SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
_ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from__________ to____________
Commission Registrant, State of Incorporation; IRS Employer
File Number Address and Telephone Number Identification No.
----------- ----------------------------------- ------------------
1-15467 Vectren Corporation 35-2086905
(An Indiana Corporation)
20 N. W. Fourth Street
Evansville, Indiana 47708
(812) 491-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
------------------- ------------------------- -----------------------
Vectren Corporation Common- Without Par Value 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) have been subject to such filing
requirements for the past 90 days: Yes X No _
As of March 22, 2002, the aggregate market value of the Common Stock held by
nonaffiliates was $1,642,637,062.
Indicate the number shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Common Stock- Without Par Value 67,726,439 March 22, 2002
------------------------------- ---------- --------------
Class Number of Shares Date
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.
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2002
Annual Meeting of Stockholders, which was filed with the Securities and Exchange
Commission on March 15, 2002, is incorporated by reference in Part III of this
Form 10-K.
Information in the Company's Current Report on Form 8-K, which was filed with
the Securities and Exchange Commission on March 26, 2002, regarding replacement
of the Company's independent auditors, is incorporated by reference in Part I
of this filing.
Table of Contents
Item Page
Number Number
Part I
1 Business ............................................................. 1
2 Properties ........................................................... 8
3 Legal Proceedings..................................................... 9
4 Submission of Matters to Vote of Security Holders..................... 9
Part II
5 Market for the Company's Common Equity
and Related Stockholder Matters .................................... 9
6 Selected Financial Data............................................... 10
7 Management's Discussion and Analysis
of Results of Operations and Financial Condition.................... 12
7A Qualitative and Quantitative Disclosures About Market Risk............ 35
8 Financial Statements and Supplementary Data........................... 37
9 Change in and Disagreements with Accountants on
Accounting and Financial Disclosure................................. 76
Part III
10 Directors and Executive Officers of
the Company......................................................... 76
11 Executive Compensation................................................ 77
12 Security Ownership of Certain Beneficial
Owners and Management............................................... 77
13 Certain Relationships and Related
Transactions........................................................ 77
Part IV
14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................................. 77
Signatures............................................................ 81
Definitions
As discussed in this Form 10-K, the abbreviations Dth means dekatherms, MDth
means thousands of dekatherms, MMDth means millions of dekatherms, MW means
megawatts, MMBTU means millions of British thermal units, kWh means kilowatt
hours, throughput means combined gas sales and gas transportation volumes, and
Mva means megavolt amperes.
PART I
ITEM 1. BUSINESS
Description of the Business
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 Accounting Principles
Board (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
(defined hereafter). 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 311 communities in 49 of Indiana's 92 counties.
SIGECO provides electric generation, transmission, and distribution services to
Evansville, Indiana, and 74 other communities in 8 counties in southwestern
Indiana and participates in the wholesale power market. SIGECO also provides
natural gas distribution and transportation services to Evansville, Indiana, and
64 communities in 10 counties in southwestern Indiana. The Ohio operations
provide natural gas distribution and transportation services to Dayton, Ohio,
and 87 other communities in 17 counties in west central Ohio.
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,
provides fuel supply management, and provides energy performance contracting
services. Coal Mining provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an Internal Revenue Service (IRS) Code Section 29 investment tax credit
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading. Broadband invests in broadband communication services such as
cable television, high-speed Internet, 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 provide supply chain
services, debt collection services, and environmental compliance testing
services.
Acquisition of 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 approximately $465.0 million. The
acquisition has been accounted for as a purchase transaction in accordance with
APB 16, and accordingly, the results of operations of the acquired businesses
are included 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."
Recent Development
On March 26, 2002, the Company filed a Current Report on Form 8-K announcing its
decision to replace Arthur Andersen LLP as its independent auditors effective
upon the completion of a transition period which is expected to extend through
the conclusion of their review of the financial results of the Company for the
first quarter of 2002. This Form 8-K is included in this filing as Exhibit 99.1.
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, 2001, the Company had $2.9 billion in
total assets, with $2.4 billion (83%) attributed to regulated, $0.4 billion
(12%) attributed to nonregulated, and $0.1 billion (5%) attributed to corporate
and other. Net income for the year ended 2001 was $63.6 million, or $0.95 per
share of common stock. Excluding nonrecurring charges with an after-tax impact
of $25.7 million, net income for the year ended 2001 was $89.3 million, or $1.34
per share of common stock, with $65.8 million attributed to regulated, $21.9
million attributed to nonregulated, and $1.6 million attributed to corporate and
other. Nonrecurring items net of tax in 2001 included $8.1 million of merger and
integration costs, $11.8 million of restructuring costs, $7.7 million of
extraordinary loss, and $1.9 million gain on the impact of SFAS 133, including
cumulative effect of change in accounting principle. Excluding nonrecurring
items, net of tax, the results reflect a decrease of $14.6 million or $0.36 per
share, compared to 2000. Nonrecurring items, net of tax, in 2000 included $36.8
million of merger and integration costs and a $4.9 million gain on restructuring
of a nonregulated investment. The operations of the corporate and other business
segment, which include primarily information technology services, are not
significant.
For further information refer to Note 18 regarding the segments' activities and
assets, Note 3 regarding special charges, Note 16 regarding the adoption of and
current year impact of SFAS 133, Note 5 regarding the extraordinary loss, and
Note 4 regarding the gain recognized on restructuring of a nonregulated
investment in the Company's consolidated financial statements included under
Item 8 Financial Statements and Supplementary Data.
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 SIGECO's power supply operations, power
marketing operations, and electric transmission and distribution services, which
operate and maintain six coal-fired electric power plants and five gas-fired
peaking units with a total of 1,271 megawatts of generating capacity to provide
electricity to primarily southwestern Indiana.
Gas Utility Services
Overview
For the year ended December 31, 2001, the Company supplied natural gas service
to 953,214 Indiana and Ohio customers, including 868,685 residential, 80,235
commercial, and 4,294 transportation customers. This represents customer base
growth of nearly 1% compared to 2000.
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, 2001, natural gas revenues were approximately
$1,031.5 million of which residential customers accounted for 66%, commercial
24%, and transportation 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 volume of gas provided to both sales and transportation customers
(throughput) was 199,761 MDth for the year ended December 31, 2001. Transported
gas represented 45% 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 eight
underground gas storage fields, six liquefied petroleum air-gas manufacturing
plants and maintains contract storage. 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
volumes during periods of peak requirements. Approximately 705,000 Dth of gas
per day can be withdrawn during peak demand periods.
Gas Purchases
In 2001, 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 114,503 MDth volumes of gas in 2001 at an
average cost of $5.63 per MDth, of which 87% was purchased from ProLiance. The
cost of gas purchased for the last five years is as follows:
Average Cost
Year of Gas Purchased
---- ----------------
1997 $3.56
1998 $3.53
1999 $3.58
2000 $5.60
2001 $5.63
Regulatory Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment.
Environmental Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding manufactured gas plants.
Electric Utility Services
Overview
The Company supplied electric service to 133,294 Indiana customers (115,770
residential, 17,327 commercial, and 197 industrial) during 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, 2001, electricity sales totaled 9,138,770
megawatt hours, resulting in revenues of approximately $378.9 million.
Residential customers accounted for 25% of 2001 revenues; commercial 20%;
industrial 22%; wholesale 32%; and other 1%.
Generating Capacity
Installed generating capacity as of December 31, 2001 was rated at 1,271
megawatts (MW). Coal-fired generating units provide 1,056 MW of capacity and gas
or oil-fired turbines used for peaking or emergency conditions provide 215 MW.
In addition to its generating capacity, the Company has 82 MW available under
firm contracts and 95 MW available under interruptible contracts. New peaking
capacity of 80 MW is under development and is planned to be available for the
summer peaking season in 2002. This new generating capacity will be fueled by
natural gas.
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 ability to
simultaneously interchange approximately 750 MW.
Total load for each of the years 1997 through 2001 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
Date of Summer Peak Load 7-14-97 7-21-98 7-6-99 8-17-00 7-31-01
------- ------- ------ ------- -------
Total Load at Peak 1,086 1,129 1,230 1,212 1,209
Generating Capability 1,236 1,256 1,256 1,256 1,271
Firm Purchase Supply - - - 75 82
Interruptible Contracts - - 95 95 95
------ ------- ------ ------- -------
Total Power Supply Capacity 1,236 1,256 1,351 1,426 1,448
Reserve Margin at Peak 14% 11% 10% 18% 20%
The winter peak load of the 2000-2001 season of approximately 925 MW occurred on
December 19, 2000 and was 6% higher than the previous winter peak load of
approximately 873 MW which occurred on January 25, 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 that 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
Electric generation for 2001 was fueled by coal (99.6%) and natural gas (0.4%).
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 strip mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.2 million tons of coal was purchased
for generating electricity during 2001. Of this amount, Vectren Fuels, Inc.
supplied 2.6 million tons, of which 1.9 million tons was produced in its coal
mines. The average cost of all coal consumed in generating electrical energy for
the years 1997 through 2001 was as follows:
Average Cost
Average Cost Average Cost Per Kwh
Year Per Ton Per MMBTU (In Mills)
---- ------------ ------------ ------------
1997 20.75 0.91 9.80
1998 21.34 0.94 9.97
1999 21.88 0.96 10.13
2000 22.49 0.98 10.39
2001 22.48 1.00 10.53
Other Operating Matters
The Company participates with 7 other utilities and 31 other affiliated groups
located in 8 states comprising the east central area of the United States, in
the East Central Area Reliability group, the purpose of which is to strengthen
the area's electric power supply reliability. In addition, see Item 7
Management's Discussion and Analysis of Results of Operations and Financial
Condition regarding the Company's participation in the Midwest Independent
System Operator group and regarding the change in operations at the Warrick
Generating Station.
Regulatory Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment.
Environmental Matters
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition for 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
Overview
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,
provides fuel supply management, and provides energy performance contracting
services. Coal Mining provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an IRS Section 29 investment tax credit relating to the production of
coal-based synthetic fuels. Utility Infrastructure Services provides underground
construction and repair, facilities locating, and meter reading. Broadband
invests in broadband communication services such as cable television, high-speed
Internet, and advanced local and long distance phone services. In addition, the
nonregulated group has investments in other businesses that invest in other
energy-related opportunities and provide supply chain services, debt collection
services, and environmental compliance testing services.
Energy Marketing and Services
The Energy Marketing and Services group relies heavily upon a customer focused,
value added strategy. The group provides natural gas, fuel supply management
services, and market intelligence to a broad range of municipalities, utilities,
industrial operations, schools, and healthcare institutions totaling almost
1,000 end-use customers. The group also focuses on performance-based energy
contracting. 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. This group is also a
significant gas supplier to the Company. At December 31, 2001, Energy Marketing
and Services had 984 customers, up from 472 in 1999. Primarily through customer
growth, volumes marketed increased to 393 MMDth in 2001, up from 287 MMDth in
1999.
Energy Marketing and Services includes two gas marketing companies. ProLiance is
an unconsolidated affiliate of the Company and Citizens Gas and Coke Utility.
SIGCORP Energy Services, Inc. is a wholly owned subsidiary of the Company. In
addition, Energy Systems Group, LLC provides energy performance contracting and
facility upgrades through its design and installation of energy-efficient
equipment. Energy Systems Group, LLC is a consolidated venture between the
Company and Citizens Gas, with the Company owning 67%.
Coal Mining
The Coal Mining group provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an IRS Code Section 29 investment tax credit relating to the production
of coal-based synthetic fuels. The Company's two coal mines produced 3.3 million
tons, up from 1.2 million in 2000. Production was boosted as the Company's new
underground mine began operation in the first quarter and produced approximately
1.9 millions tons of high-quality, low sulfur coal.
This group includes wholly owned subsidiaries of the Company, Vectren Fuels,
Inc. and Vectren Synfuels, Inc.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure to the Company and to other gas, water, electric, and
telecommunications companies as well as facilities locating and meter reading.
This group includes Reliant Services, LLC (Reliant), a 50% owned strategic
alliance with Cinergy Corp. Refer to Other Operating Matters in Item 7
Management's Discussion and Analysis of Results of Operations and Financial
Condition regarding Reliant's acquisition of Miller Pipeline Corporation.
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 28,000
residential and commercial customers (an increase of 28% from 2000) in the
greater Evansville area in southern Indiana. The present customer base has
yielded approximately 75,000 revenue generating units (up from approximately
58,000 at the end of 2000) indicating multiple lines and/or services being
utilized by the same customer.
The Company has a 14% interest in Class A units of 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. Utilicom also plans to
provide services to Indianapolis, Indiana, and Dayton, Ohio.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is due to the
current 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 committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded. This delay
necessitated and resulted in the extension of the franchising agreements into
the third quarter of 2002.
Refer to Other Operating Matters in Item 7 Management's Discussion and Analysis
of Results of Operations and Financial Condition for additional information on
the Company's investment in Utilicom.
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,
fuel cells, distributed generation projects, and similar energy-related
businesses. Additional activities include:
X A utility services business, which supplies utilities with a number of
important services ranging from supply chain management to
environmental compliance testing.
X A retail unit, providing natural gas and other related products and
services primarily in Ohio serving customers opting for choice among
energy providers.
X A broadband consulting and construction 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 wholly owned subsidiaries of the Company;
Southern Indiana Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC,
Vectren Communication Services, Inc., and IEI Financial Services, LLC.
Personnel
As of December 31, 2001, the Company and its consolidated subsidiaries had 1,986
employees.
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.
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.
The labor agreement between Indiana Gas, Local Union 1393 of the International
Brotherhood of Electrical Workers and Local Unions 7441 and 12213, United
Steelworkers of America, went into effect in November 1998 for a five year term
expiring on December 2003. The agreement contains a 4% wage increase in 1998 and
3% wage increases each year thereafter during the term of the agreement, in
addition to increased performance incentives, a new sick pay provision and a
simplified pension benefit formula.
ITEM 2. PROPERTIES
Gas Utility Services
Specific to its Indiana operations, Indiana Gas owns and operates five gas
storage fields located in Indiana covering 71,484 acres of land with an
estimated ready delivery from storage capability of 8.0 MMDth of gas with daily
delivery capabilities of 134,160 Dth. For its Indiana operations, Indiana Gas
also maintains 186,578 Dth of gas in contract storage with a daily
deliverability of 3,563 Dth and three liquefied petroleum (propane) air-gas
manufacturing plants in Indiana with a total daily capacity of 31,000 Dth of
gas. Indiana Gas' gas delivery system includes 11,336 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 with an estimated
ready delivery from storage capability of 6.2 MMDth of gas with daily delivery
capabilities of 129,000 Dth. SIGECO's gas delivery system includes 2,921 miles
of distribution and transmission mains all of which are located in Indiana.
The Ohio operations operate three liquefied petroleum (propane) air-gas
manufacturing plants located in Ohio with a total daily capacity of 52,187 Dth,
and approximately 13.9 MMDth of firm storage service from various pipelines with
daily deliverability of 354,788 Dth of gas. The Ohio operations' gas delivery
system includes 5,132 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, 2001 was rated at
1,271 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 Gas Turbine located at the Brown Station; two
Broadway Gas Turbines located in Evansville, Indiana, with a combined capacity
of 115 MW; and two Northeast Gas Turbines located northeast of Evansville in
Vanderburgh County, Indiana with a combined capacity of 20 MW. The Brown and
Broadway Unit 2 turbines are also equipped to burn oil. Total capacity of
SIGECO's five gas turbines is 215 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 828 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,014.2 megavolt amperes (Mva). The electric distribution
system includes 3,205 pole miles of lower voltage overhead lines and 255 trench
miles of conduit containing 1,465 miles of underground distribution cable. The
distribution system also includes 96 distribution substations with an installed
capacity of 1,918.2 Mva and 50,133 distribution transformers with an installed
capacity of 2,284.1 Mva.
The only utility property SIGECO owns outside of Indiana is approximately 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.
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,
as supplemented by various supplemental indentures.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in various legal proceedings
arising in the normal course of business. In the opinion of management, with the
exception of the matters described in Notes 4 and 14 of its consolidated
financial statements included in Item 8 Financial Statements and Supplementary
Data regarding transactions with ProLiance and the Clean Air Act, there are no
legal proceedings pending against the Company that could be material to its
financial position or results of operations.
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." The high and low sales prices for the Company's common stock as
reported on the New York Stock Exchange composite transactions reporting system
and dividends paid are shown in the following table for the periods indicated.
Price Range
Cash -----------------------
2001 Dividend High Low
-------- ------ ------
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 23, 2002, the board of directors declared a dividend of $0.265 per
share, payable on March 1, 2002, to common shareholders of record on February
15, 2002.
As of March 22, 2002, there were 14,151 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 table presents selected consolidated financial information. The
information should be read in conjunction with the Company's consolidated
financial statements and notes thereto presented under Part II, Item 8 Financial
Statements and Supplementary Data of this Form 10-K. The financial information
as of December 31, 1998-2001 and for each of the five years in the period ended
December 31, 2001 are derived from the Company's audited consolidated financial
statements. The financial information as of December 31, 1997 is derived from
internal unaudited consolidated financial statements. This information has been
restated to reflect the pooling of interest transaction pursuant to which each
of Indiana Energy and SIGCORP merged into Vectren.
Year Ended December 31
--------------------------------------------------------------------------------------------
(In millions, except per share data) 1997 (4) 1998 1999 2000(2,3) 2001 (1)
--------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $ 972.1 $ 997.7 $ 1,068.4 $ 1,648.7 $ 2,170.0
Operating income $ 124.6 148.5 160.8 131.1 $ 139.6
Income before extraordinary loss &
cumulative effect of change in
accounting principle $ 67.7 86.6 90.7 72.0 $ 67.4
Net income $ 67.7 86.6 90.7 72.0 $ 63.6
Average common shares outstanding 61.6 61.6 61.3 61.3 66.7
Fully diluted common shares
outstanding 61.6 61.8 61.4 61.4 66.9
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.10 $ 1.41 $ 1.48 $ 1.18 $ 1.01
Basic earnings per share
on common stock $ 1.10 $ 1.41 $ 1.48 $ 1.18 $ 0.95
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.10 $ 1.40 $ 1.48 $ 1.17 $ 1.01
Diluted earnings per share
on common stock $ 1.10 $ 1.40 $ 1.48 $ 1.17 $ 0.95
Dividends per share on common stock $ 0.88 $ 0.90 $ 0.94 $ 0.98 $ 1.03
Balance Sheet Data:
Total assets $ 1,758.6 $ 1,798.8 $ 1,980.5 $ 2,926.3 $ 2,856.8
Long-term debt, net $ 475.5 $ 388.9 $ 486.7 $ 632.0 $ 1,014.0
Redeemable preferred stock $ 8.4 $ 8.3 $ 8.2 $ 8.1 $ 0.5
Common shareholders' equity $ 653.7 $ 677.9 $ 709.8 $ 731.7 $ 848.6
(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 ($8.1 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.
(4) During 1997, the board of directors of Indiana Gas authorized management to
undertake the actions necessary and appropriate to restructure Indiana Gas'
operations and recognize a resulting restructuring charge of $39.5 million
($24.5 million after tax) which included estimated costs related to
involuntary workforce reductions.
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:
Description of the Business
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 Accounting Principles
Board (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
(defined hereafter). 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 311 communities in 49 of Indiana's 92 counties.
SIGECO provides electric generation, transmission, and distribution services to
Evansville, Indiana, and 74 other communities in 8 counties in southwestern
Indiana and participates in the wholesale power market. SIGECO also provides
natural gas distribution and transportation services to Evansville, Indiana, and
64 communities in 10 counties in southwestern Indiana. The Ohio operations
provide natural gas distribution and transportation services to Dayton, Ohio,
and 87 other communities in 17 counties in west central Ohio.
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,
provides fuel supply management, and provides energy performance contracting
services. Coal Mining provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an Internal Revenue Service (IRS) Code Section 29 investment tax credit
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading. Broadband invests in broadband communication services such as
cable television, high-speed Internet, 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 provide supply chain
services, debt collection services, and environmental compliance testing
services.
Acquisition of 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 approximately $465.0 million. The
acquisition has been accounted for as a purchase transaction in accordance with
APB 16, and accordingly, the results of operations of the acquired businesses
are included in the accompanying financial statements 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."
Consolidated Results of Operations
Year Ended December 31,
-----------------------
In millions, except per share amounts 2001 2000 1999
------ ------- ------
Net income, as reported $ 63.6 $ 72.0 $ 90.7
Merger & integration costs - net of tax 8.1 36.8 -
Restructuring costs - net of tax 11.8 - -
Extraordinary loss - net of tax 7.7 - -
Impact of SFAS 133, including cumulative effect
of change in accounting principle - net of tax (1.9) - -
Gain on restructuring of a nonregulated
investment - net of tax - (4.9) -
------ ------- ------
Net income before nonrecurring items $ 89.3 $ 103.9 $ 90.7
====== ======= ======
Attributed to:
Regulated $ 65.8 $ 84.0 $ 75.4
Nonregulated 21.9 17.8 12.5
Corporate & other 1.6 2.1 2.8
------ ------- ------
Basic earnings per share, as reported $ 0.95 $ 1.18 $ 1.48
Merger & integration costs 0.12 0.60 -
Restructuring costs 0.18 - -
Extraordinary loss 0.12 - -
Impact of SFAS 133, including cumulative effect
of change in accounting principle (0.03) - -
Gain on restructuring of a nonregulated
investment - (0.08) -
------ ------- ------
Basic earnings per share before nonrecurring items $ 1.34 $ 1.70 $ 1.48
====== ======= ======
Attributed to:
Regulated $ 0.99 $ 1.37 $ 1.23
Nonregulated 0.33 0.29 0.20
Corporate & other 0.02 0.04 0.05
In 2001, consolidated net income before the impact of nonrecurring items
decreased $14.6 million, or $0.36 per share, compared to 2000. The decrease
reflects lower regulated earnings resulting from extraordinarily high gas costs
early in the year that unfavorably impacted margins and operating costs, warmer
heating weather, especially during late 2001, and a weakened national economy.
This reduction was primarily offset by increased earnings from nonregulated
operations, primarily energy marketing and services and coal mining operations.
In 2000, consolidated net income before the impact of nonrecurring items
increased $13.2 million, or $0.22 per share compared to 1999. The increase
results from cooler weather, the inclusion of two months of the Ohio operations,
and increased nonregulated earnings from energy marketing and services and coal
mining operations and additional interest and leveraged lease income.
Dividends
In October 2001, the Company's board of directors increased its quarterly
dividend to $0.265 per share from $0.255 per share. Dividends declared for the
year ended December 31, 2001 were $1.03 per share, compared to $0.98 per share
and $0.94 per share for the same periods in 2000 and 1999, respectively.
Nonrecurring Items
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. The Company expects to
realize net merger savings of nearly $200.0 million over ten years from the
elimination of duplicate corporate and administrative programs and greater
efficiencies in operations, business processes, and purchasing. 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 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 ($8.1 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 has incurred restructuring
charges of $19.0 million, ($11.8 million after tax), or $0.18 on a basic
earnings per share basis. 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.
(See Note 3 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.
Impact of SFAS 133
Effective January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities." The cumulative impact of
adoption of SFAS 133 on January 1, 2001 was a gain of approximately $6.3 million
($3.9 million after tax.) Unrealized losses totaling $3.2 million ($2.0 million
after tax) arising from the change in market value since the date of adoption is
reflected in purchased electric energy. The net impact of SFAS 133 for the year
ended December 31, 2001 is a gain of $3.1 million ($1.9 million after tax), or
$0.03 on a basic earnings per share basis. (See below for a complete discussion
of the new accounting principle.)
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 the form of Class B units of Utilicom Networks, LLC
(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
SIGECOM Holdings, Inc. (entity formed to hold interests in SIGECOM), 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.
New Accounting Principle
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
which requires 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 accounting criteria are met.
SFAS 133, as amended, requires that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income or other comprehensive income, as appropriate, as the cumulative
effect of change in accounting principle in accordance with APB Opinion No.
20, "Accounting Changes."
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 $6.3 million ($3.9 million after
tax) 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. SFAS 133 did not impact other commodity
contracts because they were normal purchases and sales specifically excluded
from the provisions of SFAS 133.
Unrealized losses totaling $3.2 million ($2.0 million after tax) arising from
the difference between the current market value and the market value on the date
of adoption is included in purchased electric energy in the Consolidated
Statements of Income for the year ended December 31, 2001. Derivatives used in
other commodity marketing operations are not significant.
In addition to Vectren's wholly owned subsidiaries, ProLiance Energy, LLC
(ProLiance), an equity method investment, adopted SFAS 133 during 2000. The
Company's share of the impact of adoption and continued use of derivatives by
ProLiance is primarily reflected in accumulated other comprehensive income due
to the nature of the derivatives used.
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
presented 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 SIGECO's power supply operations, power
marketing operations, and electric transmission and distribution services, which
operate and maintain six coal-fired electric power plants and five gas-fired
peaking units with a total of 1,271 megawatts of generating capacity to provide
electricity to primarily southwestern Indiana. The results of regulated
operations before certain intersegment eliminations and reclassifications for
the years ended December 31, 2001, 2000, and 1999 are as follows:
In millions, except per share amounts 2001 2000 1999
--------- ------- -------
Gas revenues $ 1,031.5 $ 818.8 $ 499.6
Cost of gas 708.2 552.5 266.4
--------- ------- -------
GAS OPERATING MARGIN 323.3 266.3 233.2
--------- ------- -------
Electric revenues 378.9 336.4 307.5
Cost of fuel & purchased power 166.1 112.1 93.0
--------- ------- -------
ELECTRIC OPERATING MARGIN 212.8 224.3 214.5
--------- ------- -------
TOTAL OPERATING MARGIN 536.1 490.6 447.7
OPERATING EXPENSES
Other operating 234.7 209.9 187.5
Merger & integration costs 2.8 32.7 -
Restructuring costs 15.0 - -
Depreciation & amortization 96.9 82.4 79.5
Income tax 22.7 34.9 43.2
Taxes other than income taxes 51.3 36.2 28.5
--------- ------- -------
Total expenses 423.4 396.1 338.7
--------- ------- -------
OPERATING INCOME 112.7 94.5 109.0
Other - net 5.0 5.0 4.3
Interest expense 70.1 46.1 36.8
Preferred dividend requirement of subsidiary 0.8 1.0 1.1
--------- ------- -------
Income before cumulative effect of change
in accounting principle 46.8 52.4 75.4
Cumulative effect of change in accounting
principle - net of tax 3.9 - -
--------- ------- -------
NET INCOME, AS REPORTED $ 50.7 $ 52.4 $ 75.4
Merger & integration costs - net of tax 7.7 31.6 -
Restructuring costs - net of tax 9.3 - -
Impact of SFAS 133, including cumulative
effect of change in accounting
principle - net of tax (1.9) - -
--------- ------- -------
NET INCOME BEFORE NONRECURRING ITEMS $ 65.8 $ 84.0 $ 75.4
========= ======= =======
EARNINGS PER SHARE, AS REPORTED $ 0.76 $ 0.86 $ 1.23
Merger & integration costs 0.12 0.51 -
Restructuring costs 0.14 - -
Impact of SFAS 133, including cumulative
effect of change in accounting principle (0.03) - -
--------- ------- -------
EARNINGS PER SHARE BEFORE
NONRECURRING ITEMS $ 0.99 $ 1.37 $ 1.23
========= ======= =======
For 2001 compared to the prior year, earnings before the impact of nonrecurring
items decreased $18.2 million due to extraordinarily high gas costs early in the
year that unfavorably impacted margins and operating costs, including
uncollectible accounts expense, interest, and excise taxes; heating weather that
was 9% warmer than the prior year; and lower margins on wholesale power
marketing sales.
For 2000 compared to 1999, earnings before the impact of nonrecurring items
increased $8.6 million primarily due to cooler temperatures, and the inclusion
of the Ohio operations for two months, offset by a disallowance of gas costs by
the Indiana Utility Regulatory Commission (IURC).
Utility Margin (Utility Operating Revenues Less Utility Cost of Gas, Cost of
Fuel for Electric Generation and Purchased Electric Energy)
Gas Utility Margin
Gas Utility margin for the year ended December 31, 2001 of $323.3 million
increased $57.0 million, compared to 2000. For the incremental ten months from
January through October from the Ohio operations, margin before the impact of
higher gas costs and warmer weather was estimated at $82.5 million. Net of this
amount, gas utility margin decreased by $25.5 million. The primary factors
contributing to this decrease were weather that was 9% warmer than the prior
year and the unfavorable impact on margin resulting from extraordinarily high
gas costs early in 2001, coupled with the effects of a weakening economy. The
weather impact reduced margin by approximately $18.0 million compared to the
prior year period. The negative impact of higher gas costs on margin, along with
general economic conditions, approximated $9.4 million. These decreases were
offset somewhat by customer growth of nearly 1% compared to 2000. Including the
Ohio operations, the Company's total throughput was 199.8 MMDth in 2001, 181.2
MMDth in 2000, and 150.7 MMDth in 1999.
Gas Utility margin for the year ended December 31, 2000, of $266.3 million
increased $33.1 million compared to 1999. The Ohio operations represent $28.2
million of the increase. The remaining $4.9 million, or 2%, increase
attributable to Indiana Gas and SIGECO's gas operations reflect 8% (11.9 MMDth)
greater throughput due to much colder temperatures during the fourth quarter of
2000 than in the fourth quarter of 1999 and a 2% growth in customers.
Residential and commercial sales rose 7% and 10%, respectively, during 2000.
Temperatures were 11% colder in 2000 compared to 1999 and approached normal for
the year. These favorable impacts were partially offset by a $3.8 million
disallowance of recoverable gas costs by the IURC, charged against gas revenues
in December 2000.
Cost of gas sold was $708.2 million in 2001, $552.5 million in 2000, and $266.4
million in 1999. Of the increases, the Ohio operations contributed $178.6
million in 2001 and $83.2 million in 2000. Excluding the Ohio operations, cost
of gas sold decreased $22.9 million, or 4% in 2001 and increased $202.9 million,
or 76%, in 2000. The changes are primarily due to fluctuations in average per
unit purchased gas costs and the volume of dekatherms sold. The total average
cost per dekatherm of gas purchased by Indiana Gas and SIGECO was $5.73 in 2001,
$5.72 in 2000, and $3.58 in 1999. The price changes are due primarily to
changing commodity costs in the marketplace.
Electric Utility Margin
Electric Utility margin for the year ended December 31, 2001 of $212.8 million
decreased $11.5 million, or 5%, compared to 2000 primarily from decreased margin
on sales to wholesale energy markets and firm wholesale customers, reflecting
the weakened national economy, and a $3.2 million reduction in margin recorded
to reflect certain wholesale power marketing purchase and sale contracts at
current market values as required by SFAS 133. 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 residential and
commercial customer bases.
Electric Utility margin for the year ended December 31, 2000 of $224.3 million
increased $9.8 million, or 5%, compared to 1999 primarily due to a $4.4 million
increase in margins resulting from wholesale energy market activity. The
remaining increase results from increased sales caused by the impact of much
colder fourth quarter temperatures on electric heating sales and a 5% growth in
commercial customers during the year. Retail and firm wholesale electric sales
for 2000 increased 2% and total electric sales increased 8%.
The cost of fuel and purchased power increased $54.0 million, or 48%, in 2001
compared to 2000 and increased $19.1 million, or 20%, in 2000 compared to 1999.
The increases result primarily from more wholesale energy sales. Megawatt hours
sold to the wholesale market increased 106% in 2001 compared to 2000 and
increased 39% in 2000 compared to 1999. The 2001 increase was also affected by
the reductions in margin recorded as a result of SFAS 133.
Utility Operating Expenses (excluding Cost of Gas Sold, Fuel for Electric
Generation & Purchased Electric Energy)
Utility Other Operating
Excluding $31.4 million in additional expenses related to the Ohio operations,
utility other operating expenses for the year ended December 31, 2001 decreased
$6.6 million or 3% compared to 2000. The 2001 decrease results, primarily, from
reduced maintenance expenditures and merger synergies in the current year,
offset by increased uncollectible accounts expense resulting from increased gas
costs.
Excluding $7.1 million in expenses related to the Ohio operations, utility other
operating expenses for the year ended December 31, 2000 increased $15.3 million
or 8% compared to 1999. The increase is primarily due to increased charges for
use of corporate assets, including those assets which had useful lives shortened
as a result of the merger.
Utility Depreciation & Amortization
Utility depreciation and amortization increased $14.5 million, or 18%, and $2.9
million, or 4%, in 2001 and in 2000, respectively. The increases are due to the
inclusion of the Ohio operations and depreciation of normal utility plant
additions at Indiana Gas and SIGECO. For the years ended December 31, 2001 and
2000, the increase in utility depreciation and amortization related to the Ohio
operations was $12.9 million, including amortization of goodwill of $4.9
million, and $2.6 million, respectively.
Utility Income Tax
Federal and state income taxes related to utility operations decreased $12.2
million and $8.3 million in 2001 and in 2000, respectively. The 2001 decrease is
due to lower pre-tax earnings. The effective tax rate decreased from 40% in 2000
to 33% in 2001. This decrease results primarily from a higher effective tax rate
in 2000 due to the nondeductibility of certain merger and integration costs.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes increased $15.1 million and $7.7 million
in 2001 and in 2000, respectively. The years ended December 31, 2001 and 2000
include $15.3 million and $7.1 million, respectively, of additional expense
related to the Ohio operations, primarily state excise tax.
Utility Interest Expense
Utility interest expense increased $24.0 million and $9.3 million, respectively,
during the years ended December 31, 2001 and 2000. The increases are due
primarily to interest related to the financing of the acquisition of the Ohio
operations and increased working capital requirements resulting from higher
natural gas prices.
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 provides for choice of commodity for
all gas customers. The Company plans to implement this choice for its gas
customers in Ohio in 2002. Indiana has not adopted any regulation requiring gas
choice; however, the Company has approved tariffs permitting large volume
customers choice among commodity suppliers.
Other Operating Matters
Midwest Independent System Operator
The Federal Energy Regulatory Commission (FERC) approved the Midwest Independent
System Operator (MISO) as the nation's first regional transmission organization.
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 megawatts of
power. 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.
The FERC has made regional transmission organizations a top priority since the
California power crisis last winter. Regional transmission organizations place
public utility transmission facilities in a region under common control to boost
competition and to provide more reliable power at lower rates. 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 participation in MISO, the Company is unable to determine
the impact MISO participation may have on its operations.
Operation of Warrick Station
In March 2001, Alcoa Power Generating, Inc., a subsidiary of ALCOA, INC. (ALCOA)
began operating the Warrick Generating Station. Prior to March 2001 and since
1956, the Company operated the Warrick Generating Station as an agent for ALCOA.
Three generating units at the station are owned by ALCOA, and the Company owns a
fourth unit equally with ALCOA. The operating change has no impact on the
Company's entitlement to the generating capacity.
Under the new arrangement, the Company reimburses ALCOA for operating costs
pertaining to the Company's share of the fourth unit and pays ALCOA a fee for
agency services. The reimbursed operating costs and the related agency fee are
expected to be comparable to the costs the Company would have incurred to
operate and administer its generating facilities under the previous operating
arrangement. Therefore, this change is not expected to negatively impact the
Company's financial results. Additionally, SIGECO has retained ALCOA as a
wholesale power and transmission services customer.
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.
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 United States Environmental
Protection Agency (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 1998 and 1999.
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
(Warrick), and A.B. Brown Generating Station Unit 2 (A.B. Brown). SCR systems
reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in
chemical reaction. This technology is known to be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC issued an order that (1) approves the Company's proposed project to
achieve environmental compliance by investing in clean coal technology, (2)
approves the Company's cost estimate for the construction, subject to periodic
review of the actual costs incurred, and (3) approves a mechanism whereby, prior
to an electric base rate case, the Company may recover a return on its capital
costs for the project, at its overall cost of capital, including a return on
equity.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost ranges from $175.0 million to $195.0 million and is expected
to be expended during the 2001-2004 period. Through December 31, 2001,
approximately $22.5 million has been expended. After the equipment is installed
and operational, related additional annual operation and maintenance expenses
are estimated to be between $8.0 million and $10.0 million.
The Company expects the Culley, Warrick and A.B. Brown SCR systems to be
operational by the compliance date. Installation of SCR technology at these
stations 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 best
available control technology was, or should have been, used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana, without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
emission control technology, notice to the USEPA, or compliance with new source
review standards, SIGECO believes that the lawsuit is without merit and intends
to vigorously defend itself.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. The lawsuit does not specify the number of days or violations the
USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO
to install the best available control technology at the Culley Generating
Station. If the USEPA were successful in obtaining an order, SIGECO estimates
that it would incur capital costs of approximately $40.0 million to $50.0
million to comply with the order. As a result of the NOx SIP call issue, the
majority of the $40.0 million to $50.0 million for best available emissions
technology at Culley Generating Station is included in the $175.0 million to
$195.0 million cost range previously discussed.
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 Indiana Department of Environmental Management
(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 expert 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 accrued 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 its $20.4 million accrual.
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.
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 the
Indiana Utility Regulatory Commission (IURC). The retail gas operations of the
Ohio operations are subject to regulation by the Public Utilities Commission of
Ohio (PUCO). Changes in prices for fuel for electric generation and purchased
power are determined primarily by energy markets. Wholesale energy sales are
subject to regulation by the Federal Energy Regulatory Commission (FERC).
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 estimated and
actual costs of gas sold in a given quarter. 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 the 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 Indiana Office
of Utility Consumer Counselor (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 has been distributed in 2001.
Fuel & Purchased Power Costs
Adjustments to rates and charges related to the cost of fuel and the net energy
cost of purchased power charged to Indiana customers are made through fuel cost
adjustment procedures established by Indiana law and administered by the IURC.
Fuel cost adjustment procedures involve scheduled quarterly filings and IURC
hearings to establish the amount of price adjustments for future quarters. The
procedures also provide for inclusion in a later quarter of any variances
between estimated and actual costs of fuel and purchased power in a given
quarter. 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 2002
and additional settlement discussions are expected in 2002. 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 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,
provides fuel supply management, and provides energy performance contracting
services. Coal Mining provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an IRS Section 29 investment tax credit relating to the production of
coal-based synthetic fuels. Utility Infrastructure Services provides underground
construction and repair, facilities locating, and meter reading. Broadband
invests in broadband communication services such as cable television, high-speed
Internet, and local and long distance phone services. In addition, the
nonregulated group has investments in other businesses that invest in other
energy-related opportunities and provide supply chain services, debt collection
services, and environmental compliance testing services. The results of
nonregulated operations before certain intersegment eliminations and
reclassifications for the years ended December 31, 2001, 2000, and 1999 are as
follows:
In millions, except per share amounts 2001 2000 1999
------- ------- -------
Energy services & other revenues $ 759.6 $ 493.5 $ 261.3
Cost of energy services & other revenues 720.2 468.8 241.8
------- ------- -------
TOTAL OPERATING MARGIN 39.4 24.7 19.5
Intersegment Revenues, net of costs 1.9 1.8 -
Expenses:
Operating expenses 36.6 20.4 16.6
Merger & integration costs - 1.6 -
Restructuring costs 3.9 - -
------- ------- -------
Total expenses 40.5 22.0 16.6
------- ------- -------
OPERATING INCOME 0.8 4.5 2.9
Other income:
Equity in earnings of unconsolidated affiliates 14.1 9.8 6.4
Other - net 11.9 19.4 10.8
------- ------- -------
Total other income 26.0 29.2 17.2
------- ------- -------
Interest expense 12.2 10.2 6.1
------- ------- -------
INCOME BEFORE TAXES 14.6 23.5 14.0
Income tax (5.0) 0.7 0.6
Minority interest 0.6 1.1 0.9
------- ------- -------
Income before extraordinary loss 19.0 21.7 12.5
Extraordinary loss - net of tax (7.7) - -
NET INCOME, AS REPORTED $ 11.3 $ 21.7 $ 12.5
Merger & integration costs - net of tax - 1.0 -
Restructuring costs - net of tax 2.9 - -
Gain on restructuring of a nonregulated investment
- net of tax - (4.9) -
Extraordinary loss - net of tax 7.7 - -
------- ------- -------
NET INCOME BEFORE NONRECURRING ITEMS $ 21.9 $ 17.8 $ 12.5
======= ======= =======
EARNINGS PER SHARE, AS REPORTED $ 0.17 $ 0.35 $ 0.20
Merger & integration costs - 0.02 -
Restructuring costs 0.04 - -
Gain on restructuring of a nonregulated investment - (0.08) -
Extraordinary loss 0.12 - -
------- ------- -------
EARNINGS PER SHARE BEFORE NONRECURRING ITEMS $ 0.33 $ 0.29 $ 0.20
======= ======= =======
For 2001 compared to 2000, net income before nonrecurring items increased $4.1
million primarily due to increased earnings from Energy Marketing and Services'
investment in ProLiance and expanded coal mining operations, partially offset by
losses incurred by Vectren Communication Services, Inc., a broadband
construction and consulting company.
For 2000 compared to 1999, net income before the impact of nonrecurring items
increased $5.3 million primarily due to increases in income from Energy
Marketing and Services' consolidated operations, and Coal Mining operations, and
income from leveraged lease and notes receivable investments, offset by lower
earnings from unconsolidated affiliates.
Energy Services & Other Revenues
Revenues from Vectren's non-utility operations (primarily the operating
companies of its Energy Marketing and Services, excluding ProLiance which is
reported as equity in earnings of unconsolidated affiliates, as described below,
and Coal Mining groups) for the year ended December 31, 2001 were $759.6
million, compared to $493.5 million in 2000 and $261.3 million in 1999. The
significant increases over prior year amounts are primarily from Energy
Marketing and Services' natural gas marketing operations resulting from higher
prices for natural gas reflected in sales to its customers and increased volume.
Costs of Energy Services & Other
Cost of energy services and other increased $251.4 million and $227.0 million,
respectively, for the years ended December 31, 2001 and 2000. These costs are
primarily the cost of natural gas purchased for resale by Energy Marketing and
Services' wholly owned gas marketing operations. The increases are primarily due
to higher per unit purchased gas costs and growth in natural gas marketing
sales.
Nonregulated Margin
Margin from nonregulated operations for the year ended December 31, 2001 was
$39.4 million compared to $24.7 million, and $19.5 million for the same periods
in 2000 and 1999, respectively. The $14.7 million increase in 2001 was primarily
driven by expanded coal mining operations adding margin of $14.2 million in 2001
and $1.8 million in 2000. The Company's second mine began operations in the
first quarter of 2001. The $5.2 million increase in 2000 was primarily driven by
the wholly owned and majority owned operations of the Energy Marketing and
Services group reflecting the continued growth of its natural gas marketing
operations and its performance contracting operations, including several large
contracts in progress. The 2001 increase, however, was offset by a decrease in
margin of $7.9 million incurred by the Company's broadband construction and
consulting operations.
Nonregulated Operating Expenses (excluding Costs of Energy Services & Other
Revenues)
Nonregulated operating expenses consist of other operating expenses,
depreciation and amortization, and taxes other than income taxes. For the years
ended December 31, 2001 and 2000, nonregulated operating expenses increased
$16.2 million and $3.8 million, respectively. Growth in both years is primarily
attributable to continued growth at Energy Marketing and Services and Coal
Mining. In addition, the 2001 increase was affected by increased uncollectible
accounts expense of $2.2 million in the natural gas marketing operations.
Nonregulated Other Income
Equity in Earnings of Unconsolidated Affiliates
For the year ended December 31, 2001, earnings from unconsolidated affiliates
increased $4.3 million compared to 2000; however, excluding the gain recognized
in 2000 related to restructuring Broadband's investment in SIGECOM, LLC of $8.0
million, earnings from unconsolidated investments increased $12.3 million. The
increase is due to increased earnings from Energy Marketing and Services'
investment in ProLiance, an energy marketing joint venture, and a gain on the
sale of one of Haddington Energy Partners, LP's (Haddington) investments. (See
below for more information on ProLiance's earnings contribution.)
In March 2001, Haddington, an investment accounted for on the equity method and
included in the Other Business group, sold its investment in Bear Paw
Investments, LLC (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,
allocated per the terms of the partnership agreement, through equity in earnings
of unconsolidated affiliates. The amount of the pre-tax gain recognized by the
Company approximates $3.9 million.
Equity in earnings of unconsolidated affiliates increased $3.4 million for the
year ended December 31, 2000, compared to the prior year. The increase in 2000
is due primarily to the $8.0 million net gain related to the restructuring of
Broadband's investment in SIGECOM. The increase was partially offset by lower
pre-tax earnings recognized from ProLiance and lower other investment earnings.
Other - Net
Nonregulated other-net decreased $7.5 million for the year ended December 31,
2001. The decreases are due to a $2.3 million gain on the sale of a partial
interest in an Energy Marketing and Services' investment and a $1.1 million
premium earned by the Other Business group for a loan guarantee, both occurring
in the second quarter of 2000. The remaining decreases are due to fluctuations
in interest income and less leveraged lease income as a result of the current
year divestiture of those investments.
Nonregulated other-net increased $8.6 million for the year ended December 31,
2000, compared to the prior year primarily due to increased interest income
mainly from the Company's investments in structured finance and investment
transactions, including leveraged leases.
Nonregulated Interest Expense
Nonregulated interest expense increased by $2.0 million and $4.1 million,
respectively, for the years ended December 31, 2001 and 2000 when compared to
the prior year. The increases were due primarily to increased debt to fund
additional investments in nonregulated businesses.
Nonregulated Income Tax
Federal and state income taxes related to nonregulated operations decreased $5.7
million for the year ended December 31, 2001 compared to the prior year. The
decrease results from a lower effective tax rate offset by higher pre-tax
earnings. The nonregulated group's effective tax rate was lowered due to the
utilization of tax credits. For the year ended December 31, 2000 compared to
1999, income taxes were comparable.
Other Operating Matters
Acquisition of Miller Pipeline Corporation by Reliant Services, LLC
In December 2000, Reliant Services, LLC (Reliant), an equity method investment
owned jointly and equally by Vectren and Cinergy Corp., 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 and electric facilities 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.
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren, began providing natural gas and related services to Indiana Gas,
Citizens Gas and Coke Utility (Citizens Gas), and others in April 1996.
ProLiance also provides services to the Ohio operations. Effective in March
2001, the operating agreement between Vectren and Citizens Gas was modified to
increase on a prospective basis Vectren's allocable share of profits and losses
from 50% to 52.5%. The provisions of the operating agreement call for
governance, including voting rights, to remain at 50% for each member. As
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
For the years ended December 31, 2001, 2000, and 1999, ProLiance's contribution
to Vectren's pre-tax earnings was $12.8 million, $5.4 million, and $6.1 million,
respectively.
The sale of gas and provision of other services to Indiana Gas by ProLiance is
subject to regulatory review through the quarterly GCA process administered by
the IURC. 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. The
IURC's decision reflected the significant gas cost savings to customers obtained
through ProLiance's services and suggested that all material provisions of the
agreements between ProLiance and the utilities are reasonable. Nevertheless,
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 the pending, consolidated GCA proceeding involving Indiana
Gas and Citizens Gas.
The IURC has recently commenced the processing of the further GCA proceeding
regarding the three pricing issues. The IURC has indicated that it will also
consider the prospective relationship of ProLiance with the utilities in this
proceeding. Discovery is ongoing in this proceeding, and an evidentiary hearing
is scheduled for May 2002. Until the issues reserved by the IURC are resolved,
Vectren will continue to reserve a portion of its share of ProLiance earnings.
In August 1998, Indiana Gas, Citizens Gas and ProLiance each received a Civil
Investigative Demand (CID) from the United States Department of Justice
requesting information relating to Indiana Gas' and Citizens Gas' relationships
with and the activities of ProLiance. The Department of Justice issued the CID
to gather information regarding ProLiance's formation and operations, and to
determine if trade or commerce has been restrained. In October 2001, the
Antitrust Division of the Department of Justice informed the Company that it
closed the investigation without further action.
Utilicom Networks, LLC & Related Entities
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including cable television,
high-speed Internet, and local and long distance telephone services. The Company
has a 14% interest in Class A units of Utilicom, which is accounted for using
the equity method of accounting. The company also has a minority interest in
SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold the
interests in SIGECOM, LLC (SIGECOM). The Company accounts for its investment in
Holdings on the cost method. SIGECOM provides broadband services to the greater
Evansville, Indiana, area. Utilicom plans to provide broadband services to the
greater Indianapolis, Indiana, and Dayton, Ohio, markets.
The Company's investment in Utilicom and related entities are subject to risks
common in companies in developing industries, including, but not limited to, and
evolving and unpredictable business model, development of new technological
innovations, customer acceptance of new solutions and services, dependence on
key personnel, and a limited operating history.
In December 2000, Utilicom announced plans to raise $600.0 million in capital to
establish separate operating ventures in Indianapolis and Dayton and to
recapitalize SIGECOM. The Company has committed to invest up to a total of
$100.0 million in Utilicom and the Indianapolis and Dayton ventures subject to
Utilicom obtaining commitments for the entire $600.0 million of anticipated
funding. The Company's investments may take the form of convertible subordinated
debt or common equity. At December 31, 2001, the remaining commitment is $86.5
million.
At December 31, 2001, the Company has $24.8 million of notes receivable from
Utilicom-related entities which are convertible into equity interests. Notes
receivable totaling $22.9 million are convertible into Class A units of Utilicom
at the Company's option or upon the event of a public offering of stock by
Utilicom and $1.9 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.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is due to the
current 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 committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded. This delay
necessitated and resulted in the extension of the franchising agreements into
the third quarter of 2002.
At December 31, 2001 and 2000, the Company's combined investment in equity and
debt securities of Utilicom-related entities totaled $39.3 million and $32.5
million, respectively.
Significant Accounting Policies
As described in Note 2 to the consolidated financial statements, significant
accounting policies include the following:
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.
Utility Plant & Depreciation
Utility plant is stated at historical cost, including an allowance for the cost
of funds used during construction (AFUDC). Depreciation of utility property is
provided using the straight-line method over the estimated service lives of the
depreciable assets. 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. 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.
Impairment Review of Long-Lived Assets
Long-lived assets are reviewed for impairment in accordance with SFAS No. 121,
"Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" as facts and circumstances indicate that the carrying amount may be
impaired. Specifically, the evaluation for impairment involves 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 as a charge to operations based on the difference between the
asset's carrying amount and its fair value. The same policy is currently
utilized for goodwill.
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 at cost less write-downs for declines in value judged to be
other than temporary. Dividends are recorded as other-net when received.
Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the Indiana Utility Regulatory Commission (IURC), and retail
public utility operations affecting Ohio customers are subject to regulation by
the Public Utilities Commission of Ohio (PUCO). The Company's wholesale energy
transactions are subject to regulation by the Federal Energy Regulatory
Commission (FERC).
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 continually assesses the recoverability of costs recognized as
regulatory assets and the ability to continue to account for its activities in
accordance with SFAS 71, 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 costs of deregulated plant and inventory assets.
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.
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.
Impact of Recently Issued Accounting Guidance on Future Operations
SFAS 141 & 142
The FASB issued two new statements of financial accounting standards in July
2001: SFAS No. 141, "Business Combinations" (SFAS 141), and SFAS No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). These interrelated standards
change the accounting for business combinations and goodwill in two significant
ways:
SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001. Use of the
pooling-of-interests method is prohibited. This change does not affect the
pooling-of-interest transaction forming Vectren.
SFAS 142 changes the accounting for goodwill from an amortization approach to an
impairment-only approach. Thus, amortization of goodwill that is not included as
an allowable cost for rate-making purposes will cease upon adoption of the
statement. This includes goodwill recorded in past business combinations, such
as the Company's acquisition of the Ohio operations. Goodwill is to be tested
for impairment at a reporting unit level at least annually.
SFAS 142 also requires the initial impairment review of all goodwill and other
intangible assets within six months of the adoption date, which is January 1,
2002 for the Company. 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 would be
recognized. Results of the initial impairment review are to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations.
SFAS 142 also changes certain aspects of accounting for intangible assets;
however, the Company does not have any significant intangible assets.
The adoption of SFAS 141 will not materially impact operations. As required by
SFAS 142, amortization of goodwill relating to the acquisition of the Ohio
operations, which approximates $5.0 million per year, will cease on January 1,
2002. Initial impairment reviews to be performed within six months of adoption
of SFAS 142 are not expected to have a significant impact to operations.
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 the
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. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
SFAS 144 is effective for fiscal years beginning after December 15, 2001, with
earlier application encouraged. The Company is evaluating the impact SFAS 144
will have on its operations.
Financial Condition
The Company's equity capitalization objective is 40-50% of total capitalization.
This objective may have varied, and will vary, depending on particular business
opportunities and seasonal factors that affect the Company's operation. The
Company's equity component was 45% and 51% of total capitalization, including
current maturities of long-term debt and long-term debt subject to tender, at
December 31, 2001 and 2000, respectively.
Short-term cash working capital is required primarily to finance customer
accounts receivable, unbilled utility revenues resulting from cycle billing, gas
in underground storage, prepaid gas delivery services, capital expenditures, and
investments until permanently financed. Short-term borrowings tend to be
greatest during the summer when accounts receivable and unbilled utility
revenues related to electricity are highest and gas storage facilities are being
refilled. However, working capital requirements have been significantly higher
throughout 2001 due to the extraordinarily high natural gas costs early in 2001
and the acquisition of the Ohio operations, initially funded with short-term
borrowings.
The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds; however, additional
financing may be required due to the possible early redemption of debt at
Indiana Gas and significant capital expenditures for NOx compliance equipment at
SIGECO.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2001 are A-/A2. SIGECO's credit ratings on outstanding secured debt
at December 31, 2001 are A-/A1. VUHI's commercial paper has a credit rating of
A-2/P-1. Vectren Capital Corp. debt is rated BBB+ by Standard & Poor's.
Cash Flow From Operations
The Company's primary source of liquidity to fund working capital requirements
has been cash generated from operations, which totaled approximately $183.5
million, $40.7 million, and $149.2 million, for the years ended December 31,
2001, 2000, and 1999, respectively.
Cash flow from operations increased during the year ended December 31, 2001
compared to 2000 by $142.8 million due primarily to favorable changes in working
capital accounts due to the normalization of gas prices.
Cash from operations decreased during 2000 as compared to 1999 by approximately
$108.5 million. The decrease is primarily attributable to merger and integration
costs causing lower net income, increased recoverable fuel and natural gas
costs, and increased working capital requirements resulting from higher natural
gas costs.
Financing Activities
Sources & Uses of Liquidity
At December 31, 2001, the Company has $540.0 million of short-term borrowing
capacity, including $360.0 million for its regulated operations and $180.0
million for its nonregulated operations, of which $85.8 million is available for
regulated operations and $62.5 million is available for nonregulated operations.
Included in regulated capacity is VUHI's credit facility, which was renewed in
June 2001 and extended though June 2002. As part of the renewal, the facility's
capacity was decreased from $435.0 million to $350.0 million. Indiana Gas'
$155.0 million commercial paper program expired in 2001 and was not required
and, therefore, not renewed.
During the five-year period 2002-2006, maturities and sinking fund requirements
on long-term debt subject to mandatory redemption (in millions) are $1.3 in
2002, $17.3 in 2003, $16.3 in 2004, $39.3 in 2005, and $1.3 in 2006. Also during
the five-year period 2002-2006, exercisable put provisions on long-term debt (in
millions) are $11.5 in 2002, $3.5 in 2004, $10.0 in 2005 and $53.7 in 2006.
At December 31, 2001, $113.0 million of Vectren Capital senior unsecured notes
and $98.3 million of Vectren Capital bank loans, which as a result of certain
terms including cross-defaults and ratings triggers, would provide that the full
balance outstanding is subject to prepayment if the ratings of Indiana Gas and
SIGECO declined to BBB/Baa2 or the ratings of Vectren Capital declined to
BB+/Ba1. At December 31, 2001, $273.3 million of commercial paper was supported
by the VUHI facility whereby VUHI must maintain a rating of better than BB+/Ba1.
Financing Cash Flow
Cash flow required for financing activities of $2.6 million for the year ended
December 31, 2001 includes $41.8 million of reductions in net borrowings and
$69.5 million in common stock dividends, offset by the issuance of $129.4
million of common stock. During 2001, $344.0 million of net proceeds from
long-term debt issuances was utilized to pay down short-term borrowings.
Cash flow provided by financing activities of $638.7 million for the year ended
December 31, 2000 includes $694.3 million of additional net borrowings offset by
$60.0 million of dividends on shares of common stock. This is an increase of
$576.6 million over the prior year due primarily to funding the acquisition of
the Ohio operations and increased working capital requirements.
Financing the Ohio Operations Purchase
On October 31, 2000, the acquisition of the Ohio operations was completed for a
purchase price of approximately $465.0 million. Commercial paper and $150.0
million in floating rate notes were issued to fund the purchase. The floating
rate notes' interest rate was equal to the three-month US dollar LIBOR rate plus
0.75%. Concurrent with the completion of this financing, an interest rate swap
was executed which in effect resulted in a fixed rate of 6.64%. During 2001, the
Company has refinanced these interim borrowing arrangements with permanent
financing in the form of new equity and long-term debt.
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 with respect to a public offering of $350.0 million
aggregate principal amount of unsecured senior notes, guaranteed jointly and
severally by SIGECO, Indiana Gas, and VEDO. In October 2001, VUHI issued senior
unsecured notes with an aggregate principal amount of $100.0 million and an
interest rate of 7.25%, 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.
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.
The Company has $31.5 million of adjustable rate pollution control series first
mortgage bonds and $22.2 million of adjustable rate pollution control series
unsecured senior notes which could, at the election of the bondholder, be
tendered to the Company when interest rates are reset. Prior to the latest reset
on March 1, 2001, the interest rates were reset annually, and the bonds were
presented as current liabilities. Effective March 1, 2001, the bonds were reset
for a five-year period and have been classified as long-term debt.
In December 2000, Vectren Capital 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 totaling $77.4 million were used to repay outstanding short-term
borrowings.
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 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 utilized for general corporate purposes.
Capital Expenditures, Other Investment Activities, Guarantees, & Other
Commitments
Cash required for investing activities of $168.9 million for the year ended
December 31, 2001 includes $235.3 million of requirements for capital
expenditures and proceeds from the sale of leveraged leases of $53.8 million.
Investing activities for the years ended December 31, 2000 and 1999 were $681.6
million and $201.3 million, respectively. The $480.3 million increase occurring
in 2000 is principally the result of the $463.3 million acquisition of the Ohio
operations and additional capital expenditures for coal mining development
costs.
Planned Capital Expenditures & Investments
New construction, normal system maintenance and improvements, and information
technology investments needed to provide service to a growing customer base will
continue to require substantial expenditures. Additionally, during the
three-year period 2002-2004, construction costs for NOx emissions control
equipment are estimated to total between $150.0 million and $170.0 million and
additional generation is planned. The Company's anticipated investments in
unconsolidated affiliates during the next five years will also require funding.
Capital expenditures and investments in unconsolidated affiliates for the five
year period 2002 - 2006 are estimated as follows:
In millions 2002 2003 2004 2005 2006
------- ------- ------- ------- -------
Capital expenditures
Regulated (1) $ 165.7 $ 234.3 $ 134.4 $ 119.4 $ 150.8
Nonregulated 20.6 8.9 13.5 7.4 13.9
Corporate & other 25.4 32.2 13.5 8.7 5.3
------ ------ ------ ------ ------
Total capital expenditures $ 211.7 $ 275.4 $ 161.4 $ 135.5 $ 170.0
====== ====== ====== ====== ======
Investments in unconsolidated
affiliates $ 13.8 $ 55.5 $ 33.8 $ 31.3 $ 11.5
====== ====== ====== ====== ======
(1) Includes expenditures for NOx compliance of approximately $35.9 million in
2002, $101.3 million in 2003 and $15.1 million in 2004.
Guarantees & Other Commitments
Guarantees The Company is party to financial guarantees with off-balance sheet
risk. These guarantees include debt guarantees and performance guarantees,
including the debt of and performance of energy efficiency products installed by
affiliated companies. The Company estimates these guarantees totaled $114.6
million at December 31, 2001. Of that amount, $82.9 million relates to the
Company's guarantee of Energy Systems Group, LLC's (ESG) surety bonds and
performance guarantees. ESG is a two-thirds owned consolidated subsidiary.
Specific to the ESG guarantees, the Company is obligated for amounts due to
various insurance companies for surety bonds should ESG default on obligations
to complete construction, pay vendors or subcontractors, and achieve energy
guarantees. Through December 31, 2001, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
Rental 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 2001 and thereafter (in millions) are $4.4 in 2002, $4.5 in
2003, $3.9 in 2004, $3.0 in 2005, $3.0 in 2006 and $5.6 thereafter. Total lease
expense (in millions) was $6.2 in 2001, $3.4 in 2000 and $2.7 in 1999.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition, including, but
not limited to Vectren's realization of net merger savings and ProLiance, 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:
|X| Factors affecting utility operations such as unusual weather
conditions; catastrophic weather-related damage; unusual maintenance
or repairs; unanticipated changes to fossil fuel costs; unanticipated
changes to gas supply costs, or availability due to higher demand,
shortages, transportation problems or other developments;
environmental or pipeline incidents; transmission or distribution
incidents; unanticipated changes to electric energy supply costs, or
availability due to demand, shortages, transmission problems or other
developments; or electric transmission or gas pipeline system
constraints.
|X| Increased competition in the energy environment including effects of
industry restructuring and unbundling.
|X| Regulatory factors such as unanticipated changes in rate-setting
policies or procedures, recovery of investments and costs made under
traditional regulation, and the frequency and timing of rate
increases.
|X| Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission, state public
utility commissions, state entities which regulate natural gas
transmission, gathering and processing, and similar entities with
regulatory oversight.
|X| Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
|X| Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but
not limited to, price, basis, credit, liquidity, volatility, capacity,
interest rate, and warranty risks.
|X| Availability or cost of capital, resulting from changes in the
Company, including its security ratings, changes in interest rates,
and/or changes in market perceptions of the utility industry and other
energy-related industries.
|X| Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages.
|X| Legal and regulatory delays and other obstacles associated with
mergers, acquisitions, and investments in joint ventures.
|X| Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but
not limited to, those described in Management's Discussion and
Analysis of Results of Operations and Financial Condition.
|X| Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market 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.
Commodity Price Risk The Company's regulated operations have limited exposure to
commodity price risk for purchases and sales of natural gas and electric energy
for its retail customers due to current Indiana and Ohio regulations, which
subject to compliance with applicable state regulations, allow for recovery of
such purchases through natural gas and fuel cost adjustment mechanisms.
The Company does engage in limited wholesale power marketing and other marketing
activities that may expose it to commodity price risk associated with
fluctuating electric power, natural gas, and coal commodity prices.
The Company's wholesale power marketing activities manage the utilization of its
available electric generating capacity. The Company's other commodity marketing
activities purchase and sell natural gas and coal to meet customer demands.
These operations enter into forward contracts that commit the Company to
purchase and sell commodities in the future.
Commodity price risk results from forward sales contracts that commit the
Company to deliver commodities on specified future dates. Power marketing uses
planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.
Additionally, other commodity marketing activities use stored inventory and
forward purchase contracts to protect certain sales transactions from
unanticipated fluctuations in commodity prices.
Open positions in terms of price, volume and specified delivery points may occur
to a limited extent 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 market sensitive financial instruments (all contracts not expected to
be settled by physical receipt or delivery). For the year ended December 31,
2001, a 10% adverse change in the forward prices of electricity and natural gas
on market sensitive financial instruments would have decreased pre-tax earnings
by approximately $2.0 million.
Commodity Price Risk from Unconsolidated Affiliate. ProLiance Energy, LLC
(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
ProLiance's 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.
Under normal circumstances, 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.
At December 31, 2001, such obligations represented 29% of the Company's total
debt portfolio, due primarily to financing the increased working capital
requirements resulting from extraordinarily high gas costs experienced during
the 2000 - 2001 heating season.
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,
2001 and 2000, the combined borrowings under these facilities totaled $404.2
million and $782.4 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2001 and 2000, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $6.2 million and $3.4 million, respectively.
Other Risks By using forward purchase contracts and derivative financial
instruments to manage risk, the Company exposes itself to counter-party credit
risk and market risk. The Company manages this exposure to counter-party credit
risk by entering into contracts with financially sound companies that can be
expected to fully perform under the terms of the contract. The Company attempts
to manage exposure to market risk associated with commodity contracts and
interest rates by establishing and monitoring parameters that limit the types
and degree of market risk that may be undertaken. As of December 31, 2001, the
Company has a net receivable from Enron Corp. of approximately $1.0 million,
which has been fully reserved.
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 based on that
review. Credit risk associated with certain investments is also managed by a
review of creditworthiness and receipt of collateral.
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, are the responsibilities 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
January 24, 2002.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren
Corporation (an Indiana corporation) and subsidiary companies as of December 31,
2001 and 2000, and the related consolidated statements of income, common
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Vectren Corporation
and subsidiary companies as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.
As discussed in Note 16 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Indianapolis, Indiana,
January 24, 2002.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
-------------------
2001 2000
ASSETS -------- ---------
Current Assets
Cash & cash equivalents $ 27.2 $ 15.2
Accounts receivable-less reserves of $5.9 &
$5.7, respectively 213.8 295.4
Accrued unbilled revenues 78.4 143.4
Inventories 71.4 95.2
Recoverable fuel & natural gas costs 76.5 96.1
Prepayments & other current assets 103.4 62.3
-------- --------
Total current assets 570.7 707.6
-------- --------
Utility Plant
Original cost 2,903.2 2,788.8
Less: accumulated depreciation & amortization 1,308.2 1,233.0
-------- --------
Net utility plant 1,595.0 1,555.8
-------- --------
Investments in unconsolidated affiliates 127.7 108.6
Other investments 100.3 171.5
Non-utility property-net 181.7 104.4
Goodwill-net 193.1 198.0
Regulatory assets 61.4 56.3
Other assets 26.9 24.1
-------- --------
TOTAL ASSETS $ 2,856.8 $ 2,926.3
======== ========
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,
-------------------
2001 2000
-------- --------
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 144.4 $ 153.5
Accounts payable to affiliated companies 37.2 150.4
Accrued liabilities 101.4 106.2
Short-term borrowings 381.7 609.9
Notes payable, 6.64% - 150.0
Long-term debt subject to tender 11.5 53.7
Current maturities of long-term debt 1.3 0.2
-------- --------
Total current liabilities 677.5 1,223.9
-------- --------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 206.7 221.1
Deferred credits & other liabilities 108.1 99.2
-------- --------
Total deferred credits & other liabilities 314.8 320.3
-------- --------
Commitments & Contingencies (Notes 4, 13-15)
Minority Interest in Subsidiary 1.4 1.4
Capitalization
Long-term debt-net of current maturities and
debt subject to tender 1,014.0 632.0
Cumulative preferred stock of subsidiary
Redeemable 0.5 8.1
Nonredeemable - 8.9
-------- --------
Total preferred stock of subsidiary 0.5 17.0
-------- --------
Common shareholders' equity
Common stock (no par value) - issued & outstanding
67.7 and 61.4, respectively 346.1 217.8
Retained earnings 498.3 506.4
Accumulated other comprehensive income 4.2 7.5
-------- --------
Total common shareholders' equity 848.6 731.7
-------- --------
Total capitalization 1,863.1 1,380.7
-------- --------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,856.8 $ 2,926.3
======== ========
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,
----------------------------------
2001 2000 1999
--------- --------- ---------
OPERATING REVENUES
Gas utility $ 1,031.5 $ 818.8 $ 499.6
Electric utility 378.9 336.4 307.5
Energy services & other 759.6 493.5 261.3
--------- --------- ---------
Total operating revenues 2,170.0 1,648.7 1,068.4
--------- --------- ---------
OPERATING EXPENSES
Cost of gas sold 708.2 552.5 266.4
Fuel for electric generation 74.4 75.7 72.2
Purchased electric energy 91.7 36.4 20.8
Cost of energy services & other 720.2 468.8 241.8
Other operating 236.9 199.4 189.5
Merger & integration costs 2.8 41.1 -
Restructuring costs 19.0 - -
Depreciation & amortization 123.7 105.7 87.0
Taxes other than income taxes 53.5 38.0 29.9
--------- --------- ---------
Total operating expenses 2,030.4 1,517.6 907.6
--------- --------- ---------
OPERATING INCOME 139.6 131.1 160.8
OTHER INCOME
Equity in earnings of unconsolidated affiliates 14.1 9.8 6.4
Other - net 16.3 23.7 14.1
--------- --------- ---------
Total other income 30.4 33.5 20.5
--------- --------- ---------
Interest expense 82.6 56.4 42.9
--------- --------- ---------
INCOME BEFORE INCOME TAXES 87.4 108.2 138.4
--------- --------- ---------
Income taxes 18.6 34.2 45.7
Minority interest in subsidiary 0.6 1.0 0.9
Preferred dividend requirement of subsidiary 0.8 1.0 1.1
--------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 67.4 72.0 90.7
--------- --------- ---------
Extraordinary loss - net of tax (7.7) - -
Cumulative effect of change in accounting
principle - net of tax 3.9 - -
--------- --------- ---------
NET INCOME $ 63.6 $ 72.0 $ 90.7
========= ========= =========
AVERAGE COMMON SHARES OUTSTANDING 66.7 61.3 61.3
DILUTED COMMON SHARES OUTSTANDING 66.9 61.4 61.4
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ 1.18 $ 1.48
Extraordinary loss - net of tax (0.12) - -
Cumulative effect of change in accounting
principle - net of tax 0.06 - -
--------- --------- ---------
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ 1.18 $ 1.48
========= ========= =========
DILUTED
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ 1.17 $ 1.48
Extraordinary loss - net of tax (0.12) - -
Cumulative effect of change in accounting
principle - net of tax 0.06 - -
--------- --------- ---------
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ 1.17 $ 1.48
========= ========= =========
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,
--------------------------
2001 2000 1999
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 63.6 $ 72.0 $ 90.7
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 123.7 105.7 87.0
Deferred income taxes & investment tax credits 9.8 (5.8) 7.3
Equity in earnings of unconsolidated affiliates (14.1) (9.8) (6.4)
Net unrealized gain on derivative instruments,
including cumulative effect of change in
accounting principle (3.1) - -
Extraordinary loss on sale of leveraged leases
- net of tax 7.7 - -
Other non-cash charges- net 20.8 9.4 11.5
Changes in assets and liabilities:
Accounts receivable & accrued unbilled revenue 128.4 (255.8) (23.6)
Inventories 23.9 17.8 7.8
Recoverable fuel & natural gas costs 19.6 (82.3) 0.3
Prepayments & other current assets (40.5) (3.4) (28.7)
Regulatory assets (1.5) (1.2) 3.0
Accounts payable, including to affiliated
companies (122.2) 208.2 11.7
Accrued liabilities (29.7) (2.4) 3.4
Other noncurrent assets & liabilities (2.9) (11.7) (14.8)
------ ------ ------
Total adjustments 119.9 (31.3) 58.5
------ ------ ------
Net cash flows from operating activities 183.5 40.7 149.2
------ ------ ------
CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs 344.0 145.3 108.5
Issuance of common stock - net of issuance costs 129.4 - -
Short-term notes payable - 150.0 -
Requirements for:
Retirement of short-term notes payable (150.0) - -
Dividends on common stock (69.5) (60.0) (57.4)
Dividends on preferred stock of subsidiary (0.8) (1.0) (1.1)
Retirement of long-term debt (7.6) (3.3) (66.7)
Redemption of preferred stock of subsidiary (17.7) (2.0) (0.1)
Retirement of common stock - - (2.3)
Net change in short-term borrowings (228.2) 402.3 81.7
Proceeds (payments) from exercise of stock
options & other (2.2) 7.4 (0.5)
------ ------ ------
Net cash flows (required for) from financing
activities (2.6) 638.7 62.1
------ ------ ------
CASH FLOWS (REQUIRED FOR) FROM INVESTING ACTIVITIES
Proceeds from:
Sale of leveraged lease investments 53.8 - -
Unconsolidated affiliate distributions 22.5 7.0 4.6
Notes receivable & other collections 16.7 9.0 9.5
Requirements for:
Capital expenditures (235.3) (164.3) (135.9)
Acquisition of Ohio operations - (463.3) -
Unconsolidated affiliate investments (22.7) (29.4) (10.7)
Leveraged lease investments - - (46.8)
Notes receivable & other investments (3.9) (40.6) (22.0)
------ ------ ------
Net cash flows (required for)
investing activities (168.9) (681.6) (201.3)
------ ------ ------
Net increase (decrease) in cash & cash equivalents 12.0 (2.2) 10.0
Cash & cash equivalents at beginning of period 15.2 17.4 7.4
------ ------ ------
Cash & cash equivalents at end of period $ 27.2 $ 15.2 $ 17.4
====== ====== ======
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 December 31, 1998 61.4 $ 218.6 $ (1.4) $ 460.7 $ - $677.9
Comprehensive income:
Net income 90.7 90.7
Minimum pension liability adjustments &
other - net of tax (0.1) (0.1)
-------------------------------------------------------------------------------------------------------
Total comprehensive income 90.6
-------------------------------------------------------------------------------------------------------
Common stock:
Dividends ($0.94 per share) (57.4) (57.4)
Repurchases (0.1) (2.3) (2.3)
Other 1.2 (0.1) (0.1) 1.0
-------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 61.3 217.5 (1.5) 493.9 (0.1) 709.8
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 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 61.4 219.3 (1.5) 506.4 7.5 731.7
Comprehensive income:
Net income 63.6 63.6
Minimum pension liability adjustments &
other - net of tax (1.7) (1.7)
Comprehensive income of unconsolidated
affiliates - net of tax (1.6) (1.6)
-------------------------------------------------------------------------------------------------------
Total comprehensive income 60.3
-------------------------------------------------------------------------------------------------------
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 67.7 $ 348.6 $ (2.5) $ 498.3 $ 4.2 $848.6
========================================================================================================
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 Accounting Principles
Board (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
(defined hereafter). 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 311 communities in 49 of Indiana's 92 counties.
SIGECO provides electric generation, transmission, and distribution services to
Evansville, Indiana, and 74 other communities in 8 counties in southwestern
Indiana and participates in the wholesale power market. SIGECO also provides
natural gas distribution and transportation services to Evansville, Indiana, and
64 communities in 10 counties in southwestern Indiana. The Ohio operations
provide natural gas distribution and transportation services to Dayton, Ohio,
and 87 other communities in 17 counties in west central Ohio.
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,
provides fuel supply management, and provides energy performance contracting
services. Coal Mining provides the mining and sale of coal to the Company's
utility operations and to other third parties and generates income tax credits
through an Internal Revenue Service (IRS) Code Section 29 investment tax credit
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading. Broadband invests in broadband communication services such as
cable television, high-speed Internet, 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 provide supply chain
services, debt collection services, and environmental compliance testing
services.
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 approximately $465.0 million. The
acquisition has been accounted for as a purchase transaction in accordance with
APB 16, and accordingly, the results of operations of the acquired businesses
are included in the accompanying financial statements 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 $198.0 million, has been recognized
for the excess amount of the purchase price paid over the fair value of the net
assets acquired. Prior to the Company's adoption of Statement of Financial
Accounting Standards (SFAS) No.142 "Goodwill and Intangible Assets" on January
1, 2002, this goodwill was amortized on a straight-line basis over 40 years.
(See Note 19 for further information on the adoption of this standard.)
Had the acquisition of the Ohio operations occurred on January 1, 1999, pro
forma operating revenues, net income, and basic and diluted earnings per share
for the year ended December 31, 2000 would have been $1,831.1 million, $72.0
million, $1.17, and $1.17, respectively. For the year ended December 31, 1999,
pro forma operating revenues, net income and basic and diluted earnings per
share would have been $1,287.3 million, $87.4 million, $1.43, and $1.42,
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. These pro forma results are unaudited.
2. Summary of Significant Accounting Policies
A. Principles of Consolidation
The accompanying consolidated financial statements for periods prior to March
31, 2000 reflect 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 and also reflect the
consolidation of a majority-owned affiliate, Energy Systems Group, LLC, which
was an equity method investment of Indiana Energy and SIGCORP prior to the
merger.
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. For the year ended December 31, 1999, operating
revenues and net income contributed were $433.3 million and $38.7 million,
respectively, by Indiana Energy and $604.5 million and $52.1 million,
respectively by SIGCORP.
B. 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.
C. 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
is as follows:
Year Ended December 31,
-----------------------
In millions 2001 2000 1999
------ ------ ------
Cash paid for
Interest (net of amount capitalized) $ 74.9 $ 55.7 $ 34.8
Income taxes 38.0 53.5 36.9
------ ------ ------
Details of acquisition (Note 1)
Book value of assets acquired $ - $ 278.1 $ -
Liabilities assumed - 7.9 -
------ ------- ------
Net assets acquired $ - $ 270.2 $ -
====== ======= ======
D. Inventories
Inventories consist of the following:
At December 31,
------------------------
In millions 2001 2000
------ ------
Gas in storage - at LIFO cost $ 24.3 $ 19.0
Materials & supplies 21.5 17.0
Gas in storage - at average cost 11.6 49.4
Fuel (coal & oil) for electric generation 10.3 4.4
Emission allowances 1.4 3.9
Other 2.3 1.5
-----------------------------------------------------------------------------
Total inventories $ 71.4 $ 95.2
=============================================================================
Based on the average cost of gas purchased during December, the cost of
replacing the current portion of gas in storage carried at LIFO cost exceeded
LIFO cost at December 31, 2001 and 2000 by approximately $17.9 million and $64.3
million, respectively. All other inventories are carried at average cost.
E. Utility Plant & Depreciation
Utility plant is stated at historical cost, including an allowance for the cost
of funds used during construction (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, is as follows:
At and For the Year Ended December 31,
--------------------------------------
In millions 2001 2000
------------------------ ------------------------
Depreciation Depreciation
Rates as a Rates as a
Original Percent of Original Percent of
Cost Original Cost Cost Original Cost
-------- ------------- -------- -------------
Gas utility plant $1,523.0 3.6% $1,543.9 3.6%
Electric utility plant 1,148.9 3.3% 1,136.8 3.3%
Common utility plant 41.3 2.6% 47.3 3.3%
Construction work in progress 190.0 - 60.8 -
-------- ------- -------- -------
Total original cost $2,903.2 $2,788.8
======== ======= ======== =======
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 is as follows:
Year Ended December 31,
-----------------------
In millions 2001 2000 1999
----- ----- -----
AFUDC - equity funds $ 3.0 $ 2.6 $ 0.7
AFUDC - borrowed funds 2.6 2.6 2.9
----- ----- -----
Total AFUDC capitalized $ 5.6 $ 5.2 $ 3.6
===== ===== =====
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.
F. Non-utility Property
Non-utility property, net of accumulated depreciation and amortization, by
operating segment is as follows:
At December 31,
-------------------------
In millions 2001 2000
------- ------
Corporate & Other $ 103.2 $ 54.7
Nonregulated Operations 72.2 44.1
Electric & Gas Utility Services 6.3 5.6
------- -------
Non-utility property-net $ 181.7 $ 104.4
======= =======
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 $82.9 million and $53.6 million as of
December 31, 2001 and 2000, respectively.
G. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed for impairment in accordance with SFAS No. 121,
"Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" as facts and circumstances indicate that the carrying amount may be
impaired. Specifically, the evaluation for impairment involves 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 as a charge to operations based on the difference between the
asset's carrying amount and its fair value. (See Note 19 for further information
on the adoption of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets.") The same policy is currently utilized for goodwill.
H. Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the Indiana Utility Regulatory Commission (IURC), and retail
public utility operations affecting Ohio customers are subject to regulation by
the Public Utilities Commission of Ohio (PUCO). The Company's wholesale energy
transactions are subject to regulation by the Federal Energy Regulatory
Commission (FERC).
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 continually assesses the recoverability of costs recognized as
regulatory assets and the ability to continue to account for its activities in
accordance with SFAS 71, 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 costs of deregulated plant and inventory assets. Regulatory assets
consist of the following:
At December 31,
---------------
In millions 2001 2000
------ ------
Demand side management programs $ 26.2 $ 26.2
Unamortized debt discount & expenses 21.5 16.7
Other 13.7 13.4
------ ------
Total regulatory assets $ 61.4 $ 56.3
====== ======
As of December 31, 2001, $38.8 million of regulatory assets is reflected in
rates charged to customers. The remaining $22.6 million, which is not yet
included in rates, represents electric demand side management (DSM) costs
incurred after 1993. The Company is currently recovering $3.6 million of DSM
costs in rates. Based upon this prior regulatory authority, management believes
that future recovery of DSM costs not currently included in rates is probable.
At December 31, 2001 and 2000, the weighted average recovery period of
regulatory assets included in rates is 23.1 years and 23.3 years, respectively.
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 comprehensive income for the past three years is as follows:
1999 2000 2001
--------------------------- --------------- ---------------
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
Minimum pension liability
adjustments & other - (0.1) (0.1) 0.1 - (1.7) $ (1.7)
--------- ------- ------- ------- ------- ------- -------
Accumulated comprehensive
income $ - $ (0.1) $ (0.1) $ 7.6 $ 7.5 $ (3.3) $ 4.2
========= ======= ======= ======= ======= ======= =======
Accumulated comprehensive income arising from unconsolidated affiliates is the
Company's portion of ProLiance Energy, LLC's other comprehensive income related
to its adoption of SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," and continued use of cash flow hedges and other comprehensive
income related to unrealized gains and losses of available for sale securities
of Haddington Energy Partners, LP. (See Note 4 for more information on ProLiance
Energy, LLC and Haddington Energy Partners, LP.)
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 Taxes
Excise taxes are included in rates charged to customers. Accordingly, the
Company records excise tax received as a component of operating revenues. Excise
taxes paid are recorded as a component of taxes other than income taxes.
L. Reclassifications
Certain reclassifications have been made to the prior years' financial
statements to conform to the current year presentation. These reclassifications
have no impact on net income previously reported.
3. Special Charges
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. 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 have
been vacated.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
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 ($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.
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 has 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 incurred through
December 31, 2001. Components of restructuring expense incurred through December
31, 2001 are as follows:
Incurred Expenses Total
Accrual for -----------------------
In millions Cash Payments Paid in Cash Non-Cash Expense
------------- ------------ -------- -------
Severance & related costs $ 2.1 $ 8.0 $ 0.8 $ 10.9
Lease termination fees 3.0 - 1.0 4.0
Consulting fees & other - 4.1 - 4.1
------ ------ ----- ------
Total $ 5.1 $ 12.1 $ 1.8 $ 19.0
====== ====== ===== ======
The $10.9 million expensed for 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 have exited the business. The restructuring
program was completed during 2001, except for the departure of the remaining
employees impacted by the restructuring and the final settlement of the lease
obligation.
Components of the accrual for expected cash payments, which is included in
accrued liabilities, as of December 31, 2001 is as follows:
Accrual at Accrual at
June 30, Cash December 31,
In millions 2001 Payments Additions 2001
----------- -------- --------- ------------
Severance & related costs $ 6.8 $ (6.8) $ 2.1 $ 2.1
Lease termination fees 2.0 - 1.0 3.0
----- ------- ----- -----
Total $ 8.8 $ (6.8) $ 3.1 $ 5.1
===== ======= ===== =====
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 at cost 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 2001 2000
------ ------
Haddington Energy Partnerships $ 26.8 $ 13.0
ProLiance Energy, LLC 25.6 27.8
Reliant Services, LLC 20.6 19.2
Utilicom Networks, LLC & related entities 14.5 9.1
Pace Carbon Synfuels, LP 7.2 6.7
Other partnerships & corporations 33.0 32.8
------- -------
Total investments in unconsolidated affiliates $ 127.7 $ 108.6
======= =======
Haddington Energy Partnerships
The Company has an approximate 40% ownership interest in Haddington Energy
Partners, LP (Haddington). Haddington 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 is
expected to raise a total of approximately $50.0 million. This second fund plans
to provide additional capital for Haddington portfolio companies and make
investments in new areas, such as distributed generation, power backup and
quality devices, and emerging technologies such as fuel cells, microturbines and
photovoltaics. At December 31, 2001, $11.9 million of the commitment remains.
Upon complete funding, the Company will have an approximate 40% ownership
interest in Haddington II. Both Haddington ventures are accounted for using the
equity method of accounting. For the year ended December 31, 2001, the
partnerships' contribution to pre-tax earnings was $6.2 million. Prior to 2001,
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, 2001 revenues were $23.6 million and operating income and net
income were both $22.5 million. Revenues, operating income, and net loss for the
years ended December 31, 2000 and 1999 were (in millions) $0.0, ($0.9), ($0.9)
and $0.0, ($0.7), ($0.1), respectively. As of December 31, 2001, investments
were $79.1 million and other assets were $5.0 million. As of December 31, 2000,
investments were $31.5 million and other assets were $0.7 million. At both
December 31, 2001 and 2000, liabilities were $0.2 million.
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren, began providing natural gas and related services to Indiana Gas,
Citizens Gas and Coke Utility (Citizens Gas) and others in April 1996. ProLiance
also provides services to the Ohio operations. Effective in March 2001, the
operating agreement between Vectren and Citizens Gas was modified to increase on
a prospective basis Vectren's allocable share of profits and losses from 50% to
52.5%. The provisions of the operating agreement call for governance, including
voting rights, to remain at 50% for each member. Prior to March 2001, profits
and governance were 50% for each member. As governance of ProLiance remains
equal between the members, Vectren continues to account for its investment in
ProLiance using the equity method of accounting.
The sale of gas and provision of other services to Indiana Gas by ProLiance is
subject to regulatory review through the quarterly gas cost adjustment (GCA)
process administered by the IURC. 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. The IURC's decision reflected the significant gas cost
savings to customers obtained through ProLiance's services and suggested that
all material provisions of the agreements between ProLiance and the utilities
are reasonable. Nevertheless, 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 the pending, consolidated GCA proceeding
involving Indiana Gas and Citizens Gas.
The IURC has recently commenced processing the GCA proceeding regarding the
three pricing issues. The IURC has indicated that it will also consider the
prospective relationship of ProLiance with the utilities in this proceeding.
Discovery is ongoing, and an evidentiary hearing is scheduled for May 2002.
Until the IURC resolves these outstanding issues, the Company will continue to
reserve a portion of its share of ProLiance earnings.
Indiana Gas continues to record gas costs in accordance with the terms of the
ProLiance contract, and Vectren continues to record its proportional share of
ProLiance's earnings. Pre-tax income of $12.8 million, $5.4 million and $6.7
million was recognized as ProLiance's contribution to earnings for the years
ended December 31, 2001, 2000 and 1999, respectively. Earnings recognized from
ProLiance are included in equity in earnings of unconsolidated affiliates. At
December 31, 2001 and 2000, the Company has reserved approximately $3.2 million
and $2.4 million, respectively, of ProLiance's after tax earnings pending
resolution of the remaining issues. The reserve represents 10% of ProLiance's
cumulative earnings and serves as management's best estimate of potential
exposure arising from issues reserved by the IURC.
In August 1998, Indiana Gas, Citizens Gas and ProLiance each received a Civil
Investigative Demand (CID) from the United States Department of Justice
requesting information relating to Indiana Gas' and Citizens Gas' relationships
with and the activities of ProLiance. The Department of Justice issued the CID
to gather information regarding ProLiance's formation and operations, and to
determine if trade or commerce had been restrained. In October 2001, the
Antitrust Division of the Department of Justice informed the Company that it
closed the investigation without further action.
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2001, 2000 and 1999 totaled $610.6 million, $478.9
million and $240.7 million, respectively. Amounts owed to ProLiance at December
31, 2001 and 2000 for those purchases were $36.1 million and $147.2 million,
respectively, and are included in accounts payable to affiliated companies in
the Consolidated Balance Sheets. Amounts charged by ProLiance are market based
as evidenced by a competitive bidding process for capacity and storage services
and commodity indexes.
The following is summarized financial information as to the assets, liabilities,
and results of operations of ProLiance. For the year ended December 31, 2001,
revenues were $1,599.5 million, margin was $40.9 million, operating income was
$26.1 million, and net income was $27.7 million. For the year ended December 31,
2000, revenues were $945.8 million, margin was $21.1 million, operating income
was $10.4 million, and net income was $12.1 million. For the year ended December
31, 1999, revenues were $609.9 million, margin was $27.6 million, operating
income was $15.0 million, and net income was $14.8 million. As of December 31,
2001, current assets were $206.8 million, noncurrent assets were $24.3 million,
and current liabilities were $180.8 million. As of December 31, 2000, current
assets were $284.0 million, noncurrent assets were $9.4 million, and current
liabilities were $237.8 million. At both December 31, 2001 and 2000, noncurrent
liabilities were zero.
Utilicom Networks, LLC & Related Entities
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including cable television,
high-speed Internet, and advanced local and long distance telephone services.
The Company has a 14% interest in Class A units of Utilicom, which is accounted
for using the equity method of accounting. 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
investment in Holdings on the cost method. 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.
In January 2000, the Company restructured its investment in SIGECOM. Affiliates
of The Blackstone Group acquired a majority ownership interest in Utilicom in
the form of Class B units. 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. For the year ended December 31,
2000, the Company also recognized losses of $1.0 million to reflect its share of
Utilicom's operating results. The Company's share of Utilicom's operating
results for the year ended December 31, 2001 was not significant.
In December 2001, Utilicom announced plans to raise $600.0 million in capital to
establish separate operating ventures in Indianapolis and Dayton and to
recapitalize SIGECOM. The Company has committed to invest up to a total of
$100.0 million in Utilicom and the Indianapolis and Dayton ventures, subject to
Utilicom obtaining commitments for the entire $600.0 million of anticipated
funding. The Company's investments may take the form of convertible subordinated
debt or common equity. At December 31, 2001, the remaining commitment is $86.5
million.
At December 31, 2001, the Company has $24.8 million of notes receivable from
Utilicom-related entities which are convertible into equity interests. Notes
receivable totaling $22.9 million are convertible into Class A units of Utilicom
at the Company's option or upon the event of a public offering of stock by
Utilicom and $1.9 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.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is due to the
current 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 committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded. This delay
necessitated and resulted in the extension of the franchising agreements into
the third quarter of 2002.
At December 31, 2001 and 2000, the Company's combined investment in equity and
debt securities of Utilicom-related entities totaled $39.3 million and $32.5
million, respectively.
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. These projects generate IRS Section 29 tax credits. 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 Company's portion of pre-tax losses incurred
by Pace Carbon are included in equity in earnings of unconsolidated affiliates
and total $4.5 million in 2001, $2.4 million in 2000, and $1.4 million in 1999.
The contribution to the Company's earnings after considering the tax credits
Pace Carbon generated was $4.3 million in 2001, $2.1 million in 2000, and a loss
of $0.5 million in 1999.
The following is summarized financial information as to the assets, liabilities,
and results of operations of Pace Carbon. For the year ended December 31, 2001,
revenues were $86.2 million, margin was a loss of ($25.1) million, operating
loss was ($44.1) million, and net loss was ($44.8) million. For the year ended
December 31, 2000, revenues were $35.8 million, margin was a loss of ($24.3)
million, operating loss was ($33.6) million, and net loss was ($34.1) million.
For the year ended December 31, 1999, revenues were $3.5 million, margin was a
loss of ($8.2) million, operating loss was ($13.7) million, and net loss was
($13.7) million. As of December 31, 2001, current assets were $22.5 million,
noncurrent assets were $42.0 million, current liabilities were $18.2 million,
and noncurrent liabilities were $8.4 million. As of December 31, 2000, current
assets were $13.9 million, noncurrent assets were $38.4 million, current
liabilities were $11.3 million, and noncurrent liabilities were $8.0 million.
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 to
the Company. Fees for these services and construction-related expenditures
totaled $37.9 million, $20.9 million, and $20.2 million, respectively, for the
years ended December 31, 2001, 2000 and 1999. Amounts charged by these
affiliates are market based. Amounts owed to unconsolidated affiliates other
than ProLiance totaled $1.1 million and $3.2 million at December 31, 2001 and
2000, 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 $0.3 million and $1.2 million,
respectively, at December 31, 2001 and 2000.
In December 2000, Reliant Services, LLC (Reliant), an equity method investment
owned jointly and equally by Vectren and Cinergy Corp., purchased the common
stock of Miller Pipeline Corporation 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 and
electric facilities with Miller Pipeline Corporation's underground pipeline
construction, replacement, and repair services.
5. Other Investments
Other investments consist of the following:
At December 31,
-----------------------
In millions 2001 2000
------ ------
Notes receivable:
Utilicom Networks, LLC & related entities $ 24.8 $ 23.4
Other notes receivable 31.8 40.9
------ ------
Total notes receivable 56.6 64.3
------ ------
Leveraged leases 29.7 93.1
Other investments 14.0 14.1
------- -------
Total other investments $ 100.3 $ 171.5
======= =======
Notes Receivable
Interest rates on the above notes receivable range from fixed rates of 5% to 15%
and variable rates from prime plus 1.75% to prime plus 3% and are due at various
times through 2010. 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 $77.1 million and $409.7 million at December 31, 2001 and 2000,
respectively. 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 $59.0 million and $380.0 million at December
31, 2001 and 2000, respectively. The Company's net investment in leveraged
leases is as follows:
At December 31,
--------------------
In millions 2001 2000
------ -------
Minimum lease payments receivable $ 48.9 $ 165.1
Estimated residual value 22.1 29.1
Less: Unearned income 41.3 101.1
------ -------
Investment in lease financing receivables & loans 29.7 93.1
Less: Deferred taxes arising from leveraged leases 25.5 38.3
------ -------
Net investment in leveraged leases $ 4.2 $ 54.8
====== =======
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 of $46.7 million were used to retire short-term
borrowings.
6. Income Taxes
The components of income tax expense and utilization of investment tax credits
are as follows:
Year Ended December 31,
-------------------------------
In millions 2001 2000 1999
----- ------ ------
Current:
Federal $ 4.3 $ 37.1 $ 33.0
State 4.5 2.9 5.4
----- ------ ------
Total current taxes 8.8 40.0 38.4
----- ------ ------
Deferred:
Federal 12.5 (5.5) 8.3
State (0.4) 2.1 1.4
----- ------ ------
Total deferred taxes 12.1 (3.4) 9.7
----- ------ ------
Amortization of investment tax credits (2.3) (2.4) (2.4)
------ ------ ------
Total income tax expense $ 18.6 $ 34.2 $ 45.7
====== ====== ======
A reconciliation of the Federal statutory rate to the effective income tax rate
is as follows:
Year Ended December 31,
-------------------------------
2001 2000 1999
------- ------- -------
Statutory rate 35.0 % 35.0 % 35.0 %
State and local taxes-net of Federal benefit 3.2 3.1 3.2
Nondeductible merger costs - 4.0 -
Amortization of investment tax credit (2.7) (2.2) (1.7)
Other tax credits (11.1) (7.1) (3.2)
All other-net (2.8) (0.4) -
------- ------- -------
Effective tax rate 21.6 % 32.4 % 33.3 %
======= ======= =======
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Deferred investment tax credits are amortized over the life of
the related asset. Significant components of the net deferred tax liability are
as follows:
At December 31,
---------------------
In millions 2001 2000
------- -------
Deferred tax liabilities:
Depreciation & cost recovery timing differences $ 191.5 $ 178.7
Leveraged leases 25.5 38.3
Deferred fuel costs-net 22.7 20.3
Regulatory assets recoverable through future rates 33.5 34.0
Deferred tax assets:
Regulatory liabilities to be settled through
future rates (25.2) (22.1)
Tax credit carryforwards - (17.1)
LIFO inventory (2.0) (7.9)
Other - net (18.6) (7.8)
------- -------
Net deferred tax liability $ 227.4 $ 216.4
======= =======
The Company has no tax credit carryforwards at December 31, 2001. At December
31, 2000, the Company had Alternative Minimum Tax credit carryforwards of
approximately $13.0 million which 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. At December 31, 2000, the Company had such tax
credit carryforwards of approximately $4.1 million which were utilized in 2001.
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 performed as of and for the years ended December 31, 2001
and 2000 and use a measurement date as of September 30. The disclosures required
for the year ended December 31, 1999 have been restated based on actuarial
valuations previously performed for SIGCORP as of December 31 and Indiana Energy
as of September 30. In management's opinion, disclosures from revised actuarial
valuations would not differ materially from those presented below.
A summary of the components of net periodic benefit cost for the three years
ended December 31, 2001 is as follows:
Pension Benefits Other Benefits
------------------------ ---------------------
In millions 2001 2000 1999 2001 2000 1999
------ ------ ------ ------ ------ ------
Service cost $ 5.9 $ 4.3 $ 5.1 $ 1.0 $ 1.3 $ 1.5
Interest cost 13.6 11.7 10.5 5.8 5.9 4.9
Expected return on plan assets (16.3) (15.9) (13.9) (0.8) (0.8) (0.8)
Amortization of prior service cost 0.8 0.2 0.4 - - -
Amortization of transitional
obligation (asset) (0.6) (0.7) (0.7) 3.0 3.7 3.3
Amortization of actuarial gain (0.9) (1.1) - (1.0) (1.5) (0.9)
Settlement, curtailment, & other
charges (credits) (1.4) 2.7 - (0.6) - -
------ ------ ------ ------ ------ ------
Net periodic benefit cost $ 1.1 $ 1.2 $ 1.4 $ 7.4 $ 8.6 $ 8.0
====== ====== ====== ====== ====== ======
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, 2001 and 2000 follows:
Pension Benefits Other Benefits
------------------ ----------------
In millions 2001 2000 2001 2000
------------------ ----------------
Benefit Obligation
Benefit obligation at beginning of year $ 167.0 $ 151.5 $ 77.4 $ 68.3
Service cost - benefits earned during the year 5.9 4.3 1.0 1.3
Interest cost on projected benefit obligation 13.6 11.7 5.8 5.9
Plan amendments 9.5 2.4 - (0.7)
Acquisitions - 0.7 - -
Settlements & (curtailments) (1.5) 2.1 (0.6) -
Benefits paid (13.5) (10.4) (1.7) (5.4)
Actuarial loss 10.3 4.7 1.7 8.0
------ ------ ----- -----
Benefit obligation at end of year $ 191.3 $ 167.0 $ 83.6 $ 77.4
====== ====== ===== =====
Fair Value of Plan Assets
Plan assets at fair value at beginning of year $ 193.8 $ 187.3 $ 11.2 $ 11.7
Actual return on plan assets (20.9) 16.9 (1.6) 0.6
Employer contributions 0.7 - 0.9 4.3
Benefits paid (13.5) (10.4) (1.7) (5.4)
------ ------ ----- -----
Fair value of plan assets at end of year $ 160.1 $ 193.8 $ 8.8 $ 11.2
====== ====== ===== =====
Funded status $ (31.2) $ 26.8 $ (74.8) $ (66.2)
Unrecognized transitional obligation (asset) (0.8) (1.5) 34.9 40.0
Unrecognized service cost 12.0 5.4 - -
Unrecognized net (gain) loss and other 13.4 (36.9) (13.0) (19.7)
------ ------ ----- -----
Net amount recognized $ (6.6) $ (6.2) $ (52.9) $ (45.9)
====== ====== ===== =====
At December 31, 2001, the Company incurred additional minimum pension
liabilities totaling $7.3 million which are included in deferred credits and
other liabilities. These liabilities are offset by intangible assets totaling
$3.5 million which are included in other noncurrent assets and a pre-tax charge
to accumulated other comprehensive income totaling $3.8 million. At both
December 31, 2001 and 2000, the net amount recognized for other postretirement
benefits is included in deferred credits and other liabilities.
Pension plans with accumulated benefit obligations in excess of plan assets had
projected benefit obligations of $96.7 million and $10.5 million as of December
31, 2001 and 2000, respectively. Those plans had accumulated benefit obligations
of $84.5 million and $7.9 million as of December 31, 2001 and 2000,
respectively. The fair value of plan assets for such pension plans as of
December 31, 2001 was $73.9 million. As of December 31, 2000, such pension plans
were not funded.
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
----------------- -------------------
2001 2000 2001 2000
----------------- -------------------
Discount rate 7.25% 7.75% 7.25% 7.75%
Expected return on plan assets 9.00% 8.50% 9.00% 9.00%
Rate of compensation increase 4.75% 5.25% 4.75% 5.25%
CPI rate N/A N/A 12.00% 7.00%
----- ----- ------ -----
As of December 31, 2001, the health care cost trend rate is 12.0% declining to
5.0% 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, 2001:
In millions 1% Increase 1% Decrease
----------- -----------
Effect on the aggregate of the service &
interest cost components $ 0.6 $ (0.5)
Effect on the postretirement benefit
obligation 6.4 (5.3)
------ -------
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
2001, 2000 and 1999, the Company made contributions to these plans of $3.4
million, $1.6 million, and $1.9 million, respectively.
8. Borrowing Arrangements
Long-Term Debt Senior unsecured obligations and first mortgage bonds outstanding
and classified as long-term by subsidiary are as follows:
At December 31,
-------------------
In millions 2001 2000
-------- --------
VUHI
Fixed Rate Senior Unsecured Notes
2011, 6.625% $ 250.0 $ -
2031, 7.25% 100.0 -
------- --------
Total VUHI 350.0 -
------- --------
SIGECO
First Mortgage Bonds
Fixed Rate:
2003, 1978 Series B, 6.25%, tax exempt 1.0 1.0
2016, 1986 Series, 8.875% 13.0 13.0
2023, 1993 Series, 7.60% 45.0 45.0
2023, 1993 Series B, 6.00% 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, 1985 Pollution Control Series A, presently
4.30%, tax exempt, next rate adjustment: 2004 10.0 10.0
2025, 1998 Pollution Control Series A, presently
4.75%, tax exempt, next rate adjustment: 2006 31.5 31.5
2024, 2000 Environmental Improvement Series A,
tax exempt, adjusts every 35 days, weighted
average for year: 3.13% 22.5 22.5
------- -------
Total First Mortgage Bonds 245.8 245.8
------- -------
Adjustable Rate Senior Unsecured Bonds
2020, 1998 Pollution Control Series B, presently
4.40%, tax exempt, next rate adjustment: 2003 4.6 4.6
2030, 1998 Pollution Control Series B, presently
4.40%, tax exempt, next rate adjustment: 2003 22.0 22.0
2030, 1998 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 2001 2000
--------- --------
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 25.0 25.0
2021, Series A, 9.125% - 7.0
2025, Series E, 6.31% 5.0 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% 13.8 14.1
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% 50.0 50.0
--------- --------
Total Indiana Gas 273.8 281.1
--------- --------
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 Private Placement Fixed Rate
Senior Unsecured Notes 113.0 113.0
--------- --------
Other - 0.2
--------- --------
Total Vectren Capital Corp. & other 113.0 113.2
--------- --------
Total long-term debt outstanding 1,031.4 688.9
Less: Debt subject to tender 11.5 53.7
Maturities & sinking fund requirements 1.3 0.2
Unamortized debt premium & discount - net 4.6 3.0
--------- --------
Total long-term debt-net $1,014.0 $ 632.0
========= ========
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.
Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. VUHI has no significant independent assets or operations
other than the assets and operations of these subsidiary guarantors. 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 the hedging
arrangements (see Note 16) totaled $344.0 million and were used to reduce
existing debt outstanding under VUHI's short-term borrowing arrangements.
Vectren Capital Corp.
In December 2000, Vectren Capital 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 totaling $77.4 million were used to repay outstanding short-term
borrowings.
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 totaling $67.9 million were used to repay outstanding commercial paper
utilized for general corporate purposes.
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, 2001,
$279.3 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.
Consolidated maturities and sinking fund requirements on long-term debt subject
to mandatory redemption during the five years following 2001 (in millions) are
$1.3 in 2002, $17.3 in 2003, $16.3 in 2004, $39.3 in 2005, and $1.3 in 2006.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. 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 2001 (in millions) is $11.5 in 2002, $3.5 in 2004, $10.0 in 2005,
$53.7 in 2006 and $140.0 thereafter.
Of these debt instruments containing put options, the Company has $31.5 million
of adjustable rate pollution control series first mortgage bonds and $22.2
million of adjustable rate pollution control series unsecured senior notes which
could, at the election of the bondholder, be tendered to the Company when
interest rates are reset. Prior to the latest reset on March 1, 2001, the
interest rates were reset annually, and the bonds were presented as current
liabilities. Effective March 1, 2001, the bonds were reset for a five-year
period and have been classified as long-term debt.
Short-Term Borrowings
At December 31, 2001, the Company has approximately $540.0 million of short-term
borrowing capacity, including $360.0 million for its regulated operations and
$180.0 million for its nonregulated operations, of which approximately $85.8
million is available for regulated operations and $62.6 million is available for
nonregulated operations. The availability of short-term borrowing is reduced by
outstanding letters of credit totaling $11.1 million, primarily collateralizing
nonregulated activities. Included in regulated capacity is VUHI's credit
facility, which was renewed in June 2001 and extended through June 2002. As part
of the renewal, the facility's capacity decreased from $435.0 million to $350.0
million. Indiana Gas' $155.0 million commercial paper program expired in 2001
and was not required and, therefore, not renewed. See the table below for
interest rates and outstanding balances.
Year ended December 31,
--------------------------
In millions 2001 2000 1999
------- ------- -------
Weighted average total outstanding during the year $ 447.0 $ 316.7 $ 163.8
Weighted average interest rates during the year
Bank loans 6.77% 6.98% 5.76%
Commercial paper 4.39% 6.53% 5.40%
At December 31,
-----------------
2001 2000
------- -------
Bank loans $ 108.4 $ 146.5
Commercial paper 273.3 463.4
------- -------
Total short-term borrowings $ 381.7 $ 609.9
======= =======
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, 2001, the Company was in
compliance with all financial covenants.
9. Cumulative Preferred Stock of Subsidiary
Nonredeemable
Nonredeemable preferred stock contains call options that were exercised during
September 2001 for a total redemption price of $9.8 million. The 4.80%, $100 par
value preferred stock was redeemed at its stated call price of $110 per share,
plus accrued and unpaid dividends totaling $1.35 per share. The 4.75%, $100 par
value preferred stock was redeemed at its stated call price of $101 per share,
plus accrued and unpaid dividends totaling $0.97 per share. Prior to the
redemptions and as of December 31, 2000, there were 85,519 shares of the 4.80%
Series outstanding and 3,000 shares of the 4.75% Series outstanding.
Redeemable
In September 2001, the 6.50%, $100 par value preferred stock was redeemed for a
total redemption price of $7.9 million at $104.23 per share, plus $0.73 per
share in accrued and unpaid dividends. Prior to the redemption and as of
December 31, 2000, there were 75,000 shares outstanding.
As the 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, 2001 and
2000, there were 4,597 shares and 5,757 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 of $129.4 million were used principally to
repay outstanding commercial paper utilized for recent acquisitions and
investments.
Authorized, Reserved Common Shares
At December 31, 2001 and 2000, the Company was authorized to issue 190.0 million
shares of common stock. Of that amount, approximately 7.4 million and 3.4
million shares of common stock, respectively, were not issued, but reserved for
issuance through the Company's stock-based incentive plans and benefit plans,
and 114.9 million and 125.2 million shares of common stock, respectively, were
not issued and not reserved. These unreserved shares are 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, 2001:
2001 2000 1999
---------------------- ---------------------- ----------------------
Per Per Per
In millions, except Share Share Share
per share amounts Income Shares Amount Income Shares Amount Income Shares Amount
------ ------ ------ ------ ------ ------ ------ ------ ------
Basic EPS $63.6 66.7 $0.95 $72.0 61.3 $1.18 $90.7 61.3 $1.48
Effect of dilutive
stock equivalents 0.2 - 0.1 - 0.1
------ ------ ------ ------ ------ ------ ------ ------ ------
Diluted EPS $63.6 66.9 $0.95 $72.0 61.4 $1.17 $90.7 61.4 $1.48
====== ====== ====== ====== ====== ====== ====== ====== ======
Options to purchase 836,688 shares of common stock for the year ended December
31, 2001, 526,469 shares of common stock for the year ended December 31, 2000
and 99,973 shares of common stock for the year ended December 31, 1999 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 $22.54 to $24.05 in 2001; $19.83 to $24.05 in 2000 and
equaled $24.05 in 1999.
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. At the annual
shareholders meeting on April 25, 2001, shareholders approved the Company's
At-Risk Compensation Plan. On May 1, 2001, per the terms of the plan, 4,000,000
shares of common stock were reserved for issuance in the form of stock options,
restricted stock, and other awards. The Company applies APB Opinion 25,
"Accounting for Stock Issued to Employees" and related interpretations when
measuring compensation expense for these plans. The pro forma effect on net
income and earnings per share, as if the fair value-based method had been
applied in measuring compensation expense, is disclosed below.
Stock Option Plans
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.
A summary of the status of the Company's stock option plans for the past three
years is as follows:
Wtd. Avg.
Options Exercise Price
---------- --------------
Outstanding at December 31, 1998 671,389 $ 17.46
Granted 272,783 20.26
Exercised (13,168) 14.22
---------- --------------
Outstanding at December 31, 1999 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
========== ==============
Stock options granted in 2001 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. Options granted both before and after 2001 expire
ten years from the date of grant. 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. Had compensation cost for these stock option plans
been determined based on the fair value at the grant date consistent with the
methodology prescribed under SFAS No. 123 "Accounting for Stock-Based
Compensation," net income would have been reduced by $1.1 million in 2001, $0.4
million in 2000, and $0.6 million in 1999. Basic and diluted earnings per share
would have been reduced by $0.02 in 2001and $0.01 in both 2000 and 1999.
The fair value of each option granted used to determine pro forma net income 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, 2001 and 1999: risk-free interest rate of 5.65% and 6.46%,
respectively; expected option term of 8 years and 5 years, respectively;
expected volatility of 26.56% and 34.00%, respectively; and dividend rates of
4.42% and 4.46%, respectively. The weighted average fair value of options
granted in 2001 and 1999 were $5.21 and $5.05, respectively. No options were
granted in 2000.
The following table summarizes information about stock options outstanding and
exercisable at December 31, 2001:
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 - $17.44 243,165 3.0 $ 14.63 243,165 $ 14.63
$19.83 - $20.26 349,925 6.5 20.09 349,925 20.09
$22.54 - $24.05 834,688 9.1 22.66 65,689 24.05
--------------- ------------ ---------------- -------- ------------ ---------
Total 1,427,778 20.67 658,779 18.47
=============== ============ ================ ======== ============ =========
As of December 31, 2000 and 1999, the number of stock options that are
exercisable and those options' weighted average exercise price is 781,415 and
$18.41 in 2000; and 658,221 and $17.53 in 1999.
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 salary. 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. During the years ended December 31, 2001, 2000 and 1999, the number of
restricted stock grants and the grants' weighted average fair value was 4,257
and $22.54 per share, respectively, in 2001, 194,884 shares and $19.90 per
share, respectively, in 2000, and 15,238 shares and $23.20 per share,
respectively, in 1999. During 2001, 19,726 restricted shares were forfeited.
Members of management 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 these plans for the years ended December
31, 2001, 2000, and 1999 was $2.8 million, $2.9 million and $0.9 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
Rental 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 2001 and thereafter (in millions) are $4.4 in 2002, $4.5 in
2003, $3.9 in 2004, $3.0 in 2005, $3.0 in 2006 and $5.6 thereafter. Total lease
expense (in millions) was $6.2 in 2001, $3.4 in 2000 and $2.7 in 1999.
Construction Commitments
The Company has entered into a contract to purchase and construct an 80-megawatt
combustion gas turbine generator. The total cost of the project is estimated to
be $33.0 million and is expected to be completed by the summer of 2002. Through
December 31, 2001, $23.2 million has been expended.
Guarantees
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees include debt guarantees and performance guarantees, including the
debt of and performance of energy efficiency products installed by affiliated
companies. The Company estimates these guarantees totaled $114.6 million at
December 31, 2001. Of that amount, $82.9 million relates to the Company's
guarantee of Energy Systems Group, LLC's surety bonds and performance
guarantees. Energy Systems Group, LLC is a two-thirds owned consolidated
subsidiary.
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
Culley Generating Station Litigation and Note 4 regarding ProLiance Energy, LLC.
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
United States Environmental Protection Agency (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 1998 and 1999.
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
(Warrick), and A.B. Brown Generating Station Unit 2 (A.B. Brown). SCR systems
reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in
chemical reaction. This technology is known to be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC issued an order that (1) approves the Company's proposed project to
achieve environmental compliance by investing in clean coal technology, (2)
approves the Company's cost estimate for the construction, subject to periodic
review of the actual costs incurred, and (3) approves a mechanism whereby, prior
to an electric base rate case, the Company may recover a return on its capital
costs for the project, at its overall cost of capital, including a return on
equity.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost ranges from $175.0 million to $195.0 million and is expected
to be expended during the 2001-2004 period. Through December 31, 2001, $22.5
million has been expended. After the equipment is installed and operational,
related additional annual operation and maintenance expenses are estimated to be
between $8.0 million and $10.0 million.
The Company expects the Culley, Warrick and A.B. Brown SCR systems to be
operational by the compliance date. Installation of SCR technology at these
stations is expected to reduce the Company's overall NOx emissions to levels
compliant with Indiana's NOx emissions budget allotted by the USEPA; therefore,
the Company has recorded no accrual for potential penalties that may result from
noncompliance.
Culley Generating Station Litigation In the late 1990's, the USEPA initiated an
investigation under Section 114 of the Act of SIGECO's coal-fired electric
generating units in commercial operation by 1977 to determine compliance with
environmental permitting requirements related to repairs, maintenance,
modifications, and operations changes. The focus of the investigation was to
determine whether new source review permitting requirements were triggered by
such plant modifications, and whether the best available control technology was,
or should have been used. Numerous electric utilities were, and are currently,
being investigated by the USEPA under an industry-wide review for compliance. In
July 1999, SIGECO received a letter from the Office of Enforcement and
Compliance Assurance of the USEPA discussing the industry-wide investigation,
vaguely referring to an investigation of SIGECO and inviting SIGECO to
participate in a discussion of the issues. No specifics were noted; furthermore,
the letter stated that the communication was not intended to serve as a notice
of violation. Subsequent meetings were conducted in September and October 1999
with the USEPA and targeted utilities, including SIGECO, regarding potential
remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair and replacement activities
at the Culley Generating Station, as allowed under the Act. Because proper
maintenance does not require permits, application of the best available control
technology, notice to the USEPA, or compliance with new source performance
standards, SIGECO believes that the lawsuit is without merit, and intends to
vigorously defend itself.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. The lawsuit does not specify the number of days or violations the
USEPA believes occurred. 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 it would incur capital costs of approximately $40.0 million to $50.0
million to comply with the order. As a result of the NOx SIP call issue, the
majority of the $40.0 million to $50.0 million for best available emissions
technology at Culley Generating Station is included in the $175.0 million to
$195.0 million cost range previously discussed.
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 Indiana Department of Environmental Management
(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 expert 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 accrued 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 its $20.4 million accrual.
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.
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 Indiana Office
of Utility Consumer Counselor (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 has been 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 2002
and additional settlement discussions are expected in 2002. 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
Risk Management
The Company is exposed to market 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.
Commodity Price Risk The Company's regulated operations have limited exposure to
commodity price risk for purchases and sales of natural gas and electric energy
for its retail customers due to current Indiana and Ohio regulations, which
subject to compliance with applicable state regulations, allow for recovery of
such purchases through natural gas and fuel cost adjustment mechanisms.
The Company does engage in limited wholesale power marketing and other marketing
activities that may expose it to commodity price risk associated with
fluctuating electric power, natural gas, and coal commodity prices.
The Company's wholesale power marketing activities manage the utilization of its
available electric generating capacity. The Company's other commodity marketing
activities purchase and sell natural gas and coal to meet customer demands.
These operations enter into forward contracts that commit the Company to
purchase and sell commodities in the future.
Commodity price risk results from forward sales contracts that commit the
Company to deliver commodities on specified future dates. Power marketing uses
planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.
Additionally, other commodity marketing activities use stored inventory and
forward purchase contracts to protect certain sales transactions from
unanticipated fluctuations in commodity prices.
Open positions in terms of price, volume and specified delivery points may occur
to a limited extent 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.
Under normal circumstances, 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 this exposure to counter-party credit
risk by entering into contracts with financially sound companies that can be
expected to fully perform under the terms of the contract. The Company attempts
to manage exposure to market risk associated with commodity contracts and
interest rates by establishing and monitoring parameters that limit the types
and degree of market risk that may be undertaken. As of December 31, 2001, the
Company has a net receivable from Enron Corp. of approximately $1.0 million,
which has been fully reserved.
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.
Accounting for Forward Contracts & Other Financial Instruments
Commodity Contracts At origination, all contracts to buy and sell electric
power, natural gas, and coal are designated as "physical" or
"other-than-trading." The Company does not have any contracts designated as
"trading" as defined by EITF 98-10.
Power marketing contracts are designated as "physical" when there is intent and
ability to physically deliver power from SIGECO's unutilized generating
capacity. Power marketing contracts are designated as "other-than-trading" when
there is intent to receive power to manage base and peak load capacity. Both
contract designations generally require settlement by physical delivery of
electricity. However, certain of these contracts may be net settled in
accordance with industry standards when unplanned outages, favorable pricing
movements, and shifts in demand occur.
Prior to the adoption of SFAS 133, contracts in the "physical" and
"other-than-trading" portfolios received accounting recognition on settlement
with revenues recorded in electric utility revenues and costs recorded in fuel
for electric generation for those contracts fulfilled through generation and in
purchased electric energy for contracts purchased in the wholesale energy
market. Subsequent to the adoption of SFAS 133, certain contracts that are
periodically settled net are recorded at market value.
Other commodity contracts are designated as "physical" when the Company has the
intent to physically deliver or receive natural gas or coal. Certain contracts
in this portfolio may be settled net in accordance with industry standards.
71
Prior to the adoption of SFAS 133, "physical" contracts received accounting
recognition upon settlement with revenues recorded in energy services and other
revenues and costs recorded in cost of energy services and other. After the
adoption of SFAS 133, certain contracts that are periodically settled net are
recorded at market value.
Contracts recorded at market value are recorded as current or noncurrent assets
or liabilities in the Consolidated Balance Sheets depending on their value and
on when the contracts are expected to be settled. Changes in market value are
recorded in the Consolidated Statements of Income as purchased electric energy
or cost of energy services and other, as appropriate. Market value is determined
using quoted market prices from independent sources.
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 in other assets or other current
liabilities, as appropriate, and changes in market value are recorded in
accumulated other comprehensive income and recorded to interest expense as
settled.
Impact of New Accounting Principle
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
which requires 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 accounting criteria are met.
SFAS 133, as amended, requires that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income or other comprehensive income, as appropriate, as the 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 contracts in the power
marketing operations and other wholesale 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
$6.3 million ($3.9 million net of tax) recorded as a cumulative effect of
accounting change in the Consolidated Statements of Income. The majority of this
gain results from the Company's 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.
As of December 31, 2001, the Company has derivative assets resulting from its
power marketing operations of $5.2 million classified in other current assets as
well as derivative liabilities of $2.0 million classified in accrued
liabilities. Unrealized losses totaling $3.2 million arising from the difference
between the current market value and the market value on the date of adoption is
included in purchased electric energy in the Consolidated Statements of Income
for the year ended December 31, 2001. Derivatives used in other commodity
marketing operations are not significant.
The Company assesses and documents the hedging relationship between its
financial instruments, including 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, these
instruments are designated as cash flow hedges. The adoption of SFAS 133 had no
impact as the market value of the Company's cash flow hedges was zero on January
1, 2001.
As of December 31, 2001, no interest rate swaps are outstanding. Approximately
$0.9 million remains in accumulated other comprehensive income that is related
to interest rate swaps hedging future interest payments. Of that amount, $0.1
million will be reclassified to earnings within the next twelve months.
In addition to the Company's wholly owned subsidiaries, ProLiance, an equity
method investment, adopted SFAS 133 during 2000. The Company's share of the
impact of adoption and continued use of derivatives by ProLiance is reflected in
accumulated other comprehensive income due to the nature of the derivatives
used.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments were as follows:
At December 31,
----------------------------------------
2001 2000
------------------- -------------------
Carrying Est. Fair Carrying Est. Fair
In millions Amount Value Amount Value
-------- --------- -------- ---------
Long-term debt $1,031.4 $1,022.4 $ 688.9 $ 672.4
Short-term borrowings & notes payable 381.7 381.7 759.9 759.9
Redeemable preferred stock of subsidiary - - 7.5 7.7
Partnership obligations - - 0.2 0.3
-------- --------- -------- ---------
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.
Because of the customized nature of certain cost method investments included in
investments in unconsolidated affiliates and notes receivable included in other
investments, and since there is no readily available market for these
investments, it is not practicable to estimate the fair value of these financial
instruments.
17. Additional Operational & Balance Sheet Information
Other - net in the Consolidated Statements of Income consists of the following:
Year ended December 31,
-----------------------
In millions 2001 2000 1999
------ ------ ------
Interest income $ 5.7 $ 8.6 $ 5.8
Leveraged lease investment income 4.6 7.7 4.2
AFUDC 5.6 5.2 3.6
Other income 6.0 7.2 2.6
Other expense (5.6) (5.0) (2.3)
------ ------ ------
Total other - net $16.3 $23.7 $13.9
====== ====== ======
73
Other current assets in the Consolidated Balance Sheets consists of the
following:
At December 31,
---------------
In millions 2001 2000
------- ------
Prepaid gas delivery service $ 67.7 $ 34.8
Other prepayments & current assets 35.7 27.5
------- ------
Total prepayments & other current assets $ 103.4 $ 62.3
======= ======
Accrued liabilities in the Consolidated Balance Sheets consists of the
following:
At December 31,
---------------
In millions 2001 2000
------- -------
Deferred income taxes $ 20.7 $ -
Refunds to customers & customer deposits 18.7 22.9
Accrued interest 13.3 10.3
Accrued taxes 9.4 17.6
Other 39.3 55.4
------- -------
Total accrued liabilities $ 101.4 $ 106.2
======= =======
18. Segment Reporting
The Company had four operating segments during 2001: (1) Gas Utility Services,
(2) Electric Utility Services, (3) Nonregulated Operations, and (4) Corporate
and Other. 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 in nearly
two-thirds of Indiana and west central Ohio. The Electric Utility Services
segment includes the operations of SIGECO's power generating and marketing
operations, and electric transmission and distribution services, which provides
electricity to primarily southwestern Indiana. 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 provides general and administrative support and
assets, including computer hardware and software, to the Company's other
operating segments. During 2001, the Company reorganized its business segments
by separating the Corporate and Other segment from the Nonregulated Operations
segment. Prior year data has been restated to conform to the current year
presentation.
The following tables provide information about business 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 2001 2000 1999
---------- -------- ---------
Operating Revenues
Gas Utility Services $ 1,031.5 $ 818.8 $ 499.6
Electric Utility Services 378.9 336.4 307.5
Nonregulated Operations 797.1 519.2 281.7
Corporate & Other 29.7 33.6 33.2
Intersegment Eliminations (67.2) (59.3) (53.6)
---------- -------- ---------
Total operating revenues $ 2,170.0 $ 1,648.7 $ 1,068.4
========== ========== =========
Interest Expense
Gas Utility Services $ 51.0 $ 28.0 $ 19.3
Electric Utility Services 19.1 18.1 17.5
Nonregulated Operations 12.2 10.2 6.1
Corporate & Other 1.6 1.3 0.9
Intersegment Eliminations (1.3) (1.2) (0.9)
---------- ---------- ----------
Total interest expense $ 82.6 $ 56.4 $ 42.9
========== ========== ==========
Income Taxes
Gas Utility Services $ 2.4 $ 11.5 $ 18.9
Electric Utility Services 20.3 23.4 24.3
Nonregulated Operations (5.0) 0.7 0.6
Corporate & Other 0.9 (1.2) 1.9
Intersegment Eliminations - (0.2) -
---------- ---------- ----------
Total income taxes $ 18.6 $ 34.2 $ 45.7
========== ========== ==========
Net Income
Gas Utility Services $ 9.9 $ 15.6 $ 33.6
Electric Utility Services 40.8 36.8 41.8
Nonregulated Operations 11.3 21.7 12.5
Corporate & Other 1.6 (2.1) 2.8
---------- ---------- ----------
Net income $ 63.6 $ 72.0 $ 90.7
========== ========== ==========
Depreciation & Amortization
Gas Utility Services $ 58.2 $ 43.8 $ 38.7
Electric Utility Services 38.7 38.6 40.8
Nonregulated Operations 5.9 1.1 0.7
Corporate & Other 20.9 22.2 6.8
---------- ---------- ----------
Total depreciation & amortization $ 123.7 $ 105.7 $ 87.0
========== ========== ==========
Capital Expenditures
Gas Utility Services $ 76.1 $ 73.1 $ 72.5
Electric Utility Services 69.7 37.6 51.1
Nonregulated Operations 33.5 27.3 1.7
Corporate & Other 56.0 26.3 10.6
--------- --------- ----------
Total capital expenditures $ 235.3 $ 164.3 $ 135.9
========= ========= ==========
At December 31,
---------------
In millions 2001 2000
---------- ----------
Identifiable Assets
Gas Utility Services $ 1,557.7 $ 1,630.0
Electric Utility Services 802.1 806.3
Nonregulated Operations 677.7 672.0
Corporate & Other 147.3 85.1
Intersegment Eliminations (328.0) (267.1)
---------- ----------
Total identifiable assets $ 2,856.8 $ 2,926.3
========== ==========
19. Impact of Recently Issued Accounting Guidance
SFAS 141 & 142
The FASB issued two new statements of financial accounting standards in July
2001: SFAS No. 141, "Business Combinations" (SFAS 141), and SFAS No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). These interrelated standards
change the accounting for business combinations and goodwill in two significant
ways:
SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001. Use of the
pooling-of-interests method is prohibited. This change does not affect the
pooling-of-interest transaction forming Vectren.
SFAS 142 changes the accounting for goodwill from an amortization approach to an
impairment-only approach. Thus, amortization of goodwill that is not included as
an allowable cost for rate-making purposes will cease upon adoption of the
statement. This includes goodwill recorded in past business combinations, such
as the Company's acquisition of the Ohio operations. Goodwill is to be tested
for impairment at a reporting unit level at least annually.
SFAS 142 also requires the initial impairment review of all goodwill and other
intangible assets within six months of the adoption date, which is January 1,
2002 for the Company. 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 would be
recognized. Results of the initial impairment review are to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations.
SFAS 142 also changes certain aspects of accounting for intangible assets;
however, the Company does not have any significant intangible assets.
The adoption of SFAS 141 will not materially impact operations. As required by
SFAS 142, amortization of goodwill relating to the acquisition of the Ohio
operations, which approximates $5.0 million per year, will cease on January 1,
2002. Initial impairment reviews to be performed within six months of adoption
of SFAS 142 are not expected to have a significant impact on operations.
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. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
SFAS 144 is effective for fiscal years beginning after December 15, 2001, with
earlier application encouraged. The Company is evaluating the impact SFAS 144
will have on its operations.
20. Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for 2001 and 2000 is as follows:
In millions, except per share amounts Q1 Q2 Q3 Q4
---------------------------------------------------------------------------------------------
2001
---------------------------------------------------------------------------------------------
Operating revenues $883.1 $432.2 $358.4 $496.3
Operating income (loss) 72.7 (4.6) 19.1 52.4
Income (loss) before extraordinary loss & cumulative
effect of change in accounting principle 40.5 (10.0) 4.5 32.4
Basic earnings (loss) per share before extraordinary
loss & cumulative effect of change in accounting
principle 0.62 (0.15) 0.07 0.48
Diluted earnings (loss) per share before extraordinary
loss & cumulative effect of change in accounting
principle 0.61 (0.15) 0.07 0.48
Net income (loss) 44.4 (17.7) 4.5 32.4
Basic earnings (loss) per share 0.68 (0.26) 0.07 0.48
Diluted earnings (loss) per share 0.67 (0.26) 0.07 0.48
---------------------------------------------------------------------------------------------
2000
---------------------------------------------------------------------------------------------
Operating revenues $359.5 $263.7 $317.9 $707.6
Operating income 34.3 16.3 27.2 53.3
Net income 22.1 8.3 15.4 26.2
Basic earnings per share 0.36 0.14 0.25 0.43
Diluted earnings per share 0.36 0.13 0.25 0.43
---------------------------------------------------------------------------------------------
1. Information in any one quarterly period is not indicative of annual results
due to the seasonal variations common to the Company's utility operations.
2. Q1 of 2001 includes charges for cumulative effect of changes in accounting
principle as described in Note 16.
3. Q2 of 2001 includes restructuring charges as described in Note 3.
4. Q2 of 2001 includes an extraordinary loss as described in Note 5.
5. 2001 & 2000 include merger and integration charges as described in Note 3.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None
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 2001 Annual Meeting of
Stockholders, which was filed with the Securities and Exchange Commission,
pursuant to Regulation 14A, on March 15, 2002. The information with respect to
the executive officers of the Registrant is included below.
Niel C. Ellerbrook, age 53, 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 Fifth
Third Bank, Indiana, and Deaconess Hospital of Evansville, Indiana.
Andrew E. Goebel, age 54, 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.
Jerome A. Benkert, Jr., age 43, 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. 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., and Southern Indiana Gas and Electric Co.
Carl L. Chapman, age 46, has served as Executive Vice President of the Company
since March 2000. Mr. Chapman served as Assistant Treasurer of Indiana Energy
from 1986 to March 2000. Since October 1997, Mr. Chapman has served as President
of IGC Energy, Inc., which has been renamed Vectren Energy Solutions, Inc. Mr.
Chapman served as President of ProLiance Energy, LLC ("ProLiance"), a gas supply
and energy marketing joint venture partially owned by Vectren Energy Solutions,
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.
Ronald E. Christian, age 43, 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 50, 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 2002 Annual Meeting of Stockholders, which was filed
with the Securities and Exchange Commission, pursuant to Regulation 14A, on
March 15, 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
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 2002 Annual Meeting of Stockholders, which was filed
with the Securities and Exchange Commission, pursuant to Regulation 14A, on
March 15, 2002.
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 2002 Annual Meeting of Stockholders, which was filed
with the Securities and Exchange Commission, pursuant to Regulation 14A, on
March 15, 2002.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) List Of Documents Filed As Part Of This Report
(1) Consolidated Financial Statements
The consolidated financial statements and related notes, together with
the report of Arthur Andersen LLP, appear in Part II Item 8 Financial
Statements and Supplementary Data of this Form 10-K.
(2) Consolidated Financial Statement Schedules
PAGE IN FORM 10-K
-----------------
Report of Arthur Andersen LLP 79
For the years ended December 31, 2001,
2000, and 1999: Schedule II --
Valuation and Qualifying Accounts 80
All other schedules are omitted as the required information is inapplicable or
the information is presented in the Consolidated Financial Statements or related
notes.
(3) 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 83. Exhibits for the Company attached to this filing are
listed on page 89.
(b) Reports On Form 8-K During The Last Calendar Quarter
On October 24, 2001 and November 26, 2001, 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, six, and nine month periods ended
September 30, 2001. The financial information was released to the public through
this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Third Quarter 2001 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 26, 2001, 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 to Update Business Strategies
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Vectren Corporation:
We have audited in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements included in Vectren
Corporation's annual report to shareholders included in this Form 10-K, and have
issued our report thereon dated January 24, 2002. Our audit was made for the
purpose of forming an opinion on those statements taken as a whole. The schedule
listed in Item 14(a)(2) is the responsibility of the Company's management and is
presented for the purpose of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. The
schedule has been subjected to the auditing procedures applied in the audit of
the basic financial statements, and in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Indianapolis, Indiana,
January 24, 2001.
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:
Year 2001 - Accumulated provision for
uncollectible accounts $ 5.7 $ 17.3 $ - $ 17.1 $ 5.9
Year 2000 - Accumulated provision for
uncollectible accounts $ 3.9 $ 7.7 $ 0.5 $ 6.4 $ 5.7
Year 1999 - Accumulated provision for
uncollectible accounts $ 3.9 $ 4.0 $ - $ 4.0 $ 3.9
OTHER RESERVES:
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 2001 - Reserve for restructuring
costs $ - $ 11.9 $ - $ 6.8 $ 5.1
Year 2001 - Reserve for injuries
and damages $ 1.8 $ 2.9 $ - $ 3.0 $ 1.7
Year 2000 - Reserve for injuries
and damages $ 1.5 $ 0.9 $ - $ 0.6 $ 1.8
Year 1999 - Reserve for injuries
and damages $ 1.3 $ 0.6 $ - $ 0.4 $ 1.5
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
VECTREN CORPORATION
Dated March 28, 2002
/S/ Niel C. Ellerbrook
Niel C. Ellerbrook, Chairman and Chief
Executive Officer, Director
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in capacities and on the dates indicated.
Signature Title Date
/S/ Niel C. Ellerbrook Chairman & Chief Executive March 28, 2002
------------------------------- Officer, Director (Principal --------------
Niel C. Ellerbrook Executive Officer)
/S/ Jerome A. Benkert, Jr. Executive Vice President, March 28, 2002
------------------------------- Chief Financial Officer, & --------------
Jerome A. Benkert, Jr. Treasurer (Principal Financial
Officer)
/S/ M. Susan Hardwick Vice President & Controller March 28, 2002
------------------------------ (Principal Accounting Officer) ---------------
M. Susan Hardwick
/S/ John M. Dunn Director March 28, 2002
------------------------------ --------------
John M. Dunn
/S/ John D. Engelbrecht Director March 28, 2002
------------------------------ --------------
John D. Engelbrecht
/S/ Lawrence A. Ferger Director March 28, 2002
------------------------------ --------------
Lawrence A. Ferger
/S/ Anton H. George Director March 28, 2002
------------------------------ --------------
Anton H. George
/S/ Andrew E. Goebel Director March 28, 2002
------------------------------ --------------
Andrew E. Goebel
/S/ Robert L. Koch II Director March 28, 2002
------------------------------ --------------
Robert L. Koch II
/S/ William G. Mays Director March 28, 2002
------------------------------ --------------
William G. Mays
/S/ J. Timothy McGinley Director March 28, 2002
------------------------------ --------------
J. Timothy McGinley
/S/ Richard P. Rechter Director March 28, 2002
------------------------------ --------------
Richard P. Rechter
/S/ Ronald G. Reherman Director March 28, 2002
------------------------------ --------------
Ronald G. Reherman
/S/ Richard W. Shymanski Director March 28, 2002
------------------------------ --------------
Richard W. Shymanski
/S/ Jean L.Wojtowicz Director March 28, 2002
------------------------------ --------------
Jean L.Wojtowicz
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.)
3. 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 Code of By-Laws of Vectren Corporation. (Filed and designated in Form S-3
(No. 333-5390), filed January 19, 2001, File No. 1-15467, as Exhibit 4.2.)
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
herewith.)
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 $350.0 million Credit Agreement arranged by Banc One Capital Markets, Inc.
dated as of June 28, 2001 among Vectren Utility Holdings, Inc., as
borrower; Indiana Gas Company, Inc. as guarantor; Southern Indiana Gas and
Electric Company, as guarantor; Vectren Energy Delivery of Ohio, Inc., as
guarantor; and Lenders: Banc One, NA, as Agent; Firstar Bank, N.A., as
Co-Syndication Agent; ABN AMRO Bank, N.V., as Co-Syndication Agent; The
Bank of New York, as Co-Documentation Agent; The Industrial Bank of Japan,
Limited, as Co-Documentation Agent; the Fuji Bank, Limited, as
Co-Documentation Agent; and National City Bank of Indiana, as Co-Agent.
(Filed and designated on Form 10-K for the year ended December 31, 2001,
File No. 1-16739, as Exhibit 4.3.)
4.4 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).
9. Voting Trust Agreement
Not applicable.
10. Material Contracts
10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power
Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern
Indiana Gas and Electric Company. (Filed and designated in Registration No.
2-29653 as Exhibit 4(d)-A.)
10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June
26, 1969, between Alcoa and Southern Indiana Gas and Electric Company.
(Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.)
10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-53005 as Exhibit 4(e)-4.)
10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971,
between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
designated in Registration No. 2-41209 as Exhibit 4(e)-1.)
10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and
Letter Agreement dated April 30, 1973 - First Supplement. (Filed and
designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as
Exhibit 1(e).)
10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.)
10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and
Electric Company and Alcoa, which amends Agreement for Sale in an Emergency
of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas
and Electric Company dated June 26, 1979. (Filed and designated in Form
10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.)
10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-3.)
10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed
and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as
Exhibit A-5.)
10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement.
(Filed and designated in Form 10-K for the fiscal year 1979, File No.
1-3553, as Exhibit A-6.)
10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power
Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and
Electric Company. (Filed and designated in Form 10-K for the fiscal year
1980, File No. 1-3553, as Exhibit (20)-1.)
10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power Generating
Inc. and Southern Indiana Gas and Electric Company. (Filed herewith.)
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. (Filed and designated in Form
10-Q for the quarterly period ended September 30, 2000, File No. 1-15467,
as Exhibit 99.1.)
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 herewith.)
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 herewith.)
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 herewith.)
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 herewith.)
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 herewith.)
10.44 Vectren Corporation Retirement Agreement between Vectren Corporation and
Thomas J. Zabor dated as of May 31, 2001. (Filed herewith.)
11. Statement Re Computation Of Per Share Earnings
Not applicable.
12. Statements Re Computation Of Ratios
Not applicable.
13. Annual Report To Security Holders, Form 10-Q Or Quarterly Report To
Security Holders
Not applicable.
16. Letter Re Change In Certifying Accountant
Not applicable.
18. Letter Re Change In Accounting Principles
Not applicable.
21. Subsidiaries Of The Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit
21.1.
22. Published Report Regarding Matters Submitted To Vote Of Security Holders
Not applicable.
23. Consents Of Experts And Counsel
The consent of Arthur Andersen LLP is attached hereto as Exhibit 23.1.
24. Power Of Attorney
Not applicable.
99. Additional Exhibits
99.1 Current Report on Form 8-K, regarding replacement of the Company's
independent auditors, dated March 22, 2002 (Filed herewith.)
99.2 Letter regarding audit quality representation of
Arthur Andersen LLP (Filed herewith).
Vectren Corporation
2001 Form 10-K
Attached Exhibits
The following Exhibits are attached hereto. See Page 85 of this Annual Report on
Form 10-K for a complete list of exhibits.
Exhibit
Number Document
4.1 Supplemental Indenture to Mortgage and Deed of Trust dated March 1,
2000 between Southern Indiana Gas and Electric Company and Bankers
Trust Company, as Trustee.
10.12 Amendment Agreement between Alcoa Power Generating Inc. and Southern
Indiana Gas and Electric Company
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.
10.32 Vectren Corporation Non-Qualified Deferred Compensation Plan, as
amended and restated effective January 1, 2001.
10.39 Vectren Corporation Retirement Agreement between Vectren Corporation
and Timothy M. Hewitt
10.41 Vectren Corporation Retirement Agreement between Vectren Corporation
and J. Gordon Hurst
10.43 Vectren Corporation Employment Agreement between Vectren Corporation
and William S. Doty
10.44 Vectren Corporation Retirement Agreement between Vectren Corporation
and Thomas J. Zabor dated as of May 31, 2001. (Filed herewith.)
21.1 Subsidiaries of the Company
23.1 Consent of Independent Public Accountants
99.1 Current Report on Form 8-K, regarding the replacement of the Company's
independent auditors, dated March 22, 2002.
99.2 Letter regarding audit quality representation of Arthur Andersen LLP