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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, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to ________________________
Commission file number: 1-15467
VECTREN CORPORATION
-----------------------
(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
- ----------------------- -----------------------------------------
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
28, 2002 was $1,624,281,589.
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 68,011,649 February 15, 2003
------------------------------- ---------- -----------------
Class Number of Shares Date
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2003
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 during MMBTU: millions of British thermal units
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 Board NOx: nitrogen oxide
FERC: Federal Energy Regulatory Commission OUCC: Indiana Office of the Utility Consumer
Counselor
IDEM: Indiana Department of Environmental PUCO: Public Utilities Commission of Ohio
Management
IURC: Indiana Utility Regulatory Commission SFAS: Statement of Financial Accounting Standards
MCF / BCF: millions / billions of cubic feet USEPA: United States Environmental Protection
Agency
MDth / MMDth: thousands /millions of dekatherms Throughput: combined gas sales and gas
transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ....................................................... 1
2 Properties ..................................................... 7
3 Legal Proceedings............................................... 9
4 Submission of Matters to Vote of Security Holders............... 9
Part II
5 Market for the Company's Common Equity and Related
Stockholder Matters ....................................... 9
6 Selected Financial Data......................................... 10
7 Management's Discussion and Analysis of Results
of Operations and Financial Condition...................... 11
7A Qualitative and Quantitative Disclosures About Market Risk...... 37
8 Financial Statements and Supplementary Data..................... 39
9 Change in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 85
Part III
10 Directors and Executive Officers of the Company................. 85
11 Executive Compensation.......................................... 86
12 Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters............................ 86
13 Certain Relationships and Related Transactions.................. 87
Part IV
14 Controls and Procedures......................................... 87
15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................ 88
Signatures...................................................... 90
Certifications.................................................. 92
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge through its website at www.vectren.com, or by request, directed
to Investor Relations at the mailing address, phone number, or email address
that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812)491-4000 Steven M. Schein
Evansville, Indiana 47702-0209 Vice President, Investor
Relations
sschein@vectren.com
PART I
ITEM 1. BUSINESS
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999 solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with 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. 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 to the Company's utility operations
and to other parties 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 lease investments.
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 acquired the natural gas distribution assets as a tenancy in common
through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio,
Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana
Gas holds a 47% undivided ownership interest. VEDO is the operator of the
assets, and these operations are referred to as "the Ohio operations."
Narrative Description of the Business
The Company segregates its businesses into gas utility services, electric
utility services, nonregulated, and corporate and other business segments. The
Company collectively refers to its gas and electric utility services segments as
its regulated operations. At December 31, 2002, the Company had $2.9 billion in
total assets, with $2.4 billion (83%) attributed to the regulated operations,
$0.4 billion (14%) attributed to the nonregulated operations, and $0.1 billion
(3%) attributed to the corporate and other group. Net income for the year ended
2002 was $114.0 million, or $1.69 per share of common stock, with $93.6 million
attributed to regulated, $19.0 million attributed to nonregulated, and $1.4
million attributed to corporate and other. Net income, as restated, for the year
ended 2001 was $52.7 million, or $0.79 per share of common stock. The year
ending December 31, 2001 included nonrecurring charges with an after tax impact
of $26.4 million. Nonrecurring items net of tax in 2001 included $8.0 million of
merger and integration costs, $11.8 million of restructuring costs, $7.7 million
of extraordinary loss, and a $1.1 million gain resulting from a cumulative
effect of change in accounting principle.
For further information refer to Note 3 regarding the restatement of previously
reported information, Note 18 regarding the segments' activities and assets,
Note 19 regarding special charges in 2001 and 2000, Note 5 regarding the
extraordinary loss in the Company's consolidated financial statements, and Note
16 regarding the cumulative effect of change in accounting principle included
under Item 8 Financial Statements and Supplementary Data.
Following is a more detailed description of the regulated and nonregulated
business segments. The operations of the corporate and other business segment,
which include primarily information technology services, are not significant.
Regulated Business Segments
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. The Gas Utility Services segment includes
the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes the operations of SIGECO's electric
transmission and distribution services, which provides electricity primarily to
southwestern Indiana, and SIGECO's power generating and power marketing
operations.
Gas Utility Services
At December 31, 2002, the Company supplied natural gas service to 966,761
Indiana and Ohio customers, including 882,151 residential, 80,483 commercial,
and 4,127 industrial and other customers. This represents customer base growth
of 1.4% compared to 2001.
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, 2002, natural gas revenues were approximately
$909.0 million of which residential customers accounted for 67%, commercial 23%,
and industrial and other 10%, respectively.
The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) was 207,693 MDth for the year ended December 31, 2002. Transported
gas represented 44% of total throughput. Rates for transporting gas provide for
the same margins generally earned by selling gas under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company owns and operates eight
underground gas storage fields and six liquefied petroleum air-gas manufacturing
plants. The Company also contracts with ProLiance and other parties to ensure
availability of gas. Natural gas purchased from suppliers is injected into
storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately 909,500
MCF of gas per day can be withdrawn during peak demand periods from all sources
and for all utilities.
Gas Purchases
In 2002, the Company purchased natural gas from multiple suppliers including
ProLiance Energy, LLC (ProLiance). ProLiance is an unconsolidated, nonregulated,
energy marketing affiliate of Vectren and Citizens Gas and Coke Utility. (See
Note 4 in the Company's consolidated financial statements included in Item 8
Financial Statements and Supplementary Data regarding transactions with
ProLiance ). The Company purchased 120,764 MDth volumes of gas in 2002 at an
average cost of $4.57 per Dth, of which 94% was purchased from ProLiance. The
average cost of gas per Dth purchased for the last five years was; $4.57 in
2002; $5.83 in 2001; $5.60 in 2000; $3.58 in 1999; and $3.53 in 1998.
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, 2002, the Company supplied electric service to 134,057 Indiana
customers, including 116,979 residential, 16,881 commercial, and 197 industrial
and other customers. This represents customer base growth of 0.6% compared to
2001. In addition, the Company is obligated to provide for firm power
commitments to several municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.
The principal industries served include polycarbonate resin (Lexan) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the year ended December 31, 2002, retail and firm wholesale electricity
sales totaled 6,187,132 MWh, resulting in revenues of approximately $305.3
million. Residential customers accounted for 35% of 2002 revenues; commercial
26%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 10,711,614 MWh through non-firm wholesale contracts in 2002 generating
revenue of $302.8 million.
Generating Capacity
Installed generating capacity as of December 31, 2002 was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and 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, throughout 2002 the Company had 82MW
available under firm contracts and 95 MW available under interruptible
contracts. On January 1, 2003, a 50 MW firm contract expired and was no longer
required and therefore not renewed.
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 may 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 1998 through 2002 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
Date of summer peak load 8/5/02 7/31/01 8/17/00 7/6/99 7/21/98
------ ------- ------- ------ -------
Total load at peak (1) 1,258 1,234 1,212 1,255 1,154
Generating capability 1,351 1,271 1,256 1,256 1,256
Firm purchase supply 82 82 75 - -
Interruptible contracts 95 95 95 95 85
- ----------------------------------- ----- ----- ----- ----- -----
Total power supply capacity 1,528 1,448 1,426 1,351 1,341
- ----------------------------------- ----- ----- ----- ----- -----
Reserve margin at peak 21% 17% 18% 8% 16%
- ----------------------------------- ----- ----- ----- ----- -----
(1) The total load at peak is increased 25MW in 2002, 2001, 1999, and 1998 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 2001-2002 season of approximately 854 MW occurred on
March 4, 2002 and was 8% lower than the previous winter peak load of
approximately 925 MW which occurred on December 19, 2000.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO 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.
Fuel Costs and Purchased Power
Electric generation for 2002 was fueled by coal (97.5%) and natural gas (2.5%).
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 was purchased
for generating electricity during 2002. Of this amount, Vectren Fuels, Inc.
supplied 2.7 million tons from its mines and third party purchases. The average
cost of coal consumed in generating electrical energy for the years 1998 through
2002 follows:
Year
- -------------------------------------------------------------------------------
Avg. Cost Per 2002 2001 2000 1999 1998
- -------------------------------------------------------------------------------
Ton $ 23.50 $ 22.48 $ 22.49 $ 21.88 $ 21.34
- -------------------------------------------------------------------------------
MWh 11.00 10.53 10.39 10.13 9.97
- -------------------------------------------------------------------------------
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 non-firm wholesale customers. Volumes purchased in
2002 totaled 10,362,196 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 USEPA's
lawsuit against SIGECO for alleged violations of the Clean Air Act.
Competition
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding competition within the public utility industry for
the Company's regulated Indiana and Ohio operations.
Nonregulated Business Segment
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. ProLiance is a
significant gas supplier to the Company's regulated operations. The group also
focuses on performance-based energy contracting through Energy Systems Group,
LLC. 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.
ProLiance is an unconsolidated affiliate of the Company and Citizens Gas and
Coke Utility (Citizens Gas). Energy Systems Group, LLC is a consolidated venture
between the Company and Citizens Gas, with the Company owning two-thirds.
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. Since
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
At December 31, 2002, the Energy Marketing and Services group's natural gas
marketing operations had 1,060 customers, up from 984 in 2001. The collective
revenue of ProLiance and SES exceeded $1.7 billion in 2002.
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. The Company's two coal mines produced 3.5 million tons in
2002, up from 3.3 million in 2001. 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). Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting.
In December 2000, Reliant purchased the common stock of Miller Pipeline
Corporation (Miller) from NiSource, Inc. for approximately $68.3 million.
Vectren and Cinergy Corp. each contributed $16.0 million of equity, and the
remaining $36.3 million was funded with 7-year intermediate bank loans. The
acquisition combines Reliant's utility services of underground facility
locating, contract meter reading, and installation of telecommunications
infrastructure with Miller's underground pipeline construction, replacement, and
repair services. Miller is one of the nation's premier natural gas distribution
contractors with over 50 years of experience in the construction industry,
currently providing such services to Indiana Gas, among other customers.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Broadband group provides telecommunications services to approximately 26,800
residential and commercial customers (an increase of 7.9% from 2001) in the
greater Evansville area in southwestern Indiana. The present customer base has
yielded approximately 78,000 residential revenue generating units (up from
approximately 70,000 at the end of 2001) indicating multiple services being
utilized by the same residential customer.
The Company has a minority 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 a minority 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.
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 utility services business, which supplies utilities with a number of
important services ranging from supply chain management to
environmental compliance testing.
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 include Haddington Energy Partnerships, two partnerships both
approximately 40% owned; CIGMA, LLC, a 50% owned strategic alliance with an
affiliate of Citizens Gas; and the wholly owned subsidiaries Southern Indiana
Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC, Vectren
Communication Services, Inc., and IEI Financial Services, LLC.
Personnel
As of December 31, 2002, the Company and its consolidated subsidiaries had 1,876
employees, of which 896 are subject to collective bargaining arrangements.
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 new four-year labor agreement with Local 702 of
the International Brotherhood of Electrical Workers, ending June 2004. The new
agreement provides a 3% wage increase for each year in addition to improvements
in health care coverage, retirement benefits and incentive pay.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four gas storage fields located in Indiana
covering 58,489 acres of land with an estimated ready delivery from storage
capability of 4.2 BCF of gas with 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 31,000 MCF of manufactured gas
per day. In addition to its owned storage and manufacturing and daily delivery
capabilities, Indiana Gas contracts for a maximum of 17.2 BCF of gas
availability across various pipelines with a delivery capability of 283,298 MCF
per day. Indiana Gas' gas delivery system includes 11,590 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 8.7 BCF of gas with delivery capabilities of 124,748 MCF per day.
In addition to its owned storage and daily delivery capabilities, SIGECO
contracts for a maximum of 0.5 BCF of gas availability across various pipelines
with a delivery capability of 18,753 MCF per day. SIGECO's gas delivery system
includes 2,996 miles of distribution and transmission mains, all of which are
located in Indiana.
The Ohio operations owns and operates three liquefied petroleum (propane)
air-gas manufacturing plants and one cavern for propane storage, all of which
are located in Ohio. The plants and cavern can store 3.7 million gallons of
propane, and the plants can manufacture for delivery 51,047 MCF of manufactured
gas per day. In addition to its owned storage and manufacturing and daily
delivery capabilities, the Ohio operations contracts for a maximum of 13.2 BCF
of gas availability across various pipelines with a delivery capability of
281,491 MCF per day. The Ohio operations' gas delivery system includes 5,176
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, 2002, 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, 50MW and Broadway Avenue Unit 2,
65MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80MW 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 829 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,221.2 megavolt amperes (Mva). The electric distribution
system includes 3,212 pole miles of lower voltage overhead lines and 275 trench
miles of conduit containing 1,541 miles of underground distribution cable. The
distribution system also includes 95 distribution substations with an installed
capacity of 1,939.5 Mva and 50,030 distribution transformers with an installed
capacity of 2,352.3 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 Services
Subsidiaries other than the utility operations have no significant properties
other than the ownership and operation of coal mining property in Indiana and
investments in real estate partnerships, leveraged leases, and notes receivable.
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 14 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 involving transactions with ProLiance were substantially resolved
during 2002. See Note 4 for a discussion of regulatory matters related to
ProLiance.
ITEM 4. Submission of Matters to Vote of Security Holders
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock trades on the New York Stock Exchange under the
symbol "VVC." For each quarter in 2002 and 2001, 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 -------------------------
2002 Dividend High Low
- ---- -------- ------- -------
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
2001
- ----
First Quarter $ 0.255 $ 24.44 $ 21.00
Second Quarter 0.255 23.90 20.38
Third Quarter 0.255 22.46 19.76
Fourth Quarter 0.265 24.07 21.05
On January 22, 2003, the board of directors declared a dividend of $0.275 per
share, payable on March 3, 2003, to common shareholders of record on February
14, 2003.
As of January 31, 2003, there were 13,460 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. The
financial information as of and for the years ended December 31, 2001 and 2000
has been restated. Common shareholders' equity as of January 1, 2000 also
reflects adjustments related to years prior to 2000. See Note 3 to the
consolidated financial statements included under Item 8 Financial Statements and
Supplementary Data for further information on the restatement.
Year Ended December 31
- ----------------------------------------------------------------------------------------------
In millions, except per share data 2002 2001 (1) 2000(2,3) 1999 1998
- ----------------------------------------------------------------------------------------------
(As Restated)
---------------------
Operating Data:
Operating revenues $ 1,804.3 $ 2,081.8 $ 1,632.8 $ 1,068.4 $ 997.7
Operating income $ 211.3 $ 127.9 $ 131.7 $ 160.8 $ 148.5
Income before extraordinary
loss & cumulative effect of
change in accounting principle $ 114.0 $ 59.3 $ 72.0 $ 90.7 $ 86.6
Net income $ 114.0 $ 52.7 $ 72.0 $ 90.7 $ 86.6
Average common shares outstanding 67.6 66.7 61.3 61.3 61.6
Fully diluted common shares
outstanding 67.9 66.9 61.4 61.4 61.8
Basic earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.69 $ 0.89 $ 1.18 $ 1.48 $ 1.41
Basic earnings per share
on common stock $ 1.69 $ 0.79 $ 1.18 $ 1.48 $ 1.41
Diluted earnings per share before
extraordinary loss & cumulative
effect of change in accounting
principle $ 1.68 $ 0.89 $ 1.17 $ 1.48 $ 1.40
Diluted earnings per share
on common stock $ 1.68 $ 0.79 $ 1.17 $ 1.48 $ 1.40
Dividends per share on common stock $ 1.07 $ 1.03 $ 0.98 $ 0.94 $ 0.90
Balance Sheet Data:
Total assets $ 2,926.5 $ 2,878.7 $ 2,943.7 $ 1,980.5 $ 1,798.8
Long-term debt, net $ 954.2 $ 1,014.0 $ 632.0 $ 486.7 $ 388.9
Redeemable preferred stock $ 0.3 $ 0.5 $ 8.1 $ 8.2 $ 8.3
Common shareholders' equity $ 869.9 $ 839.3 $ 733.4 $ 709.8 $ 677.9
(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. As discussed in Note 3 in
the consolidated financial statements, subsequent to the issuance of the
Company's 2001 financial statements, the Company's management determined that
previously issued financial statements should be restated. As a result, the
Company has restated its 2001 and 2000 financial statements and has increased
reported retained earnings as of January 1, 2000 by $1.7 million. The
restatement had the effect of decreasing net income for 2001 and 2000 by $10.9
million and $48,000, respectively. Note 3 in the consolidated financial
statements includes a summary of the significant effects of the restatement. The
effect of the restatement on quarterly results, including previously reported
2002 quarterly information, is discussed in Note 21. The following discussion
and analysis gives effect to the restatement.
Consolidated Results of Operations
Year Ended December 31,
- ----------------------------------------------------------------------------
In millions, except per share amounts 2002 2001 2000
- ----------------------------------------------------------------------------
(As Restated)
------------------
Net income $ 114.0 $ 52.7 $ 72.0
Attributed to:
Regulated $ 93.6 $ 40.1 $ 52.5
Nonregulated 19.0 12.1 21.8
Corporate & other 1.4 0.5 (2.3)
- ----------------------------------------------------------------------------
Basic earnings per share $ 1.69 $ 0.79 $ 1.18
Attributed to:
Regulated $ 1.39 $ 0.60 $ 0.85
Nonregulated 0.28 0.18 0.36
Corporate & other 0.02 0.01 (0.03)
In 2002, consolidated net income increased $61.3 million, or $0.90 per share,
when compared to 2001, as restated. 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. In addition to the
nonrecurring 2001 items, the increase reflects improved margins and lower
operating costs. These resulted from favorable weather and a return to lower gas
prices and the related reduction in costs incurred in 2001. Also contributing to
the increase was increased earnings from the Energy Marketing and Services Group
and a smaller loss in the Other Businesses Group, both of which are components
of nonregulated operations.
In 2001, consolidated net income decreased $19.3 million, or $0.39 per share,
compared to 2000. The year ended December 31, 2000 included nonrecurring merger,
integration, and restructuring costs net of other nonrecurring items totaling
$31.9 million after tax, or $0.52 per share. The decrease reflects lower
regulated earnings resulting from extraordinarily high gas costs early in 2001
that unfavorably impacted margins and operating costs, warmer heating weather,
especially during late 2001, and a weakened national economy. This reduction was
offset somewhat by increased earnings from the Energy Marketing and Services and
Coal Mining Groups, both of which are components of nonregulated operations, and
a decrease in nonrecurring items.
Dividends
In November 2002, the Company's board of directors increased its quarterly
dividend to $0.275 per share from $0.265 per share. Dividends declared for the
year ended December 31, 2002 were $1.07 per share, compared to $1.03 per share
and $0.98 per share for the same periods in 2001 and 2000, respectively.
Restatement of Previously Reported Results
The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.9 million after tax, or $0.16 per
share, and other adjustments, as described below, related to 2000 and prior
periods. Adjustments were also made to previously reported 2002 quarterly
results. In addition to adjustments affecting previously reported net income,
other reclassifications were made to the previously reported 2001 and 2000
results to conform with the 2002 presentation.
Previously Reported 2001 and 2000 Net Income Adjustments
The Company determined that $11.6 million ($7.2 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.
The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $5.6 million ($3.5 million after tax).
The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.
The Company identified reconciliation errors and other errors related to the
recording of estimates that were not significant, either individually or in the
aggregate. As a result of these additional items, 2001 earnings were reduced by
$2.6 million ($1.6 million after tax). Originally reflected in 2001, the
correction of the year 2000 overstatement of electric revenue totaling $2.4
million ($1.5 million after tax), now reflected in 2000 as discussed below,
significantly offset these additional items.
The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an understatement of gas revenue by
$1.8 million ($1.1 million after tax) and an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $.6 million ($.3 million after tax). The impact of
the restatement of results for the year ended 2000 is a reduction to net income
of less than $100,000.
In addition, the Company also reduced previously reported revenues and cost of
sales by $78.1 million in 2001 and $15.5 million in 2000 to adopt EITF Issue No.
99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" and to
properly eliminate certain transactions in consolidation.
Previously Reported 2002 Quarterly Net Income Adjustments
As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, management determined that
the accrual of such carrying costs was more appropriate in periods prior to 2000
when DSM program expenditures were made. Therefore, such carrying costs
originally reflected in 2002 quarterly results were reversed and reflected in
common shareholders' equity as of January 1, 2000. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $1.4 million and $0.9 million after tax,
respectively. The cumulative impact from of these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$2.3 million.
Beginning Retained Earnings Adjustments
In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. As a result of these additional items, beginning
common shareholders' equity was reduced by $1.5 million. Accordingly, retained
earnings as of January 1, 2000 reflects a cumulative net increase of $1.7
million.
Other Balance Sheet Adjustments
Certain reclassifications were made to reflect separate Company prepaid and
accrued taxes that result in the consolidated tax position. This adjustment
added approximately $46.4 million of prepaid and other current assets with a
corresponding increase in accrued liabilities as of December 31, 2001. The
Company also reclassified all previously recorded goodwill not included in rates
to goodwill on the balance sheet. This adjustment resulted in a $5.9 million
decrease in other assets, a $3.0 million decrease in prepayments and other
current assets and an $8.9 million increase in goodwill.
The Company has restated its financial statements to give effect to the matters
discussed above. Following is a summary of the significant effects of the
restatement on previously reported financial position and results of operations.
The effects of the restatement on 2001 quarterly results and on 2002 previously
reported quarterly information, is discussed in Note 21. The consolidated
financial statements are included under Item 8 Financial Statements and
Supplementary Data.
Nonrecurring Items in 2001 and 2000
Merger & Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $41.1 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.
Since March 31, 2000, $43.9 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$20.7 million. Of this amount, $5.5 million related to employee and executive
severance costs, $13.1 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. The remaining $23.2 million was expensed ($20.4 million
in 2000 and $2.8 million in 2001) for accounting fees resulting from
merger-related filing requirements, consulting fees related to integration
activities such as organization structure, employee travel between company
locations, internal labor of employees assigned to integration teams, investor
relations communication activities, and certain benefit costs.
The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.
As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets were
shortened in 2000 to reflect this decision, resulting in additional depreciation
expense of approximately $9.6 million and $11.4 million for the years ended
December 31, 2001 and 2000, respectively.
In total, for the year ended December 31, 2001, merger and integration costs
totaled $12.4 million ($8.0 million after tax), or $0.12 on a basic earnings per
share basis compared to $52.5 million ($36.8 million after tax), or $0.60 on a
basic earnings per share basis in 2000.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, the Company's management
and board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $11.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $7.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $19.0 million, ($11.8 million after tax), or $0.18 on a basic
earnings per share basis 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. (See Note 19 for further information on restructuring costs.)
Extraordinary Loss
In June 2001, the Company sold certain leveraged lease investments with a net
book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax),
or $0.12 on a basic earnings per share basis. Because of the transaction's
significance and because the transaction occurred within two years of the
effective date of the merger of Indiana Energy and SIGCORP, which was accounted
for as a pooling-of-interests, APB 16 requires the loss on disposition of these
investments to be treated as extraordinary. Proceeds from the sale of $46.7
million were used to retire short-term borrowings.
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 on a basic earnings per share basis, 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.
Gain on Restructuring of a Nonregulated Investment
In January 2000, the Company restructured its investment in SIGECOM, LLC
(SIGECOM). Affiliates of The Blackstone Group acquired a majority ownership
interest in Utilicom. In connection with The Blackstone Group investment, the
Company exchanged its 49% preferred equity interest in SIGECOM for $16.5 million
of convertible subordinated debt of Utilicom Networks LLC and an 18.9% common
equity interest in SIGECOM Holdings, Inc, which was valued at $6.5 million. The
carrying value of the Company's 49% preferred equity interest was $15.0 million
prior to the exchange. The Company received consideration in the exchange based
upon an investment bank analysis of the fair value of SIGECOM at the transaction
date. The investment restructuring resulted in a pre-tax gain of $8.0 million
($4.9 million after tax), or $0.08 on a basic earnings per share basis, which is
classified in equity in earnings of unconsolidated affiliates in the
Consolidated Statements of Income. Refer to Note 4 for more information on the
Company's investment in Utilicom-related entities.
Results of Operations by Business Segment
Following is a more detailed discussion of the results of operations of the
Company's regulated and nonregulated businesses. The detailed results of
operations for the regulated businesses and nonregulated businesses are
discussed and analyzed before the reclassification and elimination of certain
intersegment transactions necessary to consolidate those results into the
Company's Consolidated Statements of Income. The operations of the Corporate and
Other business segment, which include primarily information technology services,
are not significant.
Results of Operations of the Regulated Businesses
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. The Gas Utility Services segment includes
the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes the operations of SIGECO's electric
transmission and distribution services, which provides electricity primarily to
southwestern Indiana, and SIGECO's power generating and power marketing
operations. The results of regulated operations before certain intersegment
eliminations and reclassifications for the years ended December 31, 2002, 2001,
and 2000 follows:
In millions,
except per share amounts 2002 2001 2000
- ----------------------------------------------------------------------
OPERATING REVENUES (As Restated)
--------------------
Gas revenues $ 909.0 $1,019.6 $ 820.4
Electric revenues 608.1 381.2 334.4
- ----------------------------------------------------------------------
Total operating revenues 1,517.1 1,400.8 1,154.8
- ----------------------------------------------------------------------
COST OF OPERATING REVENUES
Cost of gas 571.8 708.9 552.5
Fuel for electric generation 81.6 74.4 75.7
Purchased electric energy 296.3 86.9 36.4
- ----------------------------------------------------------------------
Total cost of operating revenues 949.7 870.2 664.6
- ----------------------------------------------------------------------
TOTAL OPERATING MARGIN 567.4 530.6 490.2
OPERATING EXPENSES
Other operating 220.6 241.1 209.0
Merger & integration costs - 2.8 32.7
Restructuring costs - 15.0 -
Depreciation & amortization 96.8 97.2 82.4
Taxes other than income taxes 50.8 51.2 36.2
- ----------------------------------------------------------------------
Total expenses 368.2 407.3 360.3
- ----------------------------------------------------------------------
OPERATING INCOME 199.2 123.3 129.9
OTHER INCOME
Other - net 6.9 5.5 4.7
Equity in earnings of
unconsolidated affiliates (1.8) (0.5) -
- ----------------------------------------------------------------------
Total other income 5.1 5.0 4.7
- ----------------------------------------------------------------------
Interest expense 66.1 70.1 46.1
- ----------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 138.2 58.2 88.5
- ----------------------------------------------------------------------
Income tax 44.6 18.4 35.0
Preferred dividend requirement
of subsidiary - 0.8 1.0
- ----------------------------------------------------------------------
Income before cumulative effect of
change in accounting principle 93.6 39.0 52.5
Cumulative effect of change in
accounting principle - net of tax - 1.1 -
- ----------------------------------------------------------------------
NET INCOME $ 93.6 $ 40.1 $ 52.5
======================================================================
BASIC EARNINGS PER SHARE $ 1.39 $ 0.60 $ 0.85
======================================================================
Utility operations contributed net income of $93.6 million, or $1.39 per share,
for the year ended December 31, 2002 compared to $40.1 million, or $0.60 per
share, in 2001. The year ended December 31, 2001 included nonrecurring merger,
integration, and restructuring costs and other nonrecurring items totaling $15.9
million after tax, or $0.24 per share. In addition to the nonrecurring 2001
items, the increase of $53.5 million, or $0.79 per share, was primarily the
result of improved margins and lower operating expense. These resulted from
favorable weather and a return to lower gas prices and the related reduction in
costs incurred in 2001.
For 2001 compared to 2000, net income decreased $12.4 million, or $0.25 per
share. The year ended December 31, 2000 included nonrecurring merger and
integration costs totaling $31.6 million, or $0.51 per share. The decrease is
due to extraordinarily high gas costs early in 2001 that unfavorably impacted
margins and operating costs, including uncollectible accounts expense, interest,
and excise taxes; and heating weather that was 9% warmer than the prior year.
Significant Fluctuations
Utility Margin
Gas Utility Margin
Gas Utility margin for the year ended December 31, 2002 of $337.2 million
increased $26.5 million, or 9%. 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, and customer growth of over
1% also contributed. The effects of cooler weather resulted in an overall 4%
increase in total throughput to 207.7 MMDth in 2002 from 199.3 MMDth in 2001.
Total throughput in 2000 was 181.2 MMDth, which includes two months of
throughput from the Ohio operations.
Gas Utility margin for the year ended December 31, 2001 of $310.7 million
increased $42.8 million, compared to 2000. Excluding the Ohio operations, gas
margin decreased by $17.9 million, or 7%. The primary factors contributing to
this decrease were weather that was 9% warmer than the prior year and the
unfavorable impact resulting from extraordinarily high gas costs early in 2001,
coupled with the effects of a weakened economy. These decreases were offset
somewhat by customer growth of nearly 1% compared to 2000.
Cost of gas sold was $571.8 million in 2002, $708.9 million in 2001, and $552.5
million in 2000. Cost of gas sold decreased $137.1 million, or 19%, during 2002
compared to 2001, primarily due to a return to lower gas prices somewhat offset
by an increase in retail volumes sold. Of the change in 2001 compared to 2000,
the Ohio operations contributed $179.4 million of the increase. Excluding the
Ohio operations, cost of gas sold decreased $23.0 million, or 4%, in 2001. The
decrease is primarily due to lower volumes sold due to the warmer weather and a
weakened economy, offset by an increase in gas prices. The total average cost
per dekatherm of gas purchased was $4.57 in 2002, $5.83 in 2001, and $5.60 in
2000. The price changes are due primarily to changing commodity costs in the
marketplace.
Electric Utility Margin
Electric Utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:
Year ended December 31,
- --------------------------------------------------------------------------------
In millions 2002 2001 2000
- --------------------------------------------------------------------------------
Retail & firm wholesale $ 215.3 $ 200.0 $ 201.2
Non-firm wholesale 14.9 19.9 21.1
- --------------------------------------------------------------------------------
Total margin $ 230.2 $ 219.9 $ 222.3
================================================================================
Non-firm wholesale margin:
Realized margin $ 18.5 $ 18.4 $ 21.1
Mark-to-market gains (losses) (3.6) 1.5 -
Electric Utility margin for the year ended December 31, 2002 increased $10.3
million, or 5%, when compared to 2001. The increases result primarily from the
effect on retail sales of cooling weather considerably warmer than the prior
year. Weather in 2002 was 27% warmer when compared to 2001 and 23% warmer than
normal. In addition to weather, 2002 was positively affected by a cash return on
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, retail and firm wholesale volumes sold increased from 5.8 GWh in 2001
to 6.2 GWh in 2002. Volumes sold in 2000 were 5.9 GWh. The current year increase
in margin from retail sales was partially offset by lower margins earned in the
wholesale energy market.
Electric Utility margin for the year ended December 31, 2001 decreased $2.4
million, or 1%, compared to 2000 primarily from decreased sales to firm
wholesale customers and decreased margin on non-firm wholesale activity. The
decreases were partially offset by a 3% increase in residential and commercial
sales due to cooling weather 7% warmer than the prior year and a 3% increase in
the number of residential and commercial customers.
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale transactions that expose the Company
to limited market risk. While volumes both sold and purchased in the wholesale
market have increased during 2002, margins softened as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $5.0 million during
2002 and $1.2 million during 2001. In 2002, volumes sold into the wholesale
market were 10.7 GWh compared to 3.4 GWh in 2001 and 1.6 GWh in 2000. Volumes
purchased from the wholesale market, some of which were utilized to serve retail
and firm wholesale customers, were 10.3 GWh in 2002 compared to 2.9 GWh in 2001
and 1.2 GWh in 2000.
Utility Operating Expenses
Utility Other Operating
Utility other operating expenses decreased $20.5 million for the year ended
December 31, 2002 when compared to 2001. The decrease results primarily from
lower charges for the use of corporate assets which had useful lives shortened
as a result of the merger and a return to 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 and contributions to low
income heating assistance programs. Insurance recovery in 2002 of certain
maintenance costs incurred in 2001 also contributed to the decrease.
Excluding $33.2 million in additional expenses related to the Ohio operations,
utility other operating expenses for the year ended December 31, 2001 decreased
$1.1 million compared to 2000. The 2001 decrease results, primarily from prior
merger synergies offset by higher expenses resulting from increased gas costs.
Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.5 million for the year ended
December 31, 2002 when compared to 2001. The decrease results from the
discontinuance of goodwill amortization as required by SFAS 142, which
approximated $4.9 million in 2001, offset somewhat by depreciation of plant
additions.
Utility depreciation and amortization increased $14.8 million in 2001 when
compared to 2000. The increase is due to the inclusion of the Ohio operations
and depreciation of normal utility plant additions at Indiana Gas and SIGECO.
For the year ended December 31, 2001, the increase in utility depreciation and
amortization related to the Ohio operations was $12.9 million, including
amortization of goodwill of $4.9 million.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes decreased $0.4 million in 2002 compared to
2001 as a result of lower revenues subject to gross receipts tax and increased
$15.0 million in 2001 compared to 2000. The year ended December 31, 2001
includes $15.3 million of additional expense related to the Ohio operations,
primarily state excise tax.
Utility Other Income - Net
Other- net
Utility other income, net increased $1.4 million in 2002 when compared to 2001
and amounts in 2001 were comparable to 2000. The increase in 2002 is primarily
attributable to gains recognized from the sale of excess emission allowances.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $1.3 million in 2002
and $0.5 million in 2001 principally due to increased losses and increased
ownership in a company that manufactures autoclaved aerated concrete products
from fly ash.
Utility Interest Expense
Utility interest expense decreased $4.0 million in 2002 compared to 2001. The
decrease is attributable to lower outstanding borrowings during 2002 and lower
average interest rates on adjustable rate debt.
Utility interest expense increased $24.0 million during the 2001 compared to
2000. The increase is due primarily to interest related to financing the
acquisition of the Ohio operations and increased working capital requirements
resulting from higher natural gas prices.
Utility Income Tax
Federal and state income taxes related to utility operations increased $26.2
million for the year ended December 31, 2002 when compared to 2001. The increase
results principally from higher pre-tax earnings. The effective tax rate
increased from 31.6% in 2001 to 32.3% in 2002 due to amortization of investment
tax credits and higher pre-tax income.
Federal and state income taxes related to utility operations decreased $16.6
million in 2001 when compared to 2000. The 2001 decrease is due to lower pre-tax
earnings. The effective tax rate decreased from 39.5% in 2000 to 31.6% in 2001.
This decrease results primarily from the nondeductibility of certain merger and
integration costs incurred in 2000 and amortization of investment tax credits.
Competition
The utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressures faced by electric and gas
utility companies. Increased competition may create greater risks to the
stability of utility earnings generally and may in the future reduce earnings
from retail electric and gas sales. Currently, several states, including Ohio,
have passed legislation allowing electricity customers to choose their
electricity supplier in a competitive electricity market and several other
states are considering such legislation. At the present time, Indiana has not
adopted such legislation. Ohio regulation 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
Midwest Independent System Operator
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 FERC has made regional transmission organizations a top priority to boost
competition and to provide more reliable power at lower rates. The Carmel,
Indiana, based MISO began some operations in December 2001 with control of
73,000 miles of transmission lines carrying up to 81,000 MW. More than 20 states
are included in the MISO from the Midwest and Plains states, to Texas, Arkansas,
and part of the Southeast. In December 2001, the IURC approved the Company's
request for authority to transfer operational control over its electric
transmission facilities to the MISO. 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, 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 oxides (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible to comply with.
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 .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
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 be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. 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 ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through December 31, 2002, $70.0 million has been expended.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
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. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual, and
the plant continues to operate while the matter is being decided.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by 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 Voluntary Remediation Program. 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 recently been initiated
by the Company to confirm that the sites continue to pose no such risk.
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 IURC. The
retail gas operations of the Ohio operations are subject to regulation by the
PUCO. Changes in prices for fuel for electric generation and purchased power are
determined primarily by energy markets.
Gas Costs Proceedings
Adjustments to rates and charges related to the cost of gas charged to Indiana
customers are made through gas cost adjustment (GCA) procedures established by
Indiana law and administered by the IURC. Similar adjustments to the cost of gas
charged to Ohio customers are made through gas cost recovery (GCR) procedures
established by Ohio law and administered by the PUCO. GCA and GCR procedures
involve scheduled quarterly filings and IURC and PUCO hearings to establish the
amount of price adjustments for a designated future quarter. The procedures also
provide for inclusion in later quarters any variances between the estimated cost
of gas and actual costs incurred. This reconciliation process with regard to
changes in the cost of gas sold closely matches revenues to expenses.
The IURC has also applied the statute authorizing GCA procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. Recovery of gas
costs is not allowed to the extent that net operating income for the longer of
(1) a 60-month period, including the twelve-month period provided in a gas cost
adjustment filing, or (2) the date of the last order establishing base rates and
charges exceeds the total net operating income authorized by the IURC. For the
recent past, the earnings test has not affected the Company's ability to recover
gas costs, and the Company does not anticipate the earnings test will restrict
the recovery of gas costs in the near future.
Rate structures for gas delivery operations do not include weather
normalization-type clauses that authorize the utility to recover gross margin on
sales established in its last general rate case, regardless of actual weather
patterns.
Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
the Company's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through these
commission-approved gas cost adjustment mechanisms, and margin on gas sales
should not be impacted. However, in 2001, the Company's utility subsidiaries
experienced higher working capital requirements, increased expenses including
unrecoverable interest costs, uncollectible accounts expense, and unaccounted
for gas and some level of price sensitive reduction in volumes sold.
In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.
For additional information on regulatory matters affecting the utilities, refer
to Nonregulated Section's discussion of transactions with ProLiance.
Fuel & Purchased Power Costs
Adjustments to rates and charges related to the cost of fuel and the net energy
cost of purchased power charged to Indiana customers are made through fuel cost
adjustment procedures established by Indiana law and administered by the IURC.
Fuel cost adjustment procedures involve scheduled quarterly filings and IURC
hearings to establish the amount of price adjustments for future quarters. The
procedures also provide for inclusion in a later quarter of any variances
between the estimated cost of fuel and purchased power and actual costs
incurred. The order provides that any over-or-under-recovery caused by variances
between estimated and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor. This continuous reconciliation of
estimated incremental fuel costs billed with actual incremental fuel costs
incurred closely matches revenues to expenses.
An earnings test similar to the test restricting gas cost recovery is the
principal restriction to recovery of fuel cost increases. This earnings test has
not affected the Company's ability to recover fuel costs, and the Company does
not anticipate the earnings test will restrict the recovery of fuel costs in the
near future.
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
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.
Results of Operations of the Nonregulated Businesses
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties 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 investments in other businesses that invest in energy-related
opportunities and provides utility services, municipal broadband consulting,
retail, and real estate and leveraged leases. The results of nonregulated
operations for the years ended December 31, 2002, 2001, and 2000 follows:
- --------------------------------------------------------------------------
In millions, except per share amounts 2002 2001 2000
- --------------------------------------------------------------------------
(As Restated)
- --------------------------------------------------------------------------
Energy services & other revenues $ 287.2 $ 681.0 $ 478.0
Cost of energy services & other revenues 249.4 640.9 453.2
- --------------------------------------------------------------------------
TOTAL OPERATING MARGIN 37.8 40.1 24.8
Intersegment revenues, net of costs 3.0 2.6 1.9
Expenses:
Operating expenses 36.1 36.3 20.3
Merger & integration costs - - 1.6
Restructuring costs - 3.5 -
- --------------------------------------------------------------------------
Total expenses 36.1 39.8 21.9
- --------------------------------------------------------------------------
OPERATING INCOME 4.7 2.9 4.8
Other income:
Equity in earnings of
unconsolidated affiliates 10.9 13.9 9.8
Other - net 6.1 11.4 18.5
- --------------------------------------------------------------------------
Total other income 17.0 25.3 28.3
- --------------------------------------------------------------------------
Interest expense 9.1 12.5 9.6
- --------------------------------------------------------------------------
INCOME BEFORE TAXES 12.6 15.7 23.5
Income tax (6.9) (4.7) 0.6
Minority interest 0.5 0.6 1.1
- --------------------------------------------------------------------------
Income before extraordinary loss 19.0 19.8 21.8
Extraordinary loss - net of tax - (7.7) -
- --------------------------------------------------------------------------
NET INCOME $ 19.0 $ 12.1 $ 21.8
==========================================================================
BASIC EARNINGS PER SHARE $ 0.28 $ 0.18 $ 0.36
==========================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 15.0 $ 11.3 $ 7.2
Coal Mining 12.2 13.6 4.6
Utility Infrastructure (1.2) (0.6) 0.2
Broadband 0.4 (0.1) 4.4
Other Businesses (7.4) (12.1) 5.4
For the year ended December 31, 2002, earnings from nonregulated operations
increased $6.9 million, or $0.10 per share, when compared to 2001. The increase
is primarily due to increased earnings from Energy Marketing and Services and a
smaller loss incurred by the Company's broadband consulting operations which are
part of the Other Businesses Group. 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 certain assets. In addition, 2001 benefited from gains
recognized upon sale of investments by an unconsolidated affiliate in the first
and third quarters, 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.
For 2001 compared to 2000, net income decreased $9.7 million due primarily to
nonrecurring items incurred in 2001 and 2000. Nonrecurring items in 2000 added
earnings of $3.9 million, or $0.06 per share, and included a gain from
restructuring the Company's investment in SIGECOM, offset by merger and
integration costs. Before nonrecurring items, 2001 earnings increased $4.1
million primarily due to expanded natural gas marketing and coal mining
operations, partially offset by losses incurred by the Company's broadband
consulting operations.
Energy Marketing & Services
Energy Marketing and Services includes the Company's investment in 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, Citizens Gas, and others and also began
providing service to SIGECO and Vectren Retail, LLC (the Company's retail gas
marketer) in 2002. ProLiance's primary business is optimizing the gas portfolios
of utilities and providing services to large end use customers. In addition,
Energy Marketing and Services includes the operations of Energy Systems Group,
LLC (ESG), which provides energy performance contracting and facility upgrades
through its design and installation of energy-efficient equipment. ESG is a
consolidated venture between the Company and Citizens Gas, with the Company
owning two-thirds. ESG had no significant impact on the Company's financial
results in 2002, 2001, or 2000.
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. Since
governance of ProLiance remains equal between the members, Vectren continues to
account for its investment in ProLiance using the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. SES' revenues and expenses were
the primary component of nonregulated revenues and cost of revenues. Therefore,
the integration significantly decreased revenues and costs of revenues in 2002
compared to 2001. The Company's operating expenses also decreased $4.8 million
in 2002 as a result of the integration. 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.
Pre-tax income of $19.1 million, $12.8 million and $5.4 million was recognized
as ProLiance's contribution to earnings for the years ended December 31, 2002,
2001, and 2000, respectively. Pre-tax earnings have increased primarily as a
result of increased operations at ProLiance and the Company's increased
ownership. Earnings recognized from ProLiance are included in equity in earnings
of unconsolidated affiliates.
In 2001 compared to 2000, the significant increase in the Company's nonregulated
revenues and costs of revenues was primarily attributable to SES' operations
reflecting higher prices for natural gas and increased volumes. SES' increased
activity was also a contributing factor to the increase in 2001 margin and
operating expenses when compared to 2000.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) and audit process
administered by the PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility.
However, with respect to the pricing of gas commodity purchased from ProLiance,
the price paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in a consolidated GCA proceeding involving Indiana Gas and
Citizens Gas.
On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other
consumer parties, entered into and filed with the IURC a settlement setting
forth the terms for resolution of all pending regulatory issues related to
ProLiance, including the three pricing issues. On July 23, 2002, the IURC
approved the settlement filed by the parties. The GCA proceeding has been
concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas,
and ProLiance have been approved and extended through March 31, 2007. ProLiance
will also have the opportunity, if it so elects, to participate in a "request
for proposal" process for service to the utilities after March 31, 2007.
For past services provided to Indiana Gas by ProLiance, the Company made refunds
to Indiana Gas' retail customers pursuant to the settlement totaling $6.4
million and reimbursed other costs to parties involved in the settlement
totaling $1.1 million. Payments were made in the fourth quarter of 2002. At
December 31, 2001, the Company had established a reserve specific to this GCA
proceeding totaling $5.2 million which was recorded throughout the GCA
proceeding as a reduction of ProLiance's contribution to the Company's earnings.
The amount of the settlement in excess of that accrued prior to 2002 totaling
$2.3 million was reflected as a reduction of ProLiance's contribution to
earnings in 2002.
In addition to the above, the IURC order also provides that:
o A portion of the utilities' natural gas will be purchased through a gas
cost incentive mechanism that shares price risk and reward between the
utilities and customers;
o Beginning in 2004, ProLiance will provide the utilities with an interstate
pipeline transport and storage service price discount, thus providing
additional savings to customers;
o As ProLiance continues to provide the utilities with its supply services,
Citizens Gas and Vectren will together annually provide an additional $2
million per year in customer benefits in 2003, 2004, and 2005.
Coal Mining
Coal Mining 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 group also generates IRS Code Section 29 investment tax
credits relating to the production of coal-based synthetic fuels through its
investment in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon is an
unconsolidated affiliate accounted for using the equity method.
Earnings from Vectren Fuels, Inc. were $6.2 million in 2002, $9.3 million in
2001, and $2.5 million in 2000. In 2002 compared to 2001, both net income and
margins decreased as a result of lower market prices on third party coal sales
and a somewhat lower yield per ton mined in 2002. In 2001 compared to 2000, both
net income and margin increased as a result of the Company's second mine
starting operations in mid-2001. The new mine was also a contributing factor to
increased operating expenses in 2002 and 2001.
The investment in Pace Carbon resulted in losses reflected in equity in earnings
of unconsolidated affiliates totaling $6.8 million, $4.5 million, and $2.4
million in 2002, 2001, and 2000, respectively. Losses have increased as a result
of increased production of synthetic fuels and higher production costs. The
production of synthetic fuel generates IRS Code Section 29 investment tax
credits that are reflected in income taxes. These credits have also increased in
recent years consistent with increased synthetic fuel production. Net income,
including the losses, tax benefits, and tax credits, generated from the
investment in Pace Carbon totaled $6.0 million in 2002, $4.3 million in 2001,
and $2.1 million in 2000.
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). Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting. The
investment in Reliant had no significant impact on the Company's results in
2002, 2001, or 2000.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Company has a minority 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 a minority interest in SIGECOM
Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in
SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater
Evansville, Indiana, area.
The equity investments in Utilicom and Holdings are accounted for using the cost
method of accounting. As a result, Broadband had no significant impact on the
Company's financial results with the exception of the one-time gain recorded in
2000 upon the restructuring of the Company's investment in SIGECOM previously
discussed. The $4.9 million gain is included in equity in earnings of
unconsolidated affiliates.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana, and Dayton, Ohio, markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
remain interested in the Indianapolis and Dayton projects, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
Other Businesses
The Other Businesses Group includes a variety of wholly owned operations and
investments. The significant activities that affected the nonregulated results
of operations during 2002, 2001, and 2000 are the wholly owned operations of
Vectren Communication Services, Inc. (VCS), Vectren Retail LLC (Vectren Retail),
and Southern Indiana Properties, Inc.(SIPI) and the Company's investment in the
Haddington partnerships (Haddington), which are accounted for using the equity
method of accounting.
VCS is a wholly owned broadband consulting company that incurred charges in 2002
and 2001 related to the settlement of construction contracts and the
reorganization of its operations, allowing it to focus on consulting services.
As a result, VCS incurred net losses of $2.8 million in 2002 and $8.0 million in
2001 compared to net income of $0.2 million in 2000. The majority of the costs
incurred in 2001 and 2002 are included in cost of energy services and other
revenues and are therefore a component of the change in margin in 2002 compared
to 2001 and 2001 compared to 2000.
Vectren Retail provides natural gas and other related products and services
primarily in Ohio serving customers opting for choice among energy providers.
Vectren Retail began operations in 2001 and has incurred startup costs in 2002
and 2001 which has increased operating expenses. Due to increased activity,
these operations added margin of $1.3 million in 2002 compared to 2001.
SIPI has various investments in leveraged leases, notes receivable, and
unconsolidated affiliates. The Company divested of notes receivable and
leveraged lease investments in the second and fourth quarters of 2001. These
divestitures resulted in the $7.7 million extraordinary loss previously
discussed and less leveraged lease and interest income in 2002 compared to 2001
and in 2001 compared to 2000. The decrease in leveraged lease and interest
income is the primary contributing factor to the change in other-net in 2002 and
2001. The dispositions of these assets generated cash flow of approximately $67
million.
The Haddington partnerships are equity method investments that invest in
energy-related opportunities. During 2001, these partnerships sold investments
resulting in gains reflected by the Company totaling $6.2 million. Such gains
are included in equity in earnings of unconsolidated affiliates. The most
significant portion of these earnings was derived from Haddington's sale of Bear
Paw Investments, LLC (Bear Paw). In March 2001, Haddington sold its investment
in Bear Paw in exchange for a combination of cash and securities. The cost of
Haddington's Bear Paw investment approximated $5.1 million, and the net proceeds
received totaled $18.1 million, resulting in a gain of $13.0 million. The
Company recognized its portion of the pre-tax gain totaling $3.9 million in
March 2001. Later in 2001 as the securities received were sold, the Company
recognized its portion of the additional earnings totaling $1.0 million.
Critical Accounting Policies
Management is required to make judgements, assumptions, and estimates that
affect the amounts reported in the consolidated financial statements and the
related disclosures that conform to accounting principles generally accepted in
the United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgement. These
include the estimates to perform goodwill and other asset impairments tests and
to determine pension and postretirement benefit obligations. The Company makes
other estimates in the course of accounting for unbilled revenue and the effects
of regulation that are critical to the Company's financial results but that are
less likely to be impacted by near term changes. Other estimates that
significantly affect the Company's results, but are not necessarily critical to
operations, include depreciation of utility and non-utility plant, the valuation
of derivative contracts, and the allowance for doubtful accounts, among others.
Actual results could differ from these estimates.
Impairment Review of Investments
The Company has investments in notes receivable, entities accounted for using
the cost method of accounting, and entities accounted for using the equity
met