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, 2004
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
-----------------------------
(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of (IRS Employer Identification No.)
or organization)
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, 2004, was $1,891,955,967.
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 76,082,316 January 31, 2005
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Class Number of Shares Date
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2005
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 / thousands of
megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of PUCO: Public Utilities Commission of Ohio
Environmental Management
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF/MMCF/BCF: thousands/millions/ USEPA: United States Environmental
billions of 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 .........................................................1
2 Properties .......................................................7
3 Legal Proceedings.................................................8
4 Submission of Matters to Vote of Security Holders.................8
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities................9
6 Selected Financial Data..........................................10
7 Management's Discussion and Analysis of Results of Operations and
Financial Condition..............................................11
7A Qualitative and Quantitative Disclosures About Market Risk.......34
8 Financial Statements and Supplementary Data......................36
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................75
9A Controls and Procedures, including management's assessment of
internal controls over financial reporting.......................75
9B Other Information.......................................... .....75
Part III
10 Directors and Executive Officers of the Registrant...............75
11 Executive Compensation...........................................76
12 Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters..................................76
13 Certain Relationships and Related Transactions...................77
14 Principal Accountant Fees and Services...........................77
Part IV
15 Exhibits and Financial Statement Schedules.......................77
Signatures.......................................................82
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 47702-0209 Vice President,
Investor Relations
sschein@vectren.com
PART I
ITEM 1. BUSINESS
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company organized on June 10, 1999, to effect the merger of Indiana
Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000,
Indiana Energy merged with SIGCORP and into Vectren. The transaction involved a
tax-free exchange of shares that was accounted for as a pooling-of-interests.
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for 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. VUHI's consolidated operations are collectively referred to as the
Utility Group. 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 energy delivery services to approximately 555,000 natural
gas customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 136,000 electric customers and approximately
110,000 natural gas customers located near Evansville in southwestern Indiana.
SIGECO also owns and operates electric generation to serve its electric
customers and optimizes those assets in the wholesale power market. Indiana Gas
and SIGECO generally do business as Vectren Energy Delivery of Indiana.
The Ohio operations provide energy delivery services to approximately 315,000
natural gas customers located near Dayton in west central Ohio. The Ohio
operations are 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). The Ohio operations were acquired from The Dayton Power and Light
Company on October 31, 2000. The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets and supplies
natural gas and provides energy management services, including energy
performance contracting services. Coal Mining mines and sells coal and generates
IRS Code Section 29 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 has investments 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, there are other businesses
that invest in energy-related opportunities, real estate, and leveraged leases,
among other activities. These operations are collectively referred to as the
Nonregulated Group. 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.
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. Prior to the
merger, 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. Prior to the merger, SIGCORP
had eleven wholly owned subsidiaries, including ten nonregulated subsidiaries.
Narrative Description of the Business
The Company segregates its operations into three groups: a Utility Group, a
Nonregulated Group, and Corporate and Other. At December 31, 2004, the Company
had $3.6 billion in total assets, with $3.1 billion (86%) attributed to the
Utility Group, $0.5 billion (14%) attributed to the Nonregulated Group, and less
than $0.1 billion attributed to Corporate and Other. Net income for the year
ended December 31, 2004, was $107.9 million, or $1.43 per share of common stock,
with $83.1 million attributed to the Utility Group, $26.4 million attributed to
the Nonregulated Group, and a net loss of $1.6 million attributed to Corporate
and Other. Net income for the year ended December 31, 2003, was $111.2 million,
or $1.58 per share of common stock. For further information regarding the
activities and assets of operating segments within these Groups, refer to Note
16 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. Corporate and Other operations 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 and other operations that
provide information technology and other support services to those regulated
operations. The Company segregates its regulated operations into a Gas Utility
Services operating segment and an Electric Utility Services operating segment.
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 electric distribution services primarily to southwestern Indiana,
and includes the Company's power generating and marketing operations. In total,
these regulated operations supply natural gas and/or electricity to nearly one
million customers. The Utility Group's other operations are generally not
significant.
Gas Utility Services
At December 31, 2004, the Company supplied natural gas service to approximately
980,000 Indiana and Ohio customers, including 895,000 residential, 81,000
commercial, and 4,000 contract and other customers. This represents customer
base growth of 1.2% compared to 2003.
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(R)) 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, 2004, gas utility revenues were approximately
$1,126.2 million, of which residential customers accounted for 66%, commercial
25%, and contract and other 9%, respectively.
The Company receives gas revenues by selling gas directly to customers at
approved rates or by transporting gas through its pipelines at approved rates to
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 200,343 MDth for the year ended December 31, 2004.
Gas transported or sold to residential and commercial customers was 110,666 MDth
representing 55% of throughput. Gas transported or sold to industrial and other
contract customers was 89,677 MDth representing 45% 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) 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). Periodically, purchased natural gas is injected
into storage. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. In addition, the
Company prepays ProLiance for natural gas delivery services during the seven
months prior to the peak heating season. The volume of gas per day that can be
delivered during peak demand periods for each utility is located in "Item 2
Properties."
Gas Purchases
In 2004, the Company purchased 112,372 MDth volumes of gas at an average cost of
$6.92 per Dth, all of which was purchased from ProLiance pursuant to contracts
approved by the IURC. The average cost of gas per Dth purchased for the last
five years was: $6.92 in 2004; $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; and
$5.60 in 2000.
Electric Utility Services
At December 31, 2004, the Company supplied electric service to approximately
136,000 Indiana customers, including 119,000 residential, and 17,000 commercial,
industrial, and other customers. This represents customer base growth of 0.9%
compared to 2003. 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(R)) 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, 2004, retail and firm wholesale electricity
sales totaled 6,186,160 MWh, resulting in revenues of approximately $347.5
million. Residential customers accounted for 34% of 2004 revenues; commercial
27%; industrial 31%; and municipal and other 8%. In addition, the Company sold
3,526,005 MWh through wholesale contracts in 2004, generating revenue, net of
purchased power costs, of $23.8 million.
Generating Capacity
Installed generating capacity as of December 31, 2004, 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.
Peaking capacity of 80 MW fueled by natural gas was added during 2002.
In addition to its generating capacity, in 2004, the Company had 32 MW available
under firm contracts and 51 MW available under interruptible contracts. The
Company also had a firm purchase supply contract for a maximum of 73 MW for the
peak cooling season months during 2004.
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. The
Company, as a member of the Midwest Independent System Operator (MISO), has
turned over operational control of 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 2000 through 2004 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
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Date of summer peak load 7/13/2004 8/27/2003 8/5/2002 7/31/2001 8/17/2000
---------- --------- --------- --------- ---------
Total load at peak (1) 1,222 1,272 1,258 1,234 1,212
Generating capability 1,351 1,351 1,351 1,271 1,256
Firm purchase supply 105 32 82 82 75
Interruptible contracts 51 95 95 95 95
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Total power supply capacity 1,507 1,478 1,528 1,448 1,426
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Reserve margin at peak 23% 16% 21% 17% 18%
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(1) The total load at peak is increased 25 MW in 2003, 2002, and 2001 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 2004 and
2000, summer cycler programs were not activated.
The winter peak load for the 2003-2004 season of approximately 928 MW occurred
on January 20, 2004. The prior year winter peak load was approximately 948 MW,
occurring on January 27, 2003.
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 2004 was fueled by coal (95.6%) and natural gas (4.4%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.0 million tons of coal were purchased
for generating electricity during 2004, 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 2000 through
2004 follows:
-------------------------------------------------------------------------------
Year Ended December 31,
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Avg. Cost Per 2004 2003 2002 2001 2000
------- -------- ------- ------- --------
Ton $ 27.06 $ 24.91 $ 23.50 $ 22.48 $ 22.49
MWh 13.06 11.93 11.00 10.53 10.39
The Company also purchases 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
2004 totaled 3,469,610 MWh.
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. At
December 31, 2004, approximately 73,000 customers in Vectren's Ohio service
territory purchase natural gas from a supplier other than the regulated utility.
Margin earned for transporting natural gas to those customers, who have
purchased natural gas from another supplier, are generally the same as those
earned by selling gas under Ohio tariffs. 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.
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 other
environmental matters.
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 in three areas: gas marketing, performance contracting, and
retail gas supply.
Gas Marketing
Gas marketing operations are performed through the Company's investment in
ProLiance, a nonregulated energy marketing affiliate of Vectren and Citizens
Gas. ProLiance's primary businesses include gas marketing, gas portfolio
optimization, and other portfolio and energy management services. ProLiance
provides these services to a broad range of municipalities, utilities,
industrial operations, schools, and healthcare institutions located throughout
the Midwest and Southeast United States. ProLiance's primary customers include
Vectren's utilities and nonregulated gas supply operations as well as Citizens
Gas. The Company, including its retail gas supply operations, contracted for all
natural gas purchases through ProLiance in 2004.
In 2002, the Company integrated a wholly owned subsidiary, SIGCORP Energy
Services, LLC (SES), with ProLiance. SES provided natural gas and related
services to SIGECO and others prior to the transaction. 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. 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.
For the year ended December 31, 2004, ProLiance's revenues, including sales to
Vectren companies, exceeded $2.5 billion.
Performance Contracting
Performance-based energy contracting operations are performed through Energy
Systems Group, LLC (ESG). ESG assists schools, hospitals, governmental
facilities, and other private institutions to reduce energy and maintenance
costs by upgrading their facilities with energy-efficient equipment. ESG's
customer base is located throughout the Midwest and Southeast United States.
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.
Retail Gas Supply
Vectren Retail, LLC (d/b/a Vectren Source) provides natural gas and other
related products and services in the Midwest and Southeast United States to over
100,000 residential and commercial customers opting for choice among energy
providers. Vectren Source generated approximately $81.1 million in revenues in
2004, up from $44.3 million in 2003. Gas sold in 2004 approximated 9,386 MDth.
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 investment in Pace Carbon is
accounted for using the equity method of accounting. The Company's two coal
mines produced 3.6 million tons in 2004, up from 3.3 million in 2003.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water, 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
The Company has an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom) that if converted would
bring the Company's ownership interest up to 16%. 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, such as cable television, high-speed internet, and advanced local and
long distance phone services, to the greater Evansville, Indiana area. At
December 31, 2004, SIGECOM had approximately 26,000 residential customers
yielding over 81,000 revenue generating units indicating multiple services being
utilized by the same residential customer. At December 31, 2004, there were
approximately 2,000 commercial customers. SIGECOM's operations are cash flow
positive and have not required any further investment since May 2002.
Other Utilicom-related subsidiaries owned franchising agreements to provide
broadband services to the greater Indianapolis, Indiana and Dayton, Ohio
markets. In 2004, the build out of these markets was further evaluated, and the
Company concluded that it was unlikely it would make additional investments in
those markets. As a result, the Company recorded charges totaling $6.0 million,
or $3.6 million after-tax, to write-off investments made in the Indianapolis and
Dayton markets and to write down its investment in SIGECOM.
At December 31, 2004, convertible subordinated debt investments total $31.6
million, all of which is convertible into Utilicom ownership at the Company's
option or upon the event of a public offering of stock by Utilicom. The
remaining equity investment in SIGECOM, LLC approximates $11.7 million.
Other Businesses
The Other Businesses group includes a variety of wholly owned operations and
investments that invest in energy-related opportunities, real estate, and
leveraged leases, among other investments. Major investments at December 31,
2004, include Haddington Energy Partnerships, two partnerships both
approximately 40% owned; and the wholly owned subsidiaries, Southern Indiana
Properties, Inc. and Energy Realty, Inc.
Personnel
As of December 31, 2004, the Company and its consolidated subsidiaries had 1,863
employees, of which 872 are subject to collective bargaining arrangements.
In July of 2004, the Company signed a three year labor agreement with Local 702
of the International Brotherhood of Electrical Workers, ending June 2007. The
agreement provides a 3% wage increase in the first two years and a 3.5% increase
in the third year of the agreement. The agreement also provides for improvements
in pension benefits and a multi-tiered health plan in which the employees pay
16% of the cost.
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.
The Company's contract with Local 135 of the Teamsters, Chauffeurs,
Warehousemen, and Helpers will expire in September 2005. The Company's contract
with Local 175, Utility Workers Union of America will expire in October 2005.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana
covering 58,130 acres of land with an estimated ready delivery from storage
capability of 5.6 BCF of gas with maximum peak day delivery capabilities of
144,500 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 17.8 BCF of storage
with a maximum peak day delivery capability of 299,717 MMBTU per day. Indiana
Gas' gas delivery system includes 12,150 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
108,000 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 19,166 MMBTU per day. SIGECO's gas delivery system
includes 3,074 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 13.4 BCF of storage with a maximum peak day delivery capability
of 287,684 MMBTU per day. The Ohio operations' gas delivery system includes
5,301 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, 2004, 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 an 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 28 substations with an
installed capacity of 4,635.9 megavolt amperes (Mva). The electric distribution
system includes 3,223 pole miles of lower voltage overhead lines and 302 trench
miles of conduit containing 1,688 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,630 distribution transformers with an installed
capacity of 2,388.8 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% 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. See the notes to the consolidated financial statements
regarding investments in unconsolidated affiliates, commitments and
contingencies, environmental matters, and rate and regulatory matters. The
consolidated financial statements are included in "Item 8 Financial Statements
and Supplementary Data."
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
Market Data, Dividends Paid, and Holders of Record
The Company's common stock trades on the New York Stock Exchange under the
symbol "VVC." For each quarter in 2004 and 2003, 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.
- --------------------------------------------------------------------------------
Cash Common Stock Price Range
Dividend High Low
------------- ------------ ------------
2004
First Quarter $ 0.285 $ 25.87 $ 24.11
Second Quarter 0.285 25.54 22.86
Third Quarter 0.285 25.75 24.08
Fourth Quarter 0.295 27.09 24.79
2003
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
On January 26, 2005, the board of directors declared a dividend of $0.295 per
share, payable on March 1, 2005, to common shareholders of record on February
15, 2005.
As of January 31, 2005, there were 12,635 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.
Quarterly Share Purchases
Periodically, the Company purchases shares from the open market to satisfy share
requirements associated with the Company's share-based compensation plans. The
following chart contains information regarding open market purchases made by the
Company to satisfy share-based compensation requirements during the three months
ended December 31, 2004.
- --------------------------------------------------------------------------------
Total Number
of Shares Maximum Number
Average Purchased of Shares
Number of Price as Part of That May Be
Shares Paid Per Publicly Purchased Under
Period Purchased Share Announced Plans These Plans
- -------------- ------------ --------- --------------- ---------------
October 1-31 1,365 $ 26.53 - -
November 1-30 - - - -
December 1-31 - - - -
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.
- -----------------------------------------------------------------------------------------------------
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------
(In millions, except per share data) 2004 2003 2002 2001 (1) 2000 (2,3)
- -----------------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $ 1,689.8 $ 1,587.7 $ 1,523.8 $ 2,009.1 $ 1,607.6
Operating income $ 202.7 $ 199.4 $ 211.3 $ 127.9 $ 131.7
Income before extraordinary loss &
cumulative effect of change in
accounting principle $ 107.9 $ 111.2 $ 114.0 $ 59.3 $ 72.0
Net income $ 107.9 $ 111.2 $ 114.0 $ 52.7 $ 72.0
Average common shares outstanding 75.6 70.6 67.6 66.7 61.3
Fully diluted common shares outstanding 75.9 70.8 67.9 66.9 61.4
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.43 $ 1.58 $ 1.69 $ 0.89 $ 1.18
Basic earnings per share
on common stock $ 1.43 $ 1.58 $ 1.69 $ 0.79 $ 1.18
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.42 $ 1.57 $ 1.68 $ 0.89 $ 1.17
Diluted earnings per share
on common stock $ 1.42 $ 1.57 $ 1.68 $ 0.79 $ 1.17
Dividends per share on common stock $ 1.15 $ 1.11 $ 1.07 $ 1.03 $ 0.98
Balance Sheet Data:
Total assets $ 3,586.9 $ 3,353.4 $ 3,136.5 $ 2,878.7 $ 2,943.7
Long-term debt, net $ 1,016.6 $ 1,072.8 $ 954.2 $ 1,014.0 $ 632.0
Redeemable preferred stock $ 0.1 $ 0.2 $ 0.3 $ 0.5 $ 8.1
Common shareholders' equity $ 1,094.8 $ 1,071.7 $ 869.9 $ 839.3 $ 733.4
(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) 2004 2003 2002
- --------------------------------------------------------------------------------
Net income $ 107.9 $ 111.2 $ 114.0
Attributed to:
Utility Group $ 83.1 $ 85.6 $ 97.1
Nonregulated Group 26.4 27.6 19.0
Corporate & other (1.6) (2.0) (2.1)
- --------------------------------------------------------------------------------
Basic earnings per share $ 1.43 $ 1.58 $ 1.69
Attributed to:
Utility Group $ 1.10 $ 1.21 $ 1.44
Nonregulated Group 0.35 0.39 0.28
Corporate & other (0.02) (0.02) (0.03)
Results
For the year ended December 31, 2004, reported earnings were $107.9 million, or
$1.43 per share compared to $111.2 million, or $1.58 per share, in 2003 and
$114.0 million, or $1.69 in 2002. The Company experienced significant earnings
growth from its Energy Marketing and Services, Coal Mining, and Utility
Infrastructure Services nonregulated businesses during 2004 and 2003. Earnings
from utility operations were slightly lower in 2004 due largely to mild weather
in 2004, offset somewhat by customer growth and the effects of gas base rate
increases at two of the three utilities. Mild weather also impacted 2003 results
compared to 2002, along with the write off of an investment.
While earnings have slightly decreased, earnings per share was further affected
by an equity offering of 7.4 million shares in August of 2003. The additional
shares diluted earnings per share in 2004 as compared to 2003 by $0.10 and in
2003 as compared to 2002 by $0.07. The equity offering netted proceeds of
approximately $163 million.
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 Indiana and Ohio service
territories 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, 2004, were $1.15 per share
compared to $1.11 per share in 2003 and $1.07 per share in 2002. In October
2004, the Company's board of directors increased its quarterly dividend to
$0.295 per share from $0.285 per share.
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. Corporate and Other operations 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 and other operations that
provide information technology and other support services to those regulated
operations. The Company segregates its regulated operations into a Gas Utility
Services operating segment and an Electric Utility Services operating segment.
The Gas Utility Services segment provides natural gas distribution and
transportation services to nearly two-thirds of Indiana and to west central
Ohio. The Electric Utility Services segment provides electric distribution
services primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. In total, these regulated operations supply
natural gas and/or electricity to nearly one million customers. The results of
operations of the Utility Group before certain intersegment eliminations and
reclassifications for the years ended December 31, 2004, 2003, and 2002, follow:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions, except per share data) 2004 2003 2002
- --------------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $1,126.2 $1,112.3 $ 908.0
Electric utility 371.3 335.7 328.6
Other 0.5 0.8 0.3
- --------------------------------------------------------------------------------
Total operating revenues 1,498.0 1,448.8 1,236.9
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 778.5 762.5 570.8
Fuel for electric generation 96.1 86.5 81.6
Purchased electric energy 20.7 16.2 16.8
Other operating 218.5 210.1 198.6
Depreciation & amortization 127.8 117.9 110.7
Taxes other than income taxes 58.2 56.6 50.7
- --------------------------------------------------------------------------------
Total operating expenses 1,299.8 1,249.8 1,029.2
- --------------------------------------------------------------------------------
OPERATING INCOME 198.2 199.0 207.7
OTHER INCOME (EXPENSE)
Other - net 5.2 4.8 7.1
Equity in earnings (losses) of
unconsolidated affiliates 0.2 (0.5) (1.8)
- --------------------------------------------------------------------------------
Total other income 5.4 4.3 5.3
- --------------------------------------------------------------------------------
Interest expense 67.4 66.1 69.1
- --------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 136.2 137.2 143.9
- --------------------------------------------------------------------------------
Income taxes 53.1 51.6 46.8
- --------------------------------------------------------------------------------
NET INCOME $ 83.1 $ 85.6 $ 97.1
================================================================================
- --------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 1.10 $ 1.21 $ 1.44
================================================================================
In 2004, Utility Group earnings were $83.1 million as compared to $85.6 million
in 2003. The 2004 earnings decline is due to the impact of unfavorable weather,
estimated at $5 million after tax, or $0.07 per share. Margin growth, offsetting
the weather impact, results from the recovery of NOx related environmental
expenditures, gas base rate increases implemented in 2004, and customer growth.
The primary expense changes were higher depreciation and lower bad debt expense
in 2003. Bad debt expense in 2003 associated with the Ohio service territory was
reversed and deferred for later recovery under an uncollectible accounts expense
rider.
The $11.5 million decrease in earnings occurring in 2003 compared to 2002 was
primarily due to increased operating expenses and the write-off of an
investment, partially offset by increased wholesale power margins and retail
electric rate recovery related to NOx compliance expenditures. An increase in
the Indiana state income tax rate to 8.5% from 4.5% also contributed to the
decrease.
During 2004 and 2003, the Company initiated base rate cases in its three gas
service territories. Orders in its two Indiana service territories were received
in the second half of 2004. An order in the Ohio territory is expected late in
the first quarter of 2005. On an annual basis, the Indiana orders will increase
margins an estimated $30 million, and during 2004 provided additional margin of
$4.7 million. The Company has sought and received regulatory recovery mechanisms
(trackers) affecting electric margin that provide a return on utility plant
constructed for environmental compliance and that allow for recovery of related
operating expenses. After tax earnings associated with the NOx compliance
trackers totaled $9.0 million in 2004, $4.7 million in 2003 and $1.1 million in
2002. The Company has also utilized regulatory trackers affecting gas margin
that recover, on a dollar-for-dollar basis, pipeline integrity management costs
in its Indiana territories and uncollectible accounts expense, operating
expenses related to choice implementation costs, and other costs in its Ohio
service territory.
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. 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, and Taxes other than income taxes, 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 the
Company's service territories. Margin generated from sales to large customers
(generally industrial, other contract, and firm wholesale customers) is
primarily impacted by overall economic conditions. Margin is also impacted by
the collection of state mandated taxes, which fluctuate with gas costs, and is
also impacted by some level of price sensitivity 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) 2004 2003 2002
- --------------------------------------------------------------------------------
Residential & Commercial $ 288.3 $ 292.3 $ 282.6
Contract 53.5 51.5 50.5
Other 5.9 6.0 4.1
- --------------------------------------------------------------------------------
Total gas utility margin $ 347.7 $ 349.8 $ 337.2
================================================================================
Sold & transported volumes in MMDth:
To residential & commercial customers 110.7 117.9 111.9
To contract customers 89.7 91.4 95.8
- --------------------------------------------------------------------------------
Total throughput 200.4 209.3 207.7
================================================================================
Gas utility margins were $347.7 million for the year ended December 31, 2004.
This represents a decrease in gas utility margin of $2.1 million compared to
2003. Heating weather for the year ended December 31, 2004, was 8% warmer than
normal and 8% warmer than the prior year. The estimated unfavorable impact on
gas utility margin caused by weather was approximately $9.8 million compared to
2003. Indiana base rate increases added $4.7 million compared to the prior year.
Also offsetting the effects of weather were increased late and reconnect fees,
expense recovery pursuant to Ohio regulatory trackers, and higher revenue taxes
collected from rate payers. Gas sold and transported volumes were 4% less in
2004, compared to the prior year. The decreased throughput was primarily
attributable to weather. The average cost per dekatherm of gas purchased was
$6.92 in 2004; $6.36 in 2003, and $4.57 in 2002.
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 compared to 2002. The remaining increase is
primarily attributable to $4.5 million in higher revenue taxes on higher gas
costs and volumes sold and $1.8 million in recovery of Ohio customer choice
implementation costs.
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) 2004 2003 2002
- --------------------------------------------------------------------------------
Residential & commercial $ 159.7 $ 141.1 $ 145.7
Industrial 62.4 53.5 54.9
Municipalities & other 17.4 20.1 16.9
- --------------------------------------------------------------------------------
Total retail & firm wholesale 239.5 214.7 217.5
Asset optimization 15.0 18.3 12.7
- --------------------------------------------------------------------------------
Total electric utility margin $ 254.5 $ 233.0 $ 230.2
================================================================================
Retail & Firm Wholesale Margin
Native load and firm wholesale margin was $239.5 million for the year ended
December 31, 2004. This represents a $24.8 million increase over 2003.
Additional NOx recoveries increased margin $14.6 million in 2004. Cooling
weather for the year was 12% warmer than last year, increasing margin an
estimated $2.0 million. The remaining increase in margin was attributable to
increased small customer usage and increased sales to industrial customers. Due
to the above factors, volumes sold increased 5% to 6.19 GWh for 2004, compared
to 5.90 GWh in 2003. Volumes sold in 2002 were 6.19 GWh.
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 2002, caused an $8 million decrease in residential and commercial
margin. The effect of weather was partially offset by a $7.4 million increase in
retail electric rates related to recovery of and return on 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 of primarily mild weather and slow economic
conditions, retail and firm wholesale volumes sold decreased 5%.
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 the
margin from these activities is generated from contracts that 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) 2004 2003 2002
- --------------------------------------------------------------------------------
Beginning of Year Net Asset
Optimization Position $ (0.4) $ (0.7) $ 3.3
Statement of Income Activity
Mark-to-market gains (losses)
recognized (1.4) 0.7 (3.6)
Realized gains recognized 16.4 17.6 16.3
- --------------------------------------------------------------------------------
Net activity in electric
utility margin 15.0 18.3 12.7
- --------------------------------------------------------------------------------
Net cash received & other adjustments (15.2) (18.0) (16.7)
- --------------------------------------------------------------------------------
End of Year Net Asset Optimization
Position $ (0.6) $ (0.4) $ (0.7)
================================================================================
Net wholesale margins decreased $3.3 million compared to 2003 due to reduced
available capacity. The availability of excess capacity was impacted by
scheduled outages of owned generation, related to the installation of
environmental compliance equipment and an increase in demand by native load
customers due to both weather and increased usage. The $5.6 million increase in
2003 compared to 2002 was primarily due to price volatility and additional
capacity due to weather.
Utility Group Operating Expenses
Other Operating
Other operating expenses increased $8.4 million for the year ended December 31,
2004 as compared to 2003. Expense in 2003 reflects the deferral of $4.0 million
relating to the Ohio order allowing the Company to defer for future recovery its
actual bad debt expense in excess of the amount provided in base rates (See Rate
and Regulatory Matters below). Other factors contributing to the increase were
an increase in NOx-related expenses of $2.6 million recovered in rates and
planned turbine maintenance of $1.9 million.
Other operating expense increased $11.5 million in 2003 compared to 2002. The
increase was 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, which resulted in the reversal and deferral
of 2003 uncollectible accounts expense of $4.0 million for future recovery.
Depreciation & Amortization
For the year ended December 31, 2004, depreciation expense increased $9.9
million compared to 2003. NOx-related depreciation contributed $4.8 million of
the increase with the remaining increase due primarily to normal additions to
utility plant. The increase of $7.2 million in 2003 compared to 2002 is also due
to normal additions to utility plant. In addition to the NOx scrubbers placed
into service in 2004, other significant expenditures included upgrades of
electric facilities subjected to storm damage, construction of a new substation,
and a new transmission main. Upgrades implemented in 2002 and 2003 now included
in annual depreciation expense include 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.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1.6 million in 2004 compared to 2003
and $5.9 million in 2003 compared to 2002. Almost all of the 2004 increase and
$4.5 million of the 2003 increase corresponds with increased collections of
utility receipts and excise taxes due to higher revenues. The remaining 2003
increase results principally from higher property taxes.
Utility Group Other Income (Expense)
Total other income (expense)-net increased $1.1 million during 2004 compared to
2003 and decreased $1.0 million during 2003 compared to 2002. Lower amounts of
AFUDC were recorded in 2004 as NOx expenditures were placed in service. Fiscal
year 2003 includes operating losses and the write-off of investments in an
entity that processes fly ash, totaling $4.2 million. In 2002, the Company
recognized losses associated with those investments totaling $1.5 million.
Utility Group Interest Expense
In the second half of 2003, the Company completed permanent financing
transactions 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. The changes in interest expense in 2004 and 2003
reflect the full impact of that transaction.
Utility Group Income Taxes
For the year ended December 31, 2004, income taxes were relatively consistent
with 2003 with decreased earnings offset by a slightly higher effective rate. An
increase in the Indiana state income tax rate from 4.5% to 8.5% was the primary
reason for increased tax expense in 2003 compared to 2002.
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 Company has taken steps to comply with Indiana's State Implementation Plan
(SIP) of the Clean Air Act (the Act). 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 nitrogen oxide (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% return on
its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances, 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
construction cost is consistent with amounts approved in the IURC's orders.
Through December 31, 2004, $238 million has been expended, and three of the four
SCR's are operational. Once all equipment is installed and operational, related
annual operating expenses, including depreciation expense, are estimated to be
between $24 million and $27 million. The Company is recovering the operational
costs associated with the SCR's and related technology. The 8% 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 has achieved timely compliance through the reduction of 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
During 2003, the U.S. District Court for the Southern District of Indiana
entered a consent decree among SIGECO, the Department of Justice (DOJ), and the
USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO.
The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley
Generating Station for (1) making modifications to generating station without
obtaining required permits, (2) making major modifications to the generating
station without installing the best available emission control technology, and
(3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all
challenges of past maintenance and repair activities at the Culley Generating
Station. 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 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 committed to
o either repower Culley Unit 1 (50 MW) with natural gas 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 notified the USEPA of its intention to shut down Culley Unit 1
effective December 31, 2006. The Company does not believe that implementation of
the settlement will have a material effect to its results from operations or
financial condition. The $600,000 civil penalty was expensed and paid during
2003 and is reflected in Other-net.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Clean Air 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, SIGECO, 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, SIGECO,
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 added those 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. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and any
necessary remediation costs that SIGECO may accrue under the VRP program. The
total investigative costs, and if necessary, costs of remediation at the four
SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot
be determined at this time.
Jacobsville Superfund Site
On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil
Contamination site in Evansville, Indiana, on the National Priorities List under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA). The USEPA has identified four sources of historic lead contamination.
These four sources shut down manufacturing operations years ago. When drawing up
the boundaries for the listing, the USEPA included a 250 acre block of
properties surrounding the Jacobsville neighborhood, including Vectren's Wagner
Operations Center. Vectren's property has not been named as a source of the lead
contamination, nor does the USEPA's soil testing to date indicate that the
Vectren property contains lead contaminated soils. Vectren's own soil testing,
completed during the construction of the Operations Center, did not indicate
that the Vectren property contains lead contaminated soils. At this time,
Vectren anticipates only additional soil testing, if required by the USEPA.
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. The net energy cost of purchased power, subject to an agreed upon
benchmark, is also recovered through regulatory proceedings. 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 margin. 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.
SIGECO and Indiana Gas Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for
SIGECO's gas distribution business, and on November 30, 2004, approved a $24
million base rate increase for Indiana Gas' gas distribution business. The new
rate designs include a larger service charge, which is intended to address to
some extent earnings volatility related to weather. The base rate change in
SIGECO's service territory was implemented on July 1, 2004, resulting in
additional 2004 revenues of $2.5 million. The base rate change in Indiana Gas'
service territory was implemented on December 1, 2004, resulting in additional
2004 revenues of $2.2 million.
The orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the federal Pipeline Safety Improvement Act of 2002. The Pipeline
Safety Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these
annual caps are to be deferred for future recovery.
VEDO Pending Base Rate Increase Settlement
On February 4, 2005, the Company filed with the PUCO a settlement agreement that
had been entered into with several parties, including the PUCO staff, in its
base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the
settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its
base rates and charges for its gas distribution business serving more than
315,000 customers located in west central Ohio. The settlement provides for a
$15.7 million increase in VEDO's base distribution rates to cover the ongoing
costs of operating, maintaining, and expanding the approximately 5,200-mile
distribution system. The settlement increase includes $1.1 million of funding
for weatherization and conservation programs for low income customers.
Evidentiary hearings were completed in the case on February 9, 2005. Review and
approval by the PUCO is necessary before the settlement is effective. The
proposed new rate design includes a larger service charge, which will address,
to some extent, earnings volatility related to weather. The settlement also
permits VEDO the annual recovery of on-going costs associated with the Pipeline
Safety Improvement Act of 2002. Based upon the PUCO's actions in other
proceedings, the Company would expect an order near the end of the first quarter
of 2005.
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 reversed and deferred that amount for future recovery. In 2004, the
Company recorded revenues of $3.3 million which is equal to the level of
uncollectible accounts expense recognized for Ohio residential customers.
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, a two-year audit period ended in November 2002.
That audit period provided the PUCO staff its initial review of the portfolio
administration arrangement between VEDO and ProLiance. The external auditor
retained by the PUCO staff submitted an audit report in the fall of 2003 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. A hearing has been held, and the PUCO
staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor
has recommended 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 recorded $1.1 million for its estimated share of a potential
disallowance. A PUCO decision on this matter is yet to be issued. The Company is
also unable to determine the effects that a PUCO decision for the audit period
ended in November 2002 may have on results in audit periods beginning after
November 2002.
Other Operating Matters
MISO
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. Pursuant to
an order from the IURC, certain MISO costs have been deferred for future
recovery.
During 2004, SIGECO together with three other Indiana electric utilities filed a
proceeding with the IURC seeking to recover the anticipated costs associated
with MISO's implementation of the "Day 2 energy market" on April 1, 2005. A
hearing considering this request occurred in February, 2005.
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 has been, and may continue to be, impacted. Given the nature of
MISO's policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around the "Day 2 energy market" operations,
it is difficult to predict near term operational impacts. However, as stated
above, it is believed that MISO's regional operation of the transmission system
will ultimately lead to reliability improvements.
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.
United States Securities and Exchange Commission Inquiry into PUCHA Exemption
In July 2004, the Company received a letter from the SEC regarding its exempt
status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter
asserts that Vectren's out of state electric power sales exceed the amount
previously determined by the SEC to be acceptable in order to qualify for the
exemption. There is pending a request by Vectren for an order of exemption under
Section 3(a)(1) of PUHCA. Vectren also claims the benefit of the exemption
pursuant to Rule 2 under Section 3(a)(1) of PUHCA by filing an annual statement
on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an
amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed
the method of aggregating wholesale power sales and purchases outside of Indiana
from that previously reported. The new method is to aggregate by delivery point.
The amendment also submitted clarifications as to activity outside of Indiana
related to gas utility operations.
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 and supplies 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 has investments 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
invest in energy-related opportunities, real estate, and leveraged leases, among
other activities. 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. Corporate
expenses are allocated to each business area. The results of operations of the
Nonregulated Group for the years ended December 31, 2004, 2003, and 2002,
follow:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions, except per share amounts) 2004 2003 2002
- --------------------------------------------------------------------------------
NET INCOME $ 26.4 $ 27.6 $ 19.0
================================================================================
- --------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 0.35 $ 0.39 $ 0.28
================================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 16.6 $ 15.3 $ 12.1
Coal Mining 12.5 13.0 11.5
Utility Infrastructure 1.8 (0.9) (1.2)
Broadband (3.2) (1.1) 0.3
Other Businesses (1.3) 1.3 (3.7)
Nonregulated earnings for the year ended December 31, 2004, were $26.4 million
compared to $27.6 million in 2003 and $19.0 million in 2002. The Company's three
core nonregulated businesses, Energy Marketing and Services, Coal Mining, and
Utility Infrastructure Services, contributed $30.9 million in 2004, compared to
$27.4 million in 2003 and $22.4 million in 2002. The 2004 results reflect $6.0
million in after tax charges related to the write-down of the Company's
broadband businesses. Those charges were partially offset by net gains from the
Company's investment in Haddington Energy Partners. Earnings in 2003 reflect
after tax gains from the divesture of businesses and investments totaling $2.6
million after tax.
Energy Marketing & Services
Energy Marketing and Services is comprised of the Company's gas marketing
operations, performance contracting operations, and retail gas supply
operations.
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's primary
businesses include gas marketing, gas portfolio optimization, and other
portfolio and energy management services. ProLiance's primary customers include
Vectren's utilities and nonregulated gas supply operations as well as Citizen's
Gas and other large end-use customers. As part of a settlement agreement
approved by the IURC during July 2002, the gas supply agreements with Indiana
Gas and SIGECO, were approved and extended through March 31, 2007. The utilities
may decide to conduct a "request for proposal" (RFP) for a new supply
administrator, or they may decide to make an alternative proposal for
procurement of gas supply. That decision will be made by December 2005. To the
extent an RFP is conducted, ProLiance has the opportunity, if it so elects, to
participate in the RFP process for service to the utilities after March 31,
2007.
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
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. 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 throughout the Midwest. ESG acquired Progress Energy Solutions during
2004, expanding its operations throughout the Southeast and Mid-Atlantic United
States. 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.
Vectren Retail, LLC (d/b/a Vectren Source) provides natural gas and other
related products and services in Ohio and Indiana, serving just over 100,000
customers opting for choice among energy providers. In 2004, Vectren Source was
certified by the Georgia Public Service Commission and has begun initial
marketing efforts in the Atlanta Gas Light Company service territory.
Net income generated by Energy Marketing and Services for the year ended
December 31, 2004, was $16.6 million compared to $15.3 million in 2003 and $12.1
million in 2002. Throughout the periods presented, gas marketing operations,
performed through ProLiance, provided the primary earnings contribution,
totaling $15.4 million in 2004 and in 2003 and $14.6 million in 2002. While
earnings remained relatively consistent in 2004 compared to 2003, ProLiance
experienced increased earnings primarily related to asset optimization from
storage activities as a result of significant price volatility. However, those
increases were offset by the reserve established for the contingency described
below. The 2003 increase over 2002 was principally attributable to increased
storage capacity coupled with more volatile gas prices.
Earnings growth has also been impacted by Vectren Source's operations. Vectren
Source, a start up operation, operated at a planned loss of $0.4 million, in
2004, as compared to a loss of $1.9 million in 2003 and $2.6 million in 2002.
Vectren Source has expanded its customer base and has increased margins per unit
of throughput.
Earnings from performance contracting operations, performed through ESG,
contributed earnings of $2.8 million in 2004 nearly matching last year's
contribution of $3.0 million. Earnings in 2002 were $0.7 million. The $2.3
million increase in 2003 compared to 2002 is due primarily to 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
In 2002, a lawsuit was filed 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 asserted claims based on alleged breach of contract with respect to
provision of portfolio services and/or pricing advice, fraud, fraudulent
inducement, and other theories, including conversion and violations under
Racketeering, Influenced and Corrupt Organizations Act (RICO). These claims
related generally to: (1) alleged breach of contract 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 other
management, and; (4) the sale of Huntsville Utilities' gas storage supplies to
repay the balance owed on the winter levelizing program and the alleged lack of
authority of Huntsville Utilities' gas manager to approve those sales.
In early 2005, a jury trial was commenced and on February 10, 2005, the jury
returned a verdict largely in favor of Huntsville Utilities and awarded
Huntsville Utilities compensatory damages of $8.2 million and punitive damages
of $25.0 million. The jury rejected Huntsville Utilities' claim of conversion.
The jury also rejected ProLiance's counter claim for payment. The amounts due
from Huntsville Utilities were fully reserved by ProLiance in 2003. Huntsville
Utilities claims that all or a portion of the compensatory damages may be
subject to trebling under applicable Federal statutes. The court may also assess
attorney's fees and costs in favor of Huntsville Utilities. If the Court applies
trebling and awards attorney fees, the entire award could approach $55 million.
Several matters are still pending at the trial court, including efforts by
ProLiance to reduce the amount of the verdict. ProLiance will file post judgment
motions to reduce and to set aside the verdict. The court may issue its final
rulings on the verdict and related motions by April or May. Depending on the
outcome, ProLiance would appeal the judgment of the trial court. ProLiance
management believes that there are reasonable grounds to set aside or reduce the
verdict and reasonable grounds for appeal which offer a basis for reversal of
the entire verdict. While it is reasonably possible that a liability has been
incurred by ProLiance, it is not possible to predict the ultimate outcome of an
appeal of the verdict. ProLiance has recorded a reserve of $3.9 million as of
December 31, 2004, reflective of their assessment of the lower end of the range
of possible outcomes in the case and inclusive of estimated ongoing litigation
costs.
As an equity investor in ProLiance, the Company has reflected its share of the
charge, or $1.4 million after tax, in its 2004 results. It is not expected that
an unfavorable outcome on appeal will have a material adverse effect on the
Company's consolidated financial position or its liquidity, but an unfavorable
outcome could be material to the Company's earnings.
Coal Mining
The Coal Mining group mines and sells coal to the Company's utility operations
and to third parties through its wholly owned subsidiary Vectren Fuels, Inc.
(Fuels). The Coal Mining Group also generates IRS Code Section 29 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 its
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, 2004, was $12.5 million,
as compared to $13.0 million in 2003, and $11.5 million in 2002. Synfuel-related
results, which include earnings from Pace Carbon and synfuel processing fees
earned by Fuels, were $12.1 million in 2004, $13.3 million in 2003, and $8.5
million in 2002. The 2004 decrease reflects lower production of synthetic fuel
produced by Pace Carbon due to feedstock problems at one of their four plants.
The underperforming plant was relocated and began production in January 2005.
The 2003 increase is due to greater production of synthetic fuel by Pace Carbon.
The production of synthetic fuel generates Section 29 tax credits that are
utilized by the Company, reducing income tax expense in those years. Earnings
from Mining operations were $0.4 million in 2004 compared to a loss of $0.3
million in 2003 and earnings of $3.0 million in 2002. Increased earnings in 2004
were due primarily to improved production and market pricing which were
partially offset by weather conditions and increased commodity costs, such as
steel, explosives and diesel fuel. In 2003, mining operations experienced
decreased yields due to poor mining conditions and increased mine development
cost amortization compared to 2002.
IRS Section 29 Tax Credit Recent Developments
Under Section 29 of the Internal Revenue Code, manufacturers of synthetic fuel
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
Section 29 tax credits in its consolidated results through December 31, 2004, of
approximately $56.2 million. To date, Vectren has been in a position to fully
recognize the credits generated.
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. In May
2004, the IRS completed its audit of the 1998 to 2001 tax returns of Pace Carbon
requesting only minor modifications to previously filed returns. There were no
changes to any of the filed Section 29 tax credit calculations. The Permanent
Subcommittee on Investigations of the U.S. Senate's Committee on Governmental
Affairs, however, has an ongoing investigation related to Section 29 tax
credits.
Vectren believes it is justified in its reliance on the private letter rulings
and recent IRS audit results for the Pace Carbon facilities. Therefore, the
Company will continue to recognize Section 29 tax credits as they are earned
until there is either a change in the tax code or the IRS' interpretation of
that tax code.
Further, Section 29 tax credits are only available when the price of oil is less
than a base price specified by the tax code, as adjusted for inflation. The
Company does not believe that credits realized in 2004 and prior years will be
affected by the limitation, but an average annual price in excess of the mid $50
per barrel range, as priced at the wellhead, could limit Section 29 tax credits
in 2005 and beyond. In January 2005, the Company executed an insurance
arrangement that partially limits the Company's exposure if a limitation on the
availability of tax credits were to occur in 2005 and/or 2006 due to oil prices.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair to
gas, water, 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. Infrastructure's
operations achieved annual earnings in 2004 totaling $1.8 million, compared to a
loss of $0.9 million in 2003 and $1.2 million in 2002. The $2.7 million
improvement in 2004 was primarily driven by better pricing and increases in
utility and municipal waste water construction and repair spending during 2004,
along with productivity improvements. In the first half of 2003 and throughout
all 2002, results were 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 and Other Businesses
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%. 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, such
as cable television, high-speed internet, and advanced local and long distance
phone services, to over 28,000 customers, averaging over 3 revenue generating
units per customer, in the greater Evansville, Indiana. SIGECOM's operations are
cash flow positive and have not required any further investment since May 2002.
Other Utilicom-related subsidiaries also owned franchising agreements to provide
broadband services to the greater Indianapolis, Indiana and Dayton, Ohio
markets. In 2004, the build out of these markets was further evaluated, and the
Company concluded that it was unlikely it would make additional investments in
those markets. As a result, the Company recorded charges totaling $6.0 million,
or $3.6 million after-tax, to write-off investments made in the Indianapolis and
Dayton markets and to write down its investment in SIGECOM. The year ended
December 31, 2003, also includes a $1.2 million after tax loss resulting from
the sale of a small broadband operation located in Indianapolis.
The Other Businesses group includes a variety of wholly owned operations and
investments that invest in energy-related opportunities, real estate, and
leveraged leases, among other investments. For the year ended December 31, 2004,
the Other Businesses Group reported $1.3 million in losses, as compared to
earnings of $1.3 million in 2003 and losses of $3.7 million in 2002.
As part of the Company's decision to no longer expand its broadband-related
operations, the Company ceased operations of Vectren Communications Services,
Inc. (VCS), a municipal broadband consulting business, during the second quarter
of 2004. This decision resulted in losses of $2.4 million after tax due
primarily to inventory write downs, cessation charges, and other costs. VCS'
total loss for 2004 was $2.6 million, as compared to losses of $1.8 million in
2003 and $2.8 million in 2002.
The Haddington Energy Partnerships are equity method investments that invest in
energy-related ventures. During 2004, these partnerships sold their investments
in SAGO Energy, LP, (SAGO) for cash. The Company recognized its portion of the
after tax gain totaling $5.3 million. These earnings were partially offset by
Haddington's write-down of Nations Energy Holdings, of which Vectren's portion
was $3.5 million after tax. In total, earnings from Haddington for the year
ended December 31, 2004, are $2.0 million compared to a loss of $0.6 million in
2003, and break even results in 2002.
The Other Businesses group 2003 results include $3.8 million in after tax gains
from the sale of debt collection and supply chain management subsidiaries and
the sale of an investment in a company that provides real-time power plant and
transmission line status information.
In total, Broadband and Other Businesses reported combined charges of $6.0
million after tax in 2004 to write down its broadband-related investments. Net
increases in 2004 from Haddington's results of $2.6 million were comparable to
net gains recognized in 2003 from the sale of various subsidiaries and
investments.
Impact of Recently Issued Accounting Guidance
SFAS 123 (revised 2004)
In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based
Payments" (SFAS 123R) that will require compensation costs related to
share-based payment transactions to be recognized in the financial statements.
With limited exceptions, the amount of compensation cost will be measured based
on the grant-date fair value of the equity or liability instruments issued. In
addition, liability awards will be remeasured each reporting period.
Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. SFAS 123R replaces FASB Statement No. 123,
"Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25,
"Accounting for Stock Issued to Employees." The effective date of SFAS 123R for
the Company is July 1, 2005. SFAS 123R provides for multiple transition methods,
and the Company is still evaluating potential methods for adoption. The adoption
of this standard is not expected to have any material effect on the Company's
operating results or financial condition.
EITF 03-01
In March 2004, the EITF issued a consensus on Issue No. 03-01, "The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain Investments"
(EITF 03-01). In EITF 03-01, the Task Force developed a basic model for
evaluating whether investments within the scope of EITF 03-01, which includes
cost method and equity method investments, have other-than-temporary impairment.
The basic model includes three steps: 1) determine if there is impairment; 2) if
there is impairment, decide whether it is temporary or other than temporary; and
3) if it is other than temporary, recognize it in earnings. EITF 03-01 also
requires certain qualitative and quantitative disclosure of material impairments
judged to be temporary. The EITF has yet to finalize Steps 2 and 3. Step 1 and
the disclosure requirements are currently effective, and the adoption of those
portions of the EITF did not have a material effect on the Company.
As noted in the Broadband discussion above, the Company incurred an
other-than-temporary impairment charge associated with its cost method
investment in SIGECOM, LLC, during 2004. While the Company currently believes
that the book value of that investment approximates fair value, further changes
in estimated fair value may occur.
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 depreciating utility and non-utility plant, valuating of
derivative contracts, and estimating uncollectible 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 judgment
concerning growth assumptions, longevity of cash flows, and discount rates (for
fair value calculations).
During 2004, the Company performed an impairment analysis on its
Utilicom-related investments. The Company used free cash flow analyses to
estimate fair value for the cost method portion of the Utilicom investment and
recoverability of the related notes receivable. An impairment charge totaling
$6.0 million was recorded as a result of the analysis. A 10% increase in the
discount rate assumption utilized to calculate Utilicom's fair value would have
resulted in an estimated additional $2 million impairment charge to the cost
method investment and no additional impairment charge to the notes receivable.
Impairment tests on other investments were also conducted using appraisals and
discounted cash flow models to estimate fair value. No impairment charges
resulted from these analyses in 2002 and a $3.9 million write-off of investments
in an entity that processes fly ash 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 write-off.
Goodwill
Pursuant to SFAS No. 142, the Company performs an impairment analysis of its
goodwill, almost all of which resides in the Gas Utility Services operating
segment, annually, at the beginning of each year, and more frequently if events
or circumstances indicate that an impairment loss may have 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 16 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 2004, 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.
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 2004 periodic benefit cost: a
discount rate of 6.0%, an expected return on plan assets of 8.5%, a rate of
compensation increase of 3.5%, and a health care cost trend rate of 10% in 2004
declining to 5% in 2009. During 2004, the Company reduced the discount rate by
25 basis points to value 2004 ending pension and postretirement obligations due
to a decline in benchmark interest rates. In addition, the Company reduced its
2005 expected return on plan assets 25 basis points from that used to estimate
2004 expense due to lower investment returns and changes in the economic outlook
for equity returns. Pension and postretirement periodic cost has increased from
approximately $13 million in 2002 to over $16 million in 2004. Preliminary
estimates of 2005 periodic cost approximated $18 million. In January 2005, the
Company announced the amendment of certain postretirement benefit plans,
effective January 1, 2006. The amendment will result in an estimated $3 million
annual decrease in periodic cost, a portion of which will be recognized in 2005,
reducing those preliminary estimates. Two of the unions that represent
bargaining employees at the Company's regulated subsidiaries have advised the
Company that it is their position that these changes are not permitted under the
existing collective bargaining agreements which govern the relationship between
the employees and the affected subsidiaries. With assistance from legal counsel,
management has analyzed the unions' position and continues to believe that the
Company has reserved the right to amend the affected plans and that changing
these benefits for retirees is not a mandatory subject of bargaining. 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, 2004, 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 $0.6 million and would have
increased the postretirement liability by approximately $7.6 million. Management
estimates that a 50 basis point reduction in the expected return on plan assets
would have increased 2004 periodic benefit cost by approximately $0.8 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.
Financial Condition
Within Vectren's consolidated group, VUHI funds the 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, 2004, totaled
$113.0 million and $104.0 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, 2004, totaled $550.0 million and $308.0 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 primarily reinvested in
other nonregulated ventures, but are also used to fund a portion of the
Company's dividends, 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, 2004, 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. The ratings of Moody's and Standard and Poor's are categorized
as investment grade and are unchanged from December 31, 2003. Moody's current
outlook is stable. During January 2005, Standard and Poor's changed its current
outlook to stable from negative. 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
permanent 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 operations. The Company's equity
component was 51% and 49% of permanent capitalization at December 31, 2004, and
2003, respectively. Permanent capitalization includes long-term debt, including
current maturities and debt subject to tender, as well as common shareholders'
equity and any outstanding preferred stock.
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 and expected growth in nonregulated
operations, the Company may require additional permanent financing.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities increased $64.0 million during the year ended December 31, 2004,
compared to 2003 primarily as a result of favorable changes in working capital
accounts offset by decreased earnings before non-cash charges. The decreased
earnings before non-cash charges result principally from lower deferred tax
expense due to approximately $31.9 million in alternative minimum taxes
recognized in 2004, which has reduced deferred tax expense. Operating cash flow
in 2003 decreased $115.2 million compared to 2002. The primary reason for the
decrease was the negative effect of higher gas prices on working capital, 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 when accounts receivable balances are at their highest and gas storage is
refilled. Additionally, short-term borrowings are required for capital projects
and investments until they are permanently financed.
Cash flow required for financing activities of $18.3 million for the year ended
December 31, 2004, includes a net increase of short-term borrowings of $139.5
million and the net retirement of $38.3 million of long-term debt. 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 over the
periods presented due to the issuance of new securities and board authorized
increases in the dividend rate.
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.
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. During 2004, 2003, and 2002, debt totaling $2.5
million, $0.1 million, and $5.2 million, respectively, was put to the Company.
Debt that may be put to the Company within one year is classified as Long-term
debt subject to tender in current liabilities.
SIGECO and Indiana Gas Debt Call
During 2004, the Company called $20.0 million of insured quarterly senior
unsecured notes outstanding at Indiana Gas. The notes, originally due in 2015,
were called at par.
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.
Other Financing Transactions
During 2004, the Company remarketed two first mortgage bonds outstanding at
SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate
debt into variable rate debt where interest rates reset weekly. One bond, due in
2023, had a principal amount of $22.8 million and an interest rate of 6%. The
other bond, due in 2015, had a principal amount of $10.0 million and an interest
rate of 4.3%. These remarketing efforts resulted in the extinguishment and
reissuance of debt at generally the same par value.
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.
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.
Other Company debt totaling $15.0 million in 2004, $18.5 million in 2003, and
$6.5 million in 2002 was retired as scheduled.
Investing Cash Flow
Cash flow required for investing activities was $265.1 million in 2004, $232.7
million in 2003, and $234.6 million in 2002. Capital expenditures are the
primary component of investing activities. Capital expenditures were $277.9
million in 2004 compared to $236.2 million in 2003 and $218.7 million in 2002.
The increases are primarily driven by expenditures for environmental compliance.
In 2004 and 2003, the increase in capital expenditures was offset by collections
of notes receivable and distributions by unconsolidated affiliates.
Available Sources of Liquidity
At December, 31, 2004, the Company has $615 million of short-term borrowing
capacity, including $355 million for the Utility Group and $260 million for the
wholly owned Nonregulated Group and corporate operations, of which approximately
$47 million is available for the Utility Group operations and approximately $156
million is available for the wholly owned Nonregulated Group and corporate
operations.
VUHI's short-term credit facility was renewed on June 24, 2004 at $350 million,
a slight increase from the previous year's renewal level of $346 million.
Instead of the traditional 364-day facility, the facility was renewed for a
5-year period ending June 2009.
Vectren Capital renewed its existing $200 million credit facility early,
increased the committed capacity, and obtained a multi-year commitment on that
facility as well, rather than the traditional 364-day facility. On September 30,
2004 the new Vectren Capital credit facility was closed at the $255 million
level for a 5-year period ending September 2009.
The Company periodically issues new shares to satisfy dividend reinvestment plan
and stock option plan requirements. During 2004 and 2003, these new issuances
added additional liquidity of $4.5 million and $7.1 million, respectively.
Potential & Future Uses of Liquidity
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2004:
- -----------------------------------------------------------------------------------------------------
(In millions) 2005 2006 2007 2008 2009 Thereafter
- -----------------------------------------------------------------------------------------------------
Long-term debt (1) $ 38.5 $ - $24.0 $ - $ - $1,007.7
Short-term debt 412.4 - - - -
Commodity firm purchase commitments 152.1 1.4 - - - -
Utility & nonutility plant purchase
commitments(2) 20.5 - - - -
Operating leases 5.6 4.5 3.6 1.5 0.5 1.8
Unconsolidated affiliate
investments (2) (3) 5.5 - - - -
- -------------------------------------------------------------------------------------------------------
Total $634.6 $ 5.9 $27.6 $ 1.5 $0.5 $1,009.5
=======================================================================================================
(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 2004 (in millions) is $10.0 in 2005, zero in 2006, $20.0 in
2007, zero in 2008, $80.0 in 2009, and $40.0 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 2005 - 2009 are estimated
as follows:
- --------------------------------------------------------------------------------
(In millions) 2005 2006 2007 2008 2009
- --------------------------------------------------------------------------------
Capital expenditures
Utility Group $205.2 $219.4 $259.2 $251.9 $206.4
Nonregulated Group 17.8 20.8 18.7 35.5 22.2
- --------------------------------------------------------------------------------
Total capital expenditures $223.0 $240.2 $277.9 $287.4 $228.6
================================================================================
Investments in unconsolidated
affiliates $ 74.9 $ 44.6 $ 41.2 $ 11.1 $ 6.6
================================================================================
Off Balance Sheet Arrangements
Ratings Triggers
At December 31, 2004, $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 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, 2004, guarantees
issued and outstanding on behalf of unconsolidated affiliates approximated $5
million. In addition, the Company has also issued a guarantee approximating $4
million related to the residual value of an operating lease that expires in
2006. Through December 31, 2004, the Company has not been called upon to satisfy
any obligations pursuant to its guarantees.
Pension and Postretirement Funding Obligations
The Company believes making contributions to its qualified pension plans in the
coming years will be necessary. Management currently estimates that the
qualified pension plans will require Company contributions in the range of $5
million to $10 million in both 2005 and 2006. During 2004, $7.7 million in
contributions were made.
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, commodity prices, 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 credit ratings, 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.
The Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The committee is
actively involved in identifying risks as well as reviewing and authorizing risk
mitigation strategies.
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
strategies that manage the utilization of available electric generating
capacity. Execution of asset optimization strategies require 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.
Nonregulated gas retail operations will from time-to-time purchase weather
derivatives to mitigate extreme weather affecting unregulated retail gas sales,
and the Company may purchase other tailored products that mitigate unique risks
involving emission allowances and the effect oil prices may have on the
availability of Section 29 tax credits.
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, 2004,
and 2003, a 10% adverse change in forward commodity prices would have decreased
earnings by $0.7 million and $3.0 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
manages this risk by allowing 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, 2004, such
debt obligations, as affected by designated interest rate swaps and seasonal
increases in short-term debt outstanding, represented 34% 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 2004 and 2003, the weighted average combined
borrowings under these arrangements were $276.4 million and $316.1 million,
respectively. At December 31, 2004, and 2003, combined borrowings under these
arrangements were $500.2 million and $328.3 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2004 and 2003, an increase of 100 basis points (one percentage point) in the
rates would have increased interest expense by $2.8 million and $3.2 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 RESPONSBILITY FOR THE FINANCIAL STATEMENTS
Vectren Corporation's management is responsible for establishing and maintaining
adequate internal controls over financial reporting. Those control procedures
underlie the preparation of the consolidated balance sheets, statements of
income, cash flows, and common shareholders' equity, and related footnotes
contained herein.
These consolidated financial statements were 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 these consolidated financial statements, including
required estimates and judgments, is the responsibility of management.
These consolidated financial statements are also subject to an evaluation of
internal control over financial reporting conducted under the supervision and
with the participation of management, including the Chief Executive Officer and
Chief Financial Officer. Based on that evaluation, conducted under the framework
in Internal Control -- Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission, the Company concluded that
its internal control over financial reporting was effective as of December 31,
2004. Management certified this fact in its Sarbanes Oxley Section 302
certifications, which are attached as exhibits to this 2004 Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren
Corporation and subsidiaries (the "Company") as of December 31, 2004 and 2003,
and the related consolidated statements of income, common shareholders' equity,
and cash flows for each of the three years in the period ended December 31,
2004. Our audits also included the financial statement schedule listed in the
Index at Item 15. We also have audited management's assessment, included in the
accompanying Management's Report on Internal Control over Financial Reporting,
included at Item 9A, that the Company maintained effective internal control over
financial reporting as of December 31, 2004, based on criteria established in
Internal Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company's management is
responsible for these financial statements and financial statement schedule,
for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on these financial statements and
financial statement schedule, an opinion on management's assessment, and an
opinion on the effectiveness of the Company's internal control over financial
reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal
control over financial reporting was maintained in all material respects. Our
audit of financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our
opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company'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. A company's internal control over
financial reporting 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 company; (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 company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company as of
December 31, 2004 and 2003, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2004, in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, present fairly, in all material respects, the information set forth
therein. Also, in our opinion, management's assessment that the Company
maintained effective internal control over financial reporting as of December
31, 2004, is fairly stated, in all material respects, based on the criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Furthermore, in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2004, based on the criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission.
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 23, 2005
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
- --------------------------------------------------------------------------------
2004 2003
- --------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & cash equivalents $ 9.6 $ 15.3
Accounts receivable - less reserves
of $2.0 & $3.2, respectively 173.5 137.3
Accrued unbilled revenues 176.6 137.8
Inventories 67.6 70.4
Recoverable fuel & natural gas costs 17.7 20.3
Prepayments & other current assets 141.3 131.1
- --------------------------------------------------------------------------------
Total current assets 586.3 512.2
- --------------------------------------------------------------------------------
Utility Plant
Original cost 3,465.2 3,250.7
Less: accumulated depreciation
& amortization 1,309.0 1,247.0
- --------------------------------------------------------------------------------
Net utility plant 2,156.2 2,003.7
- --------------------------------------------------------------------------------
Investments in unconsolidated affiliates 180.0 176.1
Other investments 115.1 122.9
Non-utility property - net 229.2 222.3
Goodwill - net 207.1 205.0
Regulatory assets 82.5 89.6
Other assets 30.5 21.6
- --------------------------------------------------------------------------------
TOTAL ASSETS $ 3,586.9 $ 3,353.4
================================================================================
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,
- --------------------------------------------------------------------------------
2004 2003
- --------------------------------------------------------------------------------
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 123.8 $ 85.3
Accounts payable to affiliated companies 109.3 86.4
Accrued liabilities 132.1 109.3
Short-term borrowings 412.4 274.9
Current maturities of long-term debt 38.5 15.0
Long-term debt subject to tender 10.0 13.5
- --------------------------------------------------------------------------------
Total current liabilities 826.1 584.4
- --------------------------------------------------------------------------------
Long-term Debt - Net of Current Maturities &
Debt Subject to Tender 1,016.6 1,072.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes 234.0 235.4
Regulatory liabilities 251.7 235.0
Deferred credits & other liabilities 163.2 153.6
- --------------------------------------------------------------------------------
Total deferred credits & other liabilities 648.9 624.0
- --------------------------------------------------------------------------------
Minority Interest in Subsidiary 0.4 0.3
Commitments & Contingencies (Notes 3, 12-14)
Cumulative, Redeemable Preferred Stock of a Subsidiary 0.1 0.2
Common Shareholders' Equity
Common stock (no par value) - issued & outstanding
75.9 and 75.6, respectively 526.8 520.4
Retained earnings 583.0 562.4
Accumulated other comprehensive loss (15.0) (11.1)
- --------------------------------------------------------------------------------
Total common shareholders' equity 1,094.8 1,071.7
- --------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 3,586.9 $ 3,353.4
================================================================================
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,
- --------------------------------------------------------------------------------
2004 2003 2002
- --------------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $1,126.2 $ 1,112.3 $ 908.0
Electric utility 371.3 335.7 328.6
Energy services & other 192.3 139.7 287.2
- --------------------------------------------------------------------------------
Total operating revenues 1,689.8 1,587.7 1,523.8
- --------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 778.5 762.5 570.2
Fuel for electric generation 96.1 86.5 81.6
Purchased electric energy 20.7 16.2 16.8
Cost of energy services & other 143.5 103.7 249.4
Other operating 248.8 233.7 223.0
Depreciation & amortization 140.1 128.7 119.6
Taxes other than income taxes 59.4 57.0 51.9
- --------------------------------------------------------------------------------
Total operating expenses 1,487.1 1,388.3 1,312.5
- --------------------------------------------------------------------------------
OPERATING INCOME 202.7 199.4 211.3
OTHER INCOME
Equity in earnings of
unconsolidated affiliates 20.6 12.2 9.1
Other - net 1.4 13.0 11.5
- --------------------------------------------------------------------------------
Total other income 22.0 25.2 20.6
- --------------------------------------------------------------------------------
Interest expense 77.7 75.6 78.5
- --------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 147.0 149.0 153.4
- --------------------------------------------------------------------------------
Income taxes 39.0 37.7 38.9
Minority interest 0.1 0.1 0.5
- --------------------------------------------------------------------------------
NET INCOME $ 107.9 $ 111.2 $ 114.0
================================================================================
AVERAGE COMMON SHARES OUTSTANDING 75.6 70.6 67.6
DILUTED COMMON SHARES OUTSTANDING 75.9 70.8 67.9
EARNINGS PER SHARE OF COMMON STOCK:
BASIC $ 1.43 $ 1.58 $ 1.69
DILUTED $ 1.42 $ 1.57 $ 1.68
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,
- --------------------------------------------------------------------------------
2004 2003 2002
- --------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 107.9 $ 111.2 $ 114.0
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 140.1 128.7 119.6
Deferred income taxes & investment tax credits 5.9 35.1 (28.5)
Equity in earnings of unconsolidated affiliates (20.6) (12.2) (9.1)
Net unrealized (gain) loss on derivative
instruments 1.4 (0.7) 3.6
Pension & postretirement periodic benefit cost 16.4 13.8 13.2
Other non-cash charges - net 19.8 (0.1) 7.5
Changes in working capital accounts:
Accounts receivable & accrued unbilled
revenue (84.0) (16.1) (42.0)
Inventories 0.4 (7.6) 0.4
Recoverable fuel & natural gas costs 2.6 (1.0) 48.1
Prepayments & other current assets (10.2) (42.5) 31.2
Accounts payable, including to affiliated
companies 59.9 (16.4) 40.7
Accrued liabilities 19.9 (8.4) 11.7
Changes in noncurrent assets (3.5) (3.9) (6.0)
Changes in noncurrent liabilities (14.9) (2.8) (12.1)
- --------------------------------------------------------------------------------
Net cash flows from operating activities 241.1 177.1 292.3
- --------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Stock option exercises & other stock plans 4.5 7.1 1.3
Long-term debt - net of issuance costs 32.4 202.9 -
Common stock - net of issuance costs - 163.2 -
Requirements for:
Dividends on common stock (87.3) (79.2) (72.3)
Retirement of long-term debt (70.7) (121.9) (6.5)
Redemption of preferred stock of subsidiary (0.1) (0.1) (0.2)
Net change in short-term borrowings 139.5 (124.6) 20.3
Other activity - (1.6) (0.2)
- --------------------------------------------------------------------------------
Net cash flows from financing activities 18.3 45.8 (57.6)
- --------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Unconsolidated affiliate distributions 25.5 14.1 7.4
Notes receivable & other collections 9.3 14.4 3.9
Requirements for:
Capital expenditures, excluding AFUDC equity (277.9) (236.2) (218.7)
Unconsolidated affiliate investments (18.2) (16.6) (12.5)
Notes receivable & other investments (3.8) (8.4) (14.7)
- --------------------------------------------------------------------------------
Net cash flows from investing activities (265.1) (232.7) (234.6)
- --------------------------------------------------------------------------------
Net (decrease) increase in cash & cash equivalents (5.7) (9.8) 0.1
Cash & cash equivalents at beginning of period 15.3 25.1 25.0
- --------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 9.6 $ 15.3 $ 25.1
================================================================================
- --------------------------------------------------------------------------------
Cash paid during the year for:
Interest $ 75.3 $ 70.9 $ 67.1
Income taxes 26.6 33.9 16.5
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, 2002 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
======================================================================================================
Comprehensive income:
Net income 107.9 107.9
Minimum pension liability adjustments &
other - net of tax (0.1) (0.1)
Comprehensive income of unconsolidated
affiliates - net of tax (3.8) (3.8)
- ------------------------------------------------------------------------------------------------------
Total comprehensive income 104.0
- ------------------------------------------------------------------------------------------------------
Common stock:
Stock option exercises & other
stock plans 0.2 4.5 4.5
Dividends ($1.15 per share) (87.3) (87.3)
Other 0.1 3.8 (1.9) 1.9
- ------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 75.9 $ 531.2 $ (4.4) $ 583.0 $(15.0) $ 1,094.8
======================================================================================================
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
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc.
(VUHI), serves as the intermediate holding company for three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and
Electric Company (SIGECO), and the Ohio operations. VUHI also has other assets
that provide information technology and other services to the three utilities.
VUHI's consolidated operations are collectively referred to as the Utility
Group. 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 energy delivery services to approximately 555,000 natural
gas customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 136 ,000 electric customers and approximately
110,000 gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers and
optimizes those assets in the wholesale power market. Indiana Gas and SIGECO
generally do business as Vectren Energy Delivery of Indiana. The Ohio operations
provide energy delivery services to approximately 315,000 natural gas customers
located near Dayton in west central Ohio. The Ohio operations are 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). The Ohio
operations generally do business as Vectren Energy Delivery of Ohio.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal and generates IRS Code Section 29 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 has investments 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, there are other businesses that invest in energy-related
opportunities, real estate, and leveraged leases, among other activities. These
operations are collectively referred to as the Nonregulated Group. 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.
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46) and in December 2003, the FASB codified
modifications and other decisions previously issued through certain FASB Staff
Positions related to FIN 46 into one document that was issued as a revision to
the original Interpretation (FIN 46R). FIN 46R addresses consolidation by
business enterprises of variable interest entities. The Company adopted the
provisions within FIN 46R during 2004. The Company has investments in
partnership-like structures as a limited partner or as a subordinated lender.
The activities of these entities are to purchase or construct as well as operate
multifamily housing and office properties. The Company's exposure to loss is
limited to its investment which as of December 31, 2004, and 2003, totaled $16.2
million and $17.1 million, respectively, of Investments in unconsolidated
affiliates, and $16.7 million and $20.9 million, respectively, of Other
investments. The Company is also the equity owner in three leveraged leases
where its exposure to loss is limited to its net investment, which as of
December 31, 2004, and 2003, totaled $7.0 million and $6.0 million,
respectively. The Company did not consolidate any of these entities upon
adoption of FIN 46R.
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) 2004 2003
- ----------------------------------------------------------------------------
Materials & supplies $ 22.5 $ 22.6
Gas in storage - at LIFO cost 18.8 21.9
Fuel (coal & oil) for electric generation 13.9 14.0
Gas in storage - at average cost 7.9 7.2
Other 4.5 4.7
- ----------------------------------------------------------------------------
Total inventories $ 67.6 $ 70.4
============================================================================
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,
2004, and 2003, by approximately $56.4 million and $52.2 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 rates,
which include a cost of removal component, are established through regulatory
proceedings and are applied to all in-service utility plant. The original cost
of utility plant, together with depreciation rates expressed as a percentage of
original cost, follows:
At December 31,
- -------------------------------------------------------------------------------------------
(In millions) 2004 2003
- -------------------------------------------------------------------------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of percent of
Original Cost Original Cost Original Cost Original Cost
- -------------------------------------------------------------------------------------------
Gas utility plant $ 1,793.6 3.5% $ 1,721.9 3.6%
Electric utility plant 1,458.1 3.6% 1,322.4 3.4%
Common utility plant 44.2 2.7% 44.3 2.7%
Construction work in progress 169.3 - 162.1 -
- -------------------------------------------------------------------------------------------
Total original cost $ 3,465.2 $ 3,250.7
===========================================================================================
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. AFUDC 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) 2004 2003 2002
- -----------------------------------------------------------------------
AFUDC - borrowed funds $ 1.6 $ 2.1 $ 3.1
AFUDC - equity funds 1.6 2.9 2.2
- -----------------------------------------------------------------------
Total AFUDC $ 3.2 $ 5.0 $ 5.3
=======================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced or
removed, the remaining historical value of such property is charged to Utility
plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle
and remove retired property are charged against Regulatory liabilities, where
the cost of removal obligation is classified in these financial statements.
E. Non-utility Property
Non-utility property, net of accumulated depreciation and amortization, by
operating segment follows:
At December 31,
- ----------------------------------------------------------------------------
(In millions) 2004 2003
- ----------------------------------------------------------------------------
Utility Group
Other Operations $ 144.3 $ 135.7
Gas & Electric Utility Services 5.3 5.6
Nonregulated Group 78.7 79.9
Corporate & Other 0.9 1.1
- ----------------------------------------------------------------------------
Non-utility property - net $ 229.2 $ 222.3
============================================================================
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 $111.1 million and $84.5 million as of
December 31, 2004, and 2003, respectively. For the years ended December 31,
2004, 2003, and 2002, the Company capitalized interest totaling $1.4 million,
$0.5 million, and $0.4 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 requires a portion of goodwill be
charged to expense only when it is impaired. The Company tests its goodwill for
impairment at a reporting unit level at least annually and that test is
performed at the beginning of each year. Impairment reviews consist 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. Through December 31, 2004, no goodwill
impairments have been recorded. Approximately $205 million of the Company's
goodwill is included in the Gas Utility Services operating segment. The
remaining $2.1 million is attributable to the Nonregulated Group.
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) 2004 2003
- -------------------------------------------------------------------------
Future amounts recoverable from ratepayers:
Income taxes $ 11.5 $ 18.1
Other 1.0 1.0
- -------------------------------------------------------------------------
12.5 19.1
Amounts deferred for future recovery:
Demand side management programs 25.9 25.0
Other 7.3 5.3
- -------------------------------------------------------------------------
33.2 30.3
Amounts currently recovered through base rates:
Unamortized debt issue costs 20.4 21.4
Premiums paid to reacquire debt 7.0 7.4
Demand side management programs 2.3 2.7
Rate case expenses 1.2 -
- -------------------------------------------------------------------------
30.9 31.5
Amounts currently recovered through
tracking mechanisms:
Ohio authorized trackers 6.3 7.5
Indiana authorized trackers (0.4) 1.2
- -------------------------------------------------------------------------
5.9 8.7
- -------------------------------------------------------------------------
Total regulatory assets $ 82.5 $ 89.6
=========================================================================
Of the $30.9 million currently being recovered through base rates charged to
customers, $29.7 million is earning a return. The weighted average recovery
period of regulatory assets currently being recovered is 13.9 years. The Company
has rate orders for all deferred costs not yet in rates and therefore believes
that future recovery is probable.
Regulatory liabilities consist of the following:
At December 31,
- -------------------------------------------------------------------------
(In millions) 2004 2003
- -------------------------------------------------------------------------
Cost of removal $ 246.2 $ 228.8
Interest rate hedging proceeds (See Note 15) 5.5 6.2
- -------------------------------------------------------------------------
Total regulatory liabilities $ 251.7 $ 235.0
=========================================================================
Cost of Removal and SFAS 143
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. The Company records
amounts expensed in advance of payments as a regulatory liability because the
liability does not meet the threshold of a legal asset retirement obligation
(ARO) as defined by SFAS No. 143, "Accounting for Asset Retirement Obligations"
(SFAS 143). SFAS 143 requires entities to record the fair value of a liability
for a legal ARO 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. To the extent
regulation is involved, such gain or loss may be deferred. The Company adopted
this statement on January 1, 2003. The adoption was not material to the
Company's results of operations.
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. The net energy cost of
purchased power, subject to an agreed upon benchmark, is also recovered through
regulatory proceedings. 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
non-shareholder transactions. This information is reported in the Consolidated
Statements of Common Shareholders' Equity. A summary of the after tax components
of and changes in Accumulated other comprehensive income for the past three
years follows:
2002 2003 2004
- ------------------------ -------------------------- --------------- ----------------
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 $ 5.9 $ (5.3) $ 0.6 $ 5.7 $ 6.3 $ (3.8) $ 2.5
Minimum pension liability (2.4) (9.2) (11.6) (5.8) (17.4) (0.1) (17.5)
Other 0.6 (0.1) 0.5 (0.5) - - -
- ---------------------------------------------------------------------------------------
Accumulated other
comprehenive income (loss) $ 4.1 $(14.6) $(10.5) $(0.6 $(11.1) $ (3.9) $(15.0)
=======================================================================================
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 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 on marketable 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 $38.3 million in 2004, $37.1
million in 2003, and $32.4 million in 2002. 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 9), and derivatives (Note 15).
As more fully described in Note 10, 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
share-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 related to stock option plans. The Company also
maintains restricted stock and phantom stock plans for executives, employees,
and non-employee directors that result in share-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 all of the Company's share-based
compensation plans:
Year Ended December 31,
- -----------------------------------------------------------------------------------------
(In millions, except per share amounts) 2004 2003 2002
- -----------------------------------------------------------------------------------------
Net Income:
As reported $ 107.9 $ 111.2 $ 114.0
Add: Equity-based employee compensation included
in reported net income- net of tax 1.7 2.1 1.3
Deduct:Total equity-based employee compensation
expense determined under fair value based
method for all awards- net of tax 2.6 3.4 2.1
- -----------------------------------------------------------------------------------------
Pro forma $ 107.0 $ 109.9 $ 113.2
=========================================================================================
Basic Earnings Per Share:
As reported $ 1.43 $ 1.58 $ 1.69
Pro forma 1.42 1.56 1.68
Diluted Earnings Per Share:
As reported $ 1.42 $ 1.57 $ 1.68
Pro forma 1.41 1.55 1.67
SFAS 123 (revised 2004)
In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based
Payments" (SFAS 123R) that will require compensation costs related to all
share-based payment transactions to be recognized in the financial statements.
With limited exceptions, the amount of compensation cost will be measured based
on the grant-date fair value of the equity or liability instruments issued.
Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes
APB 25. The effective date of SFAS 123R for Vectren is July 1, 2005. SFAS 123R
provides for multiple transition methods, and the Company is still evaluating
potential methods for adoption. The adoption of this standard is not expected to
have a material effect on the Company's operating results or financial
condition.
M. Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
3. 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) 2004 2003
- -------------------------------------------------------------------------------
ProLiance Energy, LLC $ 93.2 $ 84.7
Reliant Services, LLC 26.5 19.2
Haddington Energy Partnerships 20.3 26.3
Utilicom Networks, LLC & related entities 11.7 15.4
Pace Carbon Synfuels, LP 9.4 8.7
Other partnerships & corporations 18.9 21.8
- -------------------------------------------------------------------------------
Total investments in unconsolidated affiliates $ 180.0 $ 176.1
===============================================================================
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides services to a
broad range of municipalities, utilities, industrial operations, schools, and
healthcare institutions located throughout the Midwest and Southeast United
States. ProLiance's primary customers include Vectren's utilities and
nonregulated gas supply operations as well as Citizens Gas. ProLiance's primary
businesses include gas marketing, gas portfolio optimization, and other
portfolio and energy management services. The Company, including its retail gas
supply operations, contracted for all natural gas purchases through ProLiance in
2004. Pre-tax income of $25.9 million, $25.9 million, and $19.1 million was
recognized as ProLiance's contribution to earnings for the years ended December
31, 2004, 2003, and 2002, respectively.
Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC
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, including cash of $2.0 million, Vectren's allocable share of
ProLiance's profits and losses increased to 61%, consistent with Vectren's new
ownership percentage. 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, 2004, 2003, and 2002, totaled $875.9 million, $797.7
million, and $544.1 million, respectively. Amounts owed to ProLiance at December
31, 2004, and 2003, for those purchases were $108.2 million and $86.0 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. As part of a
settlement agreement approved by the IURC during July 2002, the gas supply
agreements with Indiana Gas and SIGECO, were approved and extended through March
31, 2007. The utilities may decide to conduct a "request for proposal" (RFP) for
a new supply administrator, or they may decide to make an alternative proposal
for procurement of gas supply. That decision will be made by December 2005. To
the extent an RFP is conducted, ProLiance has the opportunity, if it so elects,
to participate in the RFP process for service to the utilities after March 31,
2007.
Summarized Financial Information
For the year ended December 31, 2004, ProLiance's revenues, margin, operating
income, and net income were (in millions) $2,573.8, $74.0, $43.2, and $42.6,
respectively. 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. As of December 31, 2004, current assets,
noncurrent assets, current liabilities, and noncurrent liabilities were (in
millions) $595.6, $0.4, $462.2, and $6.6, 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.
ProLiance Contingency
In 2002, a lawsuit was filed 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 asserted claims based on alleged breach of contract with respect to
provision of portfolio services and/or pricing advice, fraud, fraudulent
inducement, and other theories, including conversion and violations under
Racketeering, Influenced and Corrupt Organizations Act (RICO). These claims
related generally to: (1) alleged breach of contract 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 other
management, and; (4) the sale of Huntsville Utilities' gas storage supplies to
repay the balance owed on the winter levelizing program and the alleged lack of
authority of Huntsville Utilities' gas manager to approve those sales.
In early 2005, a jury trial was commenced and on February 10, 2005, the jury
returned a verdict largely in favor of Huntsville Utilities and awarded
Huntsville Utilities compensatory damages of $8.2 million and punitive damages
of $25.0 million. The jury rejected Huntsville Utilities' claim of conversion.
The jury also rejected ProLiance's counter claim for payment. The amounts due
from Huntsville Utilities were fully reserved by ProLiance in 2003. Huntsville
Utilities claims that all or a portion of the compensatory damages may be
subject to trebling under applicable Federal statutes. The court may also assess
attorney's fees and costs in favor of Huntsville Utilities. If the Court applies
trebling and awards attorney fees, the entire award could approach $55 million.
Several matters are still pending at the trial court, including efforts by
ProLiance to reduce the amount of the verdict. ProLiance will file post judgment
motions to reduce and to set aside the verdict. The court may issue its final
rulings on the verdict and related motions by April or May. Depending on the
outcome, ProLiance would appeal the judgment of the trial court. ProLiance
management believes that there are reasonable grounds to set aside or reduce the
verdict and reasonable grounds for appeal which offer a basis for reversal of
the entire verdict. While it is reasonably possible that a liability has been
incurred by ProLiance, it is not possible to predict the ultimate outcome of an
appeal of the verdict. ProLiance has recorded a reserve of $3.9 million as of
December 31, 2004, reflective of their assessment of the lower end of the range
of possible outcomes in the case and inclusive of estimated ongoing litigation
costs.
As an equity investor in ProLiance, the Company has reflected its share of the
charge, or $1.4 million after tax, in its 2004 results. It is not expected that
an unfavorable outcome on appeal will have a material adverse effect on the
Company's consolidated financial position or its liquidity, but an unfavorable
outcome could be material to the Company'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, quality
devices, and other emerging technologies. At December 31, 2004, $5.0 million of
the additional $20.0 million commitment remains. The Company has an approximate
40% ownership interest in Haddington II. Both Haddington ventures are investment
companies accounted for using the equity method of accounting. For the year
ended December 31, 2004, the partnerships' contribution to the Company's pre-tax
earnings was $4.5 million. In 2003 and 2002, the earnings contribution was not
significant.
The following is summarized financial information as to the assets, liabilities,
and results of operations of the Haddington Partnerships. For the year ended
December 31, 2004, revenues, operating income, and net income were (in millions)
$3.3, $2.5, and $9.6, respectively. 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. As of December 31, 2004, investments, other assets, and
liabilities were (in millions) $50.7, $0.2, and zero, respectively. As of
December 31, 2003, investments, other assets, and liabilities were (in millions)
$64.4, $1.0, and zero, respectively.
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 $12.0
million in 2004, $11.4 million in 2003, and $6.8 million in 2002. The production
of synthetic fuel generates IRS Code Section 29 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 $9.0 million in
2004, $10.3 million in 2003, and $6.0 million in 2002.
The following is summarized financial information as to the assets, liabilities,
and results of operations of Pace Carbon. For the year ended December 31, 2004,
revenues, margin, operating loss, and net loss were (in millions) $243.0,
($99.8), ($128.6), and ($141.1), respectively. 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. As of December 31, 2004, current
assets, noncurrent assets, current liabilities, and noncurrent liabilities were
(in millions) $44.1, $57.0, $25.3, and $19.8, 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.
IRS Section 29 Tax Credit Recent Developments
Under Section 29 of the Internal Revenue Code, manufacturers of synthetic fuel
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
Section 29 tax credits in its consolidated results through December 31, 2004, of
approximately $56.2 million. To date, Vectren has been in a position to fully
recognize the credits generated.
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. In May
2004, the IRS completed its audit of the 1998 to 2001 tax returns of Pace Carbon
requesting only minor modifications to previously filed returns. There were no
changes to any of the filed Section 29 tax credit calculations. The Permanent
Subcommittee on Investigations of the U.S. Senate's Committee on Governmental
Affairs, however, has an ongoing investigation related to Section 29 tax
credits.
Vectren believes it is justified in its reliance on the private letter rulings
and recent IRS audit results for the Pace Carbon facilities. Therefore, the
Company will continue to recognize Section 29 tax credits as they are earned
until there is either a change in the tax code or the IRS' interpretation of
that tax code.
Further, Section 29 tax credits are only available when the price of oil is less
than a base price specified by the tax code, as adjusted for inflation. The
Company does not believe that credits realized in 2004 and prior years will be
affected by the limitation, but an average annual price in excess of the mid $50
per barrel range, as priced at the wellhead, could limit Section 29 tax credits
in 2005 and beyond. In January 2005, the Company executed an insurance
arrangement that partially limits the Company's exposure if a limitation on the
availability of tax credits were to occur in 2005 and/or 2006 due to oil prices.
Utilicom Networks, LLC & Related Entities
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%. 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, such as cable television, high-speed internet, and advanced local and
long distance phone services, to the greater Evansville, Indiana area. The
Company accounts for its investments in Utilicom and Holdings using the cost
method of accounting.
Other Utilicom-related subsidiaries owned franchising agreements to provide
broadband services to the greater Indianapolis, Indiana and Dayton, Ohio
markets. In 2004, the build out of these markets was further evaluated, and the
Company concluded that it was unlikely it would make additional investments in
those markets. As a result, the Company recorded charges totaling $6.0 million,
or $3.6 million after-tax, to write-off investments made in the Indianapolis and
Dayton markets and to write down its investment in SIGECOM.
At December 31, 2004, convertible subordinated debt investments total $31.6
million, all of which is convertible into Utilicom ownership at the Company's
option or upon the event of a public offering of stock by Utilicom. Investments
in the convertible notes are included in Other investments. At December 31,
2004, and 2003, the Company's combined investment in equity and debt securities
of Utilicom-related entities totaled $43.3 million and $47.7 million,
respectively.
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, 2004, 2003, and 2002, fees for these services and
construction-related expenditures paid by the Company to its affiliates totaled
$31.2 million, $37.2 million, and $38.3 million, respectively. Amounts charged
by these affiliates are market based. Amounts owed to unconsolidated affiliates
other than ProLiance totaled $1.1 million and $0.4 million at December 31, 2004,
and 2003, respectively, and are included in Accounts payable to affiliated
companies in the Consolidated Balance Sheets. Amounts due from unconsolidated
affiliates included in Accounts receivable totaled $0.6 million and $0.4
million, respectively, at December 31, 2004, and 2003.
EITF 03-01
In March 2004, the EITF issued a consensus on Issue No. 03-01, "The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain Investments"
(EITF 03-01). In EITF 03-01, the Task Force developed a basic model for
evaluating whether investments within the scope of EITF 03-01, which includes
cost method and equity method investments, have other-than-temporary impairment.
The basic model includes three steps: 1) determine if there is impairment; 2) if
there is impairment, decide whether it is temporary or other than temporary; and
3) if it is other than temporary, recognize it in earnings. EITF 03-01 also
requires certain qualitative and quantitative disclosure of material impairments
judged to be temporary. The EITF has yet to finalize Steps 2 and 3. Step 1 and
the disclosure requirements are currently effective, and the adoption of those
portions of the EITF did not have a material effect on the Company.
As noted above, the Company incurred an other-than-temporary impairment charge
associated with its cost method investment in SIGECOM, LLC, during 2004. While
the Company currently believes that the book value of that investment
approximates fair value, further changes in estimated fair value may occur.
4. Other Investments
Other investments consist of the following:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2004 2003
- ------------------------------------------------------------------------------
Leveraged leases $ 33.2 $ 32.2
Convertible notes receivable from Utilicom-related
entities (See Note 3) 31.6 32.3
Other investments 50.3 58.4
- ------------------------------------------------------------------------------
Total other investments $ 115.1 $ 122.9
==============================================================================
Leveraged Leases
The Company is a lessor in three 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, 2004, and
2003, respectively. The cost of the equipment and facilities was partially
financed by non-recourse debt provided by lenders who have been granted an
assignment of rentals due under the leases and a security interest in the leased
property, which they accepted as their sole remedy in the event of default by
the lessee. Such debt amounted to approximately $48.3 million and $51.8 million
at December 31, 2004, and 2003, respectively. At December 31, 2004 and 2003, the
Company's leveraged lease investment, net of related deferred tax liabilities,
was $7.0 million and $6.0 million, respectively.
Other Investments
Other investments include other notes receivable, the cash surrender value of
life insurance policies, restricted cash, and a municipal bond, among other
items.
5. Income Taxes
The components of income tax expense and utilization of investment tax credits
follow:
Year Ended December 31,
- ------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- ------------------------------------------------------------------------------
Current:
Federal $ 24.1 $ (11.9) $ 62.2
State 9.0 14.5 5.2
- ------------------------------------------------------------------------------
Total current taxes 33.1 2.6 67.4
- ------------------------------------------------------------------------------
Deferred:
Federal 3.8 39.1 (26.2)
State 4.3 (1.8) -
- ------------------------------------------------------------------------------
Total deferred taxes 8.1 37.3 (26.2)
- ------------------------------------------------------------------------------
Amortization of investment tax credits (2.2) (2.2) (2.3)
- ------------------------------------------------------------------------------
Total income tax expense $ 39.0 $ 37.7 $ 38.9
==============================================================================
A reconciliation of the federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- ------------------------------------------------------------------------------
2004 2003 2002
- ------------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 % 35.0 %
State and local taxes-net of federal benefit 5.9 5.5 2.4
Section 29 tax credits (11.6) (11.7) (7.0)
Amortization of investment tax credit (1.5) (1.5) (1.5)
Other tax credits (0.6) (0.9) (1.1)
All other-net (0.7) (1.1) (2.4)
- ------------------------------------------------------------------------------
Effective tax rate 26.5 % 25.3 % 25.4 %
==============================================================================
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates.
Significant components of the net deferred tax liability follow:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2004 2003
- ------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences $ 265.5 $ 225.4
Leveraged leases 26.2 26.2
Regulatory assets recoverable through future rates 19.2 26.9
Regulatory liabilities to be settled through
future rates (7.7) (8.8)
Employee benefit obligations (29.2) (29.8)
Alternative minimum tax carryforward (31.9) -
Other - net (8.1) (4.5)
- ------------------------------------------------------------------------------
Net noncurrent deferred tax liability 234.0 235.4
- ------------------------------------------------------------------------------
Current deferred tax liabilities:
Deferred fuel costs-net 4.5 6.9
- ------------------------------------------------------------------------------
Net current deferred tax liability 4.5 6.9
- ------------------------------------------------------------------------------
Net deferred tax liability $ 238.5 $ 242.3
==============================================================================
At December 31, 2004, and 2003, investment tax credits totaling $14.2 million
and $16.4 million, respectively, are included in Deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments. At December 31, 2004, the Company has alternative minimum
tax carryforwards of $31.9 million, which do not expire.
6. Retirement Plans & Other Postretirement Benefits
At December 31, 2004, 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 VEBA funding is discretionary and
is based on the projected cost over time of benefits to be provided to covered
persons consistent with acceptable actuarial methods. To the extent these
postretirement benefits are funded, the benefits are not liabilities in these
consolidated financial statements. The 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 106-2
On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Medicare Act") was enacted. The Medicare Act
introduces a Medicare prescription drug benefit, as well as a federal subsidy to
sponsors of retiree health care benefit plans that provide a benefit that is at
least "actuarially equivalent" to the Medicare benefit. In May 2004, FASB issued
FASB Staff Position ("FSP") 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003," which supercedes FSP 106-1 of the same title issued in January 2004. FSP
106-2 provides guidance on the accounting and required disclosures for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 was effective for
the first interim or annual period beginning after June 15, 2004, with earlier
adoption permitted.
The Company elected to early adopt the accounting for the federal subsidy under
the Medicare Act on April 1, 2004, and remeasured its obligation as of January
1, 2004, to incorporate the impact of the Medicare Act which resulted in a
reduction to the accumulated benefit obligation of $10.4 million. For the year
ended December 31, 2004, the remeasurement resulted in a reduction in net
periodic postretirement benefit cost of $0.8 million. The reduction is a
component of amortization of actuarial loss (gain) in the information that
follows.
The underlying determination of whether an employer's plan qualifies for the
federal subsidy is still subject to clarifying federal regulations related to
the Medicare Act. When this guidance is issued, the Company will reassess if its
plans continue to qualify for the subsidy.
Benefit Obligations
A reconciliation of the Company's benefit obligations at December 31, 2004, and
2003, follows:
- -------------------------------------------------------------------------------------
Pension Benefits Other Benefits
--------------------- ------------------
(In millions) 2004 2003 2004 2003
- --------------------------------------- --------------------- ------------------
Benefit obligation, beginning of period $ 222.7 $ 201.9 $ 97.3 $ 81.5
Service cost - benefits earned during
the period 6.6 5.8 0.9 0.9
Interest cost on projected benefit
obligation 13.4 13.6 5.3 5.4
Plan amendments 4.5 - - -
Benefits paid (11.4) (12.7) (5.3) (5.4)
Actuarial loss (gain) 5.3 14.1 (5.3) 14.9
- -------------------------------------------------------------------------------------
Benefit obligation, end of period $ 241.1 $ 222.7 $ 92.9 $ 97.3
=====================================================================================
The accumulated benefit obligation for all defined benefit pension plans was
$219.5 million and $202.7 million at December 31, 2004, and 2003, respectively.
The benefit obligation as of December 31, 2004, and 2003, was calculated using
the following weighted average assumptions:
- -----------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------- ------------------
2004 2003 2004 2003
- --------------------------------------- ------------------- ------------------
Discount rate 5.75% 6.00% 5.75% 6.00%
Rate of compensation increase 3.50% 3.50% 3.50% 3.50%
To calculate the 2004 ending postretirement benefit obligation, a 9% annual rate
of increase in the per capita cost of covered health care benefits was assumed
for 2005. 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 $7.6 million. A one percentage point
decrease would have decreased the obligation by $6.3 million. To calculate the
2003 ending postretirement benefit obligation, a 10% rate was assumed for 2004,
declining to 5% in 2009 and remaining at that level thereafter.
Plan Assets
A reconciliation of the Company's plan assets at December 31, 2004, and 2003,
follows:
- -------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------- -----------------
(In millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Plan assets at fair value,
beginning of period $ 147.8 $ 138.6 $ 9.2 $ 7.4
Actual return on plan assets 16.3 20.8 0.7 1.4
Employer contributions 8.5 1.1 3.8 5.8
Benefits paid (11.4) (12.7) (5.3) (5.4)
- -------------------------------------------------------------------------------
Fair value of plan assets,
end of period $ 161.2 $ 147.8 $ 8.4 $ 9.2
===============================================================================
The asset allocation for the Company's pension and postretirement plans at the
measurement date for 2004, 2003 and 2002, by asset category, follows:
- ------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------ ----------------------
2004 2003 2002 2004 2003 2002
- ------------------------------------------------------------------------------
Equity securities 60% 59% 57% 60% 54% 49%
Debt securities 33% 35% 43% 36% 32% 47%
Real estate 6% 6% - - - -
Short term investments
& other 1% - - 4% 14% 4%
- ------------------------------------------------------------------------------
Total 100% 100% 100% 100% 100% 100%
==============================================================================
The Company invests in a master trust that benefits its 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 2005, and for postretirement plans of 55% equities,
35% debt, and 10% short-term investments and other for 2005. 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, 2004, and 2003, follows:
- -----------------------------------------------------------------------------------------
Pension Benefits Other Benefits
-------------------- ------------------
(In millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Fair value of plan assets, end of period $ 161.2 $ 147.8 $ 8.4 $ 9.2
Benefit obligation, end of period (241.1) (222.7) (92.9) (97.3)
- -----------------------------------------------------------------------------------------
Funded status, end of period (79.9) (74.9) (84.5) (88.1)
- -----------------------------------------------------------------------------------------
Unrecognized net loss (gain) 50.9 49.4 (3.5) 1.7
Unrecognized transitional (asset) obligation - (0.2) 26.2 29.1
Unrecognized prior service cost 14.2 10.5 - -
Post measurement date adjustments 0.2 0.2 1.3 0.8
- -----------------------------------------------------------------------------------------
Net amount recognized, end of year $ (14.6) $ (15.0) $(60.5) $ (56.5)
=========================================================================================
Net amount recognized included in:
Deferred credits & other liabilities $ (18.4) $ (18.9) $(60.5) $ (56.5)
Other assets 3.8 3.9 - -
As of December 31, 2004, and 2003, the funded status of the SERP, which is
included in Pension Benefits in the chart above, was an unfunded amount of $13.8
million and $12.7 million, respectively, and the net amount recognized in the
balance sheet related to the SERP as of December 31, 2004, and 2003 was a
liability of $8.4 million and $7.8 million, respectively.
At December 31, 2004, and 2003, 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,
2004, and 2003, follow:
- --------------------------------------------------------------------------
(In millions) 2004 2003
- --------------------------------------------------------------------------
Minimum pension liability adjustment,
beginning of year $ 39.7 $ 30.0
Change in minimum pension liability
adjustment included in:
Other comprehensive income
before effect of taxes 0.1 9.7
Other assets 3.7 -
- --------------------------------------------------------------------------
Minimum pension liability adjustment,
end of year $ 43.5 $ 39.7
==========================================================================
Offset included in:
Accumulated other comprehensive
income $ 17.5 $ 17.4
Other assets 14.2 10.5
Deferred income taxes 11.8 11.8
Expected Cash Flows
In 2005, the Company expects to make contributions of approximately $3.6 million
to its pension plan trusts. In addition, the Company expects to make payments
totaling $0.8 million directly to SERP participants and $5.4 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 2004 (in millions) are $11.8 in 2005, $12.2
in 2006, $13.0 in 2007, $13.4 in 2008 $14.2 in 2009, and $82.3 in years
2010-2014. Expected benefit payments projected to be required for postretirement
benefits during the years following 2004 (in millions) are $5.4 in 2005, $5.3 in
2006, $5.5 in 2007, $5.7 in 2008, $6.0 in 2009, and $31.5 in years 2010-2014.
Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years
ended December 31, 2004, follows:
- ----------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------------------- -------------------------
(In millions) 2004 2003 2002 2004 2003 2002
- ----------------------------------------------------------------------------------------------
Service cost $ 6.6 $ 5.8 $ 5.9 $ 0.9 $ 0.9 $ 1.0
Interest cost 13.4 13.6 13.9 5.3 5.4 6.0
Expected return on plan assets (13.5) (14.8) (15.7) (0.7) (0.7) (0.7)
Amortization of prior service cost 0.9 0.8 0.8 - - -
Amortization of transitional (asset)
obligation (0.2) (0.2) (0.5) 2.9 2.9 2.9
Amortization of actuarial loss (gain) 1.0 0.5 0.1 (0.2) (0.5) (0.5)
- ----------------------------------------------------------------------------------------------
Net periodic benefit cost $ 8.2 $ 5.7 $ 4.5 $ 8.2 $ 8.0 $ 8.7
==============================================================================================
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.
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 8.5%
to calculate 2004 periodic benefit cost. For fiscal 2005, the expected long-term
rate of return will be 8.25%.
In January 2005, the Company announced the amendment of certain postretirement
benefit plans, effective January 1, 2006. The amendment will result in an
estimated $3 million annual decrease in periodic cost, a portion of which will
begin to be recognized in 2005, reducing those preliminary estimates. Two of the
unions that represent bargaining employees at the Company's regulated
subsidiaries have advised the Company that it is their position that these
changes are not permitted under the existing collective bargaining agreements
which govern the relationship between the employees and the affected
subsidiaries. With assistance from legal counsel, management has analyzed the
unions' position and continues to believe that the Company has reserved the
right to amend the affected plans and that changing these benefits for retirees
is not a mandatory subject of bargaining.
The weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
- --------------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------------- ----------------------
(In millions) 2004 2003 2002 2004 2003 2002
- --------------------------------------------------------------------------------
Discount rate 6.00% 6.75% 7.25% 6.00% 6.75% 7.25%
Rate of compensation increase 3.50% 4.25% 4.75% 3.50% 4.25% 4.75%
Expected return on plan assets 8.50% 9.00% 9.00% 8.50% 9.00% 9.00%
To measure 2004 postretirement expense, the Company used a 10% healthcare cost
trend rate for 2004, declining to 5% in 2009 and remaining level thereafter. A
one percentage point increase in assumed health care cost trend rates would have
increased the 2004 service and interest cost components of pension costs by $0.6
million. A one percentage point decrease would have decreased the 2004 benefit
costs by $0.5 million. To measure 2003 postretirement expense, the Company used
a 10% healthcare cost trend rate for 2003, declining to 5% in 2007 and remaining
level thereafter.
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
2004, 2003, and 2002, the Company made contributions to these plans of $3.5
million, $3.6 million, and $3.0 million, respectively.
7. Borrowing Arrangements
Short-Term Borrowings
At December 31, 2004, the Company has $615 million of short-term borrowing
capacity, including $355 million for the Utility Group operations and $260
million for the wholly owned Nonregulated Group and corporate operations, of
which approximately $47 million is available for the Utility Group operations
and approximately $156 million is available for wholly owned Nonregulated Group
and corporate operations. These short-term borrowing arrangements expire in
2009. See the table below for interest rates and outstanding balances.
Year Ended December 31,
- ------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- ------------------------------------------------------------------------------
Weighted average commercial paper
and bank loans outstanding
during the year $ 211.4 $ 296.9 $ 288.8
Weighted average interest rates
during the year
Commercial paper 1.78% 1.36% 2.02%
Bank loans 2.12% 1.94% 2.52%
At December 31,
- ---------------------------------------------------------------
(In millions) 2004 2003
- ---------------------------------------------------------------
Commercial paper $ 308.0 $ 184.4
Bank loans 104.3 88.4
Other 0.1 2.1
- ---------------------------------------------------------------
Total short-term borrowings $ 412.4 $ 274.9
===============================================================
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term by subsidiary follow:
At December 31,
- ------------------------------------------------------------------------------
(In millions) 2004 2003
- ------------------------------------------------------------------------------
VUHI
Fixed Rate Senior Unsecured Notes
2011, 6.625% $ 250.0 $ 250.0
2013, 5.25% 100.0 100.0
2018, 5.75% 100.0 100.0
2031, 7.25% 100.0 100.0
- ------------------------------------------------------------------------------
Total VUHI 550.0 550.0
- ------------------------------------------------------------------------------
SIGECO
First Mortgage Bonds
2016, 1986 Series, 8.875% 13.0 13.0
2023, Series B, adjustable rate
presently 2.08%, tax exempt, auction
rate mode, weighted average for 2004: 4.44% 22.6 22.8
2029, 1999 Senior Notes, 6.72% 80.0 80.0
2015, 1985 Pollution Control Series A,
adjustable rate presently 2.03%, tax
exempt, auction rate mode, weighted
average for 2004: 3.09% 9.8 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, 4.65%, tax exempt 22.5 22.5
- ------------------------------------------------------------------------------
Total first mortgage bonds 179.4 179.8
- ------------------------------------------------------------------------------
Senior Unsecured Bonds to Third Parties:
2020, 1998 Pollution Control Series B, 4.50%,
tax exempt 4.6 4.6
2030, 1998 Pollution Control Series B, 5.00%,
tax exempt 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 228.2 228.6
- ------------------------------------------------------------------------------
Indiana Gas
Senior Unsecured Notes
2004, Series F, 6.36% - 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
2015, Series E, 6.69% 5.0 5.0
2015, Series E, 6.69% 10.0 10.0
2025, Series E, 6.53% 10.0 10.0
2027, Series E, 6.42% 5.0 5.0
2027, Series E, 6.68% 1.0 3.5
2027, Series F, 6.34% 20.0 20.0
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 177.4 214.9
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------
Other Long-Term Notes Payable 1.6 -
Total long-term debt outstanding 1,070.2 1,106.5
Current maturities of long-term debt (38.5) (15.0)
Debt subject to tender (10.0) (13.5)
Unamortized debt premium & discount - net (4.6) (4.9)
Fair value of hedging arrangements (0.5) (0.3)
- ------------------------------------------------------------------------------
Total long-term debt-net $1,016.6 $1,072.8
==============================================================================
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.
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. During 2004, 2003, and 2002, debt totaling $2.5
million, $0.1 million, and $5.2 million, respectively, was put to the Company.
Debt which may be put to the Company during the years following 2004 (in
millions) is $10.0 in 2005, zero in 2006, $20.0 in 2007, zero in 2008, $80.0 in
2009, and $40.0 thereafter. Debt that may be put to the Company within one year
is classified as Long-term debt subject to tender in current liabilities.
SIGECO and Indiana Gas Debt Call
During 2004, the Company called $20.0 million of insured quarterly senior
unsecured notes outstanding at Indiana Gas. The notes, originally due in 2015,
were called at par.
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
During 2004, the Company remarketed two first mortgage bonds outstanding at
SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate
debt into variable rate debt where interest rates reset weekly. One bond, due in
2023, had a principal amount of $22.8 million and an interest rate of 6%. The
other bond, due in 2015, had a principal amount of $10.0 million and an interest
rate of 4.3%. These remarketing efforts resulted in the extinguishment of debt
and the reissuance of new debt at generally the same par value. These bonds are
classified in Long-term debt.
During 2003, the Company remarketed $26.6 million of adjustable rate senior
unsecured bonds and $22.5 million of adjustable rate first mortgage bonds. Of
the remarketed unsecured bonds, $4.6 million were placed through 2020 at a 4.5%
fixed interest rate, $22.0 million were placed through 2030 at a 5.0% fixed
interest rate, and the $22.5 million first mortgage bonds were placed through
2024 at a 4.65% fixed interest rate. These bonds are classified in Long-term
debt.
Other Company debt totaling $15.0 million in 2004, $18.5 million in 2003, and
$6.5 million in 2002 was retired as scheduled.
Future Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of
the greatest amount of bonds outstanding under the Mortgage Indenture. This
requirement may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2005 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2005 is excluded from
Current liabilities in the Consolidated Balance Sheets. At December 31, 2004,
$563.9 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture. SIGECO's gross utility plant balance subject to the Mortgage
Indenture approximated $1.8 billion at December 31, 2004.
Consolidated maturities and sinking fund requirements on long-term debt during
the five years following 2004 (in millions) are $38.5 in 2005, zero in 2006,
$24.0 in 2007, zero in 2008 and in 2009.
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, 2004, the Company was in
compliance with all financial covenants.
Ratings Triggers
At December 31, 2004, $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 $104.0 million, respectively, at December 31,
2004. 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, 2004, totaled $550.0 million and
$308.0 million, respectively.
8. Cumulative Preferred Stock of Subsidiary
Currently outstanding 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, 2004, and 2003, there were 1,177 shares and 2,277 shares
outstanding, respectively.
9. 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, 2004:
Year Ended December 31,
- ------------------------------------------------------------------------------------
(In millions, except per share data) 2004 2003 2002
- ------------------------------------------------------------------------------------
Numerator:
Numerator for basic and diluted EPS - Net income $ 107.9 $ 111.2 $ 114.0
====================================================================================
Denominator:
Denominator for basic EPS - Weighted average
common shares outstanding 75.6 70.6 67.6
Conversion of stock options and lifting of
restrictions on issued restricted stock 0.3 0.2 0.3
- ------------------------------------------------------------------------------------
Denominator for diluted EPS - Adjusted weighted
average shares outstanding and assumed
conversions outstanding 75.9 70.8 67.9
====================================================================================
Basic earnings per share $ 1.43 $ 1.58 $ 1.69
Diluted earnings per share $ 1.42 $ 1.57 $ 1.68
Options to purchase 4,200 shares of common stock for the year ended December 31,
2004, 530,663 shares of common stock for the year ended December 31, 2003, and
87,963 shares of common stock for the year ended December 31, 2002, 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 were $25.59 in 2004; $23.19 to $25.59 in 2003; and $24.05 to $25.59
in 2002.
10. Share-Based Incentive Plans
The Company has various share-based incentive plans to encourage executives,
strategic 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
Stock options granted to employees in 2004 and 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 since 2001 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. Options generally vest on a
straight-line graded basis over their terms.
A summary of activity within the Company's stock option plans for the past three
years follows:
Wtd. Avg.
Exercise
Options Price
- ---------------------------------------------------------------------------
Outstanding at January 1, 2002 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
Granted 219,000 24.74
Cancelled (6,043) 19.66
Exercised (90,400) 18.27
- ---------------------------------------------------------------------------
Outstanding at December 31, 2004 1,925,453 $ 22.57
===========================================================================
In January 2005, 286,400 options to purchase shares of common stock at an
exercise price of $26.63 were issued to management. The grant vests over three
years.
The following table summarizes information about stock options outstanding and
exercisable at December 31, 2004:
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 40,985 1.3 $ 16.88 40,985 $ 16.88
$19.83 - $20.26 261,383 3.4 20.08 261,383 20.08
$22.37 - $22.57 873,422 6.6 22.54 589,424 22.54
$23.19 - $25.59 749,663 7.8 23.78 262,718 23.54
- --------------------------------------------------------------------------------------
Total 1,925,453 6.5 $ 22.57 1,154,510 $ 22.01
======================================================================================
Stock options that were exercisable and those options' weighted average exercise
prices were 924,849 and $21.34, respectively at December 31, 2003, and 692,288
and $20.37, respectively, at December 31, 2002.
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, 2004, 2003, and
2002: risk-free rate of return of 4.37%, 4.00%, and 4.61%, respectively;
expected option term of 8 years for all 3 years presented; expected volatility
of 24.01%, 26.98%, and 26.42%, respectively; and dividend yield of 4.65%, 4.81%,
and 4.56%, respectively. The weighted average fair value of options granted in
2004, 2003, and 2002 were $4.39, $4.31, and $4.81, respectively.
Restricted Stock & Phantom Stock Plans
The Company maintains a performance-based restricted stock plan for its
executives and employees and a non-performance based restricted stock plan
through which non-employee directors receive a portion of their director fees.
A summary of restricted stock activity during the three years ended December 31,
2004, follows:
Restricted Stock
- --------------------------------------------------------------------------
Outstanding at January 1, 2002 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
Grants 168,680
Forfeitures (150)
Vested (76,980)
- --------------------------------------------------------------------------
Outstanding at December 31, 2004 300,552
==========================================================================
For the years ended December 31, 2004, 2003, and 2002, the weighted average fair
value per share of restricted stock granted was $24.87, $23.33, and $23.10,
respectively. In January 2005, 138,900 restricted shares were issued. The share
price on the date of grant was $26.63. The restrictions lift over a four year
period subject to adjustments for performance.
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, 2004, 2003, and 2002, was $2.9 million,
$3.6 million, and $2.1 million, respectively.
11. Common Shareholders' Equity
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 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.
Authorized, Reserved Common and Preferred Shares
At December 31, 2004, and 2003, 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 9.4 million shares at December 31,
2004, and 7.0 million shares at December 31, 2003, were reserved by the board of
directors for issuance through the Company's share-based compensation plans,
benefit plans, and dividend reinvestment plan. At December 31, 2004, and 2003,
there were 394.6 million and 397.4 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 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.
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 2004 and thereafter (in millions) are $5.6 in 2005, $4.5 in
2006, $3.6 in 2007, $1.5 in 2008, $0.5 in 2009 and $1.8 thereafter. Total lease
expense (in millions) was $6.7 in 2004, $7.2 in 2003, and $7.3 in 2002.
Firm purchase commitments for commodities total (in millions) $152.1 million in
2005 and $1.4 million in 2006. Firm purchase commitment for utility and
non-utility plant total $20.5 million.
Other Guarantees
Vectren 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, 2004, guarantees issued and
outstanding on behalf of unconsolidated affiliates approximated $5 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 has accrued no liabilities for these guarantees as they relate to
guarantees issued among related parties, are not material, or such guarantees
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." Liabilities accrued for, and activity
related to, product warranties are not significant.
Securities & Exchange Commission Inquiry into PUCHA Exemption
In July 2004, the Company received a letter from the SEC regarding its exempt
status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter
asserts that Vectren's out of state electric power sales exceed the amount
previously determined by the SEC to be acceptable in order to qualify for the
exemption. There is pending a request by Vectren for an order of exemption under
Section 3(a)(1) of PUHCA. Vectren also claims the benefit of the exemption
pursuant to Rule 2 under Section 3(a)(1) of PUHCA by filing an annual statement
on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an
amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed
the method of aggregating wholesale power sales and purchases outside of Indiana
from that previously reported. The new method is to aggregate by delivery point.
The amendment also submitted clarifications as to activity outside of Indiana
related to gas utility operations.
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. See the ProLiance discussion in Note 3.
13. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Company has taken steps to comply with Indiana's State Implementation Plan
(SIP) of the Clean Air Act (the Act). 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 nitrogen oxide (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% return on
its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances, 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
construction cost is consistent with amounts approved in the IURC's orders.
Through December 31, 2004, $238 million has been expended, and three of the four
SCR's are operational. Once all equipment is installed and operational, related
annual operating expenses, including depreciation expense, are estimated to be
between $24 million and $27 million. The Company is recovering the operational
costs associated with the SCR's and related technology. The 8% 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 has achieved timely compliance through the reduction of 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
During 2003, the U.S. District Court for the Southern District of Indiana
entered a consent decree among SIGECO, the Department of Justice (DOJ), and the
USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO.
The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley
Generating Station for (1) making modifications to generating station without
obtaining required permits, (2) making major modifications to the generating
station without installing the best available emission control technology, and
(3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all
challenges of past maintenance and repair activities at the Culley Generating
Station. 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 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 committed to
o either repower Culley Unit 1 (50 MW) with natural gas 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 notified the USEPA of its intention to shut down Culley Unit 1
effective December 31, 2006. The Company does not believe that implementation of
the settlement will have a material effect to its results from operations or
financial condition. The $600,000 civil penalty was accrued during 2003 and is
reflected in Other-net.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Clean Air 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, SIGECO, 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, SIGECO,
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 added those 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. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and any
necessary remediation costs that SIGECO may accrue under the VRP program. The
total investigative costs, and if necessary, costs of remediation at the four
SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot
be determined at this time.
Jacobsville Superfund Site
On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil
Contamination site in Evansville, Indiana, on the National Priorities List under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA). The USEPA has identified four sources of historic lead contamination.
These four sources shut down manufacturing operations years ago. When drawing up
the boundaries for the listing, the USEPA included a 250 acre block of
properties surrounding the Jacobsville neighborhood, including Vectren's Wagner
Operations Center. Vectren's property has not been named as a source of the lead
contamination, nor does the USEPA's soil testing to date indicate that the
Vectren property contains lead contaminated soils. Vectren's own soil testing,
completed during the construction of the Operations Center, did not indicate
that the Vectren property contains lead contaminated soils. At this time,
Vectren anticipates only additional soil testing, if required by the USEPA.
14. Rate & Regulatory Matters
SIGECO and Indiana Gas Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for
SIGECO's gas distribution business, and on November 30, 2004, approved a $24
million base rate increase for Indiana Gas' gas distribution business. The new
rate designs include a larger service charge, which is intended to address to
some extent earnings volatility related to weather. The base rate change in
SIGECO's service territory was implemented on July 1, 2004, resulting in
additional 2004 revenues of $2.5 million. The base rate change in Indiana Gas'
service territory was implemented on December 1, 2004, resulting in additional
2004 revenues of $2.2 million.
The orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the federal Pipeline Safety Improvement Act of 2002. The Pipeline
Safety Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these
annual caps are to be deferred for future recovery.
VEDO Pending Base Rate Increase Settlement
On February 4, 2005, the Company filed with the PUCO a settlement agreement that
had been entered into with several parties, including the PUCO staff, in its
base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the
settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its
base rates and charges for its gas distribution business serving more than
315,000 customers located in west central Ohio. The settlement provides for a
$15.7 million increase in VEDO's base distribution rates to cover the ongoing
costs of operating, maintaining, and expanding the approximately 5,200-mile
distribution system. The settlement increase includes $1.1 million of funding
for weatherization and conservation programs for low income customers.
Evidentiary hearings were completed in the case on February 9, 2005. Review and
approval by the PUCO is necessary before the settlement is effective. The
proposed new rate design includes a larger service charge, which will address,
to some extent, earnings volatility related to weather. The settlement also
permits VEDO the annual recovery of on-going costs associated with the Pipeline
Safety Improvement Act of 2002. Based upon the PUCO's actions in other
proceedings, the Company would expect an order near the end of the first quarter
of 2005.
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 reversed and deferred that amount for future recovery. In 2004, the
Company recorded revenues of $3.3 million which is equal to the level of
uncollectible accounts expense recognized for Ohio residential customers.
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, a two-year audit period ended in November 2002.
That audit period provided the PUCO staff its initial review of the portfolio
administration arrangement between VEDO and ProLiance. The external auditor
retained by the PUCO staff submitted an audit report in the fall of 2003 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. A hearing has been held, and the PUCO
staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor
has recommended 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 recorded $1.1 million for its estimated share of a potential
disallowance. A PUCO decision on this matter is yet to be issued. The Company is
also unable to determine the effects that a PUCO decision for the audit period
ended in November 2002 may have on results in audit periods beginning after
November 2002.
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. The Company accounts for its derivative
contracts in accordance with SFAS 133, "Accounting for Derivatives" and its
related amendments and interpretations. In most cases, SFAS 133 requires a
derivative to 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.
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 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 native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of the
margin from these activities is generated from contracts that 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.
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.
Asset optimization contracts recorded at market value at December 31, 2004,
totaled $2.5 million of Prepayments & other current assets and $3.1 million of
Accrued liabilities, compared to $2.4 million of Prepayments & other current
assets and $2.8 million of Accrued liabilities at December 31, 2003.
The proceeds received and paid upon settlement of both purchase and sale
contracts along with changes in market value of open contracts are recorded in
Electric utility revenues. The change in market value is a function of the
normal decline in market value as earnings are realized and the fluctuation in
market value resulting from price volatility. Net revenues from asset
optimization activities totaled $23.8 million in 2004, $26.5 million in 2003,
and $23.3 million in 2002.
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. These
nonregulated gas retail operations may also from time-to-time execute weather
derivatives to mitigate extreme weather affecting unregulated gas retail sales.
At December 31, 2004 and 2003, the market values of these contracts and the book
value of weather contracts were 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.
Interest rate swaps hedging the fair value of fixed-rate debt with a total
notional amount of $55.5 million are outstanding. The fair value liability
associated with those swaps was $0.5 million and $0.3 million, respectively, at
December 31, 2004 and 2003. At December 31, 2004, approximately $5.5 million
remains in Regulatory liabilities related to future interest payments. Of the
existing regulatory liability, $0.6 million will be reclassified to earnings in
2005, $0.6 million was reclassified to earnings in 2004, and $0.3 million was
reclassified to earnings during 2003.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments follow:
At December 31,
- ------------------------------------------------------------------------------
2004 2003
----------------------- ------------------------
Carrying Est. Fair Carrying Est. Fair
(In millions) Amount Value Amount Value
- --------------------------- ----------------------- ------------------------
Long-term debt $ 1,070.2 $ 1,146.2 $ 1,106.5 $ 1,184.8
Short-term borrowings &
notes payable 412.4 412.4 274.9 274.9
Certain methods and assumptions must be used to estimate the fair value of
financial instruments. The fair value of the Company's long-term debt 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 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, 2004, and 2003, fair value for these financial instruments was not
estimated.
16. Segment Reporting
The Company segregates its operations into three groups: 1) Utility Group,
2) Nonregulated Group, and 3) Corporate and Other.
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations and other operations that
provide information technology and other support services to those regulated
operations. The Company segregates its regulated operations into a Gas Utility
Services operating segment and an Electric Utility Services operating segment.
The Gas Utility Services segment provides natural gas distribution and
transportation services to nearly two-thirds of Indiana and to west central
Ohio. The Electric Utility Services segment provides electric distribution
services primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. The Company cross manages its regulated
operations 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. For these regulated
operations the Company uses after tax operating income as a measure of
profitability, consistent with regulatory reporting requirements. For the
Utility Group's other operations, net income is used as the measure of
profitability.
In total, there are three operating segments of the Utility Group as defined by
SFAS 131 "Disclosure About Segments of an Enterprise and Related Information"
(SFAS 131).
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.
Corporate and Other includes unallocated corporate expenses such as branding and
charitable contributions, among other activities, that benefit the Company's
other operating segments. Net income is the measure of profitability used by
management for both the Nonregulated Group and Corporate and Other. Information
related to the Company's business segments is summarized below:
Year Ended December 31,
- ---------------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- ---------------------------------------------------------------------------------------
Revenues
Utility Group
Gas Utility Services $ 1,126.2 $ 1,112.3 $ 908.0
Electric Utility Services 371.3 335.7 328.6
Other Operations 32.9 26.5 22.4
Eliminations (32.4) (25.7) (22.1)
- ---------------------------------------------------------------------------------------
Total Utility Group 1,498.0 1,448.8 1,236.9
- ---------------------------------------------------------------------------------------
Nonregulated Group 272.1 219.2 352.3
Corporate & Other - 1.0 1.0
Eliminations (80.3) (81.3) (66.4)
- ---------------------------------------------------------------------------------------
Consolidated Revenues $ 1,689.8 $ 1,587.7 $ 1,523.8
=======================================================================================
Year Ended December 31,
- ---------------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- ---------------------------------------------------------------------------------------
Profitability Measure
Utility Group: Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services $ 70.9 $ 74.9 $ 80.7
Electric Utility Services 65.6 63.8 73.2
- ---------------------------------------------------------------------------------------
Total Regulated Operating Income 136.5 138.7 153.9
- ---------------------------------------------------------------------------------------
Regulated other income - net 2.1 5.1 5.1
Regulated interest expense & preferred dividends (62.7) (62.0) (63.7)
- ---------------------------------------------------------------------------------------
Regulated Net Income 75.9 81.8 95.3
- ---------------------------------------------------------------------------------------
Other Operations Net Income 7.2 3.8 1.8
- ---------------------------------------------------------------------------------------
Utility Group Net Income 83.1 85.6 97.1
- ---------------------------------------------------------------------------------------
Nonregulated Group Net Income 26.4 27.6 19.0
Corporate & Other Net Loss (1.6) (2.0) (2.1)
- ---------------------------------------------------------------------------------------
Consolidated Net Income $ 107.9 $ 111.2 $ 114.0
=======================================================================================
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services $ 57.0 $ 61.1 $ 56.8
Electric Utility Services 53.3 42.6 40.0
Other Operations 17.5 14.2 13.9
- ---------------------------------------------------------------------------------------
Total Utility Group 127.8 117.9 110.7
- ---------------------------------------------------------------------------------------
Nonregulated Group 12.0 10.5 8.6
Corporate & Other 0.3 0.3 0.3
- ---------------------------------------------------------------------------------------
Consolidated Depreciation & Amortization $ 140.1 $ 128.7 $ 119.6
=======================================================================================
Interest Expense
Utility Group
Regulated Operations $ 62.7 $ 62.0 $ 63.7
Other Operations 4.7 4.1 5.4
- ---------------------------------------------------------------------------------------
Total Utility Group 67.4 66.1 69.1
- ---------------------------------------------------------------------------------------
Nonregulated Group 11.3 9.7 9.1
Corporate & Other (1.0) (0.2) 0.3
- ---------------------------------------------------------------------------------------
Consolidated Interest Expense $ 77.7 $ 75.6 78.5
=======================================================================================
Equity in Earnings of Unconsolidated
Affiliates
Utility Group: Other Operations $ 0.2 $ (0.5) $ (1.8)
Nonregulated Group 20.4 12.7 10.9
- ---------------------------------------------------------------------------------------
Consolidated Equity in Earnings
of Unconsolidated Affiliates $ 20.6 $ 12.2 $ 9.1
=======================================================================================
Year Ended December 31,
- ---------------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- ---------------------------------------------------------------------------------------
Income Taxes
Utility Group
Gas Utility Services $ 17.5 $ 19.5 $ 18.2
Electric Utility Services 30.8 29.8 27.5
Other Operations 4.8 2.3 1.1
- ---------------------------------------------------------------------------------------
Total Utility Group 53.1 51.6 46.8
- ---------------------------------------------------------------------------------------
Nonregulated Group (13.6) (13.2) (6.9)
Corporate & Other (0.5) (0.7) (1.0)
- ---------------------------------------------------------------------------------------
Consolidated Income Taxes $ 39.0 $ 37.7 $ 38.9
=======================================================================================
Capital Expenditures
Utility Group
Gas Utility Services $ 89.1 $ 95.0 $ 63.0
Electric Utility Services 150.6 124.1 88.8
Other Operations 27.9 15.9 65.5
- ---------------------------------------------------------------------------------------
Total Utility Group 267.6 235.0 217.3
- ---------------------------------------------------------------------------------------
Nonregulated Group 10.3 13.2 28.0
Corporate & Other 0.1 2.3 2.2
Transfers of Assets (0.1) (14.3) (28.8)
- ---------------------------------------------------------------------------------------
Consolidated Capital Expenditures $ 277.9 $ 236.2 $ 218.7
=======================================================================================
Investments in Equity Method Investees
Utility Group: Other Operations $ - $ - $ 0.3
Nonregulated Group 18.2 16.6 12.2
- ---------------------------------------------------------------------------------------
Consolidated Investments in Equity
Method Investees $ 18.2 $ 16.6 $ 12.5
=======================================================================================
At December 31,
- ---------------------------------------------------------------------------
(In millions) 2004 2003
- ---------------------------------------------------------------------------
Assets
Utility Group
Gas Utility Services $ 1,892.8 $ 1,805.0
Electric Utility Services 1,090.1 974.6
Other Operations 175.0 162.4
Eliminations (10.2) (16.9)
- ---------------------------------------------------------------------------
Total Utility Group 3,147.7 2,925.1
- ---------------------------------------------------------------------------
Nonregulated Group 447.9 454.0
Corporate & Other 292.8 287.5
Eliminations (301.5) (313.2)
- ---------------------------------------------------------------------------
Consolidated Assets $ 3,586.9 $ 3,353.4
===========================================================================
17. Additional Operational & Balance Sheet Information
Prepayments and other current assets in the Consolidated Balance Sheets consist
of the following:
At December 31,
- ---------------------------------------------------------------------------
(In millions) 2004 2003
- ---------------------------------------------------------------------------
Prepaid gas delivery service $ 116.9 $ 97.7
Prepaid taxes 9.8 20.1
Other prepayments & current assets 14.6 13.3
- ---------------------------------------------------------------------------
Total prepayments & other current assets $ 141.3 $ 131.1
===========================================================================
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
At December 31,
- ---------------------------------------------------------------------------
(In millions) 2004 2003
- ---------------------------------------------------------------------------
Accrued taxes $ 32.1 $ 33.2
Refunds to customers & customer deposits 31.0 24.5
Accrued interest 15.9 16.5
Refundable gas costs 6.3 -
Deferred income taxes 4.5 6.9
Accrued salaries & other 42.3 28.2
- ---------------------------------------------------------------------------
Total accrued liabilities $ 132.1 $ 109.3
===========================================================================
Other - net in the Consolidated Statements of Income consists of the following:
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- -------------------------------------------------------------------------------
AFUDC & capitalized interest $ 4.6 $ 5.9 $ 5.7
Interest income 3.0 3.2 4.7
Gains on sale of investments & assets 0.6 7.5 1.8
Leveraged lease investment income 1.5 1.9 1.1
Other income 1.0 3.2 2.7
Other expense (9.3) (8.7) (4.5)
- -------------------------------------------------------------------------------
Total other - net $ 1.4 $ 13.0 $ 11.5
===============================================================================
18. Quarterly Financial Data (Unaudited)
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 2004 and 2003 follows:
- -------------------------------------------------------------------------------
(In millions, except per share amounts) Q1 Q2 Q3 Q4
- -------------------------------------------------------------------------------
2004
Operating revenues $ 645.3 $ 276.7 $ 254.4 $ 513.4
Operating income 88.6 20.4 23.8 69.9
Net income 54.8 3.3 9.7 40.1
Earnings per share:
Basic $ 0.73 $ 0.04 $ 0.13 $ 0.53
Diluted 0.72 0.04 0.13 0.53
- -------------------------------------------------------------------------------
2003
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
Earnings per share:
Basic $ 0.82 $ 0.06 $ 0.10 $ 0.59
Diluted 0.82 0.06 0.10 0.58
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2004, there have been no changes to the
Company's internal controls over financial reporting that have materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2004, the Company conducted 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.
Management's Report on Internal Control over Financial Reporting
Vectren Corporation's management is responsible for establishing and maintaining
adequate internal control over financial reporting. Under the supervision and
with the participation of management, including the Chief Executive Officer and
Chief Financial Officer, the Company conducted an evaluation of the
effectiveness of its internal control over financial reporting based on the
framework in Internal Control - Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on that evaluation
under the framework in Internal Control -- Integrated Framework, the Company
concluded that its internal control over financial reporting was effective as of
December 31, 2004.
Management's assessment of the effectiveness of internal control over financial
reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in their report which
is included in Item 8 of this annual report.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND 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 2005 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 Company's executive
officers are the same as those named executive officers detailed in the Proxy
Statement
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 2005 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,
which is included herein, 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 2005 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.
Shares Issuable under Share-Based Compensation Plans
As of December 31, 2004, the following shares were authorized to be issued under
share-based compensation plans:
- -----------------------------------------------------------------------------------------------
A B C
Number of Weighted Number of securities
securities to be average exercise remaining available for
issued upon price of future issuance under
exercise of outstanding equity compensation
outstanding options, plans (excluding
options, warrants warrants and securities reflected
Plan category and rights rights in column (a)
- ----------------------------------- ----------------- -------------- -----------------------
Equity compensation plans approved
by security holders (1) 2,211,853 (2) $ 23.10 2,515,241 (3)
Equity compensation plans not
approved by security holders - - -
- -----------------------------------------------------------------------------------------------
Total 2,211,853 $ 23.10 2,515,241
===============================================================================================
(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 286,400 options approved by the board of
directors' Compensation Committee, effective January 1, 2005.
(3) Includes shares available for issuance under the Vectren Corporation
At-Risk Compensation Plan (1,769,221), of which up to 800,000 shares may be
issued in restricted stock, 1994 SIGCORP Stock Option Plan (387,503),
Vectren Corporation Executive Restricted Stock Plan (310,288), 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
138,900 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 2005 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 2005 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 AND FINANCIAL STATEMENT SCHEDULES
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, 2004, 2003, and 2002, the Company's Schedule II
- -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is presented herein. 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.
SCHEDULE II
Vectren Corporation and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
- ---------------------------------------------------------------------------------------------------
Additions
--------------------
Balance at Charged Charged Deductions Balance at
Beginning to to Other from End of
Description Of Year Expenses Accounts Reserves, Net Year
- ----------------------------------------------------------------------------------------------------
(In millions)
VALUATION AND QUALIFYING ACCOUNTS:
Year 2004 - Accumulated provision for
uncollectible accounts $ 3.2 $ 11.9 $ - $ 13.1 $ 2.0
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
OTHER RESERVES:
Year 2004 - Restructuring costs $ 3.2 $ - $ - $ 0.5 $ 2.7
Year 2003 - Restructuring costs $ 4.2 $ - $ - $ 1.0 $ 3.2
Year 2002 - Restructuring costs $ 5.1 $ - $ - $ 0.9 $ 4.2
Year 2002 - Merger & integration costs $ 0.4 $ - $ - $ 0.4 $ -
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified
below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company
attached to this filing filed electronically with the SEC are listed below.
Exhibits for the Company are listed in the Index to Exhibits beginning on page
80.
Vectren Corporation
Form 10-K
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
Exhibit
Number Document
- ------- --------
4.1 Southern Indiana Gas and Electric Company with Deutsche Bank Trust
Company, as Trustee. Supplemental Indenture related to the First
Mortgage Bonds Series B 1993 due 2023, dated August 1, 2004
4.2 Southern Indiana Gas and Electric Company with Deutsche Bank Trust
Company, as Trustee. Supplemental Indenture related to the First
Mortgage Bonds Series A 1985 due 2015, dated October 1, 2004
21.1 List of Company's Significant Subsidiaries
23.1 Consent of Registered Public Accounting Firm
31.1 Chief Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Chief Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
INDEX TO EXHIBITS
2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
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 Mortgage and Deed of Trust dated as of April 1, 1932 between
Southern Indiana Gas and Electric Company and Bankers Trust Company, as
Trustee, and Supplemental Indentures thereto dated August 31, 1936,
October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1,
1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965,
September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1,
1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978,
June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1,
1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986.
(Filed and designated in Registration No. 2-2536 as Exhibits B-1 and
B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as
Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in
Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No.
1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No.
1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and
November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year
1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and
January 15, 1987. (Filed and designated in Form 10-K, for the fiscal
year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed
and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553,
as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form
10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.)
April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993,
File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in
Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1,
1993. (Filed and designated in Form 10-K, for the fiscal year 1993,
File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated
in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).)
March 1, 2000. (Filed and designated in Form 10-K for the year ended
December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004.
(Filed Herewith.) October 1, 2004. (Filed Herewith.)
4.2 Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank
Trust National Association (formerly know as First Trust National
Association, which was formerly know as Bank of America Illinois, which
was formerly know as Continental Bank, National Association. Inc.'s.
(Filed and designated in Current Report on Form 8-K filed February 15,
1991, File No. 1-6494.); First Supplemental Indenture thereto dated as
of February 15, 1991. (Filed and designated in Current Report on Form
8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second
Supplemental Indenture thereto dated as of September 15, 1991, (Filed
and designated in Current Report on Form 8-K filed September 25, 1991,
File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto
dated as of September 15, 1991 (Filed and designated in Current Report
on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit
4(c).); Fourth Supplemental Indenture thereto dated as of December 2,
1992, (Filed and designated in Current Report on Form 8-K filed December
8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental
Indenture thereto dated as of December 28, 2000, (Filed and designated
in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494,
as Exhibit 4.)
4.3 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).
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 Vectren Corporation At Risk Compensation Plan specimen Restricted
Stock Grant Agreement for officers, effective January 1, 2005. (Filed
and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as
Exhibit 99-1.)
10.16 Vectren Corporation At Risk Compensation Plan specimen Stock Option
Grant Agreement for officers, effective January 1, 2005. (Filed and
designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as
Exhibit 99-2.)
10.17 Vectren Corporation specimen employment agreement dated February 1,
2005. (Filed and designated in Form 8-K, dated February 1, 2005, File
No. 1-15467, as Exhibit 99-1.)
10.18 Gas Sales and Portfolio Administration Agreement between Indiana Gas
Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003.
(Filed and designated in Form 10-K, for the year ended December 31,
2003, File No. 1-15467, as Exhibit 10.15.)
10.19 Gas Sales and Portfolio Administration Agreement between Southern
Indiana Gas and Electric Company and ProLiance Energy, LLC, effective
September 1, 2002. (Filed and designated in Form 10-K, for the year
ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.)
10.20 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.)
10.21 Coal Supply Agreement for F.B. Culley Generating Station between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated
December 17, 1997 and effective January 1, 1998. (Filed and designated
in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as
Exhibit 10.18.) Portions of the document have been omitted pursuant to a
request to a request for confidential treatment.
10.22 Amendment 1, effective January 1, 2003, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc
originally dated December 17, 1997. (Filed and designated in Form 10-K,
for the year ended December 31, 2003, File No. 1-15467, as Exhibit
10.19.)
10.23 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick
County, Indiana, and West Franklin, Posey County, Indiana between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated
January 19, 2000. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit 10.20.)
10.24 Amendment 1, effective January 1, 2004, to Coal Supply Agreement between
Southern Indiana Gas and Electric Company and Vectren Fuels, Inc
originally dated January 19, 2000. (Filed and designated in Form 10-K,
for the year ended December 31, 2003, File No. 1-15467, as Exhibit
10.21.)
10.25 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated October
1, 2003. (Filed and designated in Form 10-K, for the year ended
December 31, 2003, File No. 1-15467, as Exhibit 10.22.)
10.26 Coal Supply Agreement for Warrick Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January
1, 2004. (Filed and designated in Form 10-K, for the year ended December
31, 2003, File No. 1-15467, as Exhibit 10.23.)
10.27 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.)
21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit
21.1.
23. Consents of Experts and Counsel
The consent of Deloitte & Touche LLP is attached hereto as Exhibit 23.1.
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 Of The Sarbanes-
Oxley Act Of 2002 is attached hereto as Exhibit 31.1
Chief Financial Officer Certification Pursuant to Section 302 Of The Sarbanes-
Oxley Act Of 2002 is attached hereto as Exhibit 31.2
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is
attached hereto as Exhibit 32.1
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 23, 2005
/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 23, 2005
- ---------------------------- Director (Principal Executive -------------------
Niel C. Ellerbrook Officer)
/s/ Jerome A. Benkert, Jr. Executive Vice President & February 23, 2005
- ---------------------------- Chief Financial Officer -------------------
Jerome A. Benkert, Jr. (Principal Financial Officer)
/s/ M. Susan Hardwick Vice President & Controller February 23, 2005
- ---------------------------- (Principal Accounting Officer) -------------------
M. Susan Hardwick
/s/ John M. Dunn Director February 23, 2005
- ---------------------------- -------------------
John M. Dunn
/s/ John D. Engelbrecht Director February 23, 2005
- ---------------------------- -------------------
John D. Engelbrecht
/s/ Anton H. George Director February 23, 2005
- ---------------------------- -------------------
Anton H. George
/s/ Robert L. Koch II Director February 23, 2005
- ---------------------------- -------------------
Robert L. Koch II
/s/ William G. Mays Director February 23, 2005
- ---------------------------- -------------------
William G. Mays
/s/ J. Timothy McGinley Director February 23, 2005
- ---------------------------- -------------------
J. Timothy McGinley
/s/ Richard P. Rechter Director February 23, 2005
- ---------------------------- -------------------
Richard P. Rechter
/s/ Ronald G. Reherman Director February 23, 2005
- ---------------------------- -------------------
Ronald G. Reherman
/s/ R. Daniel Sadlier Director February 23, 2005
- ---------------------------- -------------------
R. Daniel Sadlier
/s/ Richard W. Shymanski Director February 23, 2005
- ---------------------------- -------------------
Richard W. Shymanski
/s/ Jean L.Wojtowicz Director February 23, 2005
- ---------------------------- -------------------
Jean L.Wojtowicz