UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________________ to _____________________
Commission file number: 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of incorporation (IRS Employer
or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 812-491-4000 Securities
registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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Common - Without Par New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X|. No ___.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X|. No __.
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
30, 2003, was $1,691,200,174.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Common Stock - Without Par Value 75,792,899 January 30, 2004
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Class Number of Shares Date
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2004
Annual Meeting of Stockholders, which will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A, not later than 120 days after
the end of the fiscal year, is incorporated by reference in Part III of this
Form 10-K.
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions of
megawatt hours (gigawatt hour)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission
IDEM: Indiana Department of PUCO: Public Utilities Commission of
Environmental Management Ohio Consumer Counselor
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF/BCF: millions / billions of USEPA: United States Environmental
cubic feet Protection Agency
MDth/MMDth: thousands /millions of Throughput: combined gas sales and gas
dekatherms transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ........................................................... 4
2 Properties ......................................................... 10
3 Legal Proceedings................................................... 12
4 Submission of Matters to Vote of Security Holders................... 12
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities ................. 12
6 Selected Financial Data............................................. 13
7 Management's Discussion and Analysis of Results of Operations ......
and Financial Condition............................................. 14
7A Qualitative and Quantitative Disclosures About Market Risk.......... 42
8 Financial Statements and Supplementary Data......................... 44
9 Change in and Disagreements with Accountants on Accounting ......... 88
and Financial Disclosure
9A Controls and Procedures............................................. 88
Part III
10 Directors and Executive Officers of the Registrant.................. 90
11 Executive Compensation.............................................. 91
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.......................... 92
13 Certain Relationships and Related Transactions...................... 92
14 Principal Accountant Fees and Services.............................. 93
Part IV
15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K......................................................... 93
Signatures.......................................................... 95
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge through its website at www.vectren.com, or by request, directed
to Investor Relations at the mailing address, phone number, or email address
that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812) 491-4000 Steven M. Schein
Evansville, Indiana Vice President, Investor Relations
47702-0209 sschein@vectren.com
PART I
ITEM 1. BUSINESS
Description of the Business
Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP) are the
predecessor companies to Vectren Corporation. Indiana Energy, incorporated under
Indiana law on October 24, 1985, was engaged in natural gas distribution, gas
portfolio administrative services, and marketing of natural gas, electric power
and related services. Indiana Energy had fourteen subsidiaries, including ten
nonregulated direct or indirect subsidiaries, a not-for-profit foundation and
three utility subsidiaries, as well as investments in four nonregulated joint
ventures. SIGCORP, incorporated under Indiana law on October 19, 1994, was
engaged in electric generation, transmission, and distribution, natural gas
distribution, coal mining, and broadband communication services. SIGCORP had
eleven wholly owned subsidiaries, including ten nonregulated subsidiaries.
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999, solely for the purpose of
effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax-free exchange of shares that has been accounted for as a pooling-of-
interests in accordance with APB Opinion No. 16 "Business Combinations" (APB
16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. VUHI also has other assets that provide information technology and
other services to the three utilities. Both Vectren and VUHI are exempt from
registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding
Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal and generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has other businesses that provide utility
services, municipal broadband consulting, and retail products and services that
invest in energy-related opportunities, real estate and leveraged leases. The
nonregulated group supports the Company's regulated utilities pursuant to
service contracts by providing natural gas supply services, coal, utility
infrastructure services, and other services.
Acquisition of the Gas Distribution Assets of the Dayton Power and Light Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.
The Company holds the natural gas distribution assets in Ohio as a tenancy in
common through two separate wholly owned subsidiaries. Vectren Energy Delivery
of Ohio, Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and
Indiana Gas holds a 47% undivided ownership interest. VEDO is the operator of
the assets, and these operations are referred to as "the Ohio operations."
Narrative Description of the Business
The Company segregates its operations into three groups: 1) Utility Group, 2)
Nonregulated Group, and 3) Corporate and Other Group. At December 31, 2003, the
Company had $3.4 billion in total assets, with $2.9 billion (87%) attributed to
the Utility Group, $0.4 billion (12%) attributed to the Nonregulated Group, and
less than $0.1 billion (1%) attributed to the Corporate and Other Group. Net
income for the year ended December 31, 2003, was $111.2 million, or $1.58 per
share of common stock, with $85.6 million attributed to the Utility Group, $27.6
million attributed to the Nonregulated Group, and a net loss of $2.0 million
attributed to the Corporate and Other Group. Net income for the year ended
December 31, 2002, was $114.0 million, or $1.69 per share of common stock.
For further information, refer to Note 17 regarding the activities and assets of
operating segments within these Groups, Note 18 regarding special charges in
2001, Note 4 regarding the extraordinary loss in 2001, and Note 15 regarding the
cumulative effect of change in accounting principle in 2001 in the Company's
consolidated financial statements included under "Item 8 Financial Statements
and Supplementary Data".
Following is a more detailed description of the Utility Group and Nonregulated
Group. The operations of the Corporate and Other Group are not significant.
Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and other operations that
provide information technology and other support services to those regulated
operations. The Gas Utility Services segment includes the operations of Indiana
Gas, the Ohio operations, and SIGECO's natural gas distribution business and
provides natural gas distribution and transportation services to nearly
two-thirds of Indiana and to west central Ohio. The Electric Utility Services
segment includes the operations of SIGECO's electric transmission and
distribution services, which provides electricity primarily to southwestern
Indiana, and includes the Company's power generating and marketing operations.
The Utility Group's other operations are not significant.
Gas Utility Services
At December 31, 2003, the Company supplied natural gas service to 972,230
Indiana and Ohio customers, including 887,891 residential, 80,292 commercial,
and 4,047 industrial and other customers. This represents customer base growth
of 0.6% compared to 2002.
The Company's service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served include
automotive assembly, parts and accessories, feed, flour and grain processing,
metal castings, aluminum products, appliance manufacturing, polycarbonate resin
(Lexan) and plastic products, gypsum products, electrical equipment, metal
specialties, glass, steel finishing, pharmaceutical and nutritional products,
gasoline and oil products, and coal mining. The largest Indiana communities
served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and
Richmond. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2003, natural gas revenues were approximately
$1,112.3 million, of which residential customers accounted for 67%, commercial
25%, and industrial and other 8%, respectively.
The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) were 209,344 MDth for the year ended December 31, 2003. Gas
transported or sold to residential and commercial customers were 118,460 MDth
representing 57% of throughput. Gas transported or sold to industrial and other
contract customers were 90,884 MDth representing 43% of throughput. Rates for
transporting gas provide for the same margins generally earned by selling gas
under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company has storage capacity at
seven active underground gas storage fields, six liquefied petroleum air-gas
manufacturing plants, and a propane cavern. The Company also contracts with
ProLiance Energy, LLC (ProLiance or ProLiance Energy) to ensure availability of
gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of
Energy Marketing & Services below and Note 3 in the Company's consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding transactions with ProLiance). Purchased natural gas is injected
into storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately
1,775,657 MCF of gas per day can be delivered during peak demand periods from
all sources and for all utilities.
Gas Purchases
In 2003, the Company purchased 118,684 MDth volumes of gas at an average cost of
$6.36 per Dth, substantially all of which was purchased from ProLiance which
buys the gas as an agent. The average cost of gas per Dth purchased for the last
five years was: $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; $5.60 in 2000; and
$3.58 in 1999.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment and issues
involving manufactured gas plants.
Electric Utility Services
At December 31, 2003, the Company supplied electric service to 135,098 Indiana
customers, including 117,868 residential, 17,054 commercial, and 176 industrial
and other customers. This represents customer base growth of 0.8% compared to
2002. In addition, the Company is obligated to provide for firm power
commitments to four municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.
The principal industries served include polycarbonate resin (Lexan) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the year ended December 31, 2003, retail and firm wholesale electricity
sales totaled 5,898,852 MWh, resulting in revenues of approximately $309.1
million. Residential customers accounted for 34% of 2003 revenues; commercial
27%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 4,305,190 MWh through wholesale contracts in 2003, generating revenue, net
of purchased power costs, of $26.5 million.
Generating Capacity
Installed generating capacity as of December 31, 2003, was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and natural gas or
oil-fired turbines used for peaking or emergency conditions provide 295 MW. New
peaking capacity of 80 MW fueled by natural gas was added during 2002 and was
available for the summer peaking season.
In addition to its generating capacity, in 2003, the Company had 32 MW available
under firm contracts and 95 MW available under interruptible contracts. In
October 2003, the Company executed a firm purchase supply contract for a maximum
of 73MW for the peak cooling season months in each of the next three years.
The Company has interconnections with Louisville Gas and Electric Company,
Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability has been, and may continue to be, impacted
because the Company, as a member of the Midwest Independent System Operator
(MISO), has turned over operational control over the interchange facilities and
its own transmission assets, like many other Midwestern electric utilities, to
the MISO. See "Item 7 Management's Discussion and Analysis of Results of
Operations and Financial Condition" regarding the Company's participation in
MISO.
Total load for each of the years 1999 through 2003 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
Date of summer peak load 8/27/2003 8/5/2002 7/31/2001 8/17/2000 7/6/1999
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Total load at peak (1) 1,272 1,258 1,234 1,212 1,255
Generating capability 1,351 1,351 1,271 1,256 1,256
Firm purchase supply 32 82 82 75 -
Interruptible contracts 95 95 95 95 95
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Total power supply capacity 1,478 1,528 1,448 1,426 1,351
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Reserve margin at peak 16% 21% 17% 18% 8%
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(1) The total load at peak is increased 25 MW in 2003, 2002, 2001, and 1999
from the total load actually experienced. The additional 25 MW represents
load that would have been incurred if summer cycler programs had not been
activated. The 25 MW is also included in the interruptible contract portion
of the Company's total power supply capacity. On the date of peak in 2000,
summer cycler programs were not activated.
The winter peak load of the 2002-2003 season of approximately 948 MW occurred on
January 27, 2003, and was 11% higher than the previous winter peak load of
approximately 854 MW which occurred on March 4, 2002.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO, and supplies power requirements to the United States Department of
Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for, any
available power in excess of the DOE contract demand. At the present time, the
DOE contract demand is essentially zero. Because of this decreased demand, the
Company's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.
Such generating capacity is included in firm purchase supply in the chart above.
Fuel Costs and Purchased Power
Electric generation for 2003 was fueled by coal (99.3%) and natural gas (0.7%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of the Company. Approximately 3.1 million tons of coal were purchased
for generating electricity during 2003, of which substantially all was supplied
by Vectren Fuels, Inc. from its mines and third party purchases. The average
cost of coal consumed in generating electric energy for the years 1999 through
2003 follows:
Year Ended December 31,
-----------------------------------------------
Avg. Cost Per 2003 2002 2001 2000 1999
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Ton $ 24.91 $ 23.50 $ 22.48 $ 22.49 $ 21.88
MWh 11.93 11.00 10.53 10.39 10.13
The Company will also purchase power as needed from the wholesale market to
supplement its generation capabilities in periods of peak demand; however, the
majority of power purchased through the wholesale market is used to optimize and
hedge the Company's sales to other wholesale customers. Volumes purchased in
2003 totaled 4,082,404 MWh.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment, and a
discussion of the Company's Clean Air Act Compliance Plan, and the settlement of
USEPA's lawsuit against SIGECO for alleged violations of the Clean Air Act.
Competition
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding competition within the regulated utility industry
for the Company's regulated Indiana and Ohio operations.
Nonregulated Group
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband.
Energy Marketing and Services
The Energy Marketing and Services group relies heavily upon a customer focused,
value added strategy. The group provides natural gas and fuel supply management
services to a broad range of municipalities, utilities, industrial operations,
schools, and healthcare institutions through ProLiance Energy, an unconsolidated
affiliate of the Company and Citizens Gas. The Company contracted for all
natural gas purchases through ProLiance in 2003. The group also focuses on
performance-based energy contracting through Energy Systems Group, LLC (ESG).
This service helps schools, hospitals, and other governmental and private
institutions reduce their energy and maintenance costs by upgrading their
facilities with energy-efficient equipment.
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets totaling $19.2 million,
including cash of $2.0 million, Vectren's allocable share of ProLiance's profits
and losses increased from 52.5% to 61%, consistent with Vectren's new ownership
percentage. In March 2001, Vectren's allocable share of profits and losses
increased from 50% to 52.5% when ProLiance began managing the Ohio operations'
gas portfolio. Governance and voting rights remain at 50% for each member and
therefore, Vectren continues to account for its investment in ProLiance using
the equity method of accounting.
At December 31, 2003, the Energy Marketing and Services group's natural gas
marketing operations had 1,222 customers, up from 1,060 in 2002. ProLiance's
revenue exceeded $2.2 billion in 2003.
Prior to April 2003, ESG was a consolidated venture between the Company and
Citizens Gas with the Company owning two-thirds. In April 2003, the Company
purchased the remaining interest in ESG for approximately $4 million.
Coal Mining
The Coal Mining group provides the mining and sale of coal to the Company's
utility operations and to other third parties through its wholly owned
subsidiary Vectren Fuels, Inc. The Coal Mining group also generates income tax
credits through IRS Code Section 29 investment tax credits relating to the
production of coal-based synthetic fuels through its 8.3% ownership in Pace
Carbon Synfuels, LP (Pace Carbon). The Company's two coal mines produced 3.3
million tons in 2003, down from 3.5 million in 2002. The Company's investment in
Pace Carbon is accounted for using the equity method of accounting.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water,
electric, and telecommunications companies as well as facilities locating and
meter reading services through its investment in Reliant Services, LLC (Reliant)
and Reliant's 100% ownership in Miller Pipeline, which was purchased by Reliant
in 2000. Reliant is a 50% owned strategic alliance with an affiliate of Cinergy
Corp. and is accounted for using the equity method of accounting.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Broadband group provides these services primarily to the greater Evansville area
in southwestern Indiana. At December 31, 2003, there were over 27,000
residential customers yielding over 81,000 revenue generating units (up from
77,000 at the end of 2002) indicating multiple services being utilized by the
same residential customer. At December 31, 2003, there were approximately 2,000
commercial customers.
The Company has an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of
bundled communication services focusing on last mile delivery to residential and
commercial customers. The Company also has an approximate 19% equity interest in
SIGECOM Holdings, Inc., which was formed by Utilicom to hold interests in
SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater
Evansville, Indiana area.
Utilicom also plans to provide services to Indianapolis, Indiana and Dayton,
Ohio. However, the funding of these projects has been delayed due to the
continued difficult environment within the telecommunication capital markets,
which has prevented Utilicom from obtaining debt financing on terms it considers
acceptable. While the existing investors remain interested in the Indianapolis
and Dayton projects, the Company is not required to make further investments and
does not intend to proceed unless commitments are obtained to fully fund these
projects. Franchising agreements have been extended in both locations.
The convertible subordinated debt investment totals $32.3 million, of which
$30.1 million is convertible into Utilicom ownership at the Company's option or
upon the event of a public offering of stock by Utilicom and $2.2 million is
convertible into common equity interests in the Indianapolis and Dayton ventures
at the Company's option. Upon conversion, the Company would have up to a 16%
interest in Utilicom, assuming completion of all required funding, and up to a
31% interest in the Indianapolis and Dayton ventures.
Other Businesses
In addition to the nonregulated business groups previously discussed, the Other
Businesses group invests in a portfolio of interests in gas and power storage,
distributed generation projects, and similar energy-related businesses.
Additional activities include:
o A retail unit, providing natural gas and other related products and
services primarily in Ohio serving customers opting for choice among
energy providers.
o A broadband consulting business.
Major investments at December 31, 2003, include Haddington Energy Partnerships,
two partnerships both approximately 40% owned; and the wholly owned subsidiaries
Southern Indiana Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC, and
Vectren Communications Services, Inc.
Personnel
As of December 31, 2003, the Company and its consolidated subsidiaries had 1,858
employees, of which 884 are subject to collective bargaining arrangements.
In January 2004, the Company signed a five-year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America locals 12213 and 7441. The agreement provides for
annual wage increases of 3%, a multi-tiered health care plan in which the
employees pay 12% to 16% of the premium, and pension enhancements for early
retirees.
In August 2001, the Company signed a new four-year labor agreement, ending in
September 2005, with Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The new agreement provides for annual wage increases of 3.25%, a new
401(k) savings plan and improvements in the areas of health insurance and
pension benefits.
Concurrent with the Company's purchase of the Ohio operations, VEDO and Local
Union 175, Utility Workers Union of America approved a labor agreement effective
November 2000 through October 2005. The agreement provides a 3.25% wage increase
each year, and the other terms and conditions are substantially the same as the
agreement reached between the Utility Workers Union and Dayton Power and Light
Company in August of 2000.
In July 2000, SIGECO signed a four-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2004. The agreement
provides a 3% wage increase for each year in addition to improvements in health
care coverage, retirement benefits and incentive pay.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana
covering 58,290 acres of land with an estimated ready delivery from storage
capability of 5.2 BCF of gas with maximum peak day delivery capabilities of
119,160 MCF per day. Indiana Gas also owns and operates three liquefied
petroleum (propane) air-gas manufacturing plants located in Indiana with the
ability to store 1.5 million gallons of propane and manufacture for delivery
33,000 MCF of manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.2 BCF of storage
with a maximum peak day delivery capability of 404,614 MCF per day. Indiana Gas
has the ability to meet a total annual demand, utilizing all of its assets
across various pipelines, of 131.1 BCF with a maximum peak day delivery
capability of 1,068,740 MCF per day. Indiana Gas' gas delivery system includes
11,771 miles of distribution and transmission mains, all of which are in Indiana
except for pipeline facilities extending from points in northern Kentucky to
points in southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.
SIGECO owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
124,748 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 18,699 MCF per day. SIGECO has the ability to meet a
total annual demand, utilizing all of its assets across various pipelines, of
28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day.
SIGECO's gas delivery system includes 3,026 miles of distribution and
transmission mains, all of which are located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants and a cavern for propane storage, all of which are located
in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the
plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In
addition to its propane delivery capabilities, the Ohio operations have
contracted for 13.1 BCF of storage with a maximum peak day delivery capability
of 280,667 MCF per day. The Ohio operations have the ability to meet a total
annual demand, utilizing all of its assets across various pipelines, of 57.9 BCF
with a maximum peak day delivery capability of 477,974 MCF per day. The Ohio
operations' gas delivery system includes 5,216 miles of distribution and
transmission mains, all of which are located in Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2003, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80 MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution
system includes 3,224 pole miles of lower voltage overhead lines and 289 trench
miles of conduit containing 1,622 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed
capacity of 2,368.6 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Nonregulated Properties
Subsidiaries other than the utility operations have no significant properties
other than the ownership and operation of coal mining property in Indiana and
investments in real estate partnerships, leveraged leases, and notes receivable.
The assets of the coal mining operations comprise approximately 3% percent of
total assets.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture
dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee,
and Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 13 of its consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding the Clean Air Act and related legal proceedings. Legal
proceedings regarding the Culley generating station's compliance with the Clean
Air Act were substantially resolved during 2003.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,
AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock trades on the New York Stock Exchange under the
symbol "VVC." For each quarter in 2003 and 2002, the high and low sales prices
for the Company's common stock as reported on the New York Stock Exchange and
dividends paid are shown in the following table.
Common Stock Price Range
Cash ------------------------
2003 Dividend High Low
- ---- -------- ------- -------
First Quarter $ 0.275 $ 24.50 $ 19.70
Second Quarter 0.275 26.13 21.05
Third Quarter 0.275 25.02 22.25
Fourth Quarter 0.285 24.85 22.73
2002
First Quarter $ 0.265 $ 25.95 $ 22.45
Second Quarter 0.265 26.10 23.10
Third Quarter 0.265 25.44 17.95
Fourth Quarter 0.275 25.00 21.05
On January 28, 2004, the board of directors declared a dividend of $0.285 per
share, payable on March 1, 2004, to common shareholders of record on February
13, 2004.
As of January 30, 2004, there were 12,889 shareholders of record of the
Company's common stock.
Dividends on shares of common stock are payable at the discretion of the board
of directors out of legally available funds. Future payments of dividends, and
the amounts of these dividends, will depend on the Company's financial
condition, results of operations, capital requirements, and other factors.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K. Operating
revenues for the years ended December 31, 2002, through December 31, 1999, have
been reclassified to reflect the adoption of EITF 03-11. Total assets as of
December 31, 2002, also reflect a reclassification for the adoption of SFAS 143.
See Note 15 and Note 2 to the consolidated financial statements for further
information on the adoption of EITF 03-11 and SFAS 143, respectively, included
under Item 8 "Financial Statements and Supplementary Data."
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001 (1) 2000 (2,3) 1999
- ---------------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $1,587.7 $1,523.8 $2,009.1 $1,607.6 $1,056.2
Operating income $ 199.4 $ 211.3 $ 127.9 $ 131.7 $ 160.8
Income before extraordinary loss &
cumulative effect of change in
accounting principle $ 111.2 $ 114.0 $ 59.3 $ 72.0 $ 90.7
Net income $ 111.2 $ 114.0 $ 52.7 $ 72.0 $ 90.7
Average common shares outstanding 70.6 67.6 66.7 61.3 61.3
Fully diluted common shares outstanding 70.8 67.9 66.9 61.4 61.4
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting principle $ 1.58 $ 1.69 $ 0.89 $ 1.18 $ 1.48
Basic earnings per share
on common stock $ 1.58 $ 1.69 $ 0.79 $ 1.18 $ 1.48
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting principle $ 1.57 $ 1.68 $ 0.89 $ 1.17 $ 1.48
Diluted earnings per share
on common stock $ 1.57 $ 1.68 $ 0.79 $ 1.17 $ 1.48
Dividends per share on common stock $ 1.11 $ 1.07 $ 1.03 $ 0.98 $ 0.94
Balance Sheet Data:
Total assets $3,353.4 $3,136.5 $2,878.7 $2,943.7 $1,980.5
Long-term debt, net $1,072.8 $ 954.2 $1,014.0 $ 632.0 $ 486.7
Redeemable preferred stock $ 0.2 $ 0.3 $ 0.5 $ 8.1 $ 8.2
Common shareholders' equity $1,071.7 $ 869.9 $ 839.3 $ 733.4 $ 709.8
(1) Merger and integration related costs incurred for the year ended December
31, 2001, totaled $2.8 million. These costs relate primarily to transaction
costs, severance and other merger and acquisition integration activities.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets
were shortened to reflect this decision, resulting in additional
depreciation expense of approximately $9.6 million for the year ended
December 31, 2001. In total, merger and integration related costs incurred
for the year ended December 31, 2001, were $12.4 million ($8.0 million
after tax).
The Company incurred restructuring charges of $19.0 million, ($11.8 million
after tax) relating to employee severance, related benefits and other
employee related costs, lease termination fees related to duplicate
facilities, and consulting and other fees.
(2) Merger and integration related costs incurred for the year ended December
31, 2000, totaled $41.1 million. These costs relate primarily to
transaction costs, severance and other merger and acquisition integration
activities. As a result of merger integration activities, management
identified certain information systems to be retired in 2001. Accordingly,
the useful lives of these assets were shortened to reflect this decision,
resulting in additional depreciation expense of approximately $11.4 million
for the year ended December 31, 2000. In total, merger and integration
related costs incurred for the year ended December 31, 2000, were $52.5
million ($36.8 million after tax).
(3) Reflects two months of results of the Ohio operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto.
Executive Summary of Consolidated Results of Operations
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001
- -----------------------------------------------------------------------------
Net income $ 111.2 $ 114.0 $ 52.7
Attributed to:
Utility Group $ 85.6 $ 97.1 $ 44.8
Nonregulated Group 27.6 19.0 12.1
Corporate & other (2.0) (2.1) (4.2)
- -----------------------------------------------------------------------------
Basic earnings per share $ 1.58 $ 1.69 $ 0.79
Attributed to:
Utility Group $ 1.21 $ 1.44 $ 0.67
Nonregulated Group 0.39 0.28 0.18
Corporate & other (0.02) (0.03) (0.06)
Results
For the year ended December 31, 2003, net income decreased $2.8 million, or
$0.11 per share, when compared to 2002. The decline in earnings was principally
due to the Utility Group's results which decreased $11.5 million, offset by
increased earnings of $8.6 million from the Nonregulated Group. The decrease in
earnings per share of $0.11 also reflects the impact of additional common shares
outstanding resulting from an equity offering of approximately 7.4 million
shares during 2003. The offering netted proceeds of approximately $163 million.
The additional shares had the effect of reducing earnings per share as compared
to 2002 by approximately $0.07.
The increase in Nonregulated Group earnings is due to increased earnings from
the Energy Marketing and Services and Coal Mining Groups and a net gain
recognized from business and investment divestitures. The decrease in Utility
Group earnings was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.
In 2002, consolidated net income increased $61.3 million, or $0.90 per share,
when compared to 2001. The year ended December 31, 2001, included nonrecurring
merger, integration, and restructuring costs and other nonrecurring items
totaling $26.4 million after tax, or $0.40 per share. The increase also reflects
improved Utility Group margins and lower operating costs. These resulted from
favorable weather and lower gas prices and the related reduction in costs
incurred in 2001. Also contributing to the increase was increased Nonregulated
Group earnings from gas marketing operations.
The Utility Group generates revenue primarily from the delivery of natural gas
and electric service to its customers. The primary source of cash flow for the
Utility Group results from the collection of customer bills and the payment for
goods and services procured for the delivery of gas and electric services. The
results of the Utility Group are impacted by weather patterns in its service
territory and general economic conditions both in its service territory as well
as nationally.
The Nonregulated Group generates revenue or earnings from the provision of
services to customers. The activities of the Nonregulated Group are closely
linked to the utility industry, and the results of those operations are
generally impacted by factors similar to those impacting the overall utility
industry.
The Company has in place a disclosure committee that consists of senior
management as well as financial management. The committee is actively involved
in the preparation and review of the Company's SEC filings.
Dividends
Dividends declared for the year ended December 31, 2003, were $1.11 per share
compared to $1.07 per share in 2002 and $1.03 per share in 2001. In October
2003, the Company's board of directors increased its quarterly dividend to
$0.285 per share from $0.275 per share.
Nonrecurring Items in 2001
Merger & Integration Costs
Merger and integration related costs incurred during 2001 totaled $2.8 million.
These costs relate primarily to transaction costs, severance, and other merger
and acquisition integration activities. As a result of merger and integration
activities, management retired certain information systems in 2001. Accordingly,
the useful lives of these assets were shortened to reflect this decision,
resulting in additional depreciation expense of approximately $9.6 million for
the year ended December 31, 2001. In total, merger and integration related costs
incurred during 2001 were $12.4 million ($8.0 million after tax), or $0.12 per
share. Merger and integration activities resulting from the 2000 merger forming
Vectren were completed in 2001.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, the Company's management
and board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $19.0 million ($11.8 million after tax), or $0.18 per share, in 2001.
These charges were comprised of $10.9 million for employee severance, related
benefits and other employee related costs, $4.0 million for lease termination
fees related to duplicate facilities and other facility costs, and $4.1 million
for consulting and other fees incurred through December 31, 2001. The
restructuring program was completed during 2001, except for the departure of
certain employees impacted by the restructuring which occurred during 2002 and
the final settlement of the lease obligation which has yet to occur.
Extraordinary Loss
In June 2001, the Company sold certain leveraged lease investments with a net
book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax),
or $0.12 per share. Because of the transaction's significance and because the
transaction occurred within two years of the effective date of the merger of
Indiana Energy and SIGCORP, which was accounted for as a pooling-of-interests,
APB 16 requires the loss on disposition of these investments to be treated as
extraordinary. Proceeds from the sale of $46.7 million were used to retire
short-term borrowings.
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations and gas marketing operations that are periodically settled
net were required to be recorded at market value. Previously, the Company
accounted for these contracts on settlement. The cumulative impact of the
adoption of SFAS 133 resulting from marking these contracts to market on January
1, 2001, was an earnings gain of approximately $1.8 million ($1.1 million after
tax), or $0.02 per share, recorded as a cumulative effect of change in
accounting principle in the Consolidated Statements of Income. The majority of
this gain results from the Company's power marketing operations.
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the
Company's Utility Group and Nonregulated Group. The detailed results of
operations for the Utility Group and Nonregulated Group are presented and
analyzed before the reclassification and elimination of certain intersegment
transactions necessary to consolidate those results into the Company's
Consolidated Statements of Income. The operations of the Corporate and Other
Group are not significant.
Results of Operations of the Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and other operations that
provide information technology and other support services to those regulated
operations. Gas Utility Services provides natural gas distribution and
transportation services in nearly two-thirds of Indiana and to west central
Ohio. Electric Utility Services provides electricity primarily to southwestern
Indiana, and includes the Company's power generating and marketing operations.
The results of operations of the Utility Group before certain intersegment
eliminations and reclassifications for the years ended December 31, 2003, 2002,
and 2001, follow:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions, except per share data) 2003 2002 2001
- -----------------------------------------------------------------------------
OPERATING REVENUES
Gas utility $1,112.3 $ 908.0 $1,019.6
Electric utility 335.7 328.6 308.5
Other 0.8 0.3 0.2
- -----------------------------------------------------------------------------
Total operating revenues 1,448.8 1,236.9 1,328.3
- -----------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 762.5 570.8 708.9
Fuel for electric generation 86.5 81.6 74.4
Purchased electric energy 16.2 16.8 14.2
Other operating 210.1 198.6 212.1
Merger & integration costs - - 2.8
Restructuring costs - - 15.0
Depreciation & amortization 117.9 110.7 117.9
Taxes other than income taxes 56.6 50.7 51.6
- -----------------------------------------------------------------------------
Total operating expenses 1,249.8 1,029.2 1,196.9
- -----------------------------------------------------------------------------
OPERATING INCOME 199.0 207.7 131.4
OTHER INCOME (EXPENSE)
Other - net 4.8 7.1 5.6
Equity in losses of unconsolidated
affiliates (0.5) (1.8) (0.5)
- -----------------------------------------------------------------------------
Total other income 4.3 5.3 5.1
- -----------------------------------------------------------------------------
Interest expense 66.1 69.1 70.7
- -----------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 137.2 143.9 65.8
- -----------------------------------------------------------------------------
Income taxes 51.6 46.8 21.3
Preferred dividend requirement of
subsidiary - - 0.8
- -----------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 85.6 97.1 43.7
- -----------------------------------------------------------------------------
Cumulative effect of change in
accounting principle - net of tax - - 1.1
- -----------------------------------------------------------------------------
NET INCOME $ 85.6 $ 97.1 $ 44.8
=============================================================================
BASIC EARNINGS PER SHARE $ 1.21 $ 1.44 $ 0.67
=============================================================================
In 2003, Utility Group earnings were $85.6 million as compared to $97.1 million
in 2002 and $44.8 million in 2001. The $11.5 million decrease occurring in 2003
compared to 2002 was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.
Utility Group earnings increased $52.3 million in 2002 compared to 2001. The
year ended December 31, 2001, included nonrecurring merger, integration, and
restructuring costs and other nonrecurring items totaling $15.9 million after
tax. The increase also reflects improved margins and lower operating costs.
These resulted from favorable weather and lower gas prices and the related
reduction in costs incurred in 2001. Weather increased utility earnings by an
estimated $11 million.
Throughout this discussion, the terms Gas Utility margin and Electric Utility
margin are used. Gas Utility margin and Electric Utility margin could be
considered non-GAAP measures of income. Gas Utility margin is calculated as Gas
utility revenues less the Cost of gas sold. Electric Utility margin is
calculated as Electric utility revenues less Fuel for electric generation and
Purchased electric energy. These measures exclude Other operating expenses,
Depreciation and amortization, Taxes other than income taxes, Merger and
integration costs, and Restructuring costs, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of operating performance than,
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.
Significant Fluctuations
Utility Group Margin
Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in its service
territory. Margin generated from sales to industrial and other contract
customers is impacted by overall economic conditions. In general, margin is not
sensitive to variations in gas or fuel costs. It is, however, impacted by the
collection of state mandated taxes which fluctuate with gas costs and also some
level of fluctuation in volumes sold. Electric generating asset optimization
activities are primarily affected by market conditions, the level of excess
generating capacity, and electric transmission availability. Following is a
discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- --------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------
Residential $ 225.3 $ 217.1 $ 201.9
Commercial 65.0 65.5 57.7
Contract 50.5 50.5 48.4
Other 9.0 4.1 2.7
- --------------------------------------------------------------------------
Total gas utility margin $ 349.8 $ 337.2 $ 310.7
==========================================================================
Sold & transported volumes in MMDth:
To residential & commercial customers 118.5 111.9 102.2
To contract customers 90.8 95.8 97.2
- --------------------------------------------------------------------------
Total throughput 209.3 207.7 199.4
==========================================================================
Gas Utility margin for the year ended December 31, 2003, of $349.8 million
increased $12.6 million, or 4%, compared to 2002. It is estimated that weather
near normal for the year and 6% cooler than the prior year, contributed $8
million in increased residential and commercial margin and was the primary
contributor to increased throughput. The remaining increase is primarily
attributable to $4.5 million in higher utility receipts and excise taxes on
higher gas costs and volumes sold and $1.8 million in recovery of Ohio customer
choice implementation costs. These increases are partially offset by the
negative effect of high gas prices on customer usage.
Gas Utility margin for the year ended December 31, 2002, of $337.2 million
increased $26.5 million, or 9%, compared to 2001. The increase is primarily due
to weather 7% cooler for the year and 31% cooler in the fourth quarter. Rate
recovery of excise taxes in Ohio effective July 1, 2001, an increase in the
Percent of Income Payment Plan rider affecting Ohio customers, decreased gas
costs, and customer growth of over one percent also contributed. It is estimated
that weather contributed $10 million to the increase in Gas Utility margin,
various rate recovery riders in Ohio contributed $7 million, and other items,
including the impact of lower gas costs and customer growth, contributed $9
million. The effect of cooler weather was the primary factor driving an overall
4% increase in total throughput.
As noted above, gas cost fluctuations have impacted customer usage during the
years ended December 31, 2003, 2002, and 2001. The average cost per dekatherm of
gas purchased in those years was $6.36 in 2003, $4.57 in 2002, and $5.83 in
2001.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric
Generation and Purchased Electric Energy)
Electric Utility margin by revenue type follows:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -----------------------------------------------------------------------------
Residential & commercial $ 141.1 $ 145.7 $ 134.4
Industrial 53.5 54.9 49.6
Municipalities & other 20.1 16.9 16.8
- -----------------------------------------------------------------------------
Total retail & firm wholesale 214.7 217.5 200.8
Asset optimization 18.3 12.7 19.1
- -----------------------------------------------------------------------------
Total electric utility margin $ 233.0 $ 230.2 $ 219.9
=============================================================================
Retail & Firm Wholesale Margin
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.7 million, a decrease of $2.8 million when compared
to 2002. It is estimated that summer weather 19% cooler than normal and 34%
cooler than last year caused an $8 million decrease in residential and
commercial margin. The estimated effect of weather was partially offset by a
$7.1 million increase in retail electric rates related to recovery of NOx
compliance expenditures and related operating expenses. A slowly recovering
economy continued to negatively impact industrial sales which decreased $1.4
million compared to 2002. As a result primarily of the mild weather and slow
economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90
GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh.
The current year decrease in native load and firm wholesale margin has been
offset by increased optimization margin as more fully described below.
For the year ended December 31, 2002, margin from serving native load and firm
wholesale customers increased $16.7 million or 8%, when compared to 2001. The
increase results primarily from the effect on residential and commercial sales
of cooling weather considerably warmer than the prior year. Weather in 2002 was
27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002
was positively affected by increased industrial and other wholesale volumes and
rate recovery related to NOx compliance expenditures as the expenditures are
made pursuant to a rate recovery rider approved by the IURC in August 2001. As a
result of warmer weather and increased volumes sold, native load and firm
wholesale volumes sold increased 6%. It is estimated that weather contributed $7
million to the increase in electric utility margin, and the increased industrial
and other wholesale volumes and the NOx recovery rider contributed $8 million.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of
these contracts are integrated with portfolio requirements around power supply
and delivery and are short-term purchase and sale transactions that expose the
Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
- --------------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------------------
Beginning of Year Net Asset Optimization Position $ (0.7) $ 3.3 $ -
Statement of Income Activity
Cumulative effect at adoption of SFAS 133 - - 1.8
Mark-to-market gains (losses) recognized 0.7 (3.6) 1.5
Realized gains recognized 17.6 16.3 17.6
- --------------------------------------------------------------------------------------
Net activity in electric utility margin 18.3 12.7 19.1
- --------------------------------------------------------------------------------------
Net cash received & other adjustments (18.0) (16.7) (17.6)
- --------------------------------------------------------------------------------------
End of Year Net Asset Optimization Position $ (0.4) $ (0.7) $ 3.3
======================================================================================
Included in:
Prepayments & other current assets $ 2.4 $ 3.5 $ 6.1
Accrued liabilities (2.8) (4.2) (2.8)
For the years ended December 31, 2003, 2002, and 2001, volumes sold into the
wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh respectively, while volumes
purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A portion
of volumes purchased in the wholesale market is used to serve native load and
firm wholesale customers, and in 2003, greater amounts of purchased power have
been required for native load due to scheduled outages, which has reduced
capacity available for optimization. Additionally, volumes sold and purchased
were lower in 2003 compared to 2002 due to a shorter term focus in hedging and
optimization strategies. While volumes both sold and purchased in the wholesale
market have decreased during 2003, margin from optimization activities has
increased compared to 2002 due primarily to price volatility. Despite the
increased volumes in 2002, margins were lower in 2002 compared to 2001 due to
reduced price volatility.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.
Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income.
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152.8 $ 302.8 $ 101.4
Purchase contracts (127.0) (275.9) (74.3)
Mark-to-market gains (losses) 0.7 (3.6) 1.5
- -------------------------------------------------------------------------------
Net asset optimization revenue 26.5 23.3 28.6
- -------------------------------------------------------------------------------
Fuel for electric generation (8.2) (10.6) (9.5)
- -------------------------------------------------------------------------------
Asset optimization margin $ 18.3 $ 12.7 $ 19.1
===============================================================================
Utility Group Operating Expenses
Other Operating
For the year ended December 31, 2003, other operating expenses increased $11.5
million compared to 2002. The increase is principally caused by increased
distribution, plant, and transmission operating expenses; power plant and other
maintenance; customer service initiatives; higher insurance premiums; and prior
year insurance recoveries. In addition, operating expenses reflect $1.8 million
in amortization of Ohio choice implementation costs, which are recovered through
increased gas utility margin. The increase in operating expenses was partially
offset by the impact of an Ohio regulatory order. The order allows the deferral
and recovery of uncollectible accounts expense to the extent it differs from the
level included in base rates. The Company estimated the difference to
approximate $4 million in excess of that included in base rates in 2003.
Other operating expenses decreased $13.5 million for the year ended December 31,
2002, when compared to 2001. The decrease results primarily from lower gas
prices and the related reduction in costs incurred in 2001. Specific expenses
affected by increased gas costs in 2001 were uncollectible accounts expense of
$3.4 million and contributions to low income heating assistance programs of $2.0
million. Insurance recovery in 2002 of $2.8 million of certain maintenance costs
incurred in 2001 also contributed to the decrease.
Depreciation & Amortization
For the year ended December 31, 2003, depreciation and amortization increased
$7.2 million compared to 2002 due to additions to utility plant. Increased
depreciation expense reflects depreciation of utility plant placed into service
including a full year for a gas-fired peaker unit, expenditures for implementing
a choice program for Ohio gas customers, customer system upgrades, and other
upgrades to existing transmission and distribution facilities.
Depreciation and amortization decreased $7.2 million for the year ended December
31, 2002, when compared to 2001. The decrease results from $9.6 million of
expense recognized in 2001 related to assets which had useful lives shortened as
a result of the merger. The discontinuance of goodwill amortization as required
by SFAS 142, which approximated $4.9 million in 2001, also contributed to the
decrease. These decreases were offset somewhat by depreciation of utility plant
and non-utility property additions.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5.9 million in 2003 compared to 2002.
Higher utility receipts and excise taxes of $4.5 million were recognized in 2003
due to higher gas prices and more volumes sold compared to 2002. The remaining
increase results principally from higher property taxes.
Taxes other than income taxes decreased $0.9 million in 2002 compared to 2001 as
a result of lower revenues subject to the Indiana utility receipts tax.
Utility Group Other Income (Expense) - Net
Other - net
Other - net decreased $2.3 million in 2003 compared to 2002 and increased $1.5
million in 2002 compared to 2001. The 2003 decrease is primarily due to the $3.9
million write-off of notes receivable and preferred equity investments in BABB
International (BABB), an entity that processed fly ash into building materials.
The 2002 increase results primarily from gains recognized from the sale of
excess emission allowances and other assets.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates increased $1.3 million in 2002
compared to 2001 principally due to increased losses and increased preferred
ownership in BABB. The smaller loss recognized in 2003 results from the
write-off of the BABB investment.
Utility Group Interest Expense
Interest expense decreased $3.0 million in 2003 compared to 2002 and decreased
$1.6 million in 2002 compared to 2001. The 2003 decrease reflects the impact of
permanent financing completed in the third quarter of 2003. Lower average
interest rates on adjustable rate debt also contributed to the decreases in 2003
and 2002.
Utility Group Income Taxes
For the year ended December 31, 2003, federal and state income taxes increased
$4.8 million in 2003 compared to 2002 and increased $25.5 million in 2002
compared to 2001. The 2003 increase results primarily from an increased
effective tax rate that reflects an increase in the Indiana state income tax
rate from 4.5 % to 8.5% and other changes in the effective tax rate recognized
in 2002. The increase in 2002 compared to 2001 is principally due to higher
pre-tax earnings.
Competition
The utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation. Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003.
Indiana has not adopted any regulation requiring gas choice; however, the
Company operates under approved tariffs permitting large volume customers to
choose their commodity supplier.
Other Operating Matters
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. In December 2001, the IURC approved the Company's request for
authority to transfer operational control over its electric transmission
facilities to the MISO. That transfer occurred on February 1, 2002.
Issues pertaining to certain of MISO's tariff charges for its services remain to
be determined by the FERC. Given the outstanding tariff issues, as well as the
potential for additional growth in MISO participation, the Company is unable to
determine the future impact MISO participation may have on its operations.
Pursuant to an order from the IURC, certain MISO costs are deferred for future
recovery.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, and export power to the
wholesale market may be impacted. Given the nature of MISO's policies regarding
use of transmission facilities, as well as ongoing FERC initiatives, it is
difficult to predict the impact on operational reliability. The potential need
to expend capital for improvements to the transmission system, both to SIGECO's
facilities as well as to those facilities of adjacent utilities, over the next
several years will become more predictable as MISO completes studies related to
regional transmission planning and improvements. Such expenditures may be
significant.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxide (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible with which to comply.
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for NOx emissions in
amounts that contributed to non-attainment with the ozone NAAQS in downwind
states. The USEPA required each state to revise its SIP to provide for further
NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's
final ruling, requires a 31% reduction in total NOx emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an 8 percent
return on its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations in the
government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO has entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request On January 23, 2001, SIGECO received an information request
from the USEPA under Section 114 of the Act for historical operational
information on the Warrick and A.B. Brown generating stations. SIGECO has
provided all information requested with the most recent correspondence provided
on March 26, 2001.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of
service, accounting matters, issuance of securities, and certain other
operational matters specific to its Indiana customers are regulated by the IURC.
The retail gas operations of the Ohio operations are subject to regulation by
the PUCO.
All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR clauses allow the Company to charge for changes in the cost of purchased
gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows
for adjustment in charges for electric energy to reflect changes in the cost of
fuel and the net energy cost of purchased power. Rate structures in the
Company's territories do not include weather normalization-type clauses that
authorize the utility to recover gross margin on sales established in its last
general rate case, regardless of actual weather patterns.
GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings
to establish the amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any under-or-over-recovery
resulting from gas and fuel adjustment clauses each month in revenues. A
corresponding asset or liability is recorded until the under-or-over-recovery is
billed or refunded to utility customers.
The IURC has also applied the statute authorizing GCA and FAC procedures to
reduce rates when necessary to limit net operating income to a level authorized
in its last general rate order through the application of an earnings test. For
the recent past, the earnings test has not affected the Company's ability to
recover costs, and the Company does not anticipate the earnings test will
restrict recovery in the near future.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
account expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.
Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.
Recovery of Purchased Power
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2004,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
Regulatory Initiatives
In addition to the timely recovery of incremental NOx environmental expenditures
discussed above, the Company is pursuing base rate cases in its three gas
territories. The last general rate increase for VEDO and Indiana Gas was in
1992, and was in 1996 for SIGECO gas.
The Company is currently in a collaborative dialogue with the OUCC regarding
SIGECO's existing gas rates. If an agreement is reached between the parties as a
result of that process, it will be subject to review and approval by the IURC.
The Company expects to file a base rate case for Indiana Gas' territory during
the first quarter of 2004 and for VEDO in the second quarter of 2004.
Additionally, as part of the rate case process, the Company is pursuing
authority for recovery of the costs to comply with the Pipeline Safety Act of
2002 and for regulatory authority to amortize periodic expense incurred to
overhaul its electric turbines. The timing and ultimate outcome of any of these
regulatory initiatives is uncertain.
Results of Operations of the Nonregulated Group
The Nonregulated Group is comprised of four primary business areas: Energy
Marketing and Services, Coal Mining, Utility Infrastructure Services, and
Broadband. Energy Marketing and Services markets natural gas and provides energy
management services, including energy performance contracting services. Coal
Mining mines and sells coal and generates IRS Code Section 29 investment tax
credits relating to the production of coal-based synthetic fuels. Utility
Infrastructure Services provides underground construction and repair, facilities
locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the Nonregulated Group has other businesses that provide utility
services, municipal broadband consulting, and retail products and services, and
that invest in energy-related opportunities, real estate, and leveraged leases.
The Nonregulated Group supports the Company's regulated utilities pursuant to
service contracts by providing natural gas supply services, coal, utility
infrastructure services, and other services. The results of operations of the
Nonregulated Group before certain intersegment eliminations and
reclassifications for the years ended December 31, 2003, 2002, and 2001, follow:
- ------------------------------------------------------------------------
(In millions, except per share amounts) 2003 2002 2001
- ------------------------------------------------------------------------
Energy services & other revenues $ 219.2 $ 352.3 $ 741.8
Operating Expenses:
Cost of energy services & other 180.7 311.5 699.1
Operating expenses 37.2 36.1 36.3
Restructuring costs - - 3.5
- ------------------------------------------------------------------------
Total operating expenses 217.9 347.6 738.9
- ------------------------------------------------------------------------
OPERATING INCOME 1.3 4.7 2.9
Other income:
Equity in earnings of unconsolidated
affiliates 12.7 10.9 13.9
Other - net 10.2 6.1 11.4
- ------------------------------------------------------------------------
Total other income 22.9 17.0 25.3
- ------------------------------------------------------------------------
Interest expense 9.7 9.1 12.5
- ------------------------------------------------------------------------
INCOME BEFORE TAXES 14.5 12.6 15.7
Income taxes (13.2) (6.9) (4.7)
Minority interest 0.1 0.5 0.6
- ------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY LOSS 27.6 19.0 19.8
Extraordinary loss - net of tax - - (7.7)
- ------------------------------------------------------------------------
NET INCOME $ 27.6 $ 19.0 $ 12.1
========================================================================
BASIC EARNINGS PER SHARE $ 0.39 $ 0.28 $ 0.18
========================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 20.7 $ 15.0 $ 11.3
Coal Mining 13.8 12.2 13.6
Utility Infrastructure (0.8) (1.2) (0.6)
Broadband (1.0) 0.4 (0.1)
Other Businesses (5.1) (7.4) (12.1)
Nonregulated earnings for the year ended December 31, 2003, increased $8.6
million. Energy Marketing and Services' recurring operations contributed $18.1
million in earnings, or $3.1 million of the increase over 2002. A majority of
the Energy Marketing and Services' earnings were generated by gas marketing
operations, and a majority of the increase, or $2.3 million, was contributed by
performance contracting operations. Coal Mining increased $1.6 million due to
increased synfuel-related earnings, offset by lower mining results. In addition,
net gains totaling $2.7 million after tax were recognized in 2003 from business
and investment divestitures.
For the year ended December 31, 2002, earnings from the Nonregulated Group
increased $6.9 million when compared to 2001. The increase is primarily due to
increased earnings from gas marketing operations which are part of the Energy
Marketing and Services and a smaller loss incurred by the Company's broadband
consulting operations which are part of Other Businesses. The year ended
December 31, 2001, included $2.2 million after tax, or $0.04 per share, in
nonrecurring restructuring costs and $7.7 million after tax, or $0.12 per share,
related to an extraordinary loss from the divestiture of leveraged leases. In
addition, 2001 benefited from gains recognized upon sale of investments by an
unconsolidated affiliate, and 2002 was negatively affected by a change in
Indiana corporate income tax laws enacted in June 2002, which required the
recalculation of deferred tax obligations and earnings from leveraged lease
investments at the date of enactment of the law.
Energy Marketing & Services
Energy Marketing and Services is comprised of the Company's gas marketing and
performance contracting operations and held the Company's investment in
Genscape, Inc. (Genscape), a company that provides real-time power plant and
transmission line status information using wireless technology. The investment
in Genscape was sold in the third quarter of 2003 resulting in an after tax gain
of $2.6 million.
Gas marketing operations are performed through the Company's investment in
ProLiance Energy LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). ProLiance provides
natural gas and related services to Indiana Gas, the Ohio operations, and
Citizens Gas and also began providing services to SIGECO and Vectren Retail, LLC
(the Company's retail gas marketer) in 2002. ProLiance's primary businesses
include gas marketing, gas portfolio optimization, and other portfolio and
energy management services. ProLiance's primary customers are utilities and
other large end use customers.
In June 2002, the integration of Vectren's wholly owned gas marketing
subsidiary, SIGCORP Energy Services, LLC (SES), with ProLiance was completed.
SES provided natural gas and related services to SIGECO and others prior to the
integration. In exchange for the contribution of SES' net assets totaling $19.2
million, Vectren's allocable share of ProLiance's profits and losses increased
from 52.5% to 61%, consistent with Vectren's new ownership percentage. The
transfer of net assets was accounted for at book value, consistent with joint
venture accounting, and did not result in any gain or loss. In March 2001,
Vectren's allocable share of profits and losses increased from 50% to 52.5% when
ProLiance began managing the Ohio operations' gas portfolio. Governance and
voting rights remain at 50% for each member; and therefore, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
Energy Systems Group, LLC (ESG) provides energy performance contracting and
facility upgrades through its design and installation of energy-efficient
equipment. Prior to April 2003, ESG was a consolidated venture between the
Company and Citizens Gas with the Company owning two-thirds. In April 2003, the
Company purchased the remaining interest in ESG for approximately $4 million.
Net income generated by Energy Marketing and Services for the year ended
December 31, 2003, was $20.7 million, as compared to $15.0 million in 2002 and
$11.3 million in 2001. Gas marketing operations, performed through ProLiance,
contributed $15.3 million in earnings in 2003, as compared to $14.6 million in
2002, and $10.5 million in 2001. The $0.7 million increase over 2002 was
principally attributable to increased storage capacity coupled with more
volatile gas prices, offset by settlement disputes related to the contingency
discussed below. The $4.1 million increase in 2002 compared to 2001 is primarily
due to increased operations at ProLiance and increased ownership. The
performance contracting operations, performed through ESG, contributed earnings
$3.0 million in 2003, $0.7 million in 2002, and $0.9 million in 2001. The $2.3
million increase in 2003 compared to 2002 is due primarily to success in
obtaining higher margins and working from a higher construction backlog at the
end of 2002 as well as increased ownership as of April 2003.
ProLiance Contingency
There is currently a lawsuit pending in the United States District Court for the
Northern District of Alabama filed by the City of Huntsville, Alabama d/b/a
Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville
Utilities asserts claims based on negligent provision of portfolio services
and/or pricing advice, fraud, fraudulent inducement, and other theories. These
claims relate generally to several basic arguments: (1) negligence in providing
advice and/or administering portfolio arrangements; (2) alleged promises to
provide gas at a below-market rate; (3) the creation and repayment of a "winter
levelizing program" instituted by ProLiance in conjunction with the Manager of
Huntsville's Gas Utility, to allow Huntsville Utilities to pay its gas bills
from the winter of 2000-2001 over an extended period of time coupled with the
alleged ignorance about the program on the part of Huntsville Utilities' Gas
Board, and; (4) the sale of Huntsville Utilities' gas storage supplies to repay
the balance owed on the winter levelizing program and the authority of
Huntsville Utilities' gas manager to approve those sales. In a press conference
on May 21, 2002, Huntsville Utilities asserted its monetary damages to be
approximately $10 million, and seeks to treble that amount. ProLiance has made
counterclaims asserting breach of contract, among others, based on Huntsville
Utilities' refusal to take gas under fixed price agreements. Both parties have
denied the charges contained in the respective claims.
In 2003, ProLiance established reserves for amounts due from Huntsville
Utilities due to uncertainties surrounding collection. ProLiance denies any
wrongdoing, believes its actions were proper under the contract and amendments
signed by the manager of Huntsville's Gas Utility, and is vigorously defending
against the suit. ProLiance is an insured under a policy of insurance providing
defense costs which may provide in whole or in part, indemnification within the
policy limits for claims asserted against ProLiance. Accordingly, no other loss
contingencies have been recorded at this time. However, it is not possible to
predict or determine the outcome of this litigation and accordingly there can be
no assurance that ProLiance will prevail. It is not currently expected that
costs associated with this matter will have a material adverse effect on
Vectren's consolidated financial position or liquidity but an unfavorable
outcome could possibly be material to Vectren's earnings.
Coal Mining
The Coal Mining Group mines and sells coal to the Company's utility operations
and to other third parties through its wholly owned subsidiary Vectren Fuels,
Inc. (Fuels). The Coal Mining Group also generates IRS Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels
through its 8.3% ownership interest in Pace Carbon Synfuels, LP (Pace Carbon).
Pace Carbon developed, owns, and operates four projects to produce and sell
coal-based synthetic fuel (synfuel) utilizing Covol technology. Vectren accounts
for is investment in Pace Carbon using the equity method. In addition, Fuels
receives synfuel-related fees from synfuel producers unrelated to Pace Carbon
for a portion of its coal production.
Coal Mining net income for the year ended December 31, 2003, was $13.8 million,
as compared to $12.2 million in 2002, and $13.6 million in 2001. Synfuel-related
results, which include earnings from Pace Carbon and synfuel processing fees
earned by Fuels, contributed all of the earnings in 2003, $9.0 million in 2002,
and $6.6 million in 2001. Increasing production of synthetic fuel by Pace Carbon
in 2003 and 2002 has generated a greater amount of Section 29 tax credits that
have been utilized by the Company, reducing income tax expense in those years.
The increase in synfuel-related earnings has been offset by mining operations
that have experienced decreased yields due to poor mining conditions and
increased mine development cost amortization.
IRS Section 29 Investment Tax Credit Recent Developments
Under Section 29 of the Internal Revenue Code, manufacturers such as Pace
Carbon, receive a tax credit for every ton of synthetic fuel sold. To qualify
for the credits, the synthetic fuel must meet three primary conditions: 1) there
must be a significant chemical change in the coal feedstock, 2) the product must
be sold to an unrelated person, and 3) the production facility must have been
placed in service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the
synthetic fuel produced at the Pace Carbon facilities should qualify for Section
29 tax credits. The IRS issued a private letter ruling with respect to the four
projects on November 11, 1997, and subsequently issued an updated private letter
ruling on September 23, 2002.
As a partner in Pace Carbon, Vectren has reflected total tax credits under
Section 29 in its consolidated results through December 31, 2003, of
approximately $39 million. Vectren has been in a position to fully utilize the
credits generated and continues to project full utilization.
In June 2003, the IRS, in an industry-wide announcement, stated that it would
review the scientific validity of test procedures and results presented as
evidence of significant chemical change. During this review, the IRS suspended
the issuance of new private letter rulings on that subject. In October 2003, the
IRS completed its review and determined that the test procedures and results
used by taxpayers are scientifically valid if the procedures are applied in a
consistent and unbiased manner. Also, the IRS will issue new private letter
rulings based on revised standards; however, it has continuing concerns
regarding the sampling and data/record retention practices prevalent in the
synthetic fuels industry.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year
and later expanded the audit to include tax years 1999, 2000, and 2001. Based on
conclusions reached in the industry-wide review and recently issued private
letter rulings involving other synthetic fuel facilities, Vectren believes
chemical change issues from these audits may soon be resolved. However, the IRS
has not directly notified Pace Carbon of any resolution.
Vectren believes it is justified in its reliance on the private letter rulings
for the Pace Carbon facilities, that the test results that Pace Carbon presented
to the IRS in connection with its private letter rulings are scientifically
valid, and that Pace Carbon has operated its facilities in compliance with its
private letter rulings and Section 29 of the Internal Revenue Code. However, at
this time, Vectren cannot provide any assurance as to the outcome of these
audits concerning the issue of chemical change or any other issue raised during
the audits relative to its investment in Pace Carbon. Further, it is expected
that Section 29 investments will continue to draw attention from various
interest groups.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair to
gas, water, electric and telecommunications companies primarily through its
investment in Reliant Services, LLC (Reliant) and Reliant's 100% ownership in
Miller Pipeline. Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting.
Results in recent years have been affected by cutbacks of underground
construction and repair projects by gas distribution customers. In the second
half of 2003, Miller returned to profitability due to an increase in
construction and repair projects as utilities began to return to historical
expenditure levels.
Broadband
Broadband invests in communication services, such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Company has an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the
Company's ownership interest up to 16%. Utilicom is a provider of bundled
communication services focusing on last mile delivery to residential and
commercial customers. The Company also has an approximate 19% equity interest in
SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold
interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to over
29,000 customers, averaging nearly 3 revenue generating units per customer, in
the greater Evansville, Indiana area and continues to increase its positive
operating cash flow.
The equity investments in Utilicom and Holdings are accounted for using the cost
method of accounting. As a result, for years ended December 31, 2003, 2002, and
2001, these investments had no significant impact on the Company's operating
results.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana and Dayton, Ohio markets. However, the funding of these projects has
been delayed due to the continued difficult enviro