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