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, internal labor of
employees assigned to integration teams, investor relations communication
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, resulting in additional depreciation
expense of approximately $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.
20. 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 16. 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.
The incremental disclosure requirements are included in these financial
statements in Note 13. 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.
21. Quarterly Financial Data (Unaudited)
As more fully described in Note 3, the Company has restated the results for the
year ended December 31, 2001, including each quarter, as well as the first three
quarters of 2002 to appropriately account for certain transactions. Provided
below is a comparison of restated summarized quarterly financial data to
summarized quarterly financial data previously reported. Information in any one
quarterly period is not indicative of annual results due to the seasonal
variations common to the Company's utility operations.
Summarized quarterly financial data for 2002 follows:
In millions, except
per share amounts Q1 (5) Q2 (5) (7) Q3 Q4
----------------------- ------------------ ------------------ ------------------ --------
As As As As As As As
Reported Restated Reported Restated Reported Restated Reported
2002 Operating data -------- -------- -------- -------- -------- -------- --------
Operating revenues $ 635.2 $ 630.4 $ 386.9 $ 380.1 $ 304.5 $ 304.3 $ 489.5
Operating income 84.2 82.9 23.6 25.6 32.5 31.5 71.3
Net income 45.6 45.6 14.3 12.5 14.0 13.5 42.4
Earnings per share:
Basic 0.68 0.68 0.21 0.18 0.21 0.20 0.63
Diluted 0.67 0.67 0.21 0.18 0.21 0.20 0.62
Summarized quarterly financial data for 2001 follows:
In millions, except
per share amounts Q1 (1) (5) Q2 (2) (3) (5) Q3 (5) Q4 (5) (6)
------------------------- ------------------ ------------------ ------------------ ------------------
As As As As As As As As
Reported Restated Reported Restated Reported Restated Reported Restated
2001 Operating Data (4) -------- -------- -------- -------- -------- -------- -------- --------
Operating revenues $ 883.9 $ 878.0 $ 433.1 $ 416.1 $ 356.7 $ 336.9 $ 496.3 $ 450.8
Operating income (loss) 73.5 78.2 (3.8) (4.5) 17.4 16.8 52.5 37.4
Income (loss) before
extraordinary loss &
cumulative effect of
change in accounting
principle 40.5 43.8 (10.0) (10.6) 4.5 3.8 32.4 22.3
Earnings (loss) per share
before extraordinary
loss & cumulative
effect of change in
accounting principle:
Basic 0.62 0.66 (0.15) (0.15) 0.07 0.06 0.48 0.33
Diluted 0.61 0.66 (0.15) (0.15) 0.07 0.06 0.48 0.33
Net income (loss) 44.4 44.9 (17.7) (18.3) 4.5 3.8 32.4 22.3
Earnings (loss) per share
Basic 0.68 0.68 (0.26) (0.27) 0.07 0.06 0.48 0.33
Diluted 0.67 0.68 (0.26) (0.27) 0.07 0.06 0.48 0.33
1. Q1 of 2001 includes charges for cumulative effect of changes in accounting
principle as described in Note 16.
2. Q2 of 2001 includes restructuring charges as described in Note 19.
3. Q2 of 2001 includes an extraordinary loss as described in Note 5.
4. 2001 includes merger and integration charges as described in Note 19.
5. The changes in previously reported revenues reflect principal/agent
relationships and the proper elimination of certain transactions upon
consolidation.
6. The benefit clearing adjustment and primarily all of the inventory
adjustment discussed in Note 3 were recorded in the fourth quarter of 2001.
7. 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 shareholders' equity as of January 1, 2000.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Disclosure with respect to this Item, has been previously provided on Form 8-K
originally filed with the SEC on March 26, 2002, as amended on Form 8-K/A filed
with the SEC on May 20, 2002.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Except with respect to information regarding the executive officers of the
Registrant, the information required by Part III, Item 10 of this Form 10-K is
incorporated by reference herein, and made part of this Form 10-K, from the
company's definitive Proxy Statement for its 2003 Annual Meeting of
Stockholders, will be filed with the Securities and Exchange Commission pursuant
to Regulation 14A, not later than 120 days after the end of the fiscal year. The
information with respect to the executive officers of the Registrant is included
below.
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.
Carl L. Chapman, age 47, has served as Executive Vice President of the Company
and President of Vectren Enterprises, Inc. since March 2000. Prior to March 31,
2000 and since 1999, Mr. Chapman served as Executive Vice President and Chief
Financial Officer of Indiana Energy. From October 1997 to June 2002, Mr. Chapman
served as President of IGC Energy, Inc., which has been renamed Vectren Energy
Marketing and Services, Inc. Mr. Chapman served as President of ProLiance
Energy, LLC ("ProLiance"), a gas supply and energy marketing joint venture
partially owned by Vectren Energy Marketing and Services, Inc., an indirect,
wholly-owned subsidiary of the Company, from March 1996, until April 1998.
Currently, Mr. Chapman is the chairman of ProLiance. From 1995 until March 1996,
he was Senior Vice President of Corporate Development for Indiana Gas. Prior to
1995 and since 1987, he was Vice President of Planning for Indiana Gas.
Ronald E. Christian, age 44, has served as Senior Vice President, General
Counsel, 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.
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
Information required by Part III, Item 11 of this Form 10-K is incorporated by
reference herein, and made part of this Form 10-K, from the Company's definitive
Proxy Statement for its 2003 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, not
later than 120 days after the end of the fiscal year.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Except with respect to equity compensation plan information of the Registrant,
the information required by Part III, Item 12 of this Form 10-K is incorporated
by reference herein, and made part of this Form 10-K, from the company's
definitive Proxy Statement for its 2003 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission pursuant to Regulation
14A, not later than 120 days after the end of the fiscal year.
The information with respect to common shares issuable under equity compensation
plans as of December 31, 2002 with respect to the Registrants is included below.
----------------------------------------------------------------------------------------
(a) (b) ( c)
----------------------------------------------------------------------------------------
'Number of Weighted-
securities to be average exercise Number of securities
issued upon price of remaining available
exercise of outstanding for future issuance under
outstanding options, equity compensation plans
options, warrants warrants (excluding securities
Plan category and rights and rights reflected 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
Information required by Part III, Item 13 of this Form 10-K is incorporated by
reference herein, and made part of this Form 10-K, from the Company's definitive
Proxy Statement for its 2003 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, not
later than 120 days after the end of the fiscal year.
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.
The Company has investments in unconsolidated affiliates. As the Company does
not control or manage these affiliates, its disclosure controls and procedures
with respect to them are more limited than the disclosure controls and
procedures maintained within the Company's consolidated subsidiaries.
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.
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 93. 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 95.
Exhibits for the Company attached to this filing filed electronically with
the SEC are listed on page 100.
Reports On Form 8-K During The Last Calendar Quarter
On October 25, 2002 Vectren Corporation filed a Current Report on Form 8-K with
respect to the release of financial information to the investment community
regarding the Company's results of operations, 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 21, 2002, Vectren Corporation filed a Current Report on Form 8-K
with respect to an analyst meeting where a discussion of the Company's current
financial and operating results and plans for the future will occur.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Vectren Annual Analyst Seminar to be
Webcast
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 Corporation 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 (Vectren) 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 Corporation and Subsidiaries
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 $ 5.3 $ 11.7 $ - $ 11.5 $ 5.5
Year 2001 - Accumulated provision for
uncollectible accounts $ 5.1 $ 17.3 $ - $ 17.1 $ 5.3
Year 2000 - Accumulated provision for
uncollectible accounts $ 3.9 $ 7.7 $ 0.1 $ 6.6 $ 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 $ - $ 27.2 $ - $ 25.4 $ 1.8
Year 2002 - Reserve for restructuring
costs $ 5.1 $ - $ - $ 0.9 $ 4.2
Year 2001 - Reserve for restructuring
costs $ - $ 11.9 $ - $ 6.8 $ 5.1
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 CORPORATION
Dated June 17, 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 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.)
2.2 Amendment No.1 to the Merger Agreement dated December 14, 1999 (Filed and
designated in Current Report on Form 8-K filed December 16, 1999, File No.
1-09091, as Exhibit 2.)
2.3 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.)
Articles Of Incorporation And By-Laws
3.1 Amended and Restated Articles of Incorporation of Vectren Corporation
effective March 31, 2000. (Filed and designated in Current Report on Form
8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
3.2 Amended and Restated Code of By-Laws of Vectren Corporation as of February
26, 2003. (Filed and designated in Annual Report on Form 10-K filed March
18, 2003, File No. 1-15467, as Exhibit 3.2.)
3.3 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren
Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and
designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No.
1-15467, as Exhibit 4.)
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
Carl L. Chapman 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 99.4.)
10.37 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.)
10.38 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.)
10.39 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.)
10.40 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.)
10.41 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.)
10.42 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.)
10.43 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.)
10.44 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.
1-15467, as Exhibit 21.1.)
23. Consents Of Experts And Counsel
The consent of Deloitte & Touche LLP is attached hereto as Exhibit 23.1.
99. Additional Exhibits
99.1 Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(Filed Herewith.)
99.2 Chief Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. (Filed Herewith.)
99.3 Chief Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. (Filed Herewith.)
Vectren Corporation
2002 Form 10-K/A
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
See Page 95 of this Amendment to the Annual Report on Form 10-K/A for a complete
list of exhibits.
Exhibit
Number Document
23.1 Consent of Independent Public Accountants
99.1 Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
99.2 Chief Executive Officer Certification Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
99.3 Chief Financial Officer Certification Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.