UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________________ to _____________________
Commission file number: 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of incorporation (IRS Employer
or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 812-491-4000 Securities
registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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Common - Without Par New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X|. No ___.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X|. No __.
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
30, 2003, was $1,691,200,174.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Common Stock - Without Par Value 75,792,899 January 30, 2004
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Class Number of Shares Date
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2004
Annual Meeting of Stockholders, which will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A, not later than 120 days after
the end of the fiscal year, is incorporated by reference in Part III of this
Form 10-K.
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions of
megawatt hours (gigawatt hour)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission
IDEM: Indiana Department of PUCO: Public Utilities Commission of
Environmental Management Ohio Consumer Counselor
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF/BCF: millions / billions of USEPA: United States Environmental
cubic feet Protection Agency
MDth/MMDth: thousands /millions of Throughput: combined gas sales and gas
dekatherms transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ........................................................... 4
2 Properties ......................................................... 10
3 Legal Proceedings................................................... 12
4 Submission of Matters to Vote of Security Holders................... 12
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities ................. 12
6 Selected Financial Data............................................. 13
7 Management's Discussion and Analysis of Results of Operations ......
and Financial Condition............................................. 14
7A Qualitative and Quantitative Disclosures About Market Risk.......... 42
8 Financial Statements and Supplementary Data......................... 44
9 Change in and Disagreements with Accountants on Accounting ......... 88
and Financial Disclosure
9A Controls and Procedures............................................. 88
Part III
10 Directors and Executive Officers of the Registrant.................. 90
11 Executive Compensation.............................................. 91
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.......................... 92
13 Certain Relationships and Related Transactions...................... 92
14 Principal Accountant Fees and Services.............................. 93
Part IV
15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K......................................................... 93
Signatures.......................................................... 95
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge through its website at www.vectren.com, or by request, directed
to Investor Relations at the mailing address, phone number, or email address
that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812) 491-4000 Steven M. Schein
Evansville, Indiana Vice President, Investor Relations
47702-0209 sschein@vectren.com
PART I
ITEM 1. BUSINESS
Description of the Business
Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP) are the
predecessor companies to Vectren Corporation. Indiana Energy, incorporated under
Indiana law on October 24, 1985, was engaged in natural gas distribution, gas
portfolio administrative services, and marketing of natural gas, electric power
and related services. Indiana Energy had fourteen subsidiaries, including ten
nonregulated direct or indirect subsidiaries, a not-for-profit foundation and
three utility subsidiaries, as well as investments in four nonregulated joint
ventures. SIGCORP, incorporated under Indiana law on October 19, 1994, was
engaged in electric generation, transmission, and distribution, natural gas
distribution, coal mining, and broadband communication services. SIGCORP had
eleven wholly owned subsidiaries, including ten nonregulated subsidiaries.
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999, solely for the purpose of
effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax-free exchange of shares that has been accounted for as a pooling-of-
interests in accordance with APB Opinion No. 16 "Business Combinations" (APB
16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. VUHI also has other assets that provide information technology and
other services to the three utilities. Both Vectren and VUHI are exempt from
registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding
Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal and generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has other businesses that provide utility
services, municipal broadband consulting, and retail products and services that
invest in energy-related opportunities, real estate and leveraged leases. The
nonregulated group supports the Company's regulated utilities pursuant to
service contracts by providing natural gas supply services, coal, utility
infrastructure services, and other services.
Acquisition of the Gas Distribution Assets of the Dayton Power and Light Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.
The Company holds the natural gas distribution assets in Ohio as a tenancy in
common through two separate wholly owned subsidiaries. Vectren Energy Delivery
of Ohio, Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and
Indiana Gas holds a 47% undivided ownership interest. VEDO is the operator of
the assets, and these operations are referred to as "the Ohio operations."
Narrative Description of the Business
The Company segregates its operations into three groups: 1) Utility Group, 2)
Nonregulated Group, and 3) Corporate and Other Group. At December 31, 2003, the
Company had $3.4 billion in total assets, with $2.9 billion (87%) attributed to
the Utility Group, $0.4 billion (12%) attributed to the Nonregulated Group, and
less than $0.1 billion (1%) attributed to the Corporate and Other Group. Net
income for the year ended December 31, 2003, was $111.2 million, or $1.58 per
share of common stock, with $85.6 million attributed to the Utility Group, $27.6
million attributed to the Nonregulated Group, and a net loss of $2.0 million
attributed to the Corporate and Other Group. Net income for the year ended
December 31, 2002, was $114.0 million, or $1.69 per share of common stock.
For further information, refer to Note 17 regarding the activities and assets of
operating segments within these Groups, Note 18 regarding special charges in
2001, Note 4 regarding the extraordinary loss in 2001, and Note 15 regarding the
cumulative effect of change in accounting principle in 2001 in the Company's
consolidated financial statements included under "Item 8 Financial Statements
and Supplementary Data".
Following is a more detailed description of the Utility Group and Nonregulated
Group. The operations of the Corporate and Other Group are not significant.
Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and other operations that
provide information technology and other support services to those regulated
operations. The Gas Utility Services segment includes the operations of Indiana
Gas, the Ohio operations, and SIGECO's natural gas distribution business and
provides natural gas distribution and transportation services to nearly
two-thirds of Indiana and to west central Ohio. The Electric Utility Services
segment includes the operations of SIGECO's electric transmission and
distribution services, which provides electricity primarily to southwestern
Indiana, and includes the Company's power generating and marketing operations.
The Utility Group's other operations are not significant.
Gas Utility Services
At December 31, 2003, the Company supplied natural gas service to 972,230
Indiana and Ohio customers, including 887,891 residential, 80,292 commercial,
and 4,047 industrial and other customers. This represents customer base growth
of 0.6% compared to 2002.
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, 2003, natural gas revenues were approximately
$1,112.3 million, of which residential customers accounted for 67%, commercial
25%, and industrial and other 8%, respectively.
The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) were 209,344 MDth for the year ended December 31, 2003. Gas
transported or sold to residential and commercial customers were 118,460 MDth
representing 57% of throughput. Gas transported or sold to industrial and other
contract customers were 90,884 MDth representing 43% of 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 has storage capacity at
seven active underground gas storage fields, six liquefied petroleum air-gas
manufacturing plants, and a propane cavern. The Company also contracts with
ProLiance Energy, LLC (ProLiance or ProLiance Energy) to ensure availability of
gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of
Energy Marketing & Services below and Note 3 in the Company's consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding transactions with ProLiance). Purchased natural gas is injected
into storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately
1,775,657 MCF of gas per day can be delivered during peak demand periods from
all sources and for all utilities.
Gas Purchases
In 2003, the Company purchased 118,684 MDth volumes of gas at an average cost of
$6.36 per Dth, substantially all of which was purchased from ProLiance which
buys the gas as an agent. The average cost of gas per Dth purchased for the last
five years was: $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; $5.60 in 2000; and
$3.58 in 1999.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment and issues
involving manufactured gas plants.
Electric Utility Services
At December 31, 2003, the Company supplied electric service to 135,098 Indiana
customers, including 117,868 residential, 17,054 commercial, and 176 industrial
and other customers. This represents customer base growth of 0.8% compared to
2002. In addition, the Company is obligated to provide for firm power
commitments to four 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, 2003, retail and firm wholesale electricity
sales totaled 5,898,852 MWh, resulting in revenues of approximately $309.1
million. Residential customers accounted for 34% of 2003 revenues; commercial
27%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 4,305,190 MWh through wholesale contracts in 2003, generating revenue, net
of purchased power costs, of $26.5 million.
Generating Capacity
Installed generating capacity as of December 31, 2003, was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and natural gas or
oil-fired turbines used for peaking or emergency conditions provide 295 MW. New
peaking capacity of 80 MW fueled by natural gas was added during 2002 and was
available for the summer peaking season.
In addition to its generating capacity, in 2003, the Company had 32 MW available
under firm contracts and 95 MW available under interruptible contracts. In
October 2003, the Company executed a firm purchase supply contract for a maximum
of 73MW for the peak cooling season months in each of the next three years.
The Company has interconnections with Louisville Gas and Electric Company,
Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability has been, and may continue to be, impacted
because the Company, as a member of the Midwest Independent System Operator
(MISO), has turned over operational control over the interchange facilities and
its own transmission assets, like many other Midwestern electric utilities, to
the MISO. See "Item 7 Management's Discussion and Analysis of Results of
Operations and Financial Condition" regarding the Company's participation in
MISO.
Total load for each of the years 1999 through 2003 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
Date of summer peak load 8/27/2003 8/5/2002 7/31/2001 8/17/2000 7/6/1999
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Total load at peak (1) 1,272 1,258 1,234 1,212 1,255
Generating capability 1,351 1,351 1,271 1,256 1,256
Firm purchase supply 32 82 82 75 -
Interruptible contracts 95 95 95 95 95
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Total power supply capacity 1,478 1,528 1,448 1,426 1,351
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Reserve margin at peak 16% 21% 17% 18% 8%
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(1) The total load at peak is increased 25 MW in 2003, 2002, 2001, and 1999
from the total load actually experienced. The additional 25 MW represents
load that would have been incurred if summer cycler programs had not been
activated. The 25 MW is also included in the interruptible contract portion
of the Company's total power supply capacity. On the date of peak in 2000,
summer cycler programs were not activated.
The winter peak load of the 2002-2003 season of approximately 948 MW occurred on
January 27, 2003, and was 11% higher than the previous winter peak load of
approximately 854 MW which occurred on March 4, 2002.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO, and supplies power requirements to the United States Department of
Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for, any
available power in excess of the DOE contract demand. At the present time, the
DOE contract demand is essentially zero. Because of this decreased demand, the
Company's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.
Such generating capacity is included in firm purchase supply in the chart above.
Fuel Costs and Purchased Power
Electric generation for 2003 was fueled by coal (99.3%) and natural gas (0.7%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.1 million tons of coal were purchased
for generating electricity during 2003, of which substantially all was supplied
by Vectren Fuels, Inc. from its mines and third party purchases. The average
cost of coal consumed in generating electric energy for the years 1999 through
2003 follows:
Year Ended December 31,
-----------------------------------------------
Avg. Cost Per 2003 2002 2001 2000 1999
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Ton $ 24.91 $ 23.50 $ 22.48 $ 22.49 $ 21.88
MWh 11.93 11.00 10.53 10.39 10.13
The Company will also purchase power as needed from the wholesale market to
supplement its generation capabilities in periods of peak demand; however, the
majority of power purchased through the wholesale market is used to optimize and
hedge the Company's sales to other wholesale customers. Volumes purchased in
2003 totaled 4,082,404 MWh.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment, and a
discussion of the Company's Clean Air Act Compliance Plan, and the settlement of
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 regulated utility industry
for the Company's regulated Indiana and Ohio operations.
Nonregulated Group
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband.
Energy Marketing and Services
The Energy Marketing and Services group relies heavily upon a customer focused,
value added strategy. The group provides natural gas and fuel supply management
services to a broad range of municipalities, utilities, industrial operations,
schools, and healthcare institutions through ProLiance Energy, an unconsolidated
affiliate of the Company and Citizens Gas. The Company contracted for all
natural gas purchases through ProLiance in 2003. The group also focuses on
performance-based energy contracting through Energy Systems Group, LLC (ESG).
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.
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001, Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member and
therefore, Vectren continues to account for its investment in ProLiance using
the equity method of accounting.
At December 31, 2003, the Energy Marketing and Services group's natural gas
marketing operations had 1,222 customers, up from 1,060 in 2002. ProLiance's
revenue exceeded $2.2 billion in 2003.
Prior to April 2003, ESG was a consolidated venture between the Company and
Citizens Gas with the Company owning two-thirds. In April 2003, the Company
purchased the remaining interest in ESG for approximately $4 million.
Coal Mining
The Coal Mining group provides the mining and sale of coal to the Company's
utility operations and to other third parties through its wholly owned
subsidiary Vectren Fuels, Inc. The Coal Mining group also generates income tax
credits through IRS Code Section 29 investment tax credits relating to the
production of coal-based synthetic fuels through its 8.3% ownership in Pace
Carbon Synfuels, LP (Pace Carbon). The Company's two coal mines produced 3.3
million tons in 2003, down from 3.5 million in 2002. The Company's investment in
Pace Carbon is accounted for using the equity method of accounting.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water,
electric, and telecommunications companies as well as facilities locating and
meter reading services through its investment in Reliant Services, LLC (Reliant)
and Reliant's 100% ownership in Miller Pipeline, which was purchased by Reliant
in 2000. Reliant is a 50% owned strategic alliance with an affiliate of Cinergy
Corp. and is accounted for using the equity method of accounting.
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 these services primarily to the greater Evansville area
in southwestern Indiana. At December 31, 2003, there were over 27,000
residential customers yielding over 81,000 revenue generating units (up from
77,000 at the end of 2002) indicating multiple services being utilized by the
same residential customer. At December 31, 2003, there were approximately 2,000
commercial customers.
The Company has an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of
bundled communication services focusing on last mile delivery to residential and
commercial customers. The Company also has an approximate 19% equity interest in
SIGECOM Holdings, Inc., which was formed by Utilicom to hold interests in
SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater
Evansville, Indiana area.
Utilicom also plans to provide services to Indianapolis, Indiana and Dayton,
Ohio. However, the funding of these projects has been delayed due to the
continued difficult environment within the telecommunication capital markets,
which has prevented Utilicom from obtaining debt financing on terms it considers
acceptable. While the existing investors remain interested in the Indianapolis
and Dayton projects, the Company is not required to make further investments and
does not intend to proceed unless commitments are obtained to fully fund these
projects. Franchising agreements have been extended in both locations.
The convertible subordinated debt investment totals $32.3 million, of which
$30.1 million is convertible into Utilicom ownership at the Company's option or
upon the event of a public offering of stock by Utilicom and $2.2 million is
convertible into common equity interests in the Indianapolis and Dayton ventures
at the Company's option. Upon conversion, the Company would have up to a 16%
interest in Utilicom, assuming completion of all required funding, and up to a
31% interest in the Indianapolis and Dayton ventures.
Other Businesses
In addition to the nonregulated business groups previously discussed, the Other
Businesses group invests in a portfolio of interests in gas and power storage,
distributed generation projects, and similar energy-related businesses.
Additional activities include:
o A retail unit, providing natural gas and other related products and
services primarily in Ohio serving customers opting for choice among
energy providers.
o A broadband consulting business.
Major investments at December 31, 2003, include Haddington Energy Partnerships,
two partnerships both approximately 40% owned; and the wholly owned subsidiaries
Southern Indiana Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC, and
Vectren Communications Services, Inc.
Personnel
As of December 31, 2003, the Company and its consolidated subsidiaries had 1,858
employees, of which 884 are subject to collective bargaining arrangements.
In January 2004, the Company signed a five-year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America locals 12213 and 7441. The agreement provides for
annual wage increases of 3%, a multi-tiered health care plan in which the
employees pay 12% to 16% of the premium, and pension enhancements for early
retirees.
In August 2001, the Company signed a new four-year labor agreement, ending in
September 2005, with Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The new agreement provides for annual wage increases of 3.25%, a new
401(k) savings plan and improvements in the areas of health insurance and
pension benefits.
Concurrent with the Company's purchase of the Ohio operations, VEDO and Local
Union 175, Utility Workers Union of America approved a labor agreement effective
November 2000 through October 2005. The agreement provides a 3.25% wage increase
each year, and the other terms and conditions are substantially the same as the
agreement reached between the Utility Workers Union and Dayton Power and Light
Company in August of 2000.
In July 2000, SIGECO signed a four-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2004. The agreement
provides a 3% wage increase for each year in addition to improvements in health
care coverage, retirement benefits and incentive pay.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana
covering 58,290 acres of land with an estimated ready delivery from storage
capability of 5.2 BCF of gas with maximum peak day delivery capabilities of
119,160 MCF per day. Indiana Gas also owns and operates three liquefied
petroleum (propane) air-gas manufacturing plants located in Indiana with the
ability to store 1.5 million gallons of propane and manufacture for delivery
33,000 MCF of manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.2 BCF of storage
with a maximum peak day delivery capability of 404,614 MCF per day. Indiana Gas
has the ability to meet a total annual demand, utilizing all of its assets
across various pipelines, of 131.1 BCF with a maximum peak day delivery
capability of 1,068,740 MCF per day. Indiana Gas' gas delivery system includes
11,771 miles of distribution and transmission mains, all of which are in Indiana
except for pipeline facilities extending from points in northern Kentucky to
points in southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.
SIGECO owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
124,748 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 18,699 MCF per day. SIGECO has the ability to meet a
total annual demand, utilizing all of its assets across various pipelines, of
28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day.
SIGECO's gas delivery system includes 3,026 miles of distribution and
transmission mains, all of which are located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants and a cavern for propane storage, all of which are located
in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the
plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In
addition to its propane delivery capabilities, the Ohio operations have
contracted for 13.1 BCF of storage with a maximum peak day delivery capability
of 280,667 MCF per day. The Ohio operations have the ability to meet a total
annual demand, utilizing all of its assets across various pipelines, of 57.9 BCF
with a maximum peak day delivery capability of 477,974 MCF per day. The Ohio
operations' gas delivery system includes 5,216 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, 2003, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80 MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution
system includes 3,224 pole miles of lower voltage overhead lines and 289 trench
miles of conduit containing 1,622 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed
capacity of 2,368.6 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Nonregulated Properties
Subsidiaries other than the utility operations have no significant properties
other than the ownership and operation of coal mining property in Indiana and
investments in real estate partnerships, leveraged leases, and notes receivable.
The assets of the coal mining operations comprise approximately 3% percent of
total assets.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture
dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee,
and Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 13 of its consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding the Clean Air Act and related legal proceedings. Legal
proceedings regarding the Culley generating station's compliance with the Clean
Air Act were substantially resolved during 2003.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,
AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock trades on the New York Stock Exchange under the
symbol "VVC." For each quarter in 2003 and 2002, the high and low sales prices
for the Company's common stock as reported on the New York Stock Exchange and
dividends paid are shown in the following table.
Common Stock Price Range
Cash ------------------------
2003 Dividend High Low
- ---- -------- ------- -------
First Quarter $ 0.275 $ 24.50 $ 19.70
Second Quarter 0.275 26.13 21.05
Third Quarter 0.275 25.02 22.25
Fourth Quarter 0.285 24.85 22.73
2002
First Quarter $ 0.265 $ 25.95 $ 22.45
Second Quarter 0.265 26.10 23.10
Third Quarter 0.265 25.44 17.95
Fourth Quarter 0.275 25.00 21.05
On January 28, 2004, the board of directors declared a dividend of $0.285 per
share, payable on March 1, 2004, to common shareholders of record on February
13, 2004.
As of January 30, 2004, there were 12,889 shareholders of record of the
Company's common stock.
Dividends on shares of common stock are payable at the discretion of the board
of directors out of legally available funds. Future payments of dividends, and
the amounts of these dividends, will depend on the Company's financial
condition, results of operations, capital requirements, and other factors.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K. Operating
revenues for the years ended December 31, 2002, through December 31, 1999, have
been reclassified to reflect the adoption of EITF 03-11. Total assets as of
December 31, 2002, also reflect a reclassification for the adoption of SFAS 143.
See Note 15 and Note 2 to the consolidated financial statements for further
information on the adoption of EITF 03-11 and SFAS 143, respectively, included
under Item 8 "Financial Statements and Supplementary Data."
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001 (1) 2000 (2,3) 1999
- ---------------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $1,587.7 $1,523.8 $2,009.1 $1,607.6 $1,056.2
Operating income $ 199.4 $ 211.3 $ 127.9 $ 131.7 $ 160.8
Income before extraordinary loss &
cumulative effect of change in
accounting principle $ 111.2 $ 114.0 $ 59.3 $ 72.0 $ 90.7
Net income $ 111.2 $ 114.0 $ 52.7 $ 72.0 $ 90.7
Average common shares outstanding 70.6 67.6 66.7 61.3 61.3
Fully diluted common shares outstanding 70.8 67.9 66.9 61.4 61.4
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting principle $ 1.58 $ 1.69 $ 0.89 $ 1.18 $ 1.48
Basic earnings per share
on common stock $ 1.58 $ 1.69 $ 0.79 $ 1.18 $ 1.48
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting principle $ 1.57 $ 1.68 $ 0.89 $ 1.17 $ 1.48
Diluted earnings per share
on common stock $ 1.57 $ 1.68 $ 0.79 $ 1.17 $ 1.48
Dividends per share on common stock $ 1.11 $ 1.07 $ 1.03 $ 0.98 $ 0.94
Balance Sheet Data:
Total assets $3,353.4 $3,136.5 $2,878.7 $2,943.7 $1,980.5
Long-term debt, net $1,072.8 $ 954.2 $1,014.0 $ 632.0 $ 486.7
Redeemable preferred stock $ 0.2 $ 0.3 $ 0.5 $ 8.1 $ 8.2
Common shareholders' equity $1,071.7 $ 869.9 $ 839.3 $ 733.4 $ 709.8
(1) Merger and integration related costs incurred for the year ended December
31, 2001, totaled $2.8 million. These costs relate primarily to transaction
costs, severance and other merger and acquisition integration activities.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets
were shortened to reflect this decision, resulting in additional
depreciation expense of approximately $9.6 million for the year ended
December 31, 2001. In total, merger and integration related costs incurred
for the year ended December 31, 2001, were $12.4 million ($8.0 million
after tax).
The Company incurred restructuring charges of $19.0 million, ($11.8 million
after tax) relating to employee severance, related benefits and other
employee related costs, lease termination fees related to duplicate
facilities, and consulting and other fees.
(2) Merger and integration related costs incurred for the year ended December
31, 2000, totaled $41.1 million. These costs relate primarily to
transaction costs, severance and other merger and acquisition integration
activities. As a result of merger integration activities, management
identified certain information systems to be retired in 2001. Accordingly,
the useful lives of these assets were shortened to reflect this decision,
resulting in additional depreciation expense of approximately $11.4 million
for the year ended December 31, 2000. In total, merger and integration
related costs incurred for the year ended December 31, 2000, were $52.5
million ($36.8 million after tax).
(3) Reflects two months of results of the Ohio operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto.
Executive Summary of Consolidated Results of Operations
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001
- -----------------------------------------------------------------------------
Net income $ 111.2 $ 114.0 $ 52.7
Attributed to:
Utility Group $ 85.6 $ 97.1 $ 44.8
Nonregulated Group 27.6 19.0 12.1
Corporate & other (2.0) (2.1) (4.2)
- -----------------------------------------------------------------------------
Basic earnings per share $ 1.58 $ 1.69 $ 0.79
Attributed to:
Utility Group $ 1.21 $ 1.44 $ 0.67
Nonregulated Group 0.39 0.28 0.18
Corporate & other (0.02) (0.03) (0.06)
Results
For the year ended December 31, 2003, net income decreased $2.8 million, or
$0.11 per share, when compared to 2002. The decline in earnings was principally
due to the Utility Group's results which decreased $11.5 million, offset by
increased earnings of $8.6 million from the Nonregulated Group. The decrease in
earnings per share of $0.11 also reflects the impact of additional common shares
outstanding resulting from an equity offering of approximately 7.4 million
shares during 2003. The offering netted proceeds of approximately $163 million.
The additional shares had the effect of reducing earnings per share as compared
to 2002 by approximately $0.07.
The increase in Nonregulated Group earnings is due to increased earnings from
the Energy Marketing and Services and Coal Mining Groups and a net gain
recognized from business and investment divestitures. The decrease in Utility
Group earnings was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.
In 2002, consolidated net income increased $61.3 million, or $0.90 per share,
when compared to 2001. The year ended December 31, 2001, included nonrecurring
merger, integration, and restructuring costs and other nonrecurring items
totaling $26.4 million after tax, or $0.40 per share. The increase also reflects
improved Utility Group margins and lower operating costs. These resulted from
favorable weather and lower gas prices and the related reduction in costs
incurred in 2001. Also contributing to the increase was increased Nonregulated
Group earnings from gas marketing operations.
The Utility Group generates revenue primarily from the delivery of natural gas
and electric service to its customers. The primary source of cash flow for the
Utility Group results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric services. The
results of the Utility Group are impacted by weather patterns in its service
territory and general economic conditions both in its service territory as well
as nationally.
The Nonregulated Group generates revenue or earnings from the provision of
services to customers. The activities of the Nonregulated Group are closely
linked to the utility industry, and the results of those operations are
generally impacted by factors similar to those impacting the overall utility
industry.
The Company has in place a disclosure committee that consists of senior
management as well as financial management. The committee is actively involved
in the preparation and review of the Company's SEC filings.
Dividends
Dividends declared for the year ended December 31, 2003, were $1.11 per share
compared to $1.07 per share in 2002 and $1.03 per share in 2001. In October
2003, the Company's board of directors increased its quarterly dividend to
$0.285 per share from $0.275 per share.
Nonrecurring Items in 2001
Merger & Integration Costs
Merger and integration related costs incurred during 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 and 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 during 2001 were $12.4 million ($8.0 million after tax), or $0.12 per
share. Merger and integration activities resulting from the 2000 merger forming
Vectren were completed in 2001.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, the Company's management
and board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $19.0 million ($11.8 million after tax), or $0.18 per share, in 2001.
These charges were comprised of $10.9 million for employee severance, related
benefits and other employee related costs, $4.0 million for lease termination
fees related to duplicate facilities and other facility costs, and $4.1 million
for consulting and other fees incurred through December 31, 2001. The
restructuring program was completed during 2001, except for the departure of
certain employees impacted by the restructuring which occurred during 2002 and
the final settlement of the lease obligation which has yet to occur.
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 per share. Because of the transaction's significance and because the
transaction occurred within two years of the effective date of the merger of
Indiana Energy and SIGCORP, which was accounted for as a pooling-of-interests,
APB 16 requires the loss on disposition of these investments to be treated as
extraordinary. Proceeds from the sale of $46.7 million were used to retire
short-term borrowings.
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations and gas marketing operations that are periodically settled
net were required to be recorded at market value. Previously, the Company
accounted for these contracts on settlement. The cumulative impact of the
adoption of SFAS 133 resulting from marking these contracts to market on January
1, 2001, was an earnings gain of approximately $1.8 million ($1.1 million after
tax), or $0.02 per share, 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.
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the
Company's Utility Group and Nonregulated Group. The detailed results of
operations for the Utility Group and Nonregulated Group 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
Group are not significant.
Results of Operations of the Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and other operations that
provide information technology and other support services to those regulated
operations. Gas Utility Services provides natural gas distribution and
transportation services in nearly two-thirds of Indiana and to west central
Ohio. Electric Utility Services provides electricity primarily to southwestern
Indiana, and includes the Company's power generating and marketing operations.
The results of operations of the Utility Group before certain intersegment
eliminations and reclassifications for the years ended December 31, 2003, 2002,
and 2001, follow:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001
- -----------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $1,112.3 $ 908.0 $1,019.6
Electric utility 335.7 328.6 308.5
Other 0.8 0.3 0.2
- -----------------------------------------------------------------------------
Total operating revenues 1,448.8 1,236.9 1,328.3
- -----------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 762.5 570.8 708.9
Fuel for electric generation 86.5 81.6 74.4
Purchased electric energy 16.2 16.8 14.2
Other operating 210.1 198.6 212.1
Merger & integration costs - - 2.8
Restructuring costs - - 15.0
Depreciation & amortization 117.9 110.7 117.9
Taxes other than income taxes 56.6 50.7 51.6
- -----------------------------------------------------------------------------
Total operating expenses 1,249.8 1,029.2 1,196.9
- -----------------------------------------------------------------------------
OPERATING INCOME 199.0 207.7 131.4
OTHER INCOME (EXPENSE)
Other - net 4.8 7.1 5.6
Equity in losses of unconsolidated
affiliates (0.5) (1.8) (0.5)
- -----------------------------------------------------------------------------
Total other income 4.3 5.3 5.1
- -----------------------------------------------------------------------------
Interest expense 66.1 69.1 70.7
- -----------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 137.2 143.9 65.8
- -----------------------------------------------------------------------------
Income taxes 51.6 46.8 21.3
Preferred dividend requirement of
subsidiary - - 0.8
- -----------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 85.6 97.1 43.7
- -----------------------------------------------------------------------------
Cumulative effect of change in
accounting principle - net of tax - - 1.1
- -----------------------------------------------------------------------------
NET INCOME $ 85.6 $ 97.1 $ 44.8
=============================================================================
BASIC EARNINGS PER SHARE $ 1.21 $ 1.44 $ 0.67
=============================================================================
In 2003, Utility Group earnings were $85.6 million as compared to $97.1 million
in 2002 and $44.8 million in 2001. The $11.5 million decrease occurring in 2003
compared to 2002 was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.
Utility Group earnings increased $52.3 million in 2002 compared to 2001. The
year ended December 31, 2001, included nonrecurring merger, integration, and
restructuring costs and other nonrecurring items totaling $15.9 million after
tax. The increase also reflects improved margins and lower operating costs.
These resulted from favorable weather and lower gas prices and the related
reduction in costs incurred in 2001. Weather increased utility earnings by an
estimated $11 million.
Throughout this discussion, the terms Gas Utility margin and Electric Utility
margin are used. Gas Utility margin and Electric Utility margin could be
considered non-GAAP measures of income. Gas Utility margin is calculated as Gas
utility revenues less the Cost of gas sold. Electric Utility margin is
calculated as Electric utility revenues less Fuel for electric generation and
Purchased electric energy. These measures exclude Other operating expenses,
Depreciation and amortization, Taxes other than income taxes, Merger and
integration costs, and Restructuring costs, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of operating performance than,
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.
Significant Fluctuations
Utility Group Margin
Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in its service
territory. Margin generated from sales to industrial and other contract
customers is impacted by overall economic conditions. In general, margin is not
sensitive to variations in gas or fuel costs. It is, however, impacted by the
collection of state mandated taxes which fluctuate with gas costs and also some
level of fluctuation in volumes sold. Electric generating asset optimization
activities are primarily affected by market conditions, the level of excess
generating capacity, and electric transmission availability. Following is a
discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- --------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------
Residential $ 225.3 $ 217.1 $ 201.9
Commercial 65.0 65.5 57.7
Contract 50.5 50.5 48.4
Other 9.0 4.1 2.7
- --------------------------------------------------------------------------
Total gas utility margin $ 349.8 $ 337.2 $ 310.7
==========================================================================
Sold & transported volumes in MMDth:
To residential & commercial customers 118.5 111.9 102.2
To contract customers 90.8 95.8 97.2
- --------------------------------------------------------------------------
Total throughput 209.3 207.7 199.4
==========================================================================
Gas Utility margin for the year ended December 31, 2003, of $349.8 million
increased $12.6 million, or 4%, compared to 2002. It is estimated that weather
near normal for the year and 6% cooler than the prior year, contributed $8
million in increased residential and commercial margin and was the primary
contributor to increased throughput. The remaining increase is primarily
attributable to $4.5 million in higher utility receipts and excise taxes on
higher gas costs and volumes sold and $1.8 million in recovery of Ohio customer
choice implementation costs. These increases are partially offset by the
negative effect of high gas prices on customer usage.
Gas Utility margin for the year ended December 31, 2002, of $337.2 million
increased $26.5 million, or 9%, compared to 2001. The increase is primarily due
to weather 7% cooler for the year and 31% cooler in the fourth quarter. Rate
recovery of excise taxes in Ohio effective July 1, 2001, an increase in the
Percent of Income Payment Plan rider affecting Ohio customers, decreased gas
costs, and customer growth of over one percent also contributed. It is estimated
that weather contributed $10 million to the increase in Gas Utility margin,
various rate recovery riders in Ohio contributed $7 million, and other items,
including the impact of lower gas costs and customer growth, contributed $9
million. The effect of cooler weather was the primary factor driving an overall
4% increase in total throughput.
As noted above, gas cost fluctuations have impacted customer usage during the
years ended December 31, 2003, 2002, and 2001. The average cost per dekatherm of
gas purchased in those years was $6.36 in 2003, $4.57 in 2002, and $5.83 in
2001.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric
Generation and Purchased Electric Energy)
Electric Utility margin by revenue type follows:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -----------------------------------------------------------------------------
Residential & commercial $ 141.1 $ 145.7 $ 134.4
Industrial 53.5 54.9 49.6
Municipalities & other 20.1 16.9 16.8
- -----------------------------------------------------------------------------
Total retail & firm wholesale 214.7 217.5 200.8
Asset optimization 18.3 12.7 19.1
- -----------------------------------------------------------------------------
Total electric utility margin $ 233.0 $ 230.2 $ 219.9
=============================================================================
Retail & Firm Wholesale Margin
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.7 million, a decrease of $2.8 million when compared
to 2002. It is estimated that summer weather 19% cooler than normal and 34%
cooler than last year caused an $8 million decrease in residential and
commercial margin. The estimated effect of weather was partially offset by a
$7.1 million increase in retail electric rates related to recovery of NOx
compliance expenditures and related operating expenses. A slowly recovering
economy continued to negatively impact industrial sales which decreased $1.4
million compared to 2002. As a result primarily of the mild weather and slow
economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90
GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh.
The current year decrease in native load and firm wholesale margin has been
offset by increased optimization margin as more fully described below.
For the year ended December 31, 2002, margin from serving native load and firm
wholesale customers increased $16.7 million or 8%, when compared to 2001. The
increase results primarily from the effect on residential and commercial sales
of cooling weather considerably warmer than the prior year. Weather in 2002 was
27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002
was positively affected by increased industrial and other wholesale volumes and
rate recovery related to NOx compliance expenditures as the expenditures are
made pursuant to a rate recovery rider approved by the IURC in August 2001. As a
result of warmer weather and increased volumes sold, native load and firm
wholesale volumes sold increased 6%. It is estimated that weather contributed $7
million to the increase in electric utility margin, and the increased industrial
and other wholesale volumes and the NOx recovery rider contributed $8 million.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of
these contracts are integrated with portfolio requirements around power supply
and delivery and are short-term purchase and sale transactions that expose the
Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
- --------------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------------------
Beginning of Year Net Asset Optimization Position $ (0.7) $ 3.3 $ -
Statement of Income Activity
Cumulative effect at adoption of SFAS 133 - - 1.8
Mark-to-market gains (losses) recognized 0.7 (3.6) 1.5
Realized gains recognized 17.6 16.3 17.6
- --------------------------------------------------------------------------------------
Net activity in electric utility margin 18.3 12.7 19.1
- --------------------------------------------------------------------------------------
Net cash received & other adjustments (18.0) (16.7) (17.6)
- --------------------------------------------------------------------------------------
End of Year Net Asset Optimization Position $ (0.4) $ (0.7) $ 3.3
======================================================================================
Included in:
Prepayments & other current assets $ 2.4 $ 3.5 $ 6.1
Accrued liabilities (2.8) (4.2) (2.8)
For the years ended December 31, 2003, 2002, and 2001, volumes sold into the
wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh respectively, while volumes
purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A portion
of volumes purchased in the wholesale market is used to serve native load and
firm wholesale customers, and in 2003, greater amounts of purchased power have
been required for native load due to scheduled outages, which has reduced
capacity available for optimization. Additionally, volumes sold and purchased
were lower in 2003 compared to 2002 due to a shorter term focus in hedging and
optimization strategies. While volumes both sold and purchased in the wholesale
market have decreased during 2003, margin from optimization activities has
increased compared to 2002 due primarily to price volatility. Despite the
increased volumes in 2002, margins were lower in 2002 compared to 2001 due to
reduced price volatility.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.
Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income.
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152.8 $ 302.8 $ 101.4
Purchase contracts (127.0) (275.9) (74.3)
Mark-to-market gains (losses) 0.7 (3.6) 1.5
- -------------------------------------------------------------------------------
Net asset optimization revenue 26.5 23.3 28.6
- -------------------------------------------------------------------------------
Fuel for electric generation (8.2) (10.6) (9.5)
- -------------------------------------------------------------------------------
Asset optimization margin $ 18.3 $ 12.7 $ 19.1
===============================================================================
Utility Group Operating Expenses
Other Operating
For the year ended December 31, 2003, other operating expenses increased $11.5
million compared to 2002. The increase is principally caused by increased
distribution, plant, and transmission operating expenses; power plant and other
maintenance; customer service initiatives; higher insurance premiums; and prior
year insurance recoveries. In addition, operating expenses reflect $1.8 million
in amortization of Ohio choice implementation costs, which are recovered through
increased gas utility margin. The increase in operating expenses was partially
offset by the impact of an Ohio regulatory order. The order allows the deferral
and recovery of uncollectible accounts expense to the extent it differs from the
level included in base rates. The Company estimated the difference to
approximate $4 million in excess of that included in base rates in 2003.
Other operating expenses decreased $13.5 million for the year ended December 31,
2002, when compared to 2001. The decrease results primarily from lower gas
prices and the related reduction in costs incurred in 2001. Specific expenses
affected by increased gas costs in 2001 were uncollectible accounts expense of
$3.4 million and contributions to low income heating assistance programs of $2.0
million. Insurance recovery in 2002 of $2.8 million of certain maintenance costs
incurred in 2001 also contributed to the decrease.
Depreciation & Amortization
For the year ended December 31, 2003, depreciation and amortization increased
$7.2 million compared to 2002 due to additions to utility plant. Increased
depreciation expense reflects depreciation of utility plant placed into service
including a full year for a gas-fired peaker unit, expenditures for implementing
a choice program for Ohio gas customers, customer system upgrades, and other
upgrades to existing transmission and distribution facilities.
Depreciation and amortization decreased $7.2 million for the year ended December
31, 2002, when compared to 2001. The decrease results from $9.6 million of
expense recognized in 2001 related to assets which had useful lives shortened as
a result of the merger. The discontinuance of goodwill amortization as required
by SFAS 142, which approximated $4.9 million in 2001, also contributed to the
decrease. These decreases were offset somewhat by depreciation of utility plant
and non-utility property additions.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5.9 million in 2003 compared to 2002.
Higher utility receipts and excise taxes of $4.5 million were recognized in 2003
due to higher gas prices and more volumes sold compared to 2002. The remaining
increase results principally from higher property taxes.
Taxes other than income taxes decreased $0.9 million in 2002 compared to 2001 as
a result of lower revenues subject to the Indiana utility receipts tax.
Utility Group Other Income (Expense) - Net
Other - net
Other - net decreased $2.3 million in 2003 compared to 2002 and increased $1.5
million in 2002 compared to 2001. The 2003 decrease is primarily due to the $3.9
million write-off of notes receivable and preferred equity investments in BABB
International (BABB), an entity that processed fly ash into building materials.
The 2002 increase results primarily from gains recognized from the sale of
excess emission allowances and other assets.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates increased $1.3 million in 2002
compared to 2001 principally due to increased losses and increased preferred
ownership in BABB. The smaller loss recognized in 2003 results from the
write-off of the BABB investment.
Utility Group Interest Expense
Interest expense decreased $3.0 million in 2003 compared to 2002 and decreased
$1.6 million in 2002 compared to 2001. The 2003 decrease reflects the impact of
permanent financing completed in the third quarter of 2003. Lower average
interest rates on adjustable rate debt also contributed to the decreases in 2003
and 2002.
Utility Group Income Taxes
For the year ended December 31, 2003, federal and state income taxes increased
$4.8 million in 2003 compared to 2002 and increased $25.5 million in 2002
compared to 2001. The 2003 increase results primarily from an increased
effective tax rate that reflects an increase in the Indiana state income tax
rate from 4.5 % to 8.5% and other changes in the effective tax rate recognized
in 2002. The increase in 2002 compared to 2001 is principally due to higher
pre-tax earnings.
Competition
The utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation. Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003.
Indiana has not adopted any regulation requiring gas choice; however, the
Company operates under approved tariffs permitting large volume customers to
choose their commodity supplier.
Other Operating Matters
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. In December 2001, the IURC approved the Company's request for
authority to transfer operational control over its electric transmission
facilities to the MISO. That transfer occurred on February 1, 2002.
Issues pertaining to certain of MISO's tariff charges for its services remain to
be determined by the FERC. Given the outstanding tariff issues, as well as the
potential for additional growth in MISO participation, the Company is unable to
determine the future impact MISO participation may have on its operations.
Pursuant to an order from the IURC, certain MISO costs are deferred for future
recovery.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, and export power to the
wholesale market may be impacted. Given the nature of MISO's policies regarding
use of transmission facilities, as well as ongoing FERC initiatives, it is
difficult to predict the impact on operational reliability. The potential need
to expend capital for improvements to the transmission system, both to SIGECO's
facilities as well as to those facilities of adjacent utilities, over the next
several years will become more predictable as MISO completes studies related to
regional transmission planning and improvements. Such expenditures may be
significant.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxide (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 with which to comply.
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for NOx emissions in
amounts that contributed to non-attainment with the ozone NAAQS in downwind
states. The USEPA required each state to revise its SIP to provide for further
NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's
final ruling, requires a 31% reduction in total NOx emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an 8 percent
return on its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations in the
government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO has entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request On January 23, 2001, SIGECO received an information request
from the USEPA under Section 114 of the Act for historical operational
information on the Warrick and A.B. Brown generating stations. SIGECO has
provided all information requested with the most recent correspondence provided
on March 26, 2001.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.
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 IURC.
The retail gas operations of the Ohio operations are subject to regulation by
the PUCO.
All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR clauses allow the Company to charge for changes in the cost of purchased
gas. Metered electric rates contain a fuel adjustment clause (FAC) 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. Rate structures in the
Company's territories 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.
GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings
to establish the amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. 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 IURC has also applied the statute authorizing GCA and FAC 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. For
the recent past, the earnings test has not affected the Company's ability to
recover costs, and the Company does not anticipate the earnings test will
restrict recovery in the near future.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
account expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.
Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.
Recovery of Purchased Power
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2004,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
Regulatory Initiatives
In addition to the timely recovery of incremental NOx environmental expenditures
discussed above, the Company is pursuing base rate cases in its three gas
territories. The last general rate increase for VEDO and Indiana Gas was in
1992, and was in 1996 for SIGECO gas.
The Company is currently in a collaborative dialogue with the OUCC regarding
SIGECO's existing gas rates. If an agreement is reached between the parties as a
result of that process, it will be subject to review and approval by the IURC.
The Company expects to file a base rate case for Indiana Gas' territory during
the first quarter of 2004 and for VEDO in the second quarter of 2004.
Additionally, as part of the rate case process, the Company is pursuing
authority for recovery of the costs to comply with the Pipeline Safety Act of
2002 and for regulatory authority to amortize periodic expense incurred to
overhaul its electric turbines. The timing and ultimate outcome of any of these
regulatory initiatives is uncertain.
Results of Operations of the Nonregulated Group
The Nonregulated Group is comprised of four primary business areas: Energy
Marketing and Services, Coal Mining, Utility Infrastructure Services, and
Broadband. Energy Marketing and Services markets natural gas and provides energy
management services, including energy performance contracting services. Coal
Mining mines and sells coal and generates IRS Code Section 29 investment tax
credits relating to the production of coal-based synthetic fuels. Utility
Infrastructure Services provides underground construction and repair, facilities
locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the Nonregulated Group has other businesses that provide utility
services, municipal broadband consulting, and retail products and services, and
that invest in energy-related opportunities, real estate, and leveraged leases.
The Nonregulated Group supports the Company's regulated utilities pursuant to
service contracts by providing natural gas supply services, coal, utility
infrastructure services, and other services. The results of operations of the
Nonregulated Group before certain intersegment eliminations and
reclassifications for the years ended December 31, 2003, 2002, and 2001, follow:
- ------------------------------------------------------------------------
(In millions, except per share amounts) 2003 2002 2001
- ------------------------------------------------------------------------
Energy services & other revenues $ 219.2 $ 352.3 $ 741.8
Operating Expenses:
Cost of energy services & other 180.7 311.5 699.1
Operating expenses 37.2 36.1 36.3
Restructuring costs - - 3.5
- ------------------------------------------------------------------------
Total operating expenses 217.9 347.6 738.9
- ------------------------------------------------------------------------
OPERATING INCOME 1.3 4.7 2.9
Other income:
Equity in earnings of unconsolidated
affiliates 12.7 10.9 13.9
Other - net 10.2 6.1 11.4
- ------------------------------------------------------------------------
Total other income 22.9 17.0 25.3
- ------------------------------------------------------------------------
Interest expense 9.7 9.1 12.5
- ------------------------------------------------------------------------
INCOME BEFORE TAXES 14.5 12.6 15.7
Income taxes (13.2) (6.9) (4.7)
Minority interest 0.1 0.5 0.6
- ------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY LOSS 27.6 19.0 19.8
Extraordinary loss - net of tax - - (7.7)
- ------------------------------------------------------------------------
NET INCOME $ 27.6 $ 19.0 $ 12.1
========================================================================
BASIC EARNINGS PER SHARE $ 0.39 $ 0.28 $ 0.18
========================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 20.7 $ 15.0 $ 11.3
Coal Mining 13.8 12.2 13.6
Utility Infrastructure (0.8) (1.2) (0.6)
Broadband (1.0) 0.4 (0.1)
Other Businesses (5.1) (7.4) (12.1)
Nonregulated earnings for the year ended December 31, 2003, increased $8.6
million. Energy Marketing and Services' recurring operations contributed $18.1
million in earnings, or $3.1 million of the increase over 2002. A majority of
the Energy Marketing and Services' earnings were generated by gas marketing
operations, and a majority of the increase, or $2.3 million, was contributed by
performance contracting operations. Coal Mining increased $1.6 million due to
increased synfuel-related earnings, offset by lower mining results. In addition,
net gains totaling $2.7 million after tax were recognized in 2003 from business
and investment divestitures.
For the year ended December 31, 2002, earnings from the Nonregulated Group
increased $6.9 million when compared to 2001. The increase is primarily due to
increased earnings from gas marketing operations which are part of the Energy
Marketing and Services and a smaller loss incurred by the Company's broadband
consulting operations which are part of Other Businesses. The year ended
December 31, 2001, included $2.2 million after tax, or $0.04 per share, in
nonrecurring restructuring costs and $7.7 million after tax, or $0.12 per share,
related to an extraordinary loss from the divestiture of leveraged leases. In
addition, 2001 benefited from gains recognized upon sale of investments by an
unconsolidated affiliate, and 2002 was negatively affected by a change in
Indiana corporate income tax laws enacted in June 2002, which required the
recalculation of deferred tax obligations and earnings from leveraged lease
investments at the date of enactment of the law.
Energy Marketing & Services
Energy Marketing and Services is comprised of the Company's gas marketing and
performance contracting operations and held the Company's investment in
Genscape, Inc. (Genscape), a company that provides real-time power plant and
transmission line status information using wireless technology. The investment
in Genscape was sold in the third quarter of 2003 resulting in an after tax gain
of $2.6 million.
Gas marketing operations are performed through the Company's investment in
ProLiance Energy LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). ProLiance provides
natural gas and related services to Indiana Gas, the Ohio operations, and
Citizens Gas and also began providing services to SIGECO and Vectren Retail, LLC
(the Company's retail gas marketer) in 2002. ProLiance's primary businesses
include gas marketing, gas portfolio optimization, and other portfolio and
energy management services. ProLiance's primary customers are utilities and
other large end use customers.
In June 2002, the integration of Vectren's wholly owned gas marketing
subsidiary, SIGCORP Energy Services, LLC (SES), with ProLiance was completed.
SES provided natural gas and related services to SIGECO and others prior to the
integration. In exchange for the contribution of SES' net assets totaling $19.2
million, Vectren's allocable share of ProLiance's profits and losses increased
from 52.5% to 61%, consistent with Vectren's new ownership percentage. The
transfer of net assets was accounted for at book value, consistent with joint
venture accounting, and did not result in any gain or loss. In March 2001,
Vectren's allocable share of profits and losses increased from 50% to 52.5% when
ProLiance began managing the Ohio operations' gas portfolio. Governance and
voting rights remain at 50% for each member; and therefore, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
Energy Systems Group, LLC (ESG) provides energy performance contracting and
facility upgrades through its design and installation of energy-efficient
equipment. Prior to April 2003, ESG was a consolidated venture between the
Company and Citizens Gas with the Company owning two-thirds. In April 2003, the
Company purchased the remaining interest in ESG for approximately $4 million.
Net income generated by Energy Marketing and Services for the year ended
December 31, 2003, was $20.7 million, as compared to $15.0 million in 2002 and
$11.3 million in 2001. Gas marketing operations, performed through ProLiance,
contributed $15.3 million in earnings in 2003, as compared to $14.6 million in
2002, and $10.5 million in 2001. The $0.7 million increase over 2002 was
principally attributable to increased storage capacity coupled with more
volatile gas prices, offset by settlement disputes related to the contingency
discussed below. The $4.1 million increase in 2002 compared to 2001 is primarily
due to increased operations at ProLiance and increased ownership. The
performance contracting operations, performed through ESG, contributed earnings
$3.0 million in 2003, $0.7 million in 2002, and $0.9 million in 2001. The $2.3
million increase in 2003 compared to 2002 is due primarily to success in
obtaining higher margins and working from a higher construction backlog at the
end of 2002 as well as increased ownership as of April 2003.
ProLiance Contingency
There is currently a lawsuit pending in the United States District Court for the
Northern District of Alabama filed by the City of Huntsville, Alabama d/b/a
Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville
Utilities asserts claims based on negligent provision of portfolio services
and/or pricing advice, fraud, fraudulent inducement, and other theories. These
claims relate generally to several basic arguments: (1) negligence in providing
advice and/or administering portfolio arrangements; (2) alleged promises to
provide gas at a below-market rate; (3) the creation and repayment of a "winter
levelizing program" instituted by ProLiance in conjunction with the Manager of
Huntsville's Gas Utility, to allow Huntsville Utilities to pay its gas bills
from the winter of 2000-2001 over an extended period of time coupled with the
alleged ignorance about the program on the part of Huntsville Utilities' Gas
Board, and; (4) the sale of Huntsville Utilities' gas storage supplies to repay
the balance owed on the winter levelizing program and the authority of
Huntsville Utilities' gas manager to approve those sales. In a press conference
on May 21, 2002, Huntsville Utilities asserted its monetary damages to be
approximately $10 million, and seeks to treble that amount. ProLiance has made
counterclaims asserting breach of contract, among others, based on Huntsville
Utilities' refusal to take gas under fixed price agreements. Both parties have
denied the charges contained in the respective claims.
In 2003, ProLiance established reserves for amounts due from Huntsville
Utilities due to uncertainties surrounding collection. ProLiance denies any
wrongdoing, believes its actions were proper under the contract and amendments
signed by the manager of Huntsville's Gas Utility, and is vigorously defending
against the suit. ProLiance is an insured under a policy of insurance providing
defense costs which may provide in whole or in part, indemnification within the
policy limits for claims asserted against ProLiance. Accordingly, no other loss
contingencies have been recorded at this time. However, it is not possible to
predict or determine the outcome of this litigation and accordingly there can be
no assurance that ProLiance will prevail. It is not currently expected that
costs associated with this matter will have a material adverse effect on
Vectren's consolidated financial position or liquidity but an unfavorable
outcome could possibly be material to Vectren's earnings.
Coal Mining
The Coal Mining Group mines and sells coal to the Company's utility operations
and to other third parties through its wholly owned subsidiary Vectren Fuels,
Inc. (Fuels). The Coal Mining Group also generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels
through its 8.3% ownership interest in Pace Carbon Synfuels, LP (Pace Carbon).
Pace Carbon developed, owns, and operates four projects to produce and sell
coal-based synthetic fuel (synfuel) utilizing Covol technology. Vectren accounts
for is investment in Pace Carbon using the equity method. In addition, Fuels
receives synfuel-related fees from synfuel producers unrelated to Pace Carbon
for a portion of its coal production.
Coal Mining net income for the year ended December 31, 2003, was $13.8 million,
as compared to $12.2 million in 2002, and $13.6 million in 2001. Synfuel-related
results, which include earnings from Pace Carbon and synfuel processing fees
earned by Fuels, contributed all of the earnings in 2003, $9.0 million in 2002,
and $6.6 million in 2001. Increasing production of synthetic fuel by Pace Carbon
in 2003 and 2002 has generated a greater amount of Section 29 tax credits that
have been utilized by the Company, reducing income tax expense in those years.
The increase in synfuel-related earnings has been offset by mining operations
that have experienced decreased yields due to poor mining conditions and
increased mine development cost amortization.
IRS Section 29 Investment Tax Credit Recent Developments
Under Section 29 of the Internal Revenue Code, manufacturers such as Pace
Carbon, receive a tax credit for every ton of synthetic fuel sold. To qualify
for the credits, the synthetic fuel must meet three primary conditions: 1) there
must be a significant chemical change in the coal feedstock, 2) the product must
be sold to an unrelated person, and 3) the production facility must have been
placed in service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the
synthetic fuel produced at the Pace Carbon facilities should qualify for Section
29 tax credits. The IRS issued a private letter ruling with respect to the four
projects on November 11, 1997, and subsequently issued an updated private letter
ruling on September 23, 2002.
As a partner in Pace Carbon, Vectren has reflected total tax credits under
Section 29 in its consolidated results through December 31, 2003, of
approximately $39 million. Vectren has been in a position to fully utilize the
credits generated and continues to project full utilization.
In June 2003, the IRS, in an industry-wide announcement, stated that it would
review the scientific validity of test procedures and results presented as
evidence of significant chemical change. During this review, the IRS suspended
the issuance of new private letter rulings on that subject. In October 2003, the
IRS completed its review and determined that the test procedures and results
used by taxpayers are scientifically valid if the procedures are applied in a
consistent and unbiased manner. Also, the IRS will issue new private letter
rulings based on revised standards; however, it has continuing concerns
regarding the sampling and data/record retention practices prevalent in the
synthetic fuels industry.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year
and later expanded the audit to include tax years 1999, 2000, and 2001. Based on
conclusions reached in the industry-wide review and recently issued private
letter rulings involving other synthetic fuel facilities, Vectren believes
chemical change issues from these audits may soon be resolved. However, the IRS
has not directly notified Pace Carbon of any resolution.
Vectren believes it is justified in its reliance on the private letter rulings
for the Pace Carbon facilities, that the test results that Pace Carbon presented
to the IRS in connection with its private letter rulings are scientifically
valid, and that Pace Carbon has operated its facilities in compliance with its
private letter rulings and Section 29 of the Internal Revenue Code. However, at
this time, Vectren cannot provide any assurance as to the outcome of these
audits concerning the issue of chemical change or any other issue raised during
the audits relative to its investment in Pace Carbon. Further, it is expected
that Section 29 investments will continue to draw attention from various
interest groups.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair to
gas, water, electric and telecommunications companies primarily through its
investment in Reliant Services, LLC (Reliant) and Reliant's 100% ownership in
Miller Pipeline. Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting.
Results in recent years have been affected by cutbacks of underground
construction and repair projects by gas distribution customers. In the second
half of 2003, Miller returned to profitability due to an increase in
construction and repair projects as utilities began to return to historical
expenditure levels.
Broadband
Broadband invests in communication services, such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Company has an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the
Company's ownership interest up to 16%. Utilicom is a provider of bundled
communication services focusing on last mile delivery to residential and
commercial customers. The Company also has an approximate 19% equity interest in
SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold
interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to over
29,000 customers, averaging nearly 3 revenue generating units per customer, in
the greater Evansville, Indiana area and continues to increase its positive
operating cash flow.
The equity investments in Utilicom and Holdings are accounted for using the cost
method of accounting. As a result, for years ended December 31, 2003, 2002, and
2001, these investments had no significant impact on the Company's operating
results.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana and Dayton, Ohio markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
remain interested in the Indianapolis and Dayton projects, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
For the year ended December 31, 2003, Broadband losses were $1.0 million. This
reflects the impact of a $1.2 million after tax loss on the sale of the
Company's investment in First Mile, a small broadband operation in Indianapolis,
Indiana.
Other Businesses
The Other Businesses Group includes a variety of wholly owned operations and
investments. For the year ended December 31, 2003, the Other Businesses Group
losses, including operating expenses, were $5.1 million, as compared to losses
of $7.4 million in 2002, and losses of $12.1 million in 2001. The $2.3 million
improvement occurring in 2003 resulted from a $1.2 million after tax gain
recognized upon sale of IEIFS, LLC (IEIFS), a debt collection subsidiary; and
the operating results of Vectren Retail, LLC (Vectren Source). Vectren Source
began operations in 2001 and provides natural gas and other related products and
services primarily in Ohio, serving over 72,000 customers opting for choice
among energy providers. Source's losses for the year ended December 31, 2003,
were $1.9 million, as compared to $2.6 million in 2002.
The net loss incurred in 2002 compared to 2001 narrowed $4.7 million. The
improvement results from a $7.7 million extraordinary loss incurred in 2001
related to the divesture of leveraged leases that generated positive cash flow
of approximately $67 million. In addition, the Company's wholly owned broadband
consulting company incurred charges in 2002 and 2001 related to the settlement
of construction contracts and the reorganization of its operations, allowing it
to focus on consulting services. The net losses incurred in those years totaled
$2.8 million in 2002, as compared $8.0 million in 2001. These factors have been
partially offset by less leveraged lease and other interest income in 2002 due
to divestures, a change in Indiana tax law in 2002, and gains recognized in 2001
from the Haddington Energy Partnerships' (Haddington) sale of investments.
The Haddington partnerships are equity method investments that invest in
energy-related ventures. During 2001, these partnerships sold investments
resulting in gains reflected by the Company totaling $6.2 million ($3.8 million
after tax). The most significant portion of these earnings was derived from
Haddington's sale of Bear Paw Investments, LLC (Bear Paw). In March 2001,
Haddington sold its investment in Bear Paw in exchange for a combination of cash
and securities. The cost of Haddington's Bear Paw investment approximated $5.1
million, and the net proceeds received totaled $18.1 million, resulting in a
gain of $13.0 million. The Company recognized its portion of the pre-tax gain
totaling $3.9 million in March 2001. Later in 2001, as the securities received
were sold, the Company recognized its portion of the additional earnings
totaling $1.0 million.
Significant Fluctuations
Revenues and Cost of Revenues
Resulting from the integration of the Company's two gas marketers, revenues and
cost of revenues decreased significantly. Prior to June 1, 2002, the operations
of SES were consolidated. Subsequent to June 1, 2002, SES' operating results,
now part of ProLiance, are reflected in equity in earnings of unconsolidated
affiliates. SES' operations were the majority of nonregulated revenues and cost
of revenues. As a result of the integration, revenues decreased $183.7 million
in 2003 and $392.5 million in 2002. Cost of revenues decreased $176.1 million in
2003 and $387.1 million in 2002. The decreases have been partially offset by
increased results at ESG, Fuels, and Vectren Source. Vectren Source's revenues
were $44.3 million in 2003, $10.3 million in 2002, and $0.3 million in 2001.
Equity in Earnings of Unconsolidated Affiliates
The primary components of Equity in earnings of unconsolidated affiliates relate
to earnings of ProLiance and losses incurred by Pace Carbon. For the years ended
December 31, 2003, 2002, and 2001, the Company's portion of ProLiance's earnings
were $25.9 million, $19.1 million, and $12.8 million, respectively. For the
years ended December 31, 2003, 2002, and 2001, the Company's portion of Pace
Carbon losses were $11.4 million, $6.8 million, and $4.5 million, respectively.
In addition 2001, includes $6.2 million in earnings from the Haddington
partnerships, as discussed above.
Other - net
During 2003, Other - net increased $4.1 million. The increase is due to the gain
recognized from the sale of Genscape, which on a pre-tax basis approximated just
over $5 million. The decrease in 2002 compared to 2001 totaling $5.3 million is
primarily due to less leverage lease and interest income, which is an effect of
the divestures of structured finance arrangements in 2001 and 2002.
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates that affect
the amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgment. These include
the estimates to perform goodwill and other asset impairments tests and to
determine pension and postretirement benefit obligations. The Company makes
other estimates in the course of accounting for unbilled revenue and the effects
of regulation that are critical to the Company's financial results but that are
less likely to be impacted by near term changes. Other estimates that
significantly affect the Company's results, but are not necessarily critical to
operations, include depreciation of utility and non-utility plant, the valuation
of derivative contracts, and the allowance for doubtful accounts, among others.
Actual results could differ from these estimates.
Impairment Review of Investments
The Company has investments in notes receivable, entities accounted for using
the cost method of accounting, and entities accounted for using the equity
method of accounting. When events occur that may cause one of these investments
to be impaired, the Company performs an impairment analysis. An impairment
analysis of notes receivable usually involves the comparison of the investment's
estimated free cash flows to the stated terms of the note, or for notes that are
collateral dependent, a comparison of the collateral's fair value to the
carrying amount of the note. An impairment analysis of cost method and equity
method investments involves comparison of the investment's estimated fair value
to its carrying amount. Fair value is estimated using market comparisons,
appraisals, and/or discounted cash flow analyses. Calculating free cash flows
and fair value using the above methods is subjective and requires significant
judgment in growth assumptions, longevity of cash flows, and discount rates (for
fair value calculations).
During 2002, the Company performed an impairment analysis on its
Utilicom-related investments. The Company used market comparisons to estimate
fair value for the cost method portion of the Utilicom investment and a free
cash flow analysis to estimate fair value for the note receivable portion of the
Utilicom investment. No impairment charge was recorded as a result of these
tests. However, a 10% decrease in the fair value that was estimated using market
comparables would have resulted in an impairment charge to the cost method
investment that would not have been material. A 10% decrease in the cash flow
growth assumption utilized to calculate Utilicom's free cash flows would have
resulted in no impairment charge to the notes receivable. During 2003, no
impairment analysis was performed as no triggering events occurred during the
year.
Impairment tests on other investments were also conducted using appraisals and
discounted cash flow models to estimate fair value. No impairment charges
resulted from these analyses in 2002 and a $3.9 million write-off of the BABB
investments resulted in 2003. For the other impairment tests performed during
2002, a 10% adverse change in the calculated or appraised fair value of
collateral or a 100 basis point adverse change in the discount rate used to
estimate fair value would have resulted in an approximate $3 million impairment
charge. A 10% adverse change of such factors would not have affected the 2003
BABB write-off.
Goodwill
Pursuant to SFAS No. 142, the Company performed an initial impairment analysis
of its goodwill, all of which resides in the Gas Utility Services operating
segment. Also consistent with SFAS 142, goodwill is tested for impairment
annually at the beginning of the year and more frequently if events or
circumstances indicate that an impairment loss has been incurred. Impairment
tests are performed at the reporting unit level which the Company has determined
to be consistent with its Gas Utility Services operating segment as identified
in Note 17 to the consolidated financial statements. An impairment test
performed in accordance with SFAS 142 requires that a reporting unit's fair
value be estimated. The Company used a discounted cash flow model to estimate
the fair value of its Gas Utility Services operating segment, and that estimated
fair value was compared to its carrying amount, including goodwill. The
estimated fair value was in excess of the carrying amount in both 2003 and 2002
and therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgment in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also would have resulted in no impairment charge in 2003 or
2002.
Pension and Other Postretirement Obligations
The Company estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other things, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of the Company's pension and postretirement plans. The
Company annually measures its obligations on September 30. The Company used the
following weighted average assumptions to develop 2003 periodic benefit cost: a
discount rate of 6.75%, an expected return on plan assets before expenses of
9.0%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2003 declining to 5% in 2006. During 2003, the Company reduced
the discount rate and rate of compensation increase by 75 basis points to value
2003 ending pension and postretirement obligations due to a decline in benchmark
interest rates. The Company also lengthened to 2009 the time in which the health
care trend rate declines to 5% primarily due to increases in healthcare costs.
In addition, the Company reduced its 2004 expected return on plan assets 50
basis points from that used to estimate 2003 expense due to recent lower
investment returns and lower interest rates. Future changes in health care
costs, work force demographics, interest rates, or plan changes could
significantly affect the estimated cost of these future benefits.
For the year ended December 31, 2003, a one percentage point adverse change in
the assumed health care cost trend rate for the postretirement health care plans
would have decreased pre-tax income by approximately $0.7 million and would have
increased the postretirement liability by approximately $8.4 million. Management
estimates that a 50 basis point reduction in the expected return on plan assets
would have increased 2003 periodic benefit cost by approximately $1 million and
a 50 basis point decrease in the discount rate would have also increased
periodic benefit cost by approximately $1 million.
Unbilled Revenues
To more closely match revenues and expenses, the Company records revenues for
all gas and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the month to
allocate unbilled units. Those allocated units are multiplied by rates in effect
during the month to calculate unbilled revenue at balance sheet dates. While
certain estimates are used in the calculation of unbilled revenue, the method
these estimates are derived from is not subject to near-term changes.
Regulation
At each reporting date, the Company reviews current regulatory trends in the
markets in which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Based on the Company's current review, it believes its regulatory assets are
probable of recovery. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets. In the unlikely event of a change in the current regulatory
environment, such write-offs and impairment charges could be significant.
Impact of Recently Issued Accounting Guidance
SFAS 132 (Revised 2003)
In December 2003, FASB issued SFAS No. 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits" (SFAS 132), to
improve financial statement disclosures for defined benefit plans. The change
replaces existing FASB disclosure requirements for pensions and postretirement
plans. The guidance is effective for fiscal years ending after December 15,
2003. The adoption did not impact the Company's results of operations or
financial condition. The incremental disclosure requirements are included in
these financial statements in Note 6. In addition to expanded annual
disclosures, SFAS 132, as revised, requires the reporting of various elements of
pension and other postretirement benefit costs on a quarterly basis.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $229 million and $210 million,
respectively. In 2002, the cost of removal has been included in other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
Company has approximately $200,000 of outstanding preferred stock of a
subsidiary that is redeemable on terms outside the Company's control. However,
the preferred stock is not redeemable on a specified or determinable date or
upon an event that is certain to occur. The adoption of SFAS 150 on January 1,
2004, did not affect the Company's results of operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition. The incremental disclosure
requirements are included in these financial statements in Note 12.
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004.
The Company has neither created nor obtained an interest in a VIE since January
31, 2003. Certain other entities that the Company was involved with prior to
that date, including limited partnership investments that operate affordable
housing projects, are still being evaluated to determine if the entity is a VIE
and, if so, if Vectren is the primary beneficiary. If these entities are
determined to be VIE's and Vectren is determined to be the primary beneficiary,
the effect to the Company's financial statements would not be material.
Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 consolidated financial statements, the
Company restated its annual consolidated financial statements for 2000 and 2001,
and its 2002 quarterly results. The Company received an informal inquiry from
the SEC with respect to this restatement. In response, the Company met with the
SEC staff and provided information in response to their requests, with the most
recent response provided on July 26, 2003.
Financial Condition
Within Vectren's consolidated group, VUHI funds short-term and long-term
financing needs of the Utility Group operations, and Vectren Capital Corp
(Vectren Capital) funds short-term and long-term financing needs of the
Nonregulated Group and corporate operations. Vectren Corporation guarantees
Vectren Capital's debt, but does not guarantee VUHI's debt. Vectren Capital's
long-term and short-term obligations outstanding at December 31, 2003, totaled
$113.0 million and $87.6 million, respectively. VUHI's outstanding long-term and
short-term borrowing arrangements are jointly and severally guaranteed by
Indiana Gas, SIGECO, and VEDO. VUHI's long-term and short-term obligations
outstanding at December 31, 2003, totaled $550.0 million and $184.4 million,
respectively. Additionally, prior to VUHI's formation, Indiana Gas and SIGECO
funded their operations separately, and therefore, have long-term debt
outstanding funded solely by their operations.
The Company's common stock dividends are primarily funded by utility operations.
Nonregulated operations have demonstrated sustained profitability, and the
ability to generate cash flows. These cash flows are used to fund a portion of
the Company's dividends, are reinvested in other nonregulated ventures, and from
time to time may be reinvested in utility operations or used for corporate
expenses.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2003, are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's Investors Service (Moody's), respectively.
SIGECO's credit ratings on outstanding senior unsecured debt are BBB+/Baa1.
SIGECO's credit ratings on outstanding secured debt are A-/A3. VUHI's commercial
paper has a credit rating of A-2/P-2. Vectren Capital's senior unsecured debt is
rated BBB+/Baa2. Moody's current outlook is stable while Standard and Poor's
current outlook is negative. The ratings of Moody's and Standard and Poor's are
categorized as investment grade and are unchanged from December 31, 2002. In
July 2003, Standard and Poor's reaffirmed its ratings, and Moody's reaffirmed
its ratings on VUHI's senior unsecured debt. A security rating is not a
recommendation to buy, sell, or hold securities. The rating is subject to
revision or withdrawal at any time, and each rating should be evaluated
independently of any other rating. Standard and Poor's and Moody's lowest level
investment grade rating is BBB- and Baa3, respectively.
The Company's consolidated equity capitalization objective is 45-55% of total
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, and seasonal
factors that affect the Company's operation. The Company's equity component was
49% and 46% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at December 31, 2003, and 2002,
respectively.
The Company expects the majority of its capital expenditures, investments, and
debt security redemptions to be provided by internally generated funds. However,
due to significant capital expenditures for NOx compliance equipment at SIGECO
and to further strengthen the Company's capital structure and the capital
structures of VUHI and its utility subsidiaries, the Company has completed
certain financing transactions as more fully described in the discussion of
financing activity below.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities decreased during the year ended December 31, 2003, compared to 2002
by $115.2 million and increased $104.2 million in 2002 compared to 2001. The
primary reason for these changes was favorable changes in working capital
accounts occurring in 2002 due to lower gas prices in that year and higher gas
prices in 2003 and 2001. In 2003, the decrease was partially offset by increased
earnings before non-cash charges.
Financing Cash Flow
Although working capital requirements are generally funded by cash flow from
operations, the Company uses short-term borrowings to supplement working capital
needs. Additionally, short-term borrowings are required for capital projects and
investments until they are permanently financed.
Cash flow provided by financing activities of $45.8 million for the year ended
December 31, 2003, includes the effects of the permanent financing executed
during the current year in which approximately $366 million in equity, debt, and
hedging net proceeds were received and used to retire higher coupon long-term
debt and other short term borrowings. Common stock dividends have increased in
2003 compared to 2002 due to the issuance of new securities and board authorized
increases in the dividend rate.
Cash flow required for financing activities of $57.6 million for the year ended
December 31, 2002, includes increased common stock dividends compared to 2001.
Borrowings also increased due to financing a portion of capital expenditures for
NOx compliance temporarily with short-term borrowings. Cash flow required for
financing activities of $2.7 million for the year ended December 31, 2001,
includes $59.5 million of reductions in borrowings and preferred stock and $69.5
million in common stock dividends, offset by the issuance of $129.4 million of
common stock. During 2001, $473.4 million of net proceeds from equity and debt
issuances were utilized to pay down short-term borrowings.
Equity Issuance
In March 2003, the Company filed a registration statement with the Securities
and Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock as well as the senior unsecured notes
of VUHI described below. In August 2003, the registration became effective, and
an agreement was reached to sell approximately 7.4 million shares to a group of
underwriters. The net proceeds totaled $163.2 million and were utilized entirely
by VUHI and VUHI's subsidiaries to repay short-term borrowings and to retire
long-term debt with higher interest rates.
VUHI Debt Issuance
In July 2003, VUHI issued senior unsecured notes with an aggregate principal
amount of $200 million in two $100 million tranches. The first tranche was
10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746%
to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes
due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80%
to maturity (2018 Notes).
The notes are guaranteed by the VUHI's three public utilities: SIGECO, Indiana
Gas, and VEDO. These guarantees are full and unconditional and joint and
several. In addition, they have no sinking fund requirements, and interest
payments are due semi-annually. The notes may be called by VUHI, in whole or in
part, at any time for an amount equal to accrued and unpaid interest, plus the
greater of 100% of the principal amount or the sum of the present values of the
remaining scheduled payments of principal and interest, discounted to the
redemption date on a semi-annual basis at the Treasury Rate, as defined in the
indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the
2018 Notes.
Shortly before these issues, VUHI entered into several treasury locks with a
total notional amount of $150.0 million. Upon issuance of the debt, the treasury
locks were settled resulting in the receipt of $5.7 million in cash, which was
recorded as a regulatory liability pursuant to existing regulatory orders. The
value received is being amortized as a reduction of interest expense over the
life of the issues.
The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million and were used to repay short-term
borrowing and to retire long-term debt with higher interest rates.
SIGECO and Indiana Gas Debt Call
During 2003, the Company called two first mortgage bonds outstanding at SIGECO
and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
had a principal amount of $45.0 million, an interest rate of 7.60%, was
originally due in 2023, and was redeemed at 103.745% of its stated principal
amount. The second SIGECO bond had a principal amount of $20.0 million, an
interest rate of 7.625%, was originally due in 2025, and was redeemed at
103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an
interest rate of 9.375%, was originally due in 2021, and was redeemed at
105.525% of the stated principal amount. The second Indiana Gas note had a
principal amount of $13.5 million, an interest rate of 6.75%, was originally due
in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire these notes
totaling $3.6 million were deferred as a regulatory asset.
Permanent Financing for the Ohio Operations Purchase
In January 2001, the Company filed a registration statement with the Securities
and Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock. In February 2001, the registration
became effective, and an agreement was reached to sell approximately 6.3 million
shares to a group of underwriters. The net proceeds totaled $129.4 million.
In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission for $350.0 million aggregate principal amount of
unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with
an aggregate principal amount of $100.0 million and an interest rate of 7.25%
(the October Notes), and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.
Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and
several. In addition, these issues have no sinking fund requirements, and
interest payments are due quarterly for the October Notes and semi-annually for
the December Notes. The October Notes are due October 2031, but may be called by
the Company, in whole or in part, at any time after October 2006 at 100% of the
principal amount plus any accrued interest thereon. The December Notes are due
December 2011, but may be called by the Company, in whole or in part, at any
time for an amount equal to accrued and unpaid interest, plus the greater of
100% of the principal amount or the sum of the present values of the remaining
scheduled payments of principal and interest, discounted to the redemption date
on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus
25 basis points.
The net proceeds from the sale of the senior notes and settlement of hedging
arrangements totaled $344.0 million.
The proceeds received from the equity and debt issuance were used to refinance
interim borrowing arrangements used to purchase the Ohio operations.
Other Financing Transactions
Other Company debt totaling $18.5 million in 2003, $6.5 million in 2001, and
$7.6 million in 2001 was retired as scheduled.
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.
Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.
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.
Investing Cash Flow
Cash required for investing activities of $232.7 million for the year ended
December 31, 2003, includes $236.2 million of requirements for capital
expenditures. Investing activities for 2002 were $234.6 million. The decrease
occurring in 2003 principally results from collections of notes receivable and
distributions by unconsolidated affiliates offset by slightly higher capital
expenditures.
Cash required for investing activities of $234.6 million for the year ended
December 31, 2002, includes $218.7 million of requirements for capital
expenditures. Investing activities for 2001 were $175.6 million. The $59.0
million increase occurring in 2002 is principally the result of the sale of
leveraged lease and notes receivable investments in 2001.
Available Sources of Liquidity
At December 31, 2003, the Company has $531 million of short-term borrowing
capacity, including $351 million for the Utility Group and $180 million for the
wholly owned Nonregulated Group and corporate operations, of which approximately
$166 million is available for the Utility Group operations and approximately $91
million is available for the wholly owned Nonregulated Group and corporate
operations. The availability of short-term borrowing is reduced by outstanding
letters of credit totaling $1.0 million, collateralizing Nonregulated Group
activities.
Beginning in 2003, the Company began issuing new shares to satisfy dividend
reinvestment plan requirements. During 2003, new equity issues from stock plans
provided liquidity of approximately of $7.1 million. Management estimates such
new share issues will add similar liquidity in succeeding years.
Potential & Future Uses of Liquidity
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2003:
- -------------------------------------------------------------------------------------------
(In millions) 2004 2005 2006 2007 2008 Thereafter
- -------------------------------------------------------------------------------------------
Long-term debt (1) $ 15.0 $ 38.0 $ - $24.0 $ - $1,029.5
Short-term debt 274.9 - - - - -
Commodity firm purchase
commitments 169.8 34.5 - - - -
Utility & nonutility plant
purchase commitments (2) 96.8 19.7 1.3 - - -
Operating leases 6.7 5.4 4.2 3.3 1.4 0.6
Unconsolidated affiliate
investments (2) (3) 5.5 3.5 - - - -
- -------------------------------------------------------------------------------------------
Total $568.7 $101.1 $ 5.5 $27.3 $ 1.4 $1,030.1
===========================================================================================
(1) Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow holders
to put debt back to the Company at face value or the Company to call debt
at face value or at a premium. Long-term debt subject to tender during the
years following 2003 (in millions) is $13.5 in 2004, $10.0 in 2005, $53.7
in 2006, $20.0 in 2007, zero in 2008, and $120.0 thereafter.
(2) The settlement period of these obligations is estimated.
(3) Future 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.
Planned Capital Expenditures & Investments
The timing and amount of capital expenditures and investments in nonregulated
unconsolidated affiliates, including contractual purchase and investment
commitments discussed above, for the five-year period 2004 - 2008 are estimated
as follows:
- ----------------------------------------------------------------------------------------------
(In millions) 2004 2005 2006 2007 2008
- -----------------------------------------------------------------------------------------------
Capital expenditures
Utility Group (1) $ 252.9 $ 213.8 $ 222.9 $ 216.4 $ 233.6
Nonregulated Group 9.2 9.7 11.7 6.8 6.1
- -----------------------------------------------------------------------------------------------
Total capital expenditures $ 262.1 $ 223.5 $ 234.6 $ 223.2 $ 239.7
===============================================================================================
Investments in unconsolidated affiliates $ 20.4 $ 24.0 $ 18.7 $ 37.9 $ 12.1
===============================================================================================
(1) Includes expenditures for NOx compliance of approximately $77.4 million in
2004, $19.7 million in 2005, and $3.6 million in 2006.
Off Balance Sheet Arrangements
Ratings Triggers
At December 31, 2003, $113.0 million of Vectren Capital's senior unsecured notes
were subject to cross-default and ratings trigger provisions that would provide
that the full balance outstanding is subject to prepayment if the ratings of
Indiana Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a
make whole amount based on the discounted value of the remaining payments due on
the notes would also become payable. The credit rating of Indiana Gas' senior
unsecured debt and SIGECO's secured debt remains one level and two levels,
respectively, above the ratings trigger.
Guarantees and Letters of Credit
In the normal course of business, Vectren Corporation issues guarantees to third
parties on behalf of its consolidated subsidiaries and unconsolidated
affiliates. Such guarantees allow those subsidiaries and affiliates to execute
transactions on more favorable terms than the subsidiary or affiliate could
obtain without such a guarantee. Guarantees may include posted letters of
credit, leasing guarantees, and performance guarantees. As of December 31, 2003,
guarantees issued and outstanding on behalf of unconsolidated affiliates
approximated $6 million. In addition, prior to the effective date of FIN 45, the
Company issued a guarantee approximating $4 million related to the residual
value of an operating lease that expires in 2006. Through December 31, 2003, the
Company has not been called upon to satisfy any obligations pursuant to its
guarantees.
Pension and Postretirement Funding Obligations
The Company has not made significant contributions to its qualified pension
plans in recent years. Due to recent market performance, it is likely to be
necessary for the Company to make contributions to benefits plans in the coming
years. Management currently estimates that the qualified pension plans will
require Company contributions of approximately $5 million in 2004 and
approximately $10 million in 2005.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o The performance of projects undertaken by the Company's nonregulated
businesses and the success of efforts to invest in and develop new
opportunities, including but not limited to, the realization of Section 29
income tax credits and the Company's coal mining, gas marketing, and
broadband strategies.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in our credit rating, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee or contractor workforce factors including changes in key
executives, collective bargaining agreements with union employees, or work
stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but not
limited to, those described in Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business risks associated with commodity
prices, interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company's risk management program includes, among other
things, the use of derivatives.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities to be used in operations and
optimizing its generation assets.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations, which subject to compliance with those
regulations, allow for recovery of the cost of such purchases through natural
gas and fuel cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating commodity prices including electricity, natural gas, and coal. Other
commodity-related operations include regulated sales of electricity to certain
municipalities and large industrial customers and nonregulated retail gas
marketing and coal mining operations. Open positions in terms of price, volume,
and specified delivery points may occur and are managed using methods described
below with frequent management reporting.
The Company's wholesale power marketing activities include asset optimization
activities that manage the utilization of available electric generating capacity
by entering into energy contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts. The Company accounts for asset optimization contracts that
are derivatives at fair value with the offset marked to market through earnings.
The Company's other commodity-related operations involve the purchase and sale
of commodities, including electricity, natural gas, and coal to meet customer
demands and operational needs. These operations also enter into forward and
option contracts that commit the Company to purchase and sell commodities in the
future. Price risk from forward positions obligating the Company to deliver
commodities is mitigated using stored inventory, generating capability, and
offsetting forward purchase contracts. Price risk also results from forward
contracts obligating the Company to purchase commodities to fulfill forecasted
nonregulated sales of natural gas and coal that may, or may not, occur. With the
exception of a small portion of contracts that are derivatives that qualify as
hedges of forecasted transactions under SFAS 133, these contracts are expected
to be settled by physical receipt or delivery of the commodity.
Market risk resulting from commodity contracts is measured by management using
the potential impact on pre-tax earnings caused by the effect a 10% adverse
change in forward commodity prices might have on market sensitive derivative
positions outstanding on specific dates. For the years ended December 31, 2003,
and 2002, a 10% adverse change in forward commodity prices would have decreased
earnings by $3.0 million and $1.7 million, respectively, based upon open
positions existing on the last day of those years.
Commodity Price Risk from Unconsolidated Affiliate
ProLiance, a nonregulated energy marketing affiliate, engages in energy hedging
activities to manage pricing decisions, minimize the risk of price volatility,
and minimize price risk exposure in the energy markets. ProLiance's market
exposure arises from storage inventory, imbalances, and fixed-price forward
purchase and sale contracts, which are entered into to support its operating
activities. Currently, ProLiance buys and sells physical commodities and
utilizes financial instruments to hedge its market exposure. However, net open
positions in terms of price, volume and specified delivery point do occur.
ProLiance manages open positions with policies which limit its exposure to
market risk and require reporting potential financial exposure to its management
and its members.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The
Company's risk management objective is for between 20% and 30% of its total debt
to be exposed to short-term interest rate volatility. However, there are times
when this targeted range of interest rate exposure may not be attained. To
manage this exposure, the Company may use derivative financial instruments. At
December 31, 2003, such debt obligations, as affected by designated interest
rate swaps, represented 24% of the Company's total debt portfolio.
Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2003 and 2002, the weighted average combined
borrowings under these arrangements were $316.1 million and $311.3 million,
respectively. At December 31, 2003, and 2002, combined borrowings under these
arrangements were $328.3 million and $419.4 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2003, and 2002, an increase of 100 basis points (one percentage point) in
the rates would have increased interest expense by $3.2 million and $3.1
million, respectively.
Other Risks
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages exposure to counter-party credit risk by entering into
contracts with companies that can be reasonably expected to fully perform under
the terms of the contract. Counter-party credit risk is monitored regularly and
positions are adjusted appropriately to manage risk. Further, tools such as
netting arrangements and requests for collateral are also used to manage credit
risk. Market risk is the adverse effect on the value of a financial instrument
that results from a change in commodity prices or interest rates. The Company
attempts to manage exposure to market risk associated with commodity contracts
and interest rates by establishing parameters and monitoring those parameters
that limit the types and degree of market risk that may be undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits or refunds
cash deposits based on that review. Credit risk associated with certain
investments is also managed by a review of creditworthiness and receipt of
collateral.
Although the Company's regulated operations are exposed to limited commodity
price risk, volatile natural gas prices can result in higher working capital
requirements; increased expenses including unrecoverable interest costs,
uncollectible accounts expense, and unaccounted for gas; and some level of price
sensitive reduction in volumes sold. The Company mitigates these risks by
executing derivative contracts that manage the price of forecasted natural gas
purchases. These contracts are subject to regulation, which allows for
reasonable and prudent hedging costs to be recovered through rates. When
regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
ITEM 8. Financial Statements and Supplementary Data
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Vectren Corporation is responsible for the preparation of the
consolidated financial statements and the related financial data contained in
this report. The financial statements are prepared in conformity with accounting
principles generally accepted in the United States and follow accounting
policies and principles applicable to regulated public utilities.
The integrity and objectivity of the data in this report, including required
estimates and judgments, is the responsibility of management. Management
maintains a system of internal control and utilizes an internal auditing program
to provide reasonable assurance of compliance with Company policies and
procedures and the safeguard of assets.
The board of directors pursues its responsibility for these financial statements
through its audit committee, which meets periodically with management, the
internal auditors, and the independent auditors, to assure that each is carrying
out its responsibilities. Both the internal auditors and the independent
auditors meet with the audit committee of Vectren Corporation's board of
directors, with and without management representatives present, to discuss the
scope and results of their audits, their comments on the adequacy of internal
accounting control and the quality of financial reporting.
/s/ Niel C. Ellerbrook
- -----------------------------------------------
Niel C. Ellerbrook
Chairman, President, & Chief Executive Officer
February 12, 2004
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren
Corporation and subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of income, shareholders' equity, and cash flows for each
of the three years in the period ended December 31, 2003. Our audits also
included the financial statement schedules listed in the Index at Item 15. These
financial statements and financial statement schedules are the responsibility of
the Company's management. Our responsibility is to express an opinion on the
financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Vectren Corporation and
subsidiaries as of December 31, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic consolidated financial
statements taken as a whole, present fairly in all material respects the
information set forth therein. \
As discussed in Note 2-H, effective January 1, 2003, the Company adopted
Statement of Financial Accounting Standards ("SFAS") 143, "Accounting for Asset
Retirement Obligations." As discussed in Note 2-G, effective January 1, 2002,
the Company adopted SFAS 142, "Goodwill and Other Intangibles." As discussed in
Note 15, effective January 1, 2001, the Company adopted SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended.
As discussed in Note 15, in 2003 the Company adopted EITF Issue No. 03-11,
"Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and "Not Held for Trading Purposes" as Defined in
Issue No. 02-3." Amounts for the years 2002 and 2001 have been reclassified in
the accompanying statements of income to conform to this new method of
presentation.
/s/ DELOITTE & TOUCHE LLP
- -----------------------------------------------
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 12, 2004
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
- ----------------------------------------------------------------------------
2003 2002
- ----------------------------------------------------------------------------
ASSETS
Current Assets
Cash & cash equivalents $ 15.3 $ 25.1
Accounts receivable-less reserves
of $3.2 & $5.5, respectively 137.3 154.4
Accrued unbilled revenues 137.8 116.1
Inventories 70.4 62.8
Recoverable fuel & natural gas costs 20.3 19.3
Prepayments & other current assets 131.1 87.7
- ----------------------------------------------------------------------------
Total current assets 512.2 465.4
- ----------------------------------------------------------------------------
Utility Plant
Original cost 3,250.7 3,042.2
Less: accumulated depreciation &
amortization 1,247.0 1,179.0
- ----------------------------------------------------------------------------
Net utility plant 2,003.7 1,863.2
- ----------------------------------------------------------------------------
Investments in unconsolidated affiliates 176.1 153.3
Other investments 122.9 124.3
Non-utility property - net 222.3 228.0
Goodwill - net 205.0 205.0
Regulatory assets 89.6 75.8
Other assets 21.6 21.5
- ----------------------------------------------------------------------------
TOTAL ASSETS $3,353.4 $3,136.5
============================================================================
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,
- ------------------------------------------------------------------------------
2003 2002
- ------------------------------------------------------------------------------
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 85.3 $ 101.7
Accounts payable to affiliated companies 86.4 86.4
Accrued liabilities 109.3 119.9
Short-term borrowings 274.9 399.5
Current maturities of long-term debt 15.0 39.8
Long-term debt subject to tender 13.5 26.6
- ------------------------------------------------------------------------------
Total current liabilities 584.4 773.9
- ------------------------------------------------------------------------------
Long-term Debt-Net of Current Maturities &
Debt Subject to Tender 1,072.8 954.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes 235.4 195.5
Regulatory liabilities & other removal costs 235.0 210.0
Deferred credits & other liabilities 153.6 130.8
- ------------------------------------------------------------------------------
Total deferred credits & other liabilities 624.0 536.3
- ------------------------------------------------------------------------------
Minority Interest in Subsidiary 0.3 1.9
Commitments & Contingencies (Notes 3, 12-14)
Cumulative, Redeemable Preferred Stock
of a Subsidiary 0.2 0.3
Common Shareholders' Equity
Common stock (no par value) - issued &
outstanding 75.6 and 67.9, respectively 520.4 350.0
Retained earnings 562.4 530.4
Accumulated other comprehensive loss (11.1) (10.5)
- ------------------------------------------------------------------------------
Total common shareholders' equity 1,071.7 869.9
- ------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $3,353.4 $3,136.5
==============================================================================
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,
- -------------------------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $ 1,112.3 $ 908.0 $ 1,019.6
Electric utility 335.7 328.6 308.5
Energy services & other 139.7 287.2 681.0
- -------------------------------------------------------------------------------------
Total operating revenues 1,587.7 1,523.8 2,009.1
- -------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 762.5 570.2 708.9
Fuel for electric generation 86.5 81.6 74.4
Purchased electric energy 16.2 16.8 14.2
Cost of energy services & other 103.7 249.4 640.9
Other operating 233.7 223.0 243.2
Merger & integration costs - - 2.8
Restructuring costs - - 19.0
Depreciation & amortization 128.7 119.6 124.1
Taxes other than income taxes 57.0 51.9 53.7
- -------------------------------------------------------------------------------------
Total operating expenses 1,388.3 1,312.5 1,881.2
- -------------------------------------------------------------------------------------
OPERATING INCOME 199.4 211.3 127.9
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 12.2 9.1 13.4
Other - net 13.0 11.5 16.7
- -------------------------------------------------------------------------------------
Total other income 25.2 20.6 30.1
- -------------------------------------------------------------------------------------
Interest expense 75.6 78.5 83.2
- -------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 149.0 153.4 74.8
- -------------------------------------------------------------------------------------
Income taxes 37.7 38.9 14.1
Minority interest in & preferred dividend
requirements of subsidiaries 0.1 0.5 1.4
- -------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 111.2 114.0 59.3
- -------------------------------------------------------------------------------------
Extraordinary loss - net of tax - - (7.7)
Cumulative effect of change in accounting
principle - net of tax - - 1.1
- -------------------------------------------------------------------------------------
NET INCOME $ 111.2 $ 114.0 $ 52.7
=====================================================================================
AVERAGE COMMON SHARES OUTSTANDING 70.6 67.6 66.7
DILUTED COMMON SHARES OUTSTANDING 70.8 67.9 66.9
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.58 $ 1.69 $ 0.89
Extraordinary loss - net of tax - - (0.12)
Cumulative effect of change in accounting
principle - net of tax - - 0.02
- ---------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.58 $ 1.69 $ 0.79
=============================================================================================
DILUTED
INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.57 $ 1.68 $ 0.89
Extraordinary loss - net of tax - - (0.12)
Cumulative effect of change in accounting
principle - net of tax - - 0.02
- ---------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.57 $ 1.68 $ 0.79
=============================================================================================
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,
- -----------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 111.2 $ 114.0 $ 52.7
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 128.7 119.6 124.1
Deferred income taxes & investment tax credits 35.1 (28.5) 12.4
Equity in earnings of unconsolidated affiliates (12.2) (9.1) (13.4)
Net unrealized (gain) loss on derivative
instruments, including cumulative effect
of change in accounting principle (0.7) 3.6 (3.3)
Extraordinary loss on sale of leveraged
leases - net of tax - - 7.7
Pension & postretirement periodic benefit cost 13.8 13.2 8.5
Other non-cash charges- net (0.1) 7.5 13.1
Changes in working capital accounts:
Accounts receivable & accrued unbilled
revenue (16.1) (42.0) 135.5
Inventories (7.6) 0.4 24.2
Recoverable fuel & natural gas costs (1.0) 48.1 25.9
Prepayments & other current assets (42.5) 31.2 (70.3)
Accounts payable, including to affiliated
companies (16.4) 40.7 (120.6)
Accrued liabilities (8.4) 11.7 (7.0)
Changes in noncurrent assets (3.9) (6.0) 4.6
Changes in noncurrent liabilities (2.8) (12.1) (6.0)
- -----------------------------------------------------------------------------------------
Net cash flows from operating activities 177.1 292.3 188.1
- -----------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs 202.9 - 344.0
Common stock - net of issuance costs 163.2 - 129.4
Stock option exercises & other stock plans 7.1 1.3 -
Requirements for:
Dividends on common stock (79.2) (72.3) (69.5)
Retirement of long-term debt (121.9) (6.5) (7.6)
Redemption of preferred stock of subsidiary (0.1) (0.2) (17.7)
Retirement of short-term notes payable - - (150.0)
Dividends on preferred stock of subsidiary - - (0.8)
Net change in short-term borrowings (124.6) 20.3 (228.2)
Other activity (1.6) (0.2) (2.3)
- -----------------------------------------------------------------------------------------
Net cash flows from financing activities 45.8 (57.6) (2.7)
- -----------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Unconsolidated affiliate distributions 14.1 7.4 22.5
Sale of leveraged lease investments - - 53.8
Notes receivable & other collections 14.4 3.9 16.6
Requirements for:
Capital expenditures, excluding AFUDC-equity (236.2) (218.7) (239.7)
Unconsolidated affiliate investments (16.6) (12.5) (22.7)
Notes receivable & other investments (8.4) (14.7) (6.1)
- -----------------------------------------------------------------------------------------
Net cash flows from investing activities (232.7) (234.6) (175.6)
- -----------------------------------------------------------------------------------------
Net (decrease) increase in cash & cash equivalents (9.8) 0.1 9.8
Cash & cash equivalents at beginning of period 25.1 25.0 15.2
- -----------------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 15.3 $ 25.1 $ 25.0
=========================================================================================
Cash paid during the year for:
Interest $ 70.9 $ 67.1 $ 74.9
Income taxes 33.9 16.5 38.0
The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)
Common Stock
------------------------
Accumulated
Restricted Other
Stock Retained Comprehensive
Shares Amount Grants Earnings Income (Loss) Total
- ------------------------------------------------------------------------------------------------------
Balance at January 1, 2001 61.4 $ 219.3 $ (1.5) $ 508.1 $ 7.5 $ 733.4
- ------------------------------------------------------------------------------------------------------
Comprehensive income:
Net income 52.7 52.7
Minimum pension liability adjustments &
other - net of tax (1.8) (1.8)
Comprehensive loss of unconsolidated
affiliates - net of tax (1.6) (1.6)
- ------------------------------------------------------------------------------------------------------
Total comprehensive income 49.3
- ------------------------------------------------------------------------------------------------------
Common stock:
Public issuance - net of $5.1 million of
issuance costs 6.3 129.4 129.4
Stock option exercises & other stock plans - (0.1) (1.0) (2.2) (3.3)
Dividends ($1.03 per share) (69.5) (69.5)
- ------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 67.7 348.6 (2.5) 489.1 4.1 839.3
- ------------------------------------------------------------------------------------------------------
Comprehensive income:
Net income 114.0 114.0
Minimum pension liability adjustments &
other - net of tax (9.3) (9.3)
Comprehensive loss of unconsolidated
affiliates - net of tax (5.3) (5.3)
- ------------------------------------------------------------------------------------------------------
Total comprehensive income 99.4
- ------------------------------------------------------------------------------------------------------
Common stock:
Stock option exercises & other stock plans 0.1 1.3 1.3
Dividends ($1.07 per share) (72.3) (72.3)
Other 0.1 2.4 0.2 (0.4) 2.2
- ------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 67.9 352.3 (2.3) 530.4 (10.5) 869.9
- ------------------------------------------------------------------------------------------------------
Comprehensive income:
Net income 111.2 111.2
Minimum pension liability adjustments &
other - net of tax (6.3) (6.3)
Comprehensive income of unconsolidated
affiliates - net of tax 5.7 5.7
- ------------------------------------------------------------------------------------------------------
Total comprehensive income 110.6
- ------------------------------------------------------------------------------------------------------
Common stock:
Public issuance - net of $6.2 million of
issuance costs 7.4 163.2 163.2
Stock option exercises & other stock plans 0.3 7.1 7.1
Dividends ($1.11 per share) (79.2) (79.2)
Other - 0.3 (0.2) 0.1
- ------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 75.6 $ 522.9 $ (2.5) $ 562.4 $(11.1) $1,071.7
======================================================================================================
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 that has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. VUHI also has other assets that provide information technology and
other services to the three utilities. Both Vectren and VUHI are exempt from
registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding
Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary, (53% ownership) and Indiana Gas (47% ownership), provide
natural gas distribution and transportation services to 17 counties in west
central Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal and generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has other businesses that provide utility
services, municipal broadband consulting, and retail products and services, and
that invest in energy-related opportunities, real estate and leveraged leases.
The nonregulated group supports the Company's regulated utilities pursuant to
service contracts by providing natural gas supply services, coal, utility
infrastructure services, and other services.
2. Summary of Significant Accounting Policies
A. Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its wholly owned and majority owned subsidiaries, after elimination of
significant intercompany transactions.
B. Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents.
C. Inventories
Inventories consist of the following:
At December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002
- -----------------------------------------------------------------------------
Gas in storage - at LIFO cost $ 21.9 $ 25.4
Materials & supplies 22.6 19.7
Fuel (coal & oil) for electric generation 14.0 11.3
Gas in storage - at average cost 7.2 3.2
Other 4.7 3.2
- -----------------------------------------------------------------------------
Total inventories $ 70.4 $ 62.8
=============================================================================
Based on the average cost of gas purchased during December, the cost of
replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31,
2003, and 2002, by approximately $52.2 million and $32.7 million, respectively.
Gas in storage of the Indiana regulated operations is stated at LIFO. All other
inventories are carried at average cost.
D. Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation of
utility property is provided using the straight-line method over the estimated
service lives of the depreciable assets. The original cost of utility plant,
together with depreciation rates expressed as a percentage of original cost,
follows:
At and For the Year Ended December 31,
- -------------------------------------------------------------------------------------------
(In millions) 2003 2002
- -------------------------------------------------------------------------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of Percent of
Original Cost Original Cost Original Cost Original Cost
- -------------------------------------------------------------------------------------------
Gas utility plant $ 1,721.9 3.6% $ 1,622.0 3.8%
Electric utility plant 1,322.4 3.4% 1,216.1 3.3%
Common utility plant 44.3 2.7% 41.6 2.6%
Construction work in progress 162.1 - 162.5 -
- -------------------------------------------------------------------------------------------
Total original cost $ 3,250.7 $ 3,042.2
===========================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction
purposes and is charged to construction work in progress during the construction
period and is included in Other - net in the Consolidated Statements of Income.
The total AFUDC capitalized into utility plant and the portion of which was
computed on borrowed and equity funds for all periods reported follows:
Year Ended December 31,
- ----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- ----------------------------------------------------------------------------
AFUDC - borrowed funds $ 2.1 $ 3.1 $ 2.1
AFUDC - equity funds 2.9 2.2 2.5
- ----------------------------------------------------------------------------
Total AFUDC capitalized $ 5.0 $ 5.3 $ 4.6
============================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred unless deferral is authorized by a rate order. When property that
represents a retirement unit is replaced or removed, the cost of such property
is charged to Utility plant, with an offsetting charge to Accumulated
depreciation and Regulatory liabilities for the cost of removal.
E. Non-utility Property
Non-utility property, net of accumulated depreciation and amortization, by
operating segment follows:
At December 31,
- ---------------------------------------------------------------------------
(In millions) 2003 2002
- ---------------------------------------------------------------------------
Utility Group
Other Operations $ 135.7 $ 133.8
Gas & Electric Utility Services 5.6 5.4
Nonregulated Group 79.9 78.8
Corporate & Other Group 1.1 10.0
- ---------------------------------------------------------------------------
Non-utility property - net $ 222.3 $ 228.0
===========================================================================
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 $84.5 million and $104.7 million as of
December 31, 2003, and 2002, respectively. For the years ended December 31,
2003, 2002, and 2001, the Company capitalized interest totaling $0.5 million,
$0.4 million, and $1.7 million, respectively, on non-utility plant construction
projects.
F. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the
carrying amount may be impaired. This review is performed in accordance with
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144), which the Company adopted on January 1, 2002. SFAS 144 establishes
one accounting model for all impaired long-lived assets and long-lived assets to
be disposed of by sale or otherwise. SFAS 144 requires the evaluation for
impairment involve the comparison of an asset's carrying value to the estimated
future cash flows the asset is expected to generate over its remaining life. If
this evaluation were to conclude that the carrying value of the asset is
impaired, an impairment charge would be recorded based on the difference between
the asset's carrying amount and its fair value (less costs to sell for assets to
be disposed of by sale) as a charge to operations or discontinued operations.
G. Goodwill
Goodwill arising from business combinations is accounted for in accordance with
SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company
adopted SFAS 142 on January 1, 2002. SFAS 142 changed the accounting for
goodwill from an amortization approach to an impairment-only approach. Thus,
amortization of goodwill that was not included as an allowable cost for
rate-making purposes ceased upon SFAS 142's adoption.
Goodwill is to be tested for impairment at a reporting unit level at least
annually. The impairment review consists of a comparison of the fair value of a
reporting unit to its carrying amount. If the fair value of a reporting unit is
less than its carrying amount, an impairment loss is recognized in operations.
Prior to the adoption of SFAS 142, the Company amortized goodwill on a
straight-line basis over 40 years. SFAS 142 required an initial impairment
review of all goodwill within six months of the adoption date.
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations ceased on January 1, 2002. In 2001, Net income before
extraordinary loss and cumulative effect of change in accounting principle and
Net income would have been $62.3 million and $55.7 million, respectively, had
goodwill not been amortized. The Company's goodwill is included in the Gas
Utility Services operating segment. Initial impairment reviews to be performed
within six months of adoption of SFAS 142 were completed and resulted in no
impairment, and no impairment charges have been recorded since adoption. The
impairment test is performed at the beginning of each year.
Following is a reconciliation of reported net income and earnings per share to
the adjusted net income disclosed above and related earnings per share for year
ended December 31, 2001:
Year Ended December 31, 2001
- --------------------------------------------------------------------------------
(In millions, except per share amounts) Net Income Basic EPS Diluted EPS
- --------------------------------------- ---------- --------- -----------
As Reported $ 52.7 $ 0.79 $ 0.79
Add: goodwill amortization - net of tax 3.0 0.05 0.05
- --------------------------------------------------------------------------------
As adjusted $ 55.7 $ 0.84 $ 0.84
================================================================================
H. Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the IURC, and retail public utility operations affecting Ohio
customers are subject to regulation by the PUCO.
SFAS 71
The Company's accounting policies give recognition to the rate-making and
accounting practices of these agencies and to accounting principles generally
accepted in the United States, including the provisions of SFAS No. 71
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Regulatory assets represent probable future revenues associated with certain
incurred costs, which will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable expenditures by the Company
for removal costs or future reductions in revenues associated with amounts that
are to be credited to customers through the rate-making process.
The Company assesses the recoverability of costs recognized as regulatory assets
and the ability to continue to account for its activities based on the criteria
set forth in SFAS 71. Based on current regulation, the Company believes such
accounting is appropriate. If all or part of the Company's operations cease to
meet the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets.
Regulatory assets consist of the following:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Future amounts recoverable from ratepayers:
Income taxes $ 18.1 $ 15.8
Other 1.0 -
- ------------------------------------------------------------------------------
19.1 15.8
Amounts deferred for future recovery:
Demand side management programs 25.0 23.8
Other 5.3 3.7
- ------------------------------------------------------------------------------
30.3 27.5
Amounts currently recovered through base rates:
Unamortized debt issue costs 21.4 19.5
Premiums paid to reacquire debt 7.4 4.1
Demand side management programs 2.7 3.2
- ------------------------------------------------------------------------------
31.5 26.8
Amounts currently recovered through tracking mechanisms:
Ohio authorized trackers 7.5 5.7
Indiana authorized trackers 1.2 -
- ------------------------------------------------------------------------------
8.7 5.7
- ------------------------------------------------------------------------------
Totl regulatory assets $ 89.6 $ 75.8
==============================================================================
The $31.5 million currently being recovered through base rates is earning a
return with a weighted average recovery period of 18.2 years. The Company has
rate orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.
Regulatory liabilities & other removal costs consist of the following:
At December 31,
- ------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------
Cost of removal $ 228.8 $ -
Interest rate hedging proceeds (See Note 15) 6.2 -
- ------------------------------------------------------------------------
Total regulatory liabilities 235.0 -
- ------------------------------------------------------------------------
Other removal costs - 210.0
- ------------------------------------------------------------------------
Total regulatory liabilities &
other removal costs $235.0 $ 210.0
========================================================================
SFAS 143 & Other Removal Costs
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations.
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $229 million and $210 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.
Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased
Power
All metered gas rates contain a gas cost adjustment clause that allows the
Company to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel and the net energy cost
of purchased power. Metered electric rates also allow recovery, through a
quarterly rate adjustment mechanism, for the margin on electric sales lost due
to the implementation of demand side management programs.
The Company records any under-or-over-recovery resulting from gas and fuel
adjustment clauses each month in revenues. A corresponding asset or liability is
recorded until the under-or-over-recovery is billed or refunded to utility
customers. The cost of gas sold is charged to operating expense as delivered to
customers, and the cost of fuel for electric generation is charged to operating
expense when consumed.
I. Comprehensive Income
Comprehensive income is a measure of all changes in equity that result from the
transactions or other economic events during the period from non-shareholder
transactions. This information is reported in the Consolidated Statements of
Common Shareholders' Equity.
A summary of the components of and changes in Accumulated other comprehensive
income for the past three years follows:
2001 2002 2003
--------------------------- --------------- ---------------
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 $ (1.6) $ 5.9 $ (5.3) $ 0.6 $ 5.7 $ 6.3
Minimum pension liability - (2.4) (2.4) (9.2) (11.6) (5.8) (17.4)
Other - 0.6 0.6 (0.1) 0.5 (0.5) -
- -----------------------------------------------------------------------------------------
Accumulated other
comprehensive income $ 7.5 $ (3.4) $ 4.1 $(14.6) $(10.5) $(0.6) $(11.1)
=========================================================================================
Accumulated other comprehensive income arising from unconsolidated affiliates is
the Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's
accumulated comprehensive income related to its adoption of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) and
continued use of cash flow hedges, including commodity contracts and interest
rate swaps, and the Company's portion of Haddington Energy Partners, LP's
accumulated comprehensive income related to unrealized gains and losses of
"available for sale securities." (See Note 3 for more information on
unconsolidated affiliates.)
J. Revenues
Revenues are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
K. Excise and Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates
charged to customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $37.1 million in 2003, $32.4
million in 2002, and $26.6 million in 2001. Excise and utility receipts taxes
paid are recorded as a component of Taxes other than income taxes.
L. Other Significant Policies
Included elsewhere in these Notes are significant accounting policies related to
investments in unconsolidated affiliates (Note 3), income taxes (Note 5),
earnings per share (Note 10), and derivatives (Note 15).
As more fully described in Note 11, the Company applies the intrinsic method
prescribed in APB Opinion 25, "Accounting for Stock Issued to Employees" (APB
25) and related interpretations when measuring compensation expense for its
equity-based compensation plans. The exercise price of stock options awarded
under the Company's stock option plans is equal to the fair market value of the
underlying common stock on the date of grant. Accordingly, no compensation
expense has been recognized for stock option plans. The Company also maintains
restricted stock and phantom stock plans for executives and non-employee
directors that result in equity-based compensation expense recognized in
reported net income consistent with expense that would have been recognized if
the Company used the fair value based method prescribed in SFAS No. 123
"Accounting for Stock-Based Compensation" (SFAS 123).
Following is the effect on net income and earnings per share as if the fair
value based method prescribed in SFAS 123 had been applied to the Company's
equity-based compensation plans:
Year Ended December 31,
- ------------------------------------------------------------------------------
(In millions, except per share amounts) 2003 2002 2001
- ------------------------------------------------------------------------------
Net Income:
As reported $ 111.2 $ 114.0 $ 52.7
Add: Equity-based employee compensation included
in reported net income- net of tax 2.1 1.3 1.7
DeducTotal equity-based employee compensation
expense determined under fair value based
method for all awards- net of tax 3.4 2.1 2.8
- ------------------------------------------------------------------------------
Pro forma $ 109.9 $ 113.2 $ 51.6
==============================================================================
Basic Earnings Per Share:
As reported $ 1.58 $ 1.69 $ 0.79
Pro forma 1.56 1.68 0.77
Diluted Earnings Per Share:
As reported $ 1.57 $ 1.68 $ 0.79
Pro forma 1.55 1.67 0.77
M. Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
N. Reclassification
Certain prior year amounts have been reclassified in the consolidated financial
statements and accompanying notes to conform to 2003 classifications.
3. Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates where the Company has significant
influence are accounted for using the equity method of accounting. The Company's
share of net income or loss from these investments is recorded in Equity in
earnings of unconsolidated affiliates. Dividends are recorded as a reduction of
the carrying value of the investment when received. Investments in
unconsolidated affiliates where the Company does not have significant influence
are accounted for using the cost method of accounting less write-downs for
declines in value judged to be other than temporary. Dividends are recorded as
Other - net when received.
Investments in unconsolidated affiliates consist of the following:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
ProLiance Energy, LLC $ 84.7 $ 61.4
Haddington Energy Partnerships 26.3 19.7
Reliant Services, LLC 19.2 18.4
Utilicom Networks, LLC & related entities 15.4 15.4
Pace Carbon synfuels, LP 8.7 6.8
Other partnerships & corporations 21.8 31.6
- ------------------------------------------------------------------------------
Total investments in unconsolidated affiliates $ 176.1 $ 153.3
==============================================================================
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to Indiana Gas, the Ohio operations, Citizens Gas and
others. ProLiance also began providing service to SIGECO and Vectren Retail, LLC
(the Company's retail gas marketer) in 2002. ProLiance's primary business is
optimizing the gas portfolios of utilities and providing services to large end
use customers.
Pre-tax income of $25.9 million, $19.1 million, and $12.8 million was recognized
as ProLiance's contribution to earnings for the years ended December 31, 2003,
2002, and 2001, respectively.
Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001, Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member; and
therefore, Vectren continues to account for its investment in ProLiance using
the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. The transfer of net assets was
accounted for at book value consistent with joint venture accounting and did not
result in any gain or loss. Additionally, the non-cash component of the transfer
totaling $17.2 million is excluded from the Consolidated Statement of Cash
Flows.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2003, 2002, and 2001, totaled $797.7 million, $544.1
million, and $610.6 million, respectively. Amounts owed to ProLiance at December
31, 2003, and 2002, for those purchases were $86.0 million and $84.6 million,
respectively, and are included in Accounts payable to affiliated companies in
the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
Summarized Financial Information
For the year ended December 31, 2003, ProLiance's revenues, margin, operating
income, and net income were (in millions) $2,269.7, $71.5, $43.3, and $42.5,
respectively. For the year ended December 31, 2002, revenues, margin, operating
income, and net income were (in millions) $1,534.5, $61.1, $36.5, and $37.4,
respectively. For the year ended December 31, 2001, revenues, margin, operating
income, and net income were (in millions) $1,599.5, $40.9, $26.1, and $27.7,
respectively. As of December 31, 2003, current assets, noncurrent assets,
current liabilities, and noncurrent liabilities were (in millions) $467.7,
$22.2, $346.0, and $7.8, respectively. As of December 31, 2002, current assets,
noncurrent assets, current liabilities, and noncurrent liabilities were (in
millions) $301.6, $22.8, $228.8, and $1.2, respectively.
ProLiance Contingency
There is currently a lawsuit pending in the United States District Court for the
Northern District of Alabama filed by the City of Huntsville, Alabama d/b/a
Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville
Utilities asserts claims based on negligent provision of portfolio services
and/or pricing advice, fraud, fraudulent inducement, and other theories. These
claims relate generally to several basic arguments: (1) negligence in providing
advice and/or administering portfolio arrangements; (2) alleged promises to
provide gas at a below-market rate; (3) the creation and repayment of a "winter
levelizing program" instituted by ProLiance in conjunction with the Manager of
Huntsville's Gas Utility, to allow Huntsville Utilities to pay its gas bills
over an extended period of time coupled with the alleged ignorance about the
program on the part of Huntsville Utilities' Gas Board, and; (4) the sale of
Huntsville Utilities' gas storage supplies to repay the balance owed on the
winter levelizing program and the authority of Huntsville Utilities' gas manager
to approve those sales. In a press conference on May 21, 2002, Huntsville
Utilities asserted its monetary damages to be approximately $10 million, and
seeks to treble that amount. ProLiance has made counterclaims asserting breach
of contract, among others, based on Huntsville Utilities' refusal to take gas
under fixed price agreements. Both parties have denied the charges contained in
the respective claims.
In 2003, ProLiance established reserves for amounts due from Huntsville
Utilities due to uncertainties surrounding collection. ProLiance denies any
wrongdoing, believes its actions were proper under the contract and amendments
signed by the manager of Huntsville's Gas Utility, and is vigorously defending
against the suit. ProLiance is an insured under a policy of insurance providing
defense costs which may provide in whole or in part, indemnification within the
policy limits for claims asserted against ProLiance. Accordingly, no other loss
contingencies have been recorded at this time. However, it is not possible to
predict or determine the outcome of this litigation and accordingly there can be
no assurance that ProLiance will prevail. It is not currently expected that
costs associated with this matter will have a material adverse effect on
Vectren's consolidated financial position or liquidity but an unfavorable
outcome could possibly be material to Vectren's earnings.
Haddington Energy Partnerships
The Company has an approximate 40% ownership interest in Haddington Energy
Partners, LP (Haddington I). Haddington I raised $27.0 million to invest in
energy projects. In July 2000, the Company made a commitment to fund an
additional $20.0 million in Haddington Energy Partners II, LP (Haddington II),
which raised a total of $47.0 million in firm commitments. Haddington II
provides additional capital for Haddington I portfolio companies and made
investments in new areas, such as distributed generation, power backup and
quality devices, and emerging technologies such as microturbines and
photovoltaics. At December 31, 2003, $7.7 million of the additional $20.0
million commitment remains. The Company has an approximate 40% ownership
interest in Haddington II. Both Haddington ventures are investment companies
accounted for using the equity method of accounting. For the year ended December
31, 2001, the partnerships' contribution to the Company's pre-tax earnings was
$6.2 million. In 2002 and 2003, 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, 2003, revenues, operating income, and net income were (in millions)
$0.6, ($0.3), and ($0.3), respectively. For the year ended December 31, 2002,
revenues, operating income, and net income were (in millions) zero, ($0.9), and
($0.9), respectively. For the year ended December 31, 2001, revenues, operating
income, and net income were (in millions) $23.6, $22.5, and $22.5, respectively.
As of December 31, 2003, investments, other assets, and liabilities were (in
millions) $64.4, $1.0, and zero, respectively. As of December 31, 2002,
investments, other assets, and liabilities were (in millions) $49.6, $0.3, and
zero, respectively.
Utilicom Networks, LLC & Related Entities
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has an approximate 2% equity and a convertible
subordinated debt investment in Utilicom. The Company also has an approximate
19% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by
Utilicom to hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for
its investments in Utilicom and Holdings using the cost method of accounting.
SIGECOM provides broadband services to the greater Evansville, Indiana area.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana and Dayton, Ohio markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
are still interested in the Indianapolis and Dayton markets, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
At December 31, 2003, the Company has $32.3 million of notes receivable from
Utilicom-related entities which are convertible into equity interests. Notes
receivable totaling $30.1 million are convertible into Utilicom ownership at the
Company's option or upon the event of a public offering of stock by Utilicom,
and $2.2 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 an approximate 16% interest in Utilicom, assuming
completion of all required funding and up to a 31% interest in the Indianapolis
and Dayton ventures. Investments in convertible notes receivable are included in
Other investments.
At December 31, 2003, and 2002, the Company's combined investment in equity and
debt securities of Utilicom-related entities totaled $47.7 million and $46.1
million, respectively. These investments had no significant impact on the
Company's financial results in 2003, 2002, or 2001.
Pace Carbon Synfuels, LP
Pace Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed
to develop, own, and operate four projects to produce and sell coal-based
synthetic fuel (synfuel) utilizing Covol technology. The Company has an 8.3%
interest in Pace Carbon which is accounted for using the equity method of
accounting. Additional investments in Pace Carbon will be made to the extent
Pace Carbon generates federal tax credits, with any such additional investments
to be funded by these credits. The investment in Pace Carbon resulted in losses
reflected in Equity in earnings of unconsolidated affiliates totaling $11.4
million, $6.8 million, and $4.5 million in 2003, 2002, and 2001, respectively.
The production of synthetic fuel generates IRS Code Section 29 investment tax
credits that are reflected in Income taxes. Net income, including the losses,
tax benefits, and tax credits, generated from the investment in Pace Carbon
totaled $10.3 million in 2003, $6.0 million in 2002, and $4.3 million in 2001.
The following is summarized financial information as to the assets, liabilities,
and results of operations of Pace Carbon. For the year ended December 31, 2003,
revenues, margin, operating loss, and net loss were (in millions) $254.2,
($90.7), ($121.3), and ($134.4), respectively. For the year ended December 31,
2002, revenues, margin, operating loss, and net loss were (in millions)
$125.6, ($53.1), ($72.6), and ($73.4), respectively. For the year ended December
31, 2001, revenues, margin, operating loss, and net loss were (in millions)
$86.2, ($25.1), ($44.1), and ($44.8), respectively. As of December 31, 2003,
current assets, noncurrent assets, current liabilities, and noncurrent
liabilities were (in millions) $37.0, $105.2, $25.9, and $58.4, respectively. As
of December 31, 2002, current assets, noncurrent assets, current liabilities,
and noncurrent liabilities were (in millions) $32.7, $44.8, $45.9 and $4.3,
respectively.
IRS Section 29 Investment Tax Credit Recent Developments
Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon
receive a tax credit for every ton of synthetic fuel sold. To qualify for the
credits, the synthetic fuel must meet three primary conditions: 1) there must be
a significant chemical change in the coal feedstock, 2) the product must be sold
to an unrelated person, and 3) the production facility must have been placed in
service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the
synthetic fuel produced at the Pace Carbon facilities should qualify for Section
29 tax credits. The IRS issued a private letter ruling with respect to the four
projects on November 11, 1997, and subsequently issued an updated private letter
ruling on September 23, 2002.
As a partner in Pace Carbon, Vectren has reflected total tax credits under
Section 29 in its consolidated results through December 31, 2003, of
approximately $39 million. Vectren has been in a position to fully utilize the
credits generated and continues to project full utilization.
In June 2003, the IRS, in an industry-wide announcement, stated that it would
review the scientific validity of test procedures and results presented as
evidence of significant chemical change. During this review, the IRS suspended
the issuance of new private letter rulings on that subject. In October 2003, the
IRS completed its review and determined that the test procedures and results
used by taxpayers are scientifically valid if the procedures are applied in a
consistent and unbiased manner. Also, the IRS will issue new private letter
rulings based on revised standards; however, it has continuing concerns
regarding the sampling and data/record retention practices prevalent in the
synthetic fuels industry.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year
and later expanded the audit to include tax years 1999, 2000, and 2001. Based on
conclusions reached in the industry-wide review and recently issued private
letter rulings involving other synthetic fuel facilities, Vectren believes
chemical change issues from these audits may soon be resolved. However, the IRS
has not directly notified Pace Carbon of any resolution.
Vectren believes it is justified in its reliance on the private letter rulings
for the Pace Carbon facilities, that the test results that Pace Carbon presented
to the IRS in connection with its private letter rulings are scientifically
valid, and that Pace Carbon has operated its facilities in compliance with its
private letter rulings and Section 29 of the Internal Revenue Code. However, at
this time, Vectren cannot provide any assurance as to the outcome of these
audits concerning the issue of chemical change or any other issue raised during
the audits relative to its investment in Pace Carbon. Further, it is expected
that Section 29 investments will continue to draw attention from various
interest groups.
Other Affiliate Transactions
The Company has ownership interests in other affiliated companies accounted for
using the equity method of accounting that perform underground construction and
repair, facilities locating, and meter reading services to the Company. For the
years ended December 31, 2003, 2002, and 2001, fees for these services and
construction-related expenditures paid by the Company to its affiliates totaled
$37.2 million, $38.3 million, and $37.9 million, respectively. Amounts charged
by these affiliates are market based. Amounts owed to unconsolidated affiliates
other than ProLiance totaled $0.4 million and $1.8 million at December 31, 2003,
and 2002, 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 $0.4 million and $0.6
million, respectively, at December 31, 2003, and 2002.
4. Other Investments
Other investments consist of the following:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Notes receivable:
Utilicom Networks, LLC & related entities $ 32.3 $ 30.7
Other notes receivable 32.4 41.8
- ------------------------------------------------------------------------------
Total notes receivable 64.7 72.5
- ------------------------------------------------------------------------------
Leveraged leases 32.2 30.5
Other investments 26.0 21.3
- ------------------------------------------------------------------------------
Total other investments $ 122.9 $ 124.3
==============================================================================
Notes Receivable
Interest on the notes receivable accrue at various rates up to 10%, and are due
at various times through 2024. Generally, first or second mortgages and/or
capital stock or partnership units serve as collateral for the notes. (See Note
3 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 total equipment and
facilities cost was approximately $76.2 million at both December 31, 2003, and
2002. The cost of the equipment and facilities was partially financed by
non-recourse debt provided by lenders who have been granted an assignment of
rentals due under the leases and a security interest in the leased property,
which they accepted as their sole remedy in the event of default by the lessee.
Such debt amounted to approximately $51.8 million and $51.7 million at December
31, 2003, and 2002, respectively.
The Company's net investment in leveraged leases follows:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Minimum lease payments receivable $ 49.3 $ 48.6
Estimated residual value 22.0 22.0
Less: Unearned income 39.1 40.1
- ------------------------------------------------------------------------------
Leveraged lease investments 32.2 30.5
Less: Deferred taxes arising from leveraged leases 26.2 26.3
- ------------------------------------------------------------------------------
Net investment in leveraged leases $ 6.0 $ 4.2
==============================================================================
In June 2001, the Company sold certain leveraged lease investments with a net
book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax).
Because of the transaction's significance and because the transaction occurred
within two years of the effective date of the merger of Indiana Energy and
SIGCORP, which was accounted for as a pooling-of-interests, APB 16 requires the
loss on disposition of these investments to be treated as extraordinary.
Proceeds from the sale totaled $46.7 million.
5. Income Taxes
The components of income tax expense and utilization of investment tax credits
follow:
Year Ended December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- ------------------------------------------------------------------------------
Current:
Federal $ (11.9) $ 62.2 $ (2.2)
State 14.5 5.2 3.9
- ------------------------------------------------------------------------------
Total current taxes 2.6 67.4 1.7
- ------------------------------------------------------------------------------
Deferred:
Federal 39.1 (26.2) 14.9
State (1.8) - (0.2)
- ------------------------------------------------------------------------------
Total deferred taxes 37.3 (26.2) 14.7
- ------------------------------------------------------------------------------
Amortization of investment tax credits (2.2) (2.3) (2.3)
- ------------------------------------------------------------------------------
Total income tax expense $ 37.7 $ 38.9 $ 14.1
==============================================================================
A reconciliation of the federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- -------------------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 % 35.0 %
State and local taxes-net of federal benefit 5.5 2.4 3.0
Section 29 tax credits (11.7) (7.0) (9.5)
Amortization of investment tax credit (1.5) (1.5) (3.1)
Other tax credits (0.9) (1.1) (3.6)
All other-net (1.1) (2.4) (2.6)
- -------------------------------------------------------------------------------
Effective tax rate 25.3 % 25.4 % 19.2 %
===============================================================================
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Significant components of the net deferred tax liability
follow:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences $ 225.4 $ 197.9
Leveraged leases 26.2 26.3
Regulatory assets recoverable through future rates 26.9 37.5
Regulatory liabilities to be settled through
future rates (8.8) (21.7)
Employee benefit obligations (29.8) (45.9)
Other - net (4.5) 1.4
- ------------------------------------------------------------------------------
Net noncurrent deferred tax liability 235.4 195.5
- ------------------------------------------------------------------------------
Current deferred tax liabilities (assets):
Deferred fuel costs-net 6.9 7.7
- ------------------------------------------------------------------------------
Net current deferred tax liability 6.9 7.7
- ------------------------------------------------------------------------------
Net deferred tax liability $ 242.3 $ 203.2
==============================================================================
At December 31, 2003, and 2002, investment tax credits totaling $16.4 million
and $18.6 million, respectively, are included in Deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments.
The Company had no tax credit carryforwards at December 31, 2003, or 2002.
Alternative Minimum Tax credit carryforwards of approximately $5.2 million were
utilized in 2001. Through certain of its nonregulated subsidiaries and
investments, the Company also realizes federal income tax credits associated
with affordable housing projects and the production of synthetic fuels. During
2001, tax credit carryforwards from these operations totaling $5.5 million were
utilized.
6. Retirement Plans & Other Postretirement Benefits
At December 31, 2003, the Company maintains three qualified defined benefit
pension plans, a nonqualified supplemental executive retirement plan (SERP), and
three other postretirement benefit plans. 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 Company has
Voluntary Employee Beneficiary Association (VEBA) Trust Agreements for the
partial funding of postretirement health benefits for retirees and their
eligible dependents and beneficiaries. Annual funding of the VEBA's 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 detailed disclosures
of benefit components that follow are based on an actuarial valuation using a
measurement date as of September 30. The qualified pension plans and the SERP
are aggregated under the heading "Pension Benefits." Other postretirement
benefit plans are aggregated under the heading "Other Benefits."
FSP 106-1
The recently enacted Medicare Prescription Drug, Improvement and Modernization
Act of 2003 (the Medicare Act) provides a prescription drug benefit as well as a
federal subsidy to sponsors of certain retiree health care benefit plans. As
allowed by FASB Staff Position No. 106-1 (FSP 106-1), the Company has elected to
defer reflecting the effects of the Medicare Act on the accumulated benefit
obligation and net periodic postretirement benefit cost in these financial
statements and accompanying notes. The Company's deferral election expires upon
the occurrence of any event that triggers a required remeasurement of plan
assets or obligations, or upon the issuance of specific authoritative guidance
on the accounting for the federal subsidy. Such guidance is pending and when
issued could require the Company to adjust previously reported information.
Benefit Obligations
A reconciliation of the Company's benefit obligations at December 31, 2003, and
2002, follows:
- ----------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------ ------------------
(In millions) 2003 2002 2003 2002
- ----------------------------- ------------------ ------------------
Benefit obligation,
beginning of period $ 201.9 $ 191.3 $ 81.5 $ 83.6
Service cost - benefits
earned during the period 5.8 5.9 0.9 1.0
Interest cost on projected
benefit obligation 13.6 13.9 5.4 6.0
Plan amendments - (0.1) - -
Benefits paid (12.7) (12.1) (5.4) (8.7)
Actuarial loss (gain) 14.1 3.0 14.9 (0.4)
- ----------------------------------------------------------------------------
Benefit obligation,
end of period $ 222.7 $ 201.9 $ 97.3 81.5
============================================================================
The accumulated benefit obligation for all defined benefit pension plans was
$202.7 million and $179.1 million at December 31, 2003, and 2002, respectively.
The benefit obligation as of December 31, 2003, and 2002, was calculated using
the following weighted average assumptions:
- ------------------------------------------------------------------------------
Pension Benefits Other Benefits
----------------- ------------------
2003 2002 2003 2002
- ----------------------------- ----------------- ------------------
Discount rate 6.00% 6.75% 6.00% 6.75%
Rate of compensation increase 3.50% 4.25% 3.50% 4.25%
A 10% annual rate of increase in the per capita cost of covered health care
benefits was assumed for 2004. The rate was assumed to decrease gradually to 5%
for 2009 and remain at that level thereafter. Assumed health care cost trend
rates have a significant effect on the amounts reported for health care plans. A
one percentage point increase in assumed health care cost trend rates would have
increased the benefit obligation by $8.4 million. A one percentage point
decrease would have decreased the obligation by $7.0 million.
Plan Assets
A reconciliation of the Company's plan assets at December 31, 2003, and 2002,
follows:
- -------------------------------------------------------------------------------
Pension Benefits Other Benefits
--------------------- -----------------
(In millions) 2003 2002 2003 2002
- -------------------------------------------------------------------------------
Plan assets at fair value,
beginning of period $ 138.6 $ 160.1 $ 7.4 $ 8.8
Actual return on plan assets 20.8 (10.1) 1.4 (0.5)
Employer contributions 1.1 0.7 5.8 7.8
Benefits paid (12.7) (12.1) (5.4) (8.7)
- -------------------------------------------------------------------------------
Fair value of plan assets,
end of period $ 147.8 $ 138.6 $ 9.2 $ 7.4
===============================================================================
The asset allocation for the Company's pension and postretirement plans at the
measurement date for 2003 and 2002, and the target allocation for 2004, by asset
category, follows:
- ----------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------- ----------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------
Equity securities 59% 57% 54% 49%
Debt securities 35% 43% 32% 47%
Real estate 6% - - -
Short term investments & other - - 14% 4%
- ----------------------------------------------------------------------------
Total 100% 100% 100% 100%
============================================================================
The Company invests in a master trust that benefits all qualified defined
benefit pension plans. The general investment objectives are to invest in a
diversified portfolio, comprised of both equity and fixed income investments,
which are further diversified among various asset classes. The diversification
is designed to minimize the risk of large losses while maximizing total return
within reasonable and prudent levels of risk. The investment objectives specify
a targeted investment allocation for the pension plans of 60% equities, 35%
debt, and 5% real estate for 2004, and for postretirement plans of 55% equities,
35% debt, and 10% short-term investments and other for 2004. Objectives do not
target a specific return by asset class. The portfolio's return is monitored in
total and is designed to outperform inflation. These investment objectives are
long-term in nature.
Funded Status
The funded status of the plans, reconciled to amounts reflected in the balance
sheets as of December 31, 2003, and 2002, follows:
- -------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
--------------------- ------------------
(In millions) 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------
Fair value of plan assets, end of period $ 147.8 $ 138.6 $ 9.2 $ 7.4
Benefit obligation, end of period (222.7) (201.9) (97.3) (81.5)
- -------------------------------------------------------------------------------------------
Funded status, end of period (74.9) (63.3) (88.1) (74.1)
- -------------------------------------------------------------------------------------------
Unrecognized net loss (gain) 49.4 42.2 1.7 (13.0)
Unrecognized transitional (asset) obligation (0.2) (0.4) 29.1 32.0
Unrecognized prior service cost 10.5 11.0 - -
Post measurement date adjustments 0.2 0.2 0.8 2.9
- -------------------------------------------------------------------------------------------
Net amount recognized, end of year $ (15.0) $ (10.3) (56.5) $ (52.2)
===========================================================================================
Net amount recognized included in:
Deferred credits & other liabilities $ (18.9) $ (15.2) $(56.5) $ (52.2)
Other assets 3.9 4.9 - -
As of December 31, 2003, and 2002, the funded status of the SERP, which is
included in Pension Benefits in the chart above, was an unfunded amount of $12.7
million and $11.9 million, respectively, and the net amount recognized in the
balance sheet related to the SERP as of December 31, 2003, and 2002 was a
liability of $7.8 million and $7.5 million, respectively.
At December 31, 2003, and 2002, all pension and postretirement plans had
accumulated benefit obligations in excess of plan assets. As required by SFAS
87, the Company has recorded additional minimum pension liability adjustments to
reflect the total unfunded accumulated liability arising from its pension plans.
This additional minimum pension liability adjustment is included in Deferred
credits & other liabilities. The offset to this additional liability is recorded
to an intangible asset included in Other assets to the extent pension plans have
unrecognized prior service cost. Any unfunded or unaccrued amount in excess of
prior service cost is recorded in net of tax amounts to Accumulated other
comprehensive income in shareholders' equity. The effects of additional minimum
pension liability adjustments at December 31, 2003, and 2002, follow:
- -------------------------------------------------------------------------------
(In millions) 2003 2002
- -------------------------------------------------------------------------------
Minimum pension liability adjustment, beginning of year $ 30.0 $ 7.3
Change in minimum pension liability adjustment included in:
Other comprehensive income before effect of taxes 9.7 15.7
Other assets - 7.0
- -------------------------------------------------------------------------------
Minimum pension liability adjustment, end of year $ 39.7 $ 30.0
===============================================================================
Offset included in:
Accumulated other comprehensive income $ 17.4 $ 11.6
Other assets 10.5 10.5
Deferred income taxes 11.8 7.9
Expected Cash Flows
In 2004, the Company expects to make contributions of approximately $5.3 million
to its pension plan trusts. In addition, the Company expects to make payments
totaling $0.8 million directly to SERP participants and $4.9 million directly to
those participating in other postretirement plans.
Expected retiree pension benefit payments, including the SERP, projected to be
required during the years following 2003 (in millions) are $10.5 in 2004, $10.8
in 2005, $11.2 in 2006, $11.7 in 2007, $12.2 in 2008 and $73.1 in years
2009-2013. Expected benefit payments projected to be required for postretirement
benefits during the years following 2003 (in millions) are $5.2 in 2004, $5.5 in
2005, $5.8 in 2006, $6.0 in 2007, $6.3 in 2008 and $33.8 in years 2009-2013.
Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years
ended December 31, 2003, follows:
- ---------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
--------------------------- ------------------------
(In millions) 2003 2002 2001 2003 2002 2001
- ---------------------------------------------------------------------------------------------
Service cost $ 5.8 $ 5.9 $ 5.9 $ 0.9 $ 1.0 $ 1.0
Interest cost 13.6 13.9 13.6 5.4 6.0 5.8
Expected return on plan assets (14.8) (15.7) (16.3) (0.7) (0.7) (0.8)
Amortization of prior service cost 0.8 0.8 0.8 - - -
Amortization of transitional
(asset) obligation (0.2) (0.5) (0.6) 2.9 2.9 3.0
Amortization of actuarial loss
(gain) 0.5 0.1 (0.9) (0.5) (0.5) (1.0)
Settlement, curtailment, & other
charges (credits) - - (1.4) - - (0.6)
- ---------------------------------------------------------------------------------------------
Net periodic benefit cost $ 5.7 $ 4.5 $ 1.1 $ 8.0 $ 8.7 $ 7.4
=============================================================================================
To calculate the expected return on plan assets, the Company uses the plan
assets' market-related value and an expected long-term rate of return. The fair
market value of the assets at the measurement date is adjusted to a
market-related value by recognizing the change in fair value experienced in a
given year ratably over a five-year period. The expected long-term rate of
return has not been adjusted for plan expenses. An estimate of plan expenses is
included in the service cost component of net periodic benefit cost.
Based on a targeted 60% equity, 35% debt, and 5% real estate allocation for the
pension plans, the Company has used a long-term expected rate of return of 9.0%
to calculate 2003 periodic benefit cost. For fiscal 2004, the expected long-term
rate of return will be 8.5%.
The weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
- -----------------------------------------------------------------------------
Pension Benefits Other Benefits
----------------- ----------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------
Equity securities 59% 57% 54% 49%
Debt securities 35% 43% 32% 47%
Real estate 6% - - -
Short term investments & other - - 14% 4%
- -----------------------------------------------------------------------------
Total 100% 100% 100% 100%
=============================================================================
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one percentage point increase in assumed
health care cost trend rates would have increased the service and interest cost
components of pension costs by $0.7 million. A one percentage point decrease
would have decreased the benefit costs by $0.6 million.
Defined Contribution Plan
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
2003, 2002, and 2001, the Company made contributions to these plans of $3.6
million, $3.0 million, and $3.4 million, respectively.
7. Borrowing Arrangements
Short-Term Borrowings
At December 31, 2003, the Company has $531 million of short-term borrowing
capacity, including $351 million for the Utility Group operations and $180
million for the wholly owned Nonregulated Group and corporate operations, of
which approximately $166 million is available for the Utility Group operations
and approximately $91 million is available for wholly owned Nonregulated Group
and corporate operations. The availability of short-term borrowing is reduced by
outstanding letters of credit totaling $1.0 million, collateralizing
Nonregulated Group activities. See the table below for interest rates and
outstanding balances.
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Weighted average commercial paper
and bank loans outstanding
during the year $ 296.9 $ 288.8 $ 447.0
Weighted average interest rates
during the year
Commercial paper 1.36% 2.02% 4.39%
Bank loans 1.94% 2.52% 6.77%
At December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002
- -----------------------------------------------------------------------------
Commercial paper $ 184.4 $ 239.1
Bank loans 88.4 157.8
Other 2.1 2.6
- -----------------------------------------------------------------------------
Total short-term borrowings $ 274.9 $ 399.5
=============================================================================
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding
and classified as long-term by subsidiary follow:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Vectren Capital Corp.
Fixed Rate Senior Unsecured Notes
2005, 7.67% 38.0 38.0
2007, 7.83% 17.5 17.5
2010, 7.98% 22.5 22.5
2012, 7.43% 35.0 35.0
- ------------------------------------------------------------------------------
Total Vectren Capital Corp. 113.0 113.0
- ------------------------------------------------------------------------------
VUHI
Fixed Rate Senior Unsecured Notes
2011, 6.625% $ 250.0 $ 250.0
2013, 5.25% 100.0 -
2018, 5.75% 100.0 -
2031, 7.25% 100.0 100.0
- ------------------------------------------------------------------------------
Total VUHI 550.0 350.0
- ------------------------------------------------------------------------------
SIGECO
First Mortgage Bonds
2003, 1978 Series B, 6.25%, tax exempt - 1.0
2016, 1986 Series, 8.875% 13.0 13.0
2023, Series, 7.60% - 45.0
2023, Series B, 6.00%, tax exempt 22.8 22.8
2025, 1993 Series, 7.625% - 20.0
2029, 1999 Senior Notes, 6.72% 80.0 80.0
2015, 1985 Pollution Control Series A,
adjustable rate presently 4.30%, tax
exempt, next rate adjustment: 2004 10.0 10.0
2025, 1998 Pollution Control Series A,
adjustable rate presently 4.75%, tax
exempt, next rate adjustment: 2006 31.5 31.5
2024, 2000 Environmental Improvement
Series A, fixed in April 2003 at 4.65%,
tax exempt, weighted average for year: 3.69% 22.5 22.5
- ------------------------------------------------------------------------------
Total first mortgage bonds 179.8 245.8
- ------------------------------------------------------------------------------
Senior Unsecured Bonds to Third Parties:
2020, 1998 Pollution Control Series B,
fixed in April 2003 at 4.50%, tax exempt,
weighted average for year: 4.16% 4.6 4.6
2030, 1998 Pollution Control Series B, fixed
in April 2003 at 5.00%, tax exempt,
weighted average for year: 4.48% 22.0 22.0
2030, 1998 Pollution Control Series C,
adjustable rate presently 5.00%, tax
exempt, next rate adjustment: 2006 22.2 22.2
- ------------------------------------------------------------------------------
Total senior unsecured bonds 48.8 48.8
- ------------------------------------------------------------------------------
Total SIGECO 228.6 294.6
- ------------------------------------------------------------------------------
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Indiana Gas
Senior Unsecured Notes
2003, Series F, 5.75% $ - $ 15.0
2004, Series F, 6.36% 15.0 15.0
2007, Series E, 6.54% 6.5 6.5
2013, Series E, 6.69% 5.0 5.0
2015, Series E, 7.15% 5.0 5.0
2015, Insured Quarterly, 7.15% 20.0 20.0
2015, Series E, 6.69% 5.0 5.0
2015, Series E, 6.69% 10.0 10.0
2021, Private Placement, 9.375%,
$1.3 due annually in 2002 - 23.8
2025, Series E, 6.53% 10.0 10.0
2027, Series E, 6.42% 5.0 5.0
2027, Series E, 6.68% 3.5 3.5
2027, Series F, 6.34% 20.0 20.0
2028, Series F, 6.75% - 13.6
2028, Series F, 6.36% 10.0 10.0
2028, Series F, 6.55% 20.0 20.0
2029, Series G, 7.08% 30.0 30.0
2030, Insured Quarterly, 7.45% 49.9 49.9
- ------------------------------------------------------------------------------
Total Indiana Gas 214.9 267.3
- ------------------------------------------------------------------------------
Total long-term debt outstanding 1,106.5 1,024.9
Current maturities of long-term debt (15.0) (39.8)
Debt subject to tender (13.5) (26.6)
Unamortized debt premium & discount - net (4.9) (4.3)
Fair value of hedging arrangements (0.3) -
- ------------------------------------------------------------------------------
Total long-term debt - net $ 1,072.8 $ 954.2
==============================================================================
VUHI 2003 Issuance
In July 2003, VUHI issued senior unsecured notes with an aggregate principal
amount of $200 million in two $100 million tranches. The first tranche was
10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746%
to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes
due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80%
to maturity (2018 Notes).
The notes have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by VUHI, in whole or in part, at any time
for an amount equal to accrued and unpaid interest, plus the greater of 100% of
the principal amount or the sum of the present values of the remaining scheduled
payments of principal and interest, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20
basis points for the 2013 Notes and 25 basis points for the 2018 Notes.
Shortly before these issues, VUHI entered into several treasury locks with a
total notional amount of $150.0 million. Upon issuance of the debt, the treasury
locks were settled resulting in the receipt of $5.7 million in cash, which was
recorded as a regulatory liability pursuant to existing regulatory orders. The
value received is being amortized as a reduction of interest expense over the
life of the issues.
The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million.
VUHI 2001 Issuance
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.
Shortly before these issues, the Company entered into several forward starting
interest rate swaps with total notional amount of $200.0 million. Upon issuance
of the debt, the treasury locks were settled resulting in the receipt of $0.9
million in cash, which was recorded as a regulatory liability pursuant to
existing regulatory orders. The value received is being amortized as a reduction
of interest expense over the life of the issues.
The net proceeds from the sale of the senior notes and settlement of the hedging
arrangements totaled $344.0 million.
SIGECO and Indiana Gas Debt Call
During 2003, the Company called two first mortgage bonds outstanding at SIGECO
and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
had a principal amount of $45.0 million, an interest rate of 7.60%, was
originally due in 2023, and was redeemed at 103.745% of its stated principal
amount. The second SIGECO bond had a principal amount of $20.0 million, an
interest rate of 7.625%, was originally due in 2025, and was redeemed at
103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an
interest rate of 9.375%, was originally due in 2021, and was redeemed at
105.525% of the stated principal amount. The second Indiana Gas note had a
principal amount of $13.5 million, an interest rate of 6.75%, was originally due
in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire the net carrying
value of these notes totaling $3.6 million were deferred in Regulatory assets.
Other Financing Transactions
Other Company debt totaling $18.5 million in 2003, $6.5 million in 2002, and
$7.6 million in 2001 was retired as scheduled.
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.
Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.
Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is one
percent of the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the Trustee of
unfunded property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2004 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2004 is excluded from
Current liabilities in the Consolidated Balance Sheets. At December 31, 2003,
$502.0 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.
Consolidated maturities and sinking fund requirements on long-term debt during
the five years following 2003 (in millions) are $15.0 in 2004, $38.0 in 2005,
zero in 2006, $24.0 in 2007, and zero in 2008.
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. Other than those described below
related to ratings triggers, the put or call provisions are not triggered by
specific events, but are based upon dates stated in the note agreements, such as
when notes are re-marketed. Debt which may be put to the Company during the
years following 2003 (in millions) is $13.5 in 2004, $10.0 in 2005, $53.7 in
2006, $20.0 in 2007, zero in 2008, and $120.0 thereafter. Debt that may be put
to the Company within one year is classified as Long-term debt subject to tender
in current liabilities.
Covenants
Both long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2003, the Company was in
compliance with all financial covenants.
Ratings Triggers
At December 31, 2003, $113.0 million of Vectren Capital's senior unsecured notes
were subject to cross-default and ratings trigger provisions that would provide
that the full balance outstanding is subject to prepayment if the ratings of
Indiana Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a
make whole amount based on the discounted value of the remaining payments due on
the notes would also become payable. The credit rating of Indiana Gas' senior
unsecured debt and SIGECO's secured debt remains one level and two levels,
respectively, above the ratings trigger.
Debt Guarantees
Vectren Corporation guarantees Vectren Capital's long-term and short-term debt,
which totaled $113.0 million and $87.6 million, respectively, at December 31,
2003. VUHI's currently outstanding long-term and short-term debt is jointly and
severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and
short-term debt outstanding at December 31, 2003, totaled $550.0 million and
$184.4 million, respectively.
8. Cumulative Preferred Stock of Subsidiary
Redemption of Preferred Stock of a Subsidiary
Nonredeemable preferred stock of a subsidiary containing call options was
redeemed during September 2001 for a total redemption price of $9.8 million. The
4.80%, $100 par value preferred stock was redeemed at its stated call price of
$110 per share, plus accrued and unpaid dividends totaling $1.35 per share. The
4.75%, $100 par value preferred stock was redeemed at its stated call price of
$101 per share, plus accrued and unpaid dividends totaling $0.97 per share.
Prior to the redemptions, there were 85,519 shares of the 4.80% Series
outstanding and 3,000 shares of the 4.75% Series outstanding.
In September 2001, the 6.50%, $100 par value of redeemable preferred stock of a
subsidiary was redeemed for a total redemption price of $7.9 million at $104.23
per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the
redemption, there were 75,000 shares outstanding.
As both series of preferred stock redeemed were 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, 2003,
and 2002, there were 2,277 shares and 3,437 shares outstanding, respectively.
9. Common Shareholders' Equity
Equity Issuances
In March 2003, the Company filed a registration statement with the Securities
and Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock as well as the senior unsecured notes
of VUHI described above in Note 7. In August 2003, the registration became
effective, and an agreement was reached to sell approximately 7.4 million shares
to a group of underwriters. The net proceeds totaled $163.2 million.
In January 2001, the Company filed a registration statement with the Securities
and Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock. In February 2001, the registration
became effective, and an agreement was reached to sell approximately 6.3 million
shares to a group of underwriters. The net proceeds totaled $129.4 million.
Authorized, Reserved Common and Preferred Shares
At December 31, 2003, and 2002, the Company was authorized to issue 480.0
million shares of common stock and 20.0 million shares of preferred stock. Of
the authorized common shares, approximately 7.0 million shares at December 31,
2003, and 7.3 million shares at December 31, 2002, were reserved by the board of
directors for issuance through the Company's equity-based compensation plans,
benefit plans, and dividend reinvestment plan. At December 31, 2003, and 2002,
there were 397.4 million and 404.8 million, respectively, of authorized shares
of common stock and all authorized shares of preferred stock available for a
variety of general corporate purposes, including future public offerings to
raise additional capital and for facilitating acquisitions.
Shareholder Rights Agreement
The Company's board of directors has adopted a Shareholder Rights Agreement
(Rights Agreement). As part of the Rights Agreement, the board of directors
declared a dividend distribution of one right for each outstanding Vectren
common share. Each right entitles the holder to purchase from Vectren one share
of common stock at a price of $65.00 per share (subject to adjustment to prevent
dilution). The rights become exercisable 10 days following a public announcement
that a person or group of affiliated or associated persons (Vectren Acquiring
Person) has acquired beneficial ownership of 15% or more of the outstanding
Vectren common shares (or a 10% acquirer who is determined by the board of
directors to be an adverse person), or 10 days following the announcement of an
intention to make a tender offer or exchange offer the consummation of which
would result in any person or group becoming a Vectren Acquiring Person. The
Vectren Shareholder Rights Agreement expires October 21, 2009.
10. 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, 2003:
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001
- -------------------------------------------------------------------------------
Numerator:
Numerator for basic and diluted EPS -
Net income $ 111.2 $ 114.0 $ 52.7
===============================================================================
Denominator:
Denominator for basic EPS - Weighted average
common shares outstanding 70.6 67.6 66.7
Conversion of s tock options and lifting of
restrictions on issued restricted stock 0.2 0.3 0.2
- -------------------------------------------------------------------------------
Denominator for diluted EPS - Adjusted
weighted average shares outstanding
and assumed conversions outstanding 70.8 67.9 66.9
===============================================================================
Basic earnings per share $ 1.58 $ 1.69 $ 0.79
Diluted earnings per share $ 1.57 $ 1.68 $ 0.79
Options to purchase 530,663 shares of common stock for the year ended December
31, 2003, 87,963 shares of common stock for the year ended December 31, 2002,
and 836,688 shares of common stock for the year ended December 31, 2001, were
excluded 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 $23.19 to $25.59 in 2003; $24.05 to $25.59 in 2002; and
$22.54 to $24.05 in 2001.
Equity-Based Incentive Plans
The Company has various equity-based incentive plans to encourage employees and
non-employee directors to remain with the Company and to more closely align
their interest with those of the Company's shareholders.
Stock Option Plans
A summary of the status of the Company's stock option plans for the past three
years follows:
Wtd. Avg.
Options Exercise Price
- ---------------------------------------------------------------------------
Outstanding at January 1, 2001 859,441 $ 18.41
Granted 783,999 22.54
Cancelled (92,953) 21.84
Exercised (122,709) 16.05
- ---------------------------------------------------------------------------
Outstanding at December 31, 2001 1,427,778 20.67
Granted 71,374 23.51
Cancelled (3,000) 22.54
Exercised (146,890) 14.51
- ---------------------------------------------------------------------------
Outstanding at December 31, 2002 1,349,262 21.48
Granted 521,200 23.07
Cancelled (5,800) 22.56
Exercised (61,766) 17.30
- ---------------------------------------------------------------------------
Outstanding at December 31, 2003 1,802,896 $ 22.08
===========================================================================
In January 2004, 219,000 options to purchase shares of common stock at an
exercise price of $24.74 were issued to management. The grant vests over three
years.
Stock options granted to employees in 2003 become fully vested and exercisable
at the end of three years. Stock options granted to employees in 2001 and 2002
become fully vested and exercisable at the end of five years. Stock options
granted to non-employee directors in 2001, 2002, and 2003 become fully vested
and exercisable at the end of one year. All options granted prior to 2001 are
fully vested and exercisable. Options granted both before and after 2001
generally expire ten years from the date of grant.
The fair value of each option granted used to determine pro forma net income as
disclosed in Note 2, is estimated as of the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for grants in the years ended December 31, 2003, 2002, and
2001: risk-free rate of return of 4.26%, 3.80%, and 5.65%, respectively;
expected option term of 8 years for all 3 years presented; expected volatility
of 19.01%, 26.44% and 26.56%, respectively; and dividend yield of 4.50%, 4.65%,
and 4.42%, respectively. The weighted average fair value of options granted in
2003, 2002, and 2001 were $3.31, $4.33 and $5.21, respectively.
The following table summarizes information about stock options outstanding and
exercisable at December 31, 2003:
Outstanding Exercisable
-------------------------------------------- ------------------------------
Wtd. Avg.
Remaining
Range of Contractual Wtd. Avg. Wtd. Avg.
Exercise Prices # of Options Life Exercise Price # of Options Exercise Price
- --------------- -------------------------------------------- ------------------------------
$13.82 - $17.44 80,350 1.7 $ 15.86 80,350 $ 15.86
$19.83 - $20.26 304,484 4.8 20.11 304,484 20.11
$22.37 - $22.57 887,399 7.6 22.54 412,799 22.53
$23.19 - $25.59 530,663 8.4 23.38 127,216 23.87
- --------------------------------------------------------------------------------------------
Total 1,802,896 7.1 $ 22.08 924,849 $ 21.34
============================================================================================
Stock options that were exercisable and those options' weighted average exercise
prices were 692,288 and $20.37, respectively, at December 31, 2002, and 658,221
and $18.47, respectively, at December 31, 2001.
Other Plans
The Company maintains a performance-based restricted stock plan for its
executives and a non-performance based restricted stock plan through which
non-employee directors receive a portion of their director fees. A summary of
outstanding restricted stock issued through these plans during the three years
ended December 31, 2003, follows:
Restricted Stock
- ----------------------------------------------------------------------------
Outstanding at January 1, 2001 194,884
Grants 4,257
Forfeitures (19,726)
Vested (1,302)
- ----------------------------------------------------------------------------
Outstanding at December 31, 2001 178,113
Grants 66,831
Vested (4,257)
- ----------------------------------------------------------------------------
Outstanding at December 31, 2002 240,687
Grants 120,228
Forfeitures (14,136)
Vested (137,777)
- ----------------------------------------------------------------------------
Outstanding at December 31, 2003 209,002
============================================================================
For the years ended December 31, 2003, 2002, and 2001, the weighted average fair
value per share of restricted stock granted was $23.33, $23.10, and $22.54,
respectively.
In January 2004, 133,500 options to purchase shares of common stock at an
exercise price of $24.74 were issued to management. The grant vests over three
years.
Executives and non-employee directors may defer certain portions of their
salary, annual bonus, incentive compensation, and earned restricted stock into
phantom stock units. Such units are vested when granted.
Compensation expense associated with the restricted stock and phantom stock
plans for the years ended December 31, 2003, 2002, and 2001, was $3.6 million,
$2.1 million, and $2.8 million, respectively.
12. Commitments & Contingencies
Commitments
Future minimum lease payments required under operating leases that have initial
or remaining noncancelable lease terms in excess of one year during the five
years following 2003 and thereafter (in millions) are $6.7 in 2004, $5.4 in
2005, $4.2 in 2006, $3.3 in 2007, $1.4 in 2008, and $0.6 thereafter. Total lease
expense (in millions) was $7.2 in 2003, $7.3 in 2002, and $6.2 in 2001.
Firm purchase commitments for commodities total (in millions) $169.8 in 2004 and
$34.5 in 2005. Firm purchase commitment for utility and nonutility plant total
$117.8 million.
Other Guarantees
Vectren Corporation issues guarantees to third parties on behalf of its
unconsolidated affiliates. Such guarantees allow those affiliates to execute
transactions on more favorable terms than the affiliate could obtain without
such a guarantee. Guarantees may include posted letters of credit, leasing
guarantees, and performance guarantees. As of December 31, 2003, guarantees
issued and outstanding on behalf of unconsolidated affiliates approximated $6
million. The Company has also issued a guarantee approximating $4 million
related to the residual value of an operating lease that expires in 2006.
Vectren Corporation has accrued no liabilities for these guarantees as they
relate to guarantees issued among related parties or were executed prior to the
adoption of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). As more fully described in Note 19, FIN 45 was adopted
prospectively and specifically excludes from its recognition and measurement
provisions, guarantees issued among related parties.
Through December 31, 2003, the Company has not been called upon to satisfy any
obligations pursuant to its guarantees. Liabilities accrued for, and activity
related to, product warranties are not significant.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 consolidated financial statements, the
Company restated its annual consolidated financial statements for 2000 and 2001,
and its 2002 quarterly results. The Company received an informal inquiry from
the SEC with respect to this restatement. In response, the Company met with the
SEC staff and provided information in response to their requests, with the most
recent response provided on July 26, 2003.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 13 regarding
environmental matters.
13. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an eight percent
return on its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits, (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology, and (3) failing to notify the USEPA of
the modifications. In addition, the lawsuit alleged that the modifications to
the Culley Generating Station required SIGECO to begin complying with federal
new source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations in the
government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO has entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested
with the most recent correspondence provided on March 26, 2001.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.
14. Rate & Regulatory Matters
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
accounts expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.
Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.
Recovery of Purchased Power
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2004,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
15. Derivatives & Other Financial Instruments
Accounting Policy for Derivatives
The Company executes derivative contracts in the normal course of operations
while buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk.
When an energy contract that is a derivative is designated and documented as a
normal purchase or normal sale, it is exempted from mark-to-market accounting.
Otherwise, energy contracts and financial contracts that are derivatives are
recorded at market value as current or noncurrent assets or liabilities
depending on their value and on when the contracts are expected to be settled.
The offset resulting from carrying the derivative at fair value on the balance
sheet is charged to earnings unless it qualifies as a hedge or is subject to
SFAS 71. When hedge accounting is appropriate, the Company assesses and
documents hedging relationships between the derivative contract and underlying
risks as well as its risk management objectives and anticipated effectiveness.
When the hedging relationship is highly effective, derivatives are designated as
hedges. The market value of the effective portion of the hedge is marked to
market in accumulated other comprehensive income for cash flow hedges or as an
adjustment to the underlying's basis for fair value hedges. The ineffective
portion of hedging arrangements is marked-to-market through earnings. The offset
to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or
liability. Market value for all derivative contracts is determined using quoted
market prices from independent sources. Following is a more detailed discussion
of the Company's use of mark-to-market accounting in three primary areas: asset
optimization, natural gas procurement, and interest rate management.
Asset Optimization
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. Substantially all of these
contracts are integrated with portfolio requirements around power supply and
delivery and are primarily short-term purchase and sale contracts that expose
the Company to limited market risk. Contracts with counter-parties subject to
master netting arrangements are presented net in the Consolidated Balance
Sheets. Asset optimization contracts are recorded at market value. Changes in
market value, which is a function of the normal decline in market value as
earnings are realized and the fluctuation in market value resulting from price
volatility, are recorded in Electric utility revenues.
Asset optimization contracts recorded at market value at December 31, 2003,
totaled $2.4 million of Prepayments & other current assets and $2.8 million of
Accrued liabilities, compared to $3.5 million of Prepayments & other current
assets and $4.2 million of Accrued liabilities at December 31, 2002.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation. Following is
information regarding asset optimization activities included in Electric utility
revenues and Fuel for electric generation in the Statements of Income:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -----------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152.8 $ 302.8 $ 101.4
Purchase contracts (127.0) (275.9) (74.3)
Mark-to-market gains (losses) 0.7 (3.6) 1.5
- -----------------------------------------------------------------------------
Net asset optimization revenue 26.5 23.3 28.6
- -----------------------------------------------------------------------------
Fuel for electric generation (8.2) (10.6) (9.5)
- -----------------------------------------------------------------------------
Asset optimization margin $ 18.3 $ 12.7 $ 19.1
=============================================================================
Natural Gas Procurement Activity
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although Vectren's regulated operations are exposed
to limited commodity price risk, volatile natural gas prices can result in
higher working capital requirements, increased expenses including unrecoverable
interest costs, uncollectible accounts expense, and unaccounted for gas, and
some level of price- sensitive reduction in volumes sold. The Company mitigates
these risks by executing derivative contracts that manage the price of
forecasted natural gas purchases. These contracts are subject to regulation
which allows for reasonable and prudent hedging costs to be recovered through
rates. When regulation is involved, SFAS 71 controls when the offset to
mark-to-market accounting is recognized in earnings.
The Company's wholly owned gas retail operations also mitigate price risk
associated with forecasted natural gas purchases by using derivatives. Such
contracts are ordinarily designated and documented as cash flow hedges.
The market value of natural gas procurement derivative contracts at December 31,
2003, was not significant.
Interest Rate Management
The Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The Company
has used interest rate swaps and treasury locks to hedge forecasted debt
issuances and other interest rate swaps to manage interest rate exposure.
Hedging instruments are recorded at market value. Changes in market value, when
effective, are recorded in Accumulated other comprehensive income for cash flow
hedges, as an adjustment to the outstanding debt balance for fair value hedges,
or as regulatory asset/liability when regulation is involved. Amounts are
recorded to interest expense as settled.
As of December 31, 2003, interest rate swaps hedging the fair value of
fixed-rate debt with a total notional amount of $55.5 million and a fair value
liability of $0.3 million are outstanding. At December 31, 2003, approximately
$6.2 million remains in Regulatory liabilities related to future interest
payments from the 2003 and 2001 VUHI interest rate hedging activities. Of the
existing regulatory liability, $0.6 million will be reclassified to earnings in
2004 and $0.3 million was reclassified to earnings during 2003.
Impact of Adoption of SFAS 133
In June 1998, the FASB issued SFAS 133 which required that every derivative
instrument be recorded on the balance sheet as an asset or liability measured at
its market value and that a change in the derivative's market value be
recognized currently in earnings unless specific hedge criteria are met.
SFAS 133, as amended, required that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income or other comprehensive income, as appropriate. A change in
earnings or other comprehensive income was reported as a cumulative effect of a
change in accounting principle in accordance with APB Opinion No. 20,
"Accounting Changes."
Resulting from the adoption of SFAS 133, certain asset optimization contracts
and other commodity contracts that are periodically settled net were required to
be recorded at market value. Previously, the Company accounted for these
contracts on settlement. The cumulative impact of the adoption of SFAS 133
resulting from marking these contracts to market on January 1, 2001, was an
earnings gain of approximately $1.8 million ($1.1 million net of tax) recorded
as a cumulative effect of accounting change. The majority of this gain results
from the Company's asset optimization operations. SFAS 133 did not impact other
commodity contracts because they were normal purchases and sales specifically
excluded from the provisions of SFAS 133 and did not impact the Company's cash
flow hedges because they had no value on the date of adoption.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments follow:
At December 31,
- ---------------------------------------------------------------------------------------
2003 2002
--------------------- ---------------------
Carrying Est. Fair Carrying Est. Fair
(In millions) Amount Value Amount Value
- ------------------------------------------------------- -------------------------------
Long-term debt $ 1,106.5 $ 1,184.8 $ 1,024.9 $ 1,095.3
Short-term borrowings & notes payable 274.9 274.9 399.5 399.5
Certain methods and assumptions must be used to estimate the fair value of
financial instruments. The fair value of the Company's other financial
instruments was estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to the Company for instruments
with similar characteristics. Because of the maturity dates and variable
interest rates of short-term borrowings, its carrying amount approximates its
fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term
debt are generally recovered in customer rates over the life of the refunding
issue or over a 15-year period. Accordingly, any reacquisition would not be
expected to have a material effect on the Company's financial position or
results of operations.
Periodically, the Company tests its cost method investments and notes receivable
for impairment which may require their fair value to be estimated. Because of
the customized nature of these investments and lack of a readily available
market, it is not practicable to estimate the fair value of these financial
instruments at specific dates without considerable effort and costs. At December
31, 2003, and 2002, fair value for these financial instruments has not been
estimated.
16. Additional Operational & Balance Sheet Information
Other - net in the Consolidated Statements of Income consists of the following:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -----------------------------------------------------------------------------
AFUDC & capitalized interest $ 5.9 $ 5.7 $ 6.3
Interest income 3.2 4.7 5.7
Gains on sale of investments & assets 7.5 1.8 2.9
Leveraged lease investment income 1.9 1.1 4.6
Other income 3.2 2.7 6.0
Other expense (8.7) (4.5) (8.8)
- -----------------------------------------------------------------------------
Total other - net $ 13.0 $ 11.5 $ 16.7
=============================================================================
Prepayments and other current assets in the Consolidated Balance Sheets consist
of the following:
At December 31,
- ----------------------------------------------------------------------------
(In millions) 2003 2002
- ----------------------------------------------------------------------------
Prepaid gas delivery service $ 97.7 $ 70.3
Prepaid taxes 20.1 4.8
Other prepayments & current assets 13.3 12.6
- ----------------------------------------------------------------------------
Total prepayments & other current assets $ 131.1 $ 87.7
============================================================================
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
At December 31,
- ----------------------------------------------------------------------------
(In millions) 2003 2002
- ----------------------------------------------------------------------------
Accrued taxes $ 33.2 $ 47.2
Refunds to customers & customer deposits 24.5 21.0
Accrued interest 16.5 14.0
Deferred income taxes 6.9 7.7
Accrued salaries & other 28.2 30.0
- ----------------------------------------------------------------------------
Total accrued liabilities $ 109.3 $ 119.9
============================================================================
17. Segment Reporting
During 2003, Vectren transferred certain information technology systems and
related assets and buildings from other entities within its consolidated group
to VUHI. These assets primarily support the operations of VUHI's subsidiaries.
The Company has reorganized and restated its operating segments from those
segments reported in its 2002 financial statements to reflect this transfer. The
reorganization did not reflect the previous reporting of the Nonregulated group,
but did affect all other previously reported segments. The Company now
segregates its operations into three groups: 1) Utility Group, 2) Nonregulated
Group, and 3) Corporate and Other Group.
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and other operations that
provide information technology and other support services to those regulated
operations. In total, there are three operating segments as defined by SFAS 131
"Disclosure About Segments of an Enterprise and Related Information" (SFAS 131).
Gas Utility Services provides natural gas distribution and transportation
services in nearly two-thirds of Indiana and to west central Ohio. Electric
Utility Services provides electricity primarily to southwestern Indiana, and
includes the Company's power generating and marketing operations. The Company
collectively refers to its gas and electric operating segments as its regulated
operations. For these regulated operations the Company uses after tax operating
income as a measure of profitability, consistent with regulatory reporting
requirements. The Company cross manages its regulated margin, other operating
expenses, and capital expenditures as separated between Energy Delivery, which
includes the gas and electric transmission and distribution functions, and Power
Supply, which includes the power generating and marketing operations.
The Utility Group's other operations were formerly a component of the Corporate
and Other Group. Other operations also contain other assets and operations that
were previously allocated to the Gas Utility and Electric Utility Segments. The
Company uses net income as the measure of the profitability for this segment.
The Nonregulated Group is comprised of one operating segment as defined by SFAS
131 that includes 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 Group is comprised of one operating segment as defined
by SFAS 131 that includes unallocated corporate expenses such as branding and
charitable contributions, among other activities, that benefit the Company's
other operating segments.
Information related to the Company's business segments is summarized below:
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Revenues
Utility Group
Gas Utility Services $ 1,112.3 $ 908.0 $ 1,019.6
Electric Utility Services 335.7 328.6 308.5
Other Operations 26.5 22.4 29.1
Eliminations (25.7) (22.1) (28.9)
- -------------------------------------------------------------------------------
Total Utility Group 1,448.8 1,236.9 1,328.3
- -------------------------------------------------------------------------------
Nonregulated Group 219.2 352.3 741.8
Corporate & Other Group 1.0 1.0 0.5
Eliminations (81.3) (66.4) (61.5)
- -------------------------------------------------------------------------------
Consolidated Revenues $ 1,587.7 $ 1,523.8 $ 2,009.1
===============================================================================
Year Ended December 31,
- --------------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------------------
Profitability Measure
Utility Group: Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services $ 74.9 $ 80.7 $ 47.1
Electric Utility Services 63.8 73.2 56.5
- --------------------------------------------------------------------------------------
Total Regulated Operating Income 138.7 153.9 103.6
- --------------------------------------------------------------------------------------
Regulated other income - net 5.1 5.1 4.7
Regulated interest expense & preferred dividends (62.0) (63.7) (68.2)
Regulated cumulative effect change in
accounting principle - - 1.1
- --------------------------------------------------------------------------------------
Regulated Net Income 81.8 95.3 41.2
- --------------------------------------------------------------------------------------
Other Operations Net Income 3.8 1.8 3.6
- --------------------------------------------------------------------------------------
Utility Group Net Income 85.6 97.1 44.8
- --------------------------------------------------------------------------------------
Nonregulated Group Net Income 27.6 19.0 12.1
Corporate & Other Group Net Loss (2.0) (2.1) (4.2)
- --------------------------------------------------------------------------------------
Consolidated Net Income $ 111.2 $ 114.0 $ 52.7
======================================================================================
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services $ 61.1 $ 56.8 $ 58.5
Electric Utility Services 42.6 40.0 38.7
Other Operations 14.2 13.9 20.7
- --------------------------------------------------------------------------------------
Total Utility Group 117.9 110.7 117.9
- --------------------------------------------------------------------------------------
Nonregulated Group 10.5 8.6 5.9
Corporate & Other Group 0.3 0.3 0.3
- --------------------------------------------------------------------------------------
Consolidated Depreciation & Amortization $ 128.7 $ 119.6 $ 124.1
======================================================================================
Interest Expense
Utility Group
Regulated Operations $ 62.0 $ 63.7 $ 68.2
Other Operations 4.1 5.4 2.5
- --------------------------------------------------------------------------------------
Total Utility Group 66.1 69.1 70.7
- --------------------------------------------------------------------------------------
Nonregulated Group 9.7 9.1 12.5
Corporate & Other Group (0.2) 0.3 -
- --------------------------------------------------------------------------------------
Consolidated Interest Expense $ 75.6 $ 78.5 $ 83.2
======================================================================================
Equity in Earnings of Unconsolidated Affiliates
Utility Group: Other Operations $ (0.5) $ (1.8) $ (0.5)
Nonregulated Group 12.7 10.9 13.9
- --------------------------------------------------------------------------------------
Consolidated Equity in Earnings of
Unconsolidated Affiliates $ 12.2 $ 9.1 $ 13.4
======================================================================================
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -----------------------------------------------------------------------------
Income Taxes
Utility Group
Gas Utility Services $ 19.5 $ 18.2 $ (2.2)
Electric Utility Services 29.8 27.5 21.1
Other Operations 2.3 1.1 2.4
- -----------------------------------------------------------------------------
Total Utility Group 51.6 46.8 21.3
- -----------------------------------------------------------------------------
Nonregulated Group (13.2) (6.9) (4.7)
Corporate & Other Group (0.7) (1.0) (2.5)
- -----------------------------------------------------------------------------
Consolidated Income Taxes $ 37.7 $ 38.9 $ 14.1
=============================================================================
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002
- ------------------------------------------------------------------------------
Assets
Utility Group
Gas Utility Services $ 1,805.0 $ 1,728.4
Electric Utility Services 974.6 891.6
Other Operations 162.4 171.6
Eliminations (16.9) (11.2)
- ------------------------------------------------------------------------------
Total Utility Group 2,925.1 2,780.4
- ------------------------------------------------------------------------------
Nonregulated Group 454.0 418.2
Corporate & Other Group 287.5 385.7
Eliminations (313.2) (447.8)
- ------------------------------------------------------------------------------
Consolidated Assets $ 3,353.4 $ 3,136.5
==============================================================================
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Capital Expenditures
Utility Group
Gas Utility Services $ 95.0 $ 63.0 $ 77.8
Electric Utility Services 124.1 88.8 69.8
Other Operations 15.9 65.5 55.2
- --------------------------------------------------------------------------------
Total Utility Group 235.0 217.3 202.8
- --------------------------------------------------------------------------------
Nonregulated Group 13.2 28.0 35.0
Corporate & Other Group 2.3 2.2 17.2
Transfers of Assets (14.3) (28.8) (15.3)
- --------------------------------------------------------------------------------
Consolidated Capital Expenditures $ 236.2 $ 218.7 $ 239.7
================================================================================
Investments in Equity Method Investees
Utility Group: Other Operations $ - $ 0.3 $ 3.0
Nonregulated Group 16.6 12.2 19.7
- --------------------------------------------------------------------------------
Consolidated Investments in Equity
Method Investees $ 16.6 $ 12.5 $ 22.7
================================================================================
18. Special Charges for 2001
Restructuring & Related Charges
As part of continued cost saving efforts, in June 2001, the Company's management
and the board of directors approved a plan to restructure, primarily, its
regulated operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $19.0 million. These charges were comprised of $10.9 million for
employee severance, related benefits and other employee related costs, $4.0
million for lease termination fees related to duplicate facilities and other
facility costs, and $4.1 million for consulting and other fees.
The $10.9 million of severance and related costs includes $1.6 million of
deferred compensation payable at various times through 2016 and $0.8 million of
non-cash pension costs. The $4.0 million of lease termination fees includes $1.0
million of non-cash charges for impaired leasehold improvements. Restructuring
expenses were incurred by the Company's operating segments as follows: $10.3
million by the Gas Utility Services segment; $4.8 million by the Electric
Utility Services segment; and $3.9 million by the Nonregulated segment.
Employee severance and related costs are associated with approximately 100
employees. Employee separation benefits include severance, healthcare, and
outplacement services. During 2001, approximately 80 employees had exited the
business. The restructuring program was completed during 2001, except for the
departure of the remaining employees impacted by the restructuring which
occurred during 2002 and the final settlement of the lease obligation which has
yet to occur.
At the beginning of 2002, the remaining accrual related to the restructuring was
$5.1 million. Of that amount, $2.1 million remained accrued for severance,
almost all of which relates to deferred compensation arrangements, and $3.0
million remained for lease termination fees. During 2002, the accrual for
severance did not substantially change, and $1.0 million of lease costs were
paid. At December 31, 2002, the remaining restructuring accrual was $4.2 million
($2.2 million for severance and $2.0 million for lease costs). During 2003, $1.0
million was paid for severance, and the accrual for lease costs did not
substantially change. At December 31, 2003, the remaining restructuring accrual
was $3.2 million ($1.2 million for severance and $2.0 million for lease costs).
The restructuring accrual is included in Accrued liabilities.
Merger & Integration Costs
Merger and integration costs incurred for the year ended December 31, 2001,
totaled $2.8 million. Those costs related primarily to transaction costs,
severance, and other merger and acquisition integration activities. As a result
of merger integration activities, management retired certain information systems
in 2001. Accordingly, the useful lives of these assets were shortened in 2000 to
reflect this decision, resulting in additional depreciation expense of
approximately $9.6 million ($6.0 million after tax) for the year ended December
31, 2001. Merger and integration activities resulting from the 2000 merger were
completed in 2001.
19. Impact of Recently Issued Accounting Guidance
SFAS 132 (Revised 2003)
In December 2003, FASB issued SFAS No. 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits" (SFAS 132), to
improve financial statement disclosures for defined benefit plans. The change
replaces existing FASB disclosure requirements for pensions and postretirement
plans. The guidance is effective for fiscal years ending after December 15,
2003. The adoption did not impact the Company's results of operations or
financial condition. The incremental disclosure requirements are included in
these financial statements in Note 6. In addition to expanded annual
disclosures, SFAS 132, as revised, requires the reporting of various elements of
pension and other postretirement benefit costs on a quarterly basis.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
Company has approximately $200,000 of outstanding preferred stock of a
subsidiary that is redeemable on terms outside the Company's control. However,
the preferred stock is not redeemable on a specified or determinable date or
upon an event that is certain to occur. The adoption of SFAS 150 on January 1,
2004, did not affect the Company's results of operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition. The incremental disclosure
requirements are included in these financial statements in Note 12.
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004.
The Company has neither created nor obtained an interest in a VIE since January
31, 2003. Certain other entities that the Company was involved with prior to
that date, including limited partnership investments that operate affordable
housing projects, are still being evaluated to determine if the entity is a VIE
and, if so, if Vectren is the primary beneficiary. If these entities are
determined to be VIE's and Vectren is determined to be the primary beneficiary,
the effect to the Company's financial statements would not be material.
Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.
20. Quarterly Financial Data (Unaudited)
Quarterly operating revenues presented below have been adjusted to reflect the
adoption of EITF 03-11. See Note 15 to the consolidated financial statements for
further information on the adoption of EITF 03-11. Information in any one
quarterly period is not indicative of annual results due to the seasonal
variations common to the Company's utility operations. Summarized quarterly
financial data for 2003 and 2002 follows:
- -------------------------------------------------------------------------------
(In millions, except per share amounts) Q1 Q2 Q3 Q4
- -------------------------------------------------------------------------------
2003
Results of Operations:
Operating revenues $ 626.7 $ 268.4 $ 240.3 $ 452.3
Operating income 94.7 17.5 18.2 69.0
Net income 55.7 4.1 7.3 44.1
Per Share Data:
Earnings per share:
Basic $ 0.82 $ 0.06 $ 0.10 $ 0.59
Diluted 0.82 0.06 0.10 0.58
2002
Results of Operations:
Operating revenues $ 574.2 $ 298.0 $ 216.3 $ 435.3
Operating income 82.9 25.6 31.5 71.3
Net income 45.6 12.5 13.5 42.4
Per Share Data:
Earnings per share:
Basic $ 0.68 $ 0.18 $ 0.20 $ 0.63
Diluted 0.67 0.18 0.20 0.62
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9a. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2003, the Company carried out an evaluation under the
supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer of the effectiveness and the design and operation of the
Company's disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective at providing
reasonable assurance that material information relating to the Company required
to be disclosed by the Company in its filings under the Securities Exchange Act
of 1934 (Exchange Act) is brought to their attention on a timely basis.
Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-15(e) and 15d-15(e), are controls and other procedures of the Company that
are designed to ensure that information required to be disclosed by the Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC's rules and forms. "Disclosure controls and procedures" include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate, to allow timely decisions regarding required
disclosure.
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2003, there have been no significant
changes to the Company's internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, the
Company's internal control over financial reporting.
Internal control over financial reporting is defined by the SEC in Final Rule:
Management's Reports on Internal Control Over Financial Reporting and
Certification of Disclosure in Exchange Act Periodic Reports. The final rule
defines internal control over financial reporting as a process designed by, or
under the supervision of, the registrant's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
registrant's board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that: (1) pertain to the maintenance of records that in reasonable
detail accurately and fairly reflect the transactions and dispositions of the
assets of the registrant, (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the registrant are being made only in accordance with
authorizations of management and directors of the registrant, and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the registrant's assets that could have a
material effect on the financial statements.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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 2004 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
The information with respect to the executive officers of the Registrant is
included below:
Niel C. Ellerbrook, age 55, has been a director of Indiana Energy, Inc.
("Indiana Energy"), a predecessor to the Company, or the Company since 1991. Mr.
Ellerbrook has been Chairman of the Board and Chief Executive Officer of the
Company since March 31, 2000, and President of the Company since May 1, 2003.
Mr. Ellerbrook has also served as a Chairman and Chief Executive Officer of
Indiana Gas, SIGECO, and VUHI since March 31, 2000, and of VEDO since November
1, 2000. Prior to March 31, 2000, and since June 1999, Mr. Ellerbrook served as
President and Chief Executive Officer of Indiana Energy. Prior to that time, and
since October 1997, Mr. Ellerbrook served as President and Chief Operating
Officer of Indiana Energy. From January through October 1997, Mr. Ellerbrook
served as Executive Vice President, Treasurer and Chief Financial Officer of
Indiana Energy, and prior to that time and since 1986, Vice President,
Treasurer, and Chief Financial Officer. Mr. Ellerbrook is also the Chair and a
director of Vectren Capital and Vectren Enterprises and President, Chair and a
director of Vectren Foundation. He is also a director of Old National Bancorp.
Jerome A. Benkert, Jr., age 45, has served as Executive Vice President and Chief
Financial Officer of the Company since March 31, 2000, and as Treasurer of the
Company from October 2001 to March 31, 2002. Mr. Benkert has also served as a
director and Executive Vice President and Chief Financial Officer of Indiana
Gas, SIGECO and VUHI since March 31, 2000, and of VEDO since November 1, 2000.
Prior to March 31, 2000, and since October 1, 1997, he was Executive Vice
President and Chief Operating Officer of Indiana Energy's administrative
services company. Mr. Benkert has served as Controller and Vice President of
Indiana Gas. Mr. Benkert served as Assistant Treasurer for Indiana Gas from
January 1, 1991, to October 1, 1993. Mr. Benkert served as Chief Accountant,
Secretary/Treasurer and was a member of the board of directors of Richmond Gas
Corporation from February 1, 1986, to January 1, 1991. Mr. Benkert is also a
director and President of Vectren Capital and a director of Vectren Enterprises
and Vectren Foundation. He is also a director of Fifth Third Bank, Indiana
(Southern), Deaconess Hospital of Evansville, Indiana, and ProLiance.
Carl L. Chapman, age 48, was elected Executive Vice President of the Company and
President of Vectren Enterprises, Inc. on March 31, 2000. Prior to March 31,
2000, and since 1999, Mr. Chapman served as Executive Vice President and Chief
Financial Officer of Indiana Energy. From October 1, 1997, to June, 2002, Mr.
Chapman served as President of IGC Energy, Inc., which has been renamed Vectren
Energy Marketing and Services, Inc. ("VEMS"). Mr. Chapman served as President of
ProLiance Energy, LLC ("ProLiance"), a gas supply and energy marketing joint
venture partially owned by VEMS, an indirect, wholly owned subsidiary of the
Company, from March 15, 1996, until April 30, 1998. Currently, Mr. Chapman is
the Chair and a director of ProLiance. From 1995 until March 15, 1996, he was
Senior Vice President of Corporate Development for Indiana Gas. Prior to 1995
and since 1987, he was Vice President of Planning for Indiana Gas. Mr. Chapman
is also a director and President of Vectren Enterprises and a director of
Vectren Capital and Vectren Foundation.
Ronald E. Christian, age 45, was elected Executive Vice President, General
Counsel and Secretary of the Company on May 1, 2003. Prior to May 1, 2003, and
since March 31, 2000, Mr. Christian served as Senior Vice President, General
Counsel and Secretary of the Company. Mr. Christian has also served as a
director and Executive Vice President and Secretary of Indiana Gas, SIGECO, and
VUHI, and VEDO since May 1, 2003. Prior to March 31, 2000, and since 1999, he
was Vice President and General Counsel of Indiana Energy, Inc. From July of 1998
to July of 1999, Mr. Christian served as Vice President, General Counsel and
Secretary of Michigan Consolidated Gas Company. Mr. Christian served as General
Counsel and Secretary of Indiana Energy, Inc. from 1993 to 1998. Prior to 1993
and since 1988, Mr. Christian was employed as counsel for the Company. Mr.
Christian is also a director and Executive Vice President and General Counsel,
and Secretary of Vectren Enterprises and a director and Vice President,
Secretary and Assistant Treasurer of Vectren Capital and Vectren Foundation. Mr.
Christian is a director of ProLiance.
William S. Doty, age 52, was elected Executive Vice President of Utility
Operations on May 1, 2003. Prior to May 1, 2003, and since April 2001, Mr. Doty
served as Senior Vice President-Energy Delivery of the Company. Mr. Doty has
also served as a director and President of Indiana Gas, SIGECO, and VUHI and as
a director and Executive Vice President of VEDO since May 1, 2003. Mr. Doty
served as Senior Vice President of Customer Relationship Management of the
Company from January 2001 to April 2001. From January 1999 to January 2001, Mr.
Doty was Vice President of Energy Delivery for SIGECO and previous to January
1999, he was Director of Gas Operations for SIGECO.
Richard G. Lynch, age 52, was elected Senior Vice President-Human Resources and
Administration of the Company on March 31, 2000. Mr. Lynch has also served as
Senior Vice President-Human Resources and Administration of Indiana Gas, SIGECO,
VUHI, and Vectren Enterprises since March 31, 2000, and of VEDO since November
1, 2000. Mr. Lynch served as 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.
The Company's Corporate Governance Guidelines, its charters for each of its
Audit, Compensation and Nominating and Corporate Governance Committees, and its
Code of Ethics covering the Company's directors, officers and employees are
available on the Company's website, www.vectren.com, and a copy will be mailed
upon request to Investor Relations, Attention: Steve Schein, 20 N.W. Fourth
Street, Evansville, Indiana 47708. The Company intends to disclose any
amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of
the Company's directors or officers including, but not limited to, the principal
executive officer, principal financial officer, principal accounting officer or
controller and persons performing similar functions on the Company's website at
the Internet address set forth above promptly following the date of such
amendment or waiver and such information will also be available by mail upon
request to Investor Relations, Attention: Steve Schein, 20 N.W. Fourth Street,
Evansville, Indiana 47708.
ITEM 11. EXECUTIVE COMPENSATION
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 2004 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, within
120 days after the end of the fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Except with respect to equity compensation plan information of the Registrant,
the information required by Part III, Item 12 of this Form 10-K is incorporated
by reference herein, and made part of this Form 10-K, from the company's
definitive Proxy Statement for its 2004 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission pursuant to Regulation
14A, within 120 days after the end of the fiscal year.
The information with respect to common shares issuable under equity compensation
plans as of December 31, 2003, with respect to the Registrant is included below:
- --------------------------------------------------------------------------------------------------
(a) (b) (c)
- --------------------------------------------------------------------------------------------------
Number of Weighted Number of securities
securities to be average remaining available
issued upon exercise price for future issuance
exercise of of outstanding under equity
outstanding options, compensation plans
options, warrants warrants (excluding securities
Plan category and rights and rights reflected in column (a)
- --------------------------------------------------------------------------------------------------
Equity compensation plans approved by
security holders (1) 2,021,896 (2) $ 22.37 2,901,780 (3)
- --------------------------------------------------------------------------------------------------
Equity compensation plans not approved
by security holders - - -
- --------------------------------------------------------------------------------------------------
Total 2,021,896 $ 22.37 2,901,780
==================================================================================================
(1) Includes the following Vectren Corporation Plans: Vectren Corporation
At-Risk Compensation Plan, 1994 SIGCORP Stock Option Plan, Vectren
Corporation Executive Restricted Stock Plan, and Vectren Corporation
Directors Restricted Stock Plan.
(2) Includes a stock option grant of 219,000 options approved by the board of
directors' Compensation Committee, effective January 1, 2004.
(3) Includes shares available for issuance under the Vectren Corporation
At-Risk Compensation Plan (2,218,964), of which up to 800,000 shares may be
issued in restricted stock, 1994 SIGCORP Stock Option Plan (374,249),
Vectren Corporation Executive Restricted Stock Plan (273,338), and Vectren
Corporation Directors Restricted Stock Plan (48,229). Shares available for
issuance under the At Risk Plan have been reduced by the issuance of
133,500 restricted shares approved by the board of directors' Compensation
Committee, effective January 1, 2004.
The SIGCORP stock option plan was approved by SIGCORP common shareholders prior
to the merger forming Vectren, and both the directors and executive restricted
stock plans were approved by Indiana Energy common shareholders prior to the
merger forming Vectren. The At-Risk Compensation plan was approved by Vectren
Corporation common shareholders after the merger forming Vectren.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Part III, Item 13 of this Form 10-K is incorporated by
reference herein, and made part of this Form 10-K, from the Company's definitive
Proxy Statement for its 2004 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, within
120 days after the end of the fiscal year.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Part III, Item 14 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 2004 Annual Meeting of Stockholders, which will be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, within
120 days after the end of the fiscal year.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
List Of Documents Filed As Part Of This Report
Consolidated Financial Statements
The consolidated financial statements and related notes, together with the
report of Deloitte & Touche LLP, appear in Part II "Item 8 Financial Statements
and Supplementary Data" of this Form 10-K.
Supplemental Schedules
For the years ended December 31, 2003, 2002, and 2001, the Company's Schedule II
- -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is presented on page 94. The report of Deloitte & Touche LLP on the schedule may
be found in Item 8.
All other schedules are omitted as the required information is inapplicable or
the information is presented in the Consolidated Financial Statements or related
notes in Item 8.
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified
below pursuant to Rule 12b-32 under the Exchange Act.
Exhibits for the Company are listed in the Index to Exhibits beginning on
page 97.
Exhibits for the Company attached to this filing filed electronically with
the SEC are listed on page 101.
Reports On Form 8-K During The Last Calendar Quarter
On October 22, 2003, Vectren Corporation filed a Current Report on Form 8-K with
respect to the release of financial information to the investment community
regarding the Company's results of operations, financial position and cash flows
for the three, nine, and twelve month periods ended September 30, 2003. The
financial information was released to the public through this filing.
Item 7. Exhibits
99-1 - Press Release - Vectren Corporation Reports Third
Quarter 2003 Results
99-2 - Cautionary Statement for Purposes of the "Safe
Harbor" Provisions of the Private Securities Litigation
Reform Act of 1995
Item 12. Results of Operations and Financial Condition
On December 11, 2003, 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 9. Regulation FD Disclosure
Index to Exhibits
99-1 - Press Release - Vectren Corporation Provides 2004
Earnings Guidance
99- 2 - Cautionary Statement for Purposes of the "Safe
Harbor" Provisions of the Private Securities Litigation
Reform Act of 1995
SCHEDULE II
Vectren Corporation and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
- ---------------------------------------------------------------------------------------------------
Additions
------------------
Balance at Charged Charged Deductions Balance at
Beginning to to Other from End of
Description Of Year Expenses Accounts Reserves, Net Year
- ---------------------------------------------------------------------------------------------------
(In millions)
VALUATION AND QUALIFYING
ACCOUNTS: AS RESTATED
Year 2003 - Accumulated provision for
uncollectible accounts $ 5.5 $ 12.8 $ - $ 15.1 $ 3.2
Year 2002 - Accumulated provision for
uncollectible accounts $ 5.3 $ 11.7 $ - $ 11.5 $ 5.5
Year 2001 - Accumulated provision for
uncollectible accounts $ 5.1 $ 17.3 $ - $ 17.1 $ 5.3
OTHER RESERVES:
Year 2003 - Reserve for restructuring
costs $ 4.2 $ - $ - $ 1.0 $ 3.2
Year 2002 - Reserve for restructuring
costs $ 5.1 $ - $ - $ 0.9 $ 4.2
Year 2001 - Reserve for restructuring
costs $ - $ 11.9 $ - $ 6.8 $ 5.1
Year 2002 - Reserve for merger and
integration charges $ 0.4 $ - $ - $ 0.4 $ -
Year 2001 - Reserve for merger and
integration charges $ 1.8 $ - $ - $ 1.4 $ 0.4
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 February 25, 2004
/s/ Niel C. Ellerbrook
------------------------------
Niel C. Ellerbrook,
Chairman, President, Chief Executive
Officer, and Director
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in capacities and on the dates indicated.
Signature Title Date
Chairman, President, Chief
/s/ Niel C. Ellerbrook Executive Officer, & February 25, 2004
- -------------------------- Director (Principal Executive -----------------
Niel C. Ellerbrook Officer)
/s/ Jerome A. Benkert, Jr. Executive Vice President & February 25, 2004
- -------------------------- Chief Financial Officer -----------------
Jerome A. Benkert, Jr. (Principal Financial Officer)
/s/ M. Susan Hardwick Vice President & Controller February 25, 2004
- -------------------------- (Principal Accounting Officer) -----------------
M. Susan Hardwick
/s/ John M. Dunn Director February 25, 2004
- -------------------------- -----------------
John M. Dunn
/s/ John D. Engelbrecht Director February 25, 2004
- -------------------------- -----------------
John D. Engelbrecht
/s/ Lawrence A. Ferger Director February 25, 2004
- -------------------------- -----------------
Lawrence A. Ferger
/s/ Anton H. George Director February 25, 2004
- -------------------------- -----------------
Anton H. George
/s/ Robert L. Koch II Director February 25, 2004
- -------------------------- -----------------
Robert L. Koch II
/s/ William G. Mays Director February 25, 2004
- -------------------------- -----------------
William G. Mays
/s/ J. Timothy McGinley Director February 25, 2004
- -------------------------- -----------------
J. Timothy McGinley
/s/ Richard P. Rechter Director February 25, 2004
- -------------------------- -----------------
Richard P. Rechter
/s/ Ronald G. Reherman Director February 25, 2004
- -------------------------- -----------------
Ronald G. Reherman
/s/ R. Daniel Sadlier Director February 25, 2004
- -------------------------- -----------------
R. Daniel Sadlier
/s/ Richard W. Shymanski Director February 25, 2004
- --------------------------- -----------------
Richard W. Shymanski
/s/ Jean L.Wojtowicz Director February 25, 2004
- -------------------------- -----------------
Jean L.Wojtowicz
INDEX TO EXHIBITS
2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1 Asset Purchase Agreement dated December 14, 1999 between Indiana Energy,
Inc. and The Dayton Power and Light Company and Number-3CHK with a
commitment letter for a 364-Day Credit Facility dated December 16,1999.
(Filed and designated in Current Report on Form 8-K dated December 28,
1999, File No. 1-9091, as Exhibit 2 and 99.1.)
3. Articles of Incorporation and By-Laws
3.1 Amended and Restated Articles of Incorporation of Vectren Corporation
effective March 31, 2000. (Filed and designated in Current Report on Form
8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
3.2 Amended and Restated Code of By-Laws of Vectren Corporation as of October
29, 2003. (Filed and designated in Quarterly Report on Form 10-Q filed
November 13, 2003, File No. 1-15467, as Exhibit 3.1.)
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 Indenture dated October 19, 2001, among Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated October 19, 2001,
File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated
October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed
and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio,
Inc., and U.S. Bank Trust National Association. (Filed and designated in
Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit 4.1) .
4.2 Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust
National Association (formerly know as First Trust National Association,
which was formerly know as Bank of America Illinois, which was formerly
know as Continental Bank, National Association. Inc.'s. (Filed and
designated in Current Report on Form 8-K filed February 15, 1991, File No.
1-6494.); First Supplemental Indenture thereto dated as of February 15,
1991. (Filed and designated in Current Report on Form 8-K filed February
15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture
thereto dated as of September 15, 1991, (Filed and designated in Current
Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit
4(b).); Third supplemental Indenture thereto dated as of September 15, 1991
(Filed and designated in Current Report on Form 8-K filed September 25,
1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture
thereto dated as of December 2, 1992, (Filed and designated in Current
Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit
4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000,
(Filed and designated in Current Report on Form 8-K filed December 27,
2000, File No. 1-6494, as Exhibit 4.)
4.3 Indenture dated October 19, 2001, between Vectren Utility Holdings, Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated October 19, 2001,
File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated
October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed
and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as
Exhibit 4.2); Second Supplemental Indenture, between Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1).
10. Material Contracts
10.1 Summary description of Southern Indiana Gas and Electric Company's
nonqualified Supplemental Retirement Plan (Filed and designated in Form
10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First
Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for
the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).
10.2 Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and
designated in Southern Indiana Gas and Electric Company's Proxy Statement
dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.3 Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select
Group of Management Employees as amended and restated effective December 1,
1998. (Filed and designated in Form 10-Q for the quarterly period ended
December 31, 1998, File No. 1-9091, as Exhibit 10-G.)
10.4 Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective
January 1, 1999. (Filed and designated in Form 10-Q for the quarterly
period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.)
10.5 Indiana Energy, Inc. Executive Restricted Stock Plan as amended and
restated effective October 1, 1998. (Filed and designated in Form 10-K for
the fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit
10-O.) First Amendment, effective December 1, 1998 (Filed and designated in
Form 10-Q for the quarterly period ended December 31, 1998, File No.
1-9091, as Exhibit 10-I.).
10.6 Indiana Energy, Inc. Director's Restricted Stock Plan as amended and
restated effective May 1, 1997. (Filed and designated in Form 10-Q for the
quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit 10-B.)
First Amendment, effective December 1, 1998. (Filed and designated in Form
10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as
Exhibit 10-J.) Second Amendment, Plan renamed the Vectren Corporation
Directors Restricted Stock Plan effective October 1, 2000. (Filed and
designated in Form 10-K for the year ended December 31, 2000, File No.
1-15467, as Exhibit 10-34.) Third Amendment, effective March 28, 2001.
(Filed and designated in Form 10-K for the year ended December 31, 2000,
File No. 1-15467, as Exhibit 10-35.)
10.7 Vectren Corporation At Risk Compensation Plan effective May 1, 2001. (Filed
and designated in Vectren Corporation's Proxy Statement dated March 16,
2001, File No. 1-15467, as Appendix B.)
10.8 Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended
and restated effective January 1, 2001. (Filed and designated in Form 10-K,
for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)
10.9 Vectren Corporation Employment Agreement between Vectren Corporation and
Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in
Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
as Exhibit 99.1.)
10.10 Vectren Corporation Employment Agreement between Vectren Corporation and
Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in
Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
as Exhibit 99.3.)
10.11 Vectren Corporation Employment Agreement between Vectren Corporation and
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.)
10.12 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.)
10.13 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.)
10.14 Vectren Corporation Employment Agreement between Vectren Corporation and
William S. Doty dated as of April 30, 2001. (Filed and designated in Form
10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.43.)
10.15 Gas Sales and Portfolio Administration Agreement between Indiana Gas
Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed
herewith)
10.16 Gas Sales and Portfolio Administration Agreement between Southern Indiana
Gas and Electric Company and ProLiance Energy, LLC, effective September 1,
2002. (Filed herewith.)
10.17 Gas Sales and Portfolio Administration Agreement between Vectren Energy
Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000.
(Filed and designated in Form 10-K, for the year ended December 31, 2001,
File No. 1-15467, as Exhibit 10-24.)
10.18 Coal Supply Agreement for F.B. Culley Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December
17, 1997 and effective January 1, 1998. (Filed herewith.)
10.19 Amendment 1, effective January 1, 2003, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally
dated December 17, 1997. (Filed herewith.)
10.20 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick
County, Indiana, and West Franklin, Posey County, Indiana between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19,
2000. (Filed herewith.)
10.21 Amendment 1, effective January 1, 2004, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally
dated January 19, 2000. (Filed herewith.)
10.22 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated October 1,
2003. (Filed herewith.)
10.23 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January 1,
2004. (Filed herewith.)
10.24 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.)
Vectren Corporation
2003 Form 10-K
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
See Page 97 of this Annual Report on Form 10-K for a complete list of exhibits.
Exhibit
Number Document
10.15 Gas Sales and Portfolio Administration Agreement between Indiana Gas
Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003.
10.16 Gas Sales and Portfolio Administration Agreement between Southern Indiana
Gas and Electric Company and ProLiance Energy, LLC, effective September 1,
2002.
10.18 Coal Supply Agreement for F.B. Culley Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December
17, 1997 and effective January 1, 1998.
10.19 Amendment 1, effective January 1, 2003, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally
dated December 17, 1997.
10.20 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick
County, Indiana, and West Franklin, Posey County, Indiana between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19,
2000.
10.21 Amendment 1, effective January 1, 2004, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally
dated January 19, 2000.
10.22 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January 1,
2004.
10.23 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January 1,
2004.
21.1 List of Company's significant subsidiaries
23.1 Consent of Independent Public Accountants
31.1 Chief Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Chief Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.