UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to ________________________
Commission file number: 1-16739
VECTREN UTILITY HOLDINGS, INC.
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(Exact name of registrant as specified in its charter)
INDIANA 35-2104850
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 812-491-4000 Securities
registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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7 1/4% Senior Notes, due 10/15/2031 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Name of each exchange on which registered
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Common - Without Par 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__. No |X|.
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of June
30, 2003, was zero. All shares outstanding of the Registrant's common stock were
held by Vectren Corporation.
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 10 March 1, 2004
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Class Number of Shares Date
Omission of Information by Certain Wholly Owned Subsidiaries
The Registrant is a wholly owned subsidiary of Vectren Corporation and meets the
conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and
is therefore filing with the reduced disclosure format contemplated thereby.
Definitions
AFUDC: allowance for funds used during MMBTU: millions of British thermal
construction units
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions
of megawatt hours (gigawatt hour)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of PUCO: Public Utilities Commission of
Environmental Management Ohio
IURC: Indiana Utility Regulatory SFAS: Statement of Financial
Commission Accounting Standards
MCF/BCF: millions / billions of USEPA: United States Environmental
cubic feet Protection Agency
MDth/MMDth: thousands /millions of Throughput: combined gas sales and
dekatherms gas transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ...........................................................4
2 Properties .........................................................8
3 Legal Proceedings...................................................9
4 Submission of Matters to Vote of Security Holders..................10
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities ................10
6 Selected Financial Data............................................11
7 Management's Discussion and Analysis of Results of
Operations and Financial Condition.................................12
7A Qualitative and Quantitative Disclosures About Market Risk.........32
8 Financial Statements and Supplementary Data........................34
9 Change in and Disagreements with Accountants on Accounting
and Financial Disclosure...........................................71
9A Controls and Procedures............................................71
Part III
10 Directors and Executive Officers of the Registrant (A).............72
11 Executive Compensation (A).........................................72
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters (A).....................72
13 Certain Relationships and Related Transactions (A).................72
14 Principal Accountant Fees and Services.............................72
Part IV
15 Exhibits, Financial Statement Schedules, and
Reports on Form 8-K................................................73
Signatures.........................................................81
(A) - Omitted or amended as the Registrant is a wholly-owned subsidiary of
Vectren Corporation and meets the conditions set forth in General
Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with
the reduced disclosure format contemplated thereby.
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports
free of charge through its website at www.vectren.com, or by request, directed
to Investor Relations at the mailing address, phone number, or email address
that follows:
Mailing Address: Phone Number: Investor Relations Contact:
P.O. Box 209 (812) 491-4000 Steven M. Schein
Evansville, Indiana Vice President, Investor Relations
47702-0209 sschein@vectren.com
PART I
ITEM 1. BUSINESS
Description of the Business
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the
Ohio operations. VUHI also has assets that provide information technology and
other services to the utilities.
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.
Vectren is an energy and applied technology holding company headquartered in
Evansville, Indiana and was organized on June 10, 1999, solely for the purpose
of effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax-free exchange of shares that has been accounted for as a
pooling-of-interests in accordance with APB Opinion No. 16 "Business
Combinations" (APB 16).
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.
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 three operating segments: Gas Utility
Services, Electric Utility Services, and Other Operations. The Gas Utility
Services segment includes the operations of Indiana Gas, the Ohio operations,
and SIGECO's natural gas distribution business and provides natural gas
distribution and transportation services in nearly two-thirds of Indiana and to
west central Ohio. The Electric Utility Services segment includes the operations
of SIGECO's electric transmission and distribution services, which provides
electricity primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. The Company collectively refers to its gas
and electric operating segments as its regulated operations. Other Operations
primarily provide information technology and other support services to those
utility operations.
At December 31, 2003, the Company had $2.9 billion in total assets, with $1.8
billion (62%) attributed to the Gas Utility Services, $1.0 billion (33%)
attributed to the Electric Utility Services, and $0.1 billion (5%) attributed to
Other Operations. Net income for the year ended December 31, 2003, was $85.6
million with $81.8 million attributed to regulated operations and $3.8 million
attributed to other operations. Net income for the year ended 2002 was $97.1
million.
For further information, refer to Note 14 regarding the activities and assets of
the Company's operating segments, Note 15 regarding special charges in 2001, and
Note 11 regarding the cumulative effect of change in accounting principle in
2001 in the Company's consolidated financial statements included under "Item 8
Financial Statements and Supplementary Data".
Following is a more detailed description of the Gas Utility Services and
Electric Utility Services operating segments. The Company's Other Operations are
not significant.
Gas Utility Services
At December 31, 2003, the Company supplied natural gas service to 972,230
Indiana and Ohio customers, including 887,891 residential, 80,292 commercial,
and 4,047 industrial and other customers. This represents customer base growth
of 0.6% compared to 2002.
The Company's service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served include
automotive assembly, parts and accessories, feed, flour and grain processing,
metal castings, aluminum products, appliance manufacturing, polycarbonate resin
(Lexan) and plastic products, gypsum products, electrical equipment, metal
specialties, glass, steel finishing, pharmaceutical and nutritional products,
gasoline and oil products, and coal mining. The largest Indiana communities
served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and
Richmond. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2003, natural gas revenues were approximately
$1,112.3 million, of which residential customers accounted for 67%, commercial
25%, and industrial and other 8%, respectively.
The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) were 209,344 MDth for the year ended December 31, 2003. Gas
transported or sold to residential and commercial customers were 118,460 MDth
representing 57% of throughput. Gas transported or sold to industrial and other
contract customers were 90,884 MDth representing 43% of throughput. Rates for
transporting gas provide for the same margins generally earned by selling gas
under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company has storage capacity at
seven active underground gas storage fields, six liquefied petroleum air-gas
manufacturing plants, and a propane cavern. The Company also contracts with
ProLiance Energy, LLC (ProLiance or ProLiance Energy) to ensure availability of
gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of
Energy Marketing & Services below and Note 4 in the Company's consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding transactions with ProLiance). Purchased natural gas is injected
into storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately
1,775,657 MCF of gas per day can be delivered during peak demand periods from
all sources and for all utilities.
Gas Purchases
In 2003, the Company purchased 118,684 MDth volumes of gas at an average cost of
$6.36 per Dth, substantially all of which was purchased from ProLiance, which
buys the gas as an agent. The average cost of gas per Dth purchased for the last
five years was: $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; $5.60 in 2000; and
$3.58 in 1999.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment and issues
involving manufactured gas plants.
Electric Utility Services
At December 31, 2003, the Company supplied electric service to 135,098 Indiana
customers, including 117,868 residential, 17,054 commercial, and 176 industrial
and other customers. This represents customer base growth of 0.8% compared to
2002. In addition, the Company is obligated to provide for firm power
commitments to four municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.
The principal industries served include polycarbonate resin (Lexan) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the year ended December 31, 2003, retail and firm wholesale electricity
sales totaled 5,898,852 MWh, resulting in revenues of approximately $309.1
million. Residential customers accounted for 34% of 2003 revenues; commercial
27%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 4,305,190 MWh through wholesale contracts in 2003, generating revenue, net
of purchased power costs, of $26.5 million.
Generating Capacity
Installed generating capacity as of December 31, 2003, was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and natural gas or
oil-fired turbines used for peaking or emergency conditions provide 295 MW. New
peaking capacity of 80 MW fueled by natural gas was added during 2002 and was
available for the summer peaking season.
In addition to its generating capacity, in 2003, the Company had 32 MW available
under firm contracts and 95 MW available under interruptible contracts. In
October 2003, the Company executed a firm purchase supply contract for a maximum
of 73MW for the peak cooling season months in each of the next three years.
The Company has interconnections with Louisville Gas and Electric Company,
Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability has been, and may continue to be, impacted
because the Company, as a member of the Midwest Independent System Operator
(MISO), has turned over operational control over the interchange facilities and
its own transmission assets, like many other Midwestern electric utilities, to
the MISO. See "Item 7 Management's Discussion and Analysis of Results of
Operations and Financial Condition" regarding the Company's participation in
MISO.
Total load for each of the years 1999 through 2003 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
Date of summer peak load 8/27/2003 8/5/2002 7/31/2001 8/17/2000 7/6/1999
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Total load at peak (1) 1,272 1,258 1,234 1,212 1,255
Generating capability 1,351 1,351 1,271 1,256 1,256
Firm purchase supply 32 82 82 75 -
Interruptible contracts 95 95 95 95 95
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Total power supply capacity 1,478 1,528 1,448 1,426 1,351
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Reserve margin at peak 16% 21% 17% 18% 8%
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(1) The total load at peak is increased 25 MW in 2003, 2002, 2001, and 1999
from the total load actually experienced. The additional 25 MW represents
load that would have been incurred if summer cycler programs had not been
activated. The 25 MW is also included in the interruptible contract portion
of the Company's total power supply capacity. On the date of peak in 2000,
summer cycler programs were not activated.
The winter peak load of the 2002-2003 season of approximately 948 MW occurred on
January 27, 2003, and was 11% higher than the previous winter peak load of
approximately 854 MW which occurred on March 4, 2002.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO, and supplies power requirements to the United States Department of
Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for, any
available power in excess of the DOE contract demand. At the present time, the
DOE contract demand is essentially zero. Because of this decreased demand, the
Company's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.
Such generating capacity is included in firm purchase supply in the chart above.
Fuel Costs and Purchased Power
Electric generation for 2003 was fueled by coal (99.3%) and natural gas (0.7%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of Vectren. Approximately 3.1 million tons of coal were purchased
for generating electricity during 2003, of which substantially all was supplied
by Vectren Fuels, Inc. from its mines and third party purchases. The average
cost of coal consumed in generating electric energy for the years 1999 through
2003 follows:
Year Ended December 31,
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Avg. Cost Per 2003 2002 2001 2000 1999
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Ton $ 24.91 $ 23.50 $ 22.48 $ 22.49 $ 21.88
MWh 11.93 11.00 10.53 10.39 10.13
The Company will also purchase power as needed from the wholesale market to
supplement its generation capabilities in periods of peak demand; however, the
majority of power purchased through the wholesale market is used to optimize and
hedge the Company's sales to other wholesale customers. Volumes purchased in
2003 totaled 4,082,404 MWh.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment, and a
discussion of the Company's Clean Air Act Compliance Plan, and the settlement of
USEPA's lawsuit against SIGECO for alleged violations of the Clean Air Act.
Competition
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding competition within the regulated utility industry
for the Company's regulated Indiana and Ohio operations.
Personnel
As of December 31, 2003, the Company and its consolidated subsidiaries had 1,547
employees, of which 884 are subject to collective bargaining arrangements.
In January 2004, the Company signed a five-year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America locals 12213 and 7441. The agreement provides for
annual wage increases of 3%, a multi-tiered health care plan in which the
employees pay 12% to 16% of the premium, and pension enhancements for early
retirees.
In August 2001, the Company signed a new four-year labor agreement, ending in
September 2005, with Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The new agreement provides for annual wage increases of 3.25%, a new
401(k) savings plan and improvements in the areas of health insurance and
pension benefits.
Concurrent with the Company's purchase of the Ohio operations, VEDO and Local
Union 175, Utility Workers Union of America approved a labor agreement effective
November 2000 through October 2005. The agreement provides a 3.25% wage increase
each year, and the other terms and conditions are substantially the same as the
agreement reached between the Utility Workers Union and Dayton Power and Light
Company in August of 2000.
In July 2000, SIGECO signed a four-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2004. The agreement
provides a 3% wage increase for each year in addition to improvements in health
care coverage, retirement benefits and incentive pay.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana
covering 58,290 acres of land with an estimated ready delivery from storage
capability of 5.2 BCF of gas with maximum peak day delivery capabilities of
119,160 MCF per day. Indiana Gas also owns and operates three liquefied
petroleum (propane) air-gas manufacturing plants located in Indiana with the
ability to store 1.5 million gallons of propane and manufacture for delivery
33,000 MCF of manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.2 BCF of storage
with a maximum peak day delivery capability of 404,614 MCF per day. Indiana Gas
has the ability to meet a total annual demand, utilizing all of its assets
across various pipelines, of 131.1 BCF with a maximum peak day delivery
capability of 1,068,740 MCF per day. Indiana Gas' gas delivery system includes
11,771 miles of distribution and transmission mains, all of which are in Indiana
except for pipeline facilities extending from points in northern Kentucky to
points in southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.
SIGECO owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
124,748 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 18,699 MCF per day. SIGECO has the ability to meet a
total annual demand, utilizing all of its assets across various pipelines, of
28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day.
SIGECO's gas delivery system includes 3,026 miles of distribution and
transmission mains, all of which are located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants and a cavern for propane storage, all of which are located
in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the
plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In
addition to its propane delivery capabilities, the Ohio operations have
contracted for 13.1 BCF of storage with a maximum peak day delivery capability
of 280,667 MCF per day. The Ohio operations have the ability to meet a total
annual demand, utilizing all of its assets across various pipelines, of 57.9 BCF
with a maximum peak day delivery capability of 477,974 MCF per day. The Ohio
operations' gas delivery system includes 5,216 miles of distribution and
transmission mains, all of which are located in Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2003, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80 MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution
system includes 3,224 pole miles of lower voltage overhead lines and 289 trench
miles of conduit containing 1,622 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed
capacity of 2,368.6 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
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 8 and Note 9 of its
consolidated financial statements included in "Item 8 Financial Statements and
Supplementary Data" regarding the Clean Air Act and related legal proceedings.
Legal proceedings regarding the Culley generating station's compliance with the
Clean Air Act were substantially resolved during 2003.
ITEM 4. Submission of Matters to Vote of Security Holders
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND
ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Market Price
All of the outstanding shares of VUHI's common stock are owned by Vectren.
VUHI's common stock is not traded. There are no outstanding options or warrants
to purchase VUHI's common equity or securities convertible into VUHI's common
equity. Additionally, VUHI has no plans to publicly offer any of its common
equity.
Dividends Paid to Parent
During 2003, VUHI paid dividends to its parent company of $18.0 million in the
first quarter, $18.2 million in the second quarter, $20.7 million in the third
quarter, and $21.1 million in the fourth quarter.
During 2002, VUHI paid dividends to its parent company of $17.3 million in the
first quarter, $16.7 million in the second quarter, $17.8 million in the third
quarter, and $17.9 million in the fourth quarter.
On January 28, 2004, the board of directors declared a $19.9 million dividend,
payable to Vectren on March 1, 2004.
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.
Debt Security
The Company's 7 1/4% Senior Notes, due October 15, 2031, trade on the New York
Stock Exchange under the symbol "AVU." The high and low sales prices for the
Company's publicly traded debt security since issuance in October 2001 as
reported on the New York Stock Exchange are shown in the following table for the
periods indicated.
Price Range
-----------------------------
2003 High Low
- ---- ------------- -------------
First Quarter $ 26.60 $ 25.76
Second Quarter 27.80 25.69
Third Quarter 27.05 25.86
Fourth Quarter 27.16 26.00
2002
First Quarter $ 25.60 $ 24.50
Second Quarter 25.40 24.50
Third Quarter 25.95 24.80
Fourth Quarter 26.08 25.15
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K. Operating
revenues for the years ended December 31, 2002, through December 31, 1999, have
been reclassified to reflect the adoption of EITF 03-11. Total assets as of
December 31, 2002, also reflect a reclassification for the adoption of SFAS 143.
See Note 11 and Note 2 to the consolidated financial statements for further
information on the adoption of EITF 03-11 and SFAS 143, respectively, included
under Item 8 "Financial Statements and Supplementary Data." The following
selected financial data also gives effect to the transfer of certain information
technology systems and related assets and buildings from other entities within
Vectren's consolidated group to VUHI that was effective January 1, 2003. The
transfer required retroactive restatement of VUHI's consolidated financial
statements for all periods presented under accounting rules governing
combinations of entities under common control.
Year Ended December 31,
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(In millions) 2003 2002 2001(1) 2000(2,3) 1999
- --------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $ 1,448.8 $ 1,236.9 $ 1,328.3 $ 1,129.9 $ 794.9
Operating income 199.0 207.7 131.4 136.1 109.0
Income before cumulative effect
of change in accounting principle 85.6 97.1 43.7 55.9 75.4
Net income 85.6 97.1 44.8 55.9 75.4
Balance Sheet Data:
Total assets $ 2,925.1 $2,780.4 $ 2,489.3 $ 2,509.0 $1,667.7
Redeemable preferred stock 0.2 0.3 0.5 8.1 8.2
Long-term debt-net of current
maturities & debt subject to tender 960.5 841.2 900.9 572.6 450.1
Common shareholder's equity 979.8 768.6 738.9 624.3 627.0
(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 ($7.7 million
after tax).
The Company incurred restructuring charges of $15.0 million, ($9.3 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 $32.7 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 $44.1
million ($31.6 million after tax).
(3) Reflects two months of results of the Ohio operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto.
Executive Summary of Consolidated Results of Operations
In 2003, Utility Group earnings were $85.6 million as compared to $97.1 million
in 2002 and $44.8 million in 2001. The $11.5 million decrease occurring in 2003
compared to 2002 was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.
Utility Group earnings increased $52.3 million in 2002 compared to 2001. The
year ended December 31, 2001, included nonrecurring merger, integration, and
restructuring costs and other nonrecurring items totaling $15.9 million after
tax. The increase also reflects improved margins and lower operating costs.
These resulted from favorable weather and lower gas prices and the related
reduction in costs incurred in 2001. Weather increased utility earnings by an
estimated $11 million.
VUHI generates revenue primarily from the delivery of natural gas and electric
service to its customers. The primary source of cash flow results from the
collection of customer bills and the payment for goods and services procured for
the delivery of gas and electric services. Results are impacted by weather
patterns in its service territory and general economic conditions both in its
service territory as well as nationally.
The Company has in place a disclosure committee that consists of senior
management as well as financial management. The committee is actively involved
in the preparation and review of the Company's SEC filings.
Nonrecurring Items in 2001
Merger & Integration Costs
Merger and integration related costs incurred during 2001 totaled $2.8 million.
These costs relate primarily to transaction costs, severance, and other merger
and acquisition integration activities. As a result of merger and integration
activities, management retired certain information systems in 2001. Accordingly,
the useful lives of these assets were shortened to reflect this decision,
resulting in additional depreciation expense of approximately $9.6 million for
the year ended December 31, 2001. In total, merger and integration related costs
incurred during 2001 were $12.4 million ($7.7 million after tax). Merger and
integration activities resulting from the 2000 merger forming Vectren were
completed in 2001.
Restructuring Costs
As part of continued cost saving efforts, in June 2001, the Company's management
and board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $10.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $4.2 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 $15.0 million ($9.3 million after tax) in 2001. These charges were
comprised of $7.6 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 $3.4 million for consulting
and other. 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.
Cumulative Effect of Change in Accounting Principle
Resulting from the adoption of SFAS 133, certain contracts in the power
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) recorded as a cumulative
effect of change in accounting principle in the Consolidated Statements of
Income.
Significant Fluctuations
Throughout this discussion, the terms Gas Utility margin and Electric Utility
margin are used. Gas Utility margin and Electric Utility margin could be
considered non-GAAP measures of income. Gas Utility margin is calculated as Gas
utility revenues less the Cost of gas sold. Electric Utility margin is
calculated as Electric utility revenues less Fuel for electric generation and
Purchased electric energy. These measures exclude Other operating expenses,
Depreciation and amortization, Taxes other than income taxes, Merger and
integration costs, and Restructuring costs, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of operating performance than,
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.
Margin
Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in its service
territory. Margin generated from sales to industrial and other contract
customers is impacted by overall economic conditions. In general, margin is not
sensitive to variations in gas or fuel costs. It is, however, impacted by the
collection of state mandated taxes which fluctuate with gas costs and also some
level of fluctuation in volumes sold. Electric generating asset optimization
activities are primarily affected by market conditions, the level of excess
generating capacity, and electric transmission availability. Following is a
discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- --------------------------------------------------------------------------
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------
Residential $ 225.3 $ 217.1 $ 201.9
Commercial 65.0 65.5 57.7
Contract 50.5 50.5 48.4
Other 9.0 4.1 2.7
- --------------------------------------------------------------------------
Total gas utility margin $ 349.8 $ 337.2 $ 310.7
==========================================================================
Sold & transported volumes in MMDth:
To residential & commercial customers 118.5 111.9 102.2
To contract customers 90.8 95.8 97.2
- --------------------------------------------------------------------------
Total throughput 209.3 207.7 199.4
==========================================================================
Gas Utility margin for the year ended December 31, 2003, of $349.8 million
increased $12.6 million, or 4%, compared to 2002. It is estimated that weather
near normal for the year and 6% cooler than the prior year, contributed $8
million in increased residential and commercial margin and was the primary
contributor to increased throughput. The remaining increase is primarily
attributable to $4.5 million in higher utility receipts and excise taxes on
higher gas costs and volumes sold and $1.8 million in recovery of Ohio customer
choice implementation costs. These increases are partially offset by the
negative effect of high gas prices on customer usage.
Gas Utility margin for the year ended December 31, 2002, of $337.2 million
increased $26.5 million, or 9%, compared to 2001. The increase is primarily due
to weather 7% cooler for the year and 31% cooler in the fourth quarter. Rate
recovery of excise taxes in Ohio effective July 1, 2001, an increase in the
Percent of Income Payment Plan rider affecting Ohio customers, decreased gas
costs, and customer growth of over one percent also contributed. It is estimated
that weather contributed $10 million to the increase in Gas Utility margin,
various rate recovery riders in Ohio contributed $7 million, and other items,
including the impact of lower gas costs and customer growth, contributed $9
million. The effect of cooler weather was the primary factor driving an overall
4% increase in total throughput.
As noted above, gas cost fluctuations have impacted customer usage during the
years ended December 31, 2003, 2002, and 2001. The average cost per dekatherm of
gas purchased in those years was $6.36 in 2003, $4.57 in 2002, and $5.83 in
2001.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric
Generation and Purchased Electric Energy)
Electric Utility margin by revenue type follows:
Year Ended December 31,
- ------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- ------------------------------------------------------------------------------
Residential & commercial $ 141.1 $ 145.7 $ 134.4
Industrial 53.5 54.9 49.6
Municipalities & other 20.1 16.9 16.8
- ------------------------------------------------------------------------------
Total retail & firm wholesale 214.7 217.5 200.8
Asset optimization 18.3 12.7 19.1
- ------------------------------------------------------------------------------
Total electric utility margin $ 233.0 $ 230.2 $ 219.9
==============================================================================
Retail & Firm Wholesale Margin
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.7 million, a decrease of $2.8 million when compared
to 2002. It is estimated that summer weather 19% cooler than normal and 34%
cooler than last year caused an $8 million decrease in residential and
commercial margin. The estimated effect of weather was partially offset by a
$7.1 million increase in retail electric rates related to recovery of NOx
compliance expenditures and related operating expenses. A slowly recovering
economy continued to negatively impact industrial sales which decreased $1.4
million compared to 2002. As a result primarily of the mild weather and slow
economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90
GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh.
The current year decrease in native load and firm wholesale margin has been
offset by increased optimization margin as more fully described below.
For the year ended December 31, 2002, margin from serving native load and firm
wholesale customers increased $16.7 million or 8%, when compared to 2001. The
increase results primarily from the effect on residential and commercial sales
of cooling weather considerably warmer than the prior year. Weather in 2002 was
27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002
was positively affected by increased industrial and other wholesale volumes and
rate recovery related to NOx compliance expenditures as the expenditures are
made pursuant to a rate recovery rider approved by the IURC in August 2001. As a
result of warmer weather and increased volumes sold, native load and firm
wholesale volumes sold increased 6%. It is estimated that weather contributed $7
million to the increase in electric utility margin, and the increased industrial
and other wholesale volumes and the NOx recovery rider contributed $8 million.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of
these contracts are integrated with portfolio requirements around power supply
and delivery and are short-term purchase and sale transactions that expose the
Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Beginning of Year Net Asset Optimization
Position $ (0.7) $ 3.3 $ -
Statement of Income Activity
Cumulative effect at adoption of SFAS 133 - - 1.8
Mark-to-market gains (losses) recognized 0.7 (3.6) 1.5
Realized gains recognized 17.6 16.3 17.6
- -------------------------------------------------------------------------------
Net activity in electric utility margin 18.3 12.7 19.1
- -------------------------------------------------------------------------------
Net cash received & other adjustments (18.0) (16.7) (17.6)
- -------------------------------------------------------------------------------
End of Year Net Asset Optimization Position $ (0.4) $(0.7) $ 3.3
===============================================================================
Included in:
Prepayments & other current assets $ 2.4 $ 3.5 $ 6.1
Accrued liabilities (2.8) (4.2) (2.8)
For the years ended December 31, 2003, 2002, and 2001, volumes sold into the
wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh respectively, while volumes
purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A portion
of volumes purchased in the wholesale market is used to serve native load and
firm wholesale customers, and in 2003, greater amounts of purchased power have
been required for native load due to scheduled outages, which has reduced
capacity available for optimization. Additionally, volumes sold and purchased
were lower in 2003 compared to 2002 due to a shorter term focus in hedging and
optimization strategies. While volumes both sold and purchased in the wholesale
market have decreased during 2003, margin from optimization activities has
increased compared to 2002 due primarily to price volatility. Despite the
increased volumes in 2002, margins were lower in 2002 compared to 2001 due to
reduced price volatility.
In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.
After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.
Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income:
Year Ended December 31,
- -------------------------------------------------------------------------------
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Activity related to:
Sales contracts $ 152.8 $ 302.8 $ 101.4
Purchase contracts (127.0) (275.9) (74.3)
Mark-to-market gains (losses) 0.7 (3.6) 1.5
- -------------------------------------------------------------------------------
Net asset optimization revenue 26.5 23.3 28.6
- -------------------------------------------------------------------------------
Fuel for electric generation (8.2) (10.6) (9.5)
- -------------------------------------------------------------------------------
Asset optimization margin $ 18.3 $ 12.7 $ 19.1
===============================================================================
Operating Expenses
Other Operating
For the year ended December 31, 2003, other operating expenses increased $11.5
million compared to 2002. The increase is principally caused by increased
distribution, plant, and transmission operating expenses; power plant and other
maintenance; customer service initiatives; higher insurance premiums; and prior
year insurance recoveries. In addition, operating expenses reflect $1.8 million
in amortization of Ohio choice implementation costs, which are recovered through
increased gas utility margin. The increase in operating expenses was partially
offset by the impact of an Ohio regulatory order. The order allows the deferral
and recovery of uncollectible accounts expense to the extent it differs from the
level included in base rates. The Company estimated the difference to
approximate $4 million in excess of that included in base rates in 2003.
Other operating expenses decreased $13.5 million for the year ended December 31,
2002, when compared to 2001. The decrease results primarily from lower gas
prices and the related reduction in costs incurred in 2001. Specific expenses
affected by increased gas costs in 2001 were uncollectible accounts expense of
$3.4 million and contributions to low income heating assistance programs of $2.0
million. Insurance recovery in 2002 of $2.8 million of certain maintenance costs
incurred in 2001 also contributed to the decrease.
Depreciation & Amortization
For the year ended December 31, 2003, depreciation and amortization increased
$7.2 million compared to 2002 due to additions to utility plant. Increased
depreciation expense reflects depreciation of utility plant placed into service
including a full year for a gas-fired peaker unit, expenditures for implementing
a choice program for Ohio gas customers, customer system upgrades, and other
upgrades to existing transmission and distribution facilities.
Depreciation and amortization decreased $7.2 million for the year ended December
31, 2002, when compared to 2001. The decrease results from $9.6 million of
expense recognized in 2001 related to assets which had useful lives shortened as
a result of the merger. The discontinuance of goodwill amortization as required
by SFAS 142, which approximated $4.9 million in 2001, also contributed to the
decrease. These decreases were offset somewhat by depreciation of utility plant
and non-utility property additions.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5.9 million in 2003 compared to 2002.
Higher utility receipts and excise taxes of $4.5 million were recognized in 2003
due to higher gas prices and more volumes sold compared to 2002. The remaining
increase results principally from higher property taxes.
Taxes other than income taxes decreased $0.9 million in 2002 compared to 2001 as
a result of lower revenues subject to the Indiana utility receipts tax.
Other Income (Expense)
Other - net
Other - net decreased $2.3 million in 2003 compared to 2002 and increased $1.5
million in 2002 compared to 2001. The 2003 decrease is primarily due to the $3.9
million write-off of notes receivable and preferred equity investments in BABB
International (BABB), an entity that processed fly ash into building materials.
The 2002 increase results primarily from gains recognized from the sale of
excess emission allowances and other assets.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates increased $1.3 million in 2002
compared to 2001 principally due to increased losses and increased preferred
ownership in BABB. The smaller loss recognized in 2003 results from the
write-off of the BABB investment.
Interest Expense
Interest expense decreased $3.0 million in 2003 compared to 2002 and decreased
$1.6 million in 2002 compared to 2001. The 2003 decrease reflects the impact of
permanent financing completed in the third quarter of 2003. Lower average
interest rates on adjustable rate debt also contributed to the decreases in 2003
and 2002.
Income Taxes
For the year ended December 31, 2003, federal and state income taxes increased
$4.8 million in 2003 compared to 2002 and increased $25.5 million in 2002
compared to 2001. The 2003 increase results primarily from an increased
effective tax rate that reflects an increase in the Indiana state income tax
rate from 4.5 % to 8.5% and other changes in the effective tax rate recognized
in 2002. The increase in 2002 compared to 2001 is principally due to higher
pre-tax earnings.
Competition
The utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation. Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003.
Indiana has not adopted any regulation requiring gas choice; however, the
Company operates under approved tariffs permitting large volume customers to
choose their commodity supplier.
Other Operating Matters
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. In December 2001, the IURC approved the Company's request for
authority to transfer operational control over its electric transmission
facilities to the MISO. That transfer occurred on February 1, 2002.
Issues pertaining to certain of MISO's tariff charges for its services remain to
be determined by the FERC. Given the outstanding tariff issues, as well as the
potential for additional growth in MISO participation, the Company is unable to
determine the future impact MISO participation may have on its operations.
Pursuant to an order from the IURC, certain MISO costs are deferred for future
recovery.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, and export power to the
wholesale market may be impacted. Given the nature of MISO's policies regarding
use of transmission facilities, as well as ongoing FERC initiatives, it is
difficult to predict the impact on operational reliability. The potential need
to expend capital for improvements to the transmission system, both to SIGECO's
facilities as well as to those facilities of adjacent utilities, over the next
several years will become more predictable as MISO completes studies related to
regional transmission planning and improvements. Such expenditures may be
significant.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxide (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible with which to comply.
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for NOx emissions in
amounts that contributed to non-attainment with the ozone NAAQS in downwind
states. The USEPA required each state to revise its SIP to provide for further
NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's
final ruling, requires a 31% reduction in total NOx emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an 8 percent
return on its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations in the
government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO has entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions; o install a baghouse for
further particulate matter reductions at Culley Unit 3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested
with the most recent correspondence provided on March 26, 2001.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of
service, accounting matters, issuance of securities, and certain other
operational matters specific to its Indiana customers are regulated by the IURC.
The retail gas operations of the Ohio operations are subject to regulation by
the PUCO.
All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR clauses allow the Company to charge for changes in the cost of purchased
gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows
for adjustment in charges for electric energy to reflect changes in the cost of
fuel and the net energy cost of purchased power. Rate structures in the
Company's territories do not include weather normalization-type clauses that
authorize the utility to recover gross margin on sales established in its last
general rate case, regardless of actual weather patterns.
GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings
to establish the amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any under-or-over-recovery
resulting from gas and fuel adjustment clauses each month in revenues. A
corresponding asset or liability is recorded until the under-or-over-recovery is
billed or refunded to utility customers.
The IURC has also applied the statute authorizing GCA and FAC procedures to
reduce rates when necessary to limit net operating income to a level authorized
in its last general rate order through the application of an earnings test. For
the recent past, the earnings test has not affected the Company's ability to
recover costs, and the Company does not anticipate the earnings test will
restrict recovery in the near future.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
account expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.
Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.
Recovery of Purchased Power
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2004,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.
Regulatory Initiatives
In addition to the timely recovery of incremental NOx environmental expenditures
discussed above, the Company is pursuing base rate cases in its three gas
territories. The last general rate increase for VEDO and Indiana Gas was in
1992, and was in 1996 for SIGECO gas.
The Company is currently in a collaborative dialogue with the OUCC regarding
SIGECO's existing gas rates. If an agreement is reached between the parties as a
result of that process, it will be subject to review and approval by the IURC.
The Company expects to file a base rate case for Indiana Gas' territory during
the first quarter of 2004 and for VEDO in the second quarter of 2004.
Additionally, as part of the rate case process, the Company is pursuing
authority for recovery of the costs to comply with the Pipeline Safety Act of
2002 and for regulatory authority to amortize periodic expense incurred to
overhaul its electric turbines. The timing and ultimate outcome of any of these
regulatory initiatives is uncertain.
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates that affect
the amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgment. These include
the estimates to perform goodwill and other asset impairments tests. The Company
makes other estimates in the course of accounting for unbilled revenue, the
effects of regulation, and intercompany allocations 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.
Goodwill
Pursuant to SFAS No. 142, the Company performed an initial impairment analysis
of its goodwill, all of which resides in the Gas Utility Services operating
segment. Also consistent with SFAS 142, goodwill is tested for impairment
annually at the beginning of the year and more frequently if events or
circumstances indicate that an impairment loss has been incurred. Impairment
tests are performed at the reporting unit level which the Company has determined
to be consistent with its Gas Utility Services operating segment as identified
in Note 14 to the consolidated financial statements. An impairment test
performed in accordance with SFAS 142 requires that a reporting unit's fair
value be estimated. The Company used a discounted cash flow model to estimate
the fair value of its Gas Utility Services operating segment, and that estimated
fair value was compared to its carrying amount, including goodwill. The
estimated fair value was in excess of the carrying amount in both 2003 and 2002
and therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgment in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also would have resulted in no impairment charge in 2003 or
2002.
Impairment Review of Investments
The Company has investments in unconsolidated affiliated and notes receivable
convertible into equity interests. When events occur that may cause one of these
investments to be impaired, the Company performs an impairment analysis. An
impairment analysis of notes receivable usually involves the comparison of the
investment's estimated free cash flows to the stated terms of the note. An
impairment analysis of equity method investments involves comparison of the
investment's estimated fair value to its carrying amount. Fair value is
estimated using primarily discounted cash flow analyses. Calculating free cash
flows and fair value is subjective and requires significant judgment in growth
assumptions, longevity of cash flows, and discount rates (for fair value
calculations). As a result of such tests, a $3.9 million dollar write-off of the
BABB investments resulted in 2003.
Unbilled Revenues
To more closely match revenues and expenses, the Company records revenues for
all gas and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the month to
allocate unbilled units. Those allocated units are multiplied by rates in effect
during the month to calculate unbilled revenue at balance sheet dates. While
certain estimates are used in the calculation of unbilled revenue, the method
these estimates are derived from is not subject to near-term changes.
Regulation
At each reporting date, the Company reviews current regulatory trends in the
markets in which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Based on the Company's current review, it believes its regulatory assets are
probable of recovery. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets. In the unlikely event of a change in the current regulatory
environment, such write-offs and impairment charges could be significant.
Intercompany Allocations
Support Services
Vectren and certain subsidiaries of Vectren provide corporate, general and
administrative services to the Company including legal, finance, tax, risk
management, and human resources, which includes charges for restricted stock
compensation and for pension and other postretirement benefits not directly
charged to subsidiaries. These costs have been allocated using various
allocators, primarily number of employees, number of customers and/or revenues.
Allocations are based on cost. Management believes that the allocation
methodology is reasonable and approximates the costs that would have been
incurred had the Company secured those services on a stand-alone basis. The
allocation methodology is not subject to near term changes.
Pension and Other Postretirement Obligations
Vectren satisfies the future funding requirements of its pension and other
postretirement plans and the payment of benefits from general corporate assets.
An allocation of expense is determined by Vectren's actuaries, comprised of only
service cost and interest on that service cost, by subsidiary based on headcount
at each measurement date, which occurs on September 30. These costs are directly
charged to individual subsidiaries. Other components of costs (such as interest
cost and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Neither plan assets nor the FAS
87/106 liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. Further, Vectren
satisfies the future funding requirements of plans and the payment of benefits
from general corporate assets. Management believes these direct charges when
combined with benefit-related corporate charges discussed in "support services"
above approximate costs that would have been incurred if the Company accounted
for benefit plans on a stand-alone basis.
Vectren estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other things, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of pension and postretirement plans. Vectren used the
following weighted average assumptions to develop 2003 periodic benefit cost: a
discount rate of 6.75%, an expected return on plan assets before expenses of
9.0%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2003 declining to 5% in 2006. During 2003, Vectren reduced the
discount rate and rate of compensation increase by 75 basis points to value 2003
ending pension and postretirement obligations due to a decline in benchmark
interest rates. The Company also lengthened to 2009 the time in which the health
care trend rate declines to 5% primarily due to increases in healthcare costs.
In addition, the Company reduced its 2004 expected return on plan assets 50
basis points from that used to estimate 2003 expense due to recent lower
investment returns and lower interest rates. Future changes in health care
costs, work force demographics, interest rates, or plan changes could
significantly affect the estimated cost of these future benefits that are
allocated to VUHI and its subsidiaries.
Impact of Recently Issued Accounting Guidance
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $229 million and $210 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
Company has approximately $200,000 of outstanding preferred stock of a
subsidiary that is redeemable on terms outside the Company's control. However,
the preferred stock is not redeemable on a specified or determinable date or
upon an event that is certain to occur. The adoption of SFAS 150 on January 1,
2004, did not affect the Company's results of operations or financial condition.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. Although management is
still evaluating the impact of FIN 46 and related Staff Positions on its
financial position and results of operations, the adoption is not expected to
have a material effect.
Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 consolidated financial statements, the
Company restated its annual consolidated financial statements for 2000 and 2001,
and its 2002 quarterly results. The Company received an informal inquiry from
the SEC with respect to this restatement. In response, the Company met with the
SEC staff and provided information in response to their requests, with the most
recent response provided on July 26, 2003.
Financial Condition
Within Vectren's consolidated group, VUHI, the parent company, funds short-term
and long-term financing needs of the utility group operations. Vectren does not
guarantee VUHI's debt. VUHI's currently outstanding long-term and short-term
borrowing arrangements are jointly and severally guaranteed by Indiana Gas,
SIGECO, and VEDO. The guarantees are full and unconditional and joint and
several, and VUHI has no subsidiaries other than the subsidiary guarantors.
VUHI's long-term and short-term obligations outstanding at December 31, 2003,
totaled $550.0 million and $184.4 million, respectively. Additionally, prior to
VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and
therefore, have long-term debt outstanding funded solely by their operations.
VUHI's operations have historically funded almost all of Vectren's common stock
dividends.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2003, are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's Investors Service (Moody's), respectively.
SIGECO's credit ratings on outstanding senior unsecured debt are BBB+/Baa1.
SIGECO's credit ratings on outstanding secured debt are A-/A3. VUHI's commercial
paper has a credit rating of A-2/P-2. Moody's current outlook is stable while
Standard and Poor's current outlook is negative. The ratings of Moody's and
Standard and Poor's are categorized as investment grade and are unchanged from
December 31, 2002. In July 2003, Standard and Poor's reaffirmed its ratings, and
Moody's reaffirmed its ratings on VUHI's senior unsecured debt. A security
rating is not a recommendation to buy, sell, or hold securities. The rating is
subject to revision or withdrawal at any time, and each rating should be
evaluated independently of any other rating. Standard and Poor's and Moody's
lowest level investment grade rating is BBB- and Baa3, respectively.
The Company's consolidated equity capitalization objective is 45-55% of total
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, and seasonal
factors that affect the Company's operation. The Company's equity component was
50% and 46% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at December 31, 2003, and 2002,
respectively.
The Company expects the majority of its capital expenditures, investments, and
debt security redemptions to be provided by internally generated funds. However,
due to significant capital expenditures for NOx compliance equipment at SIGECO
and to further strengthen the Company's capital structure and the capital
structures of its utility subsidiaries, the Company has completed certain
financing transactions as more fully described in the discussion of financing
activity below.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities decreased during the year ended December 31, 2003, compared to 2002
by $108.4 million and increased $92.3 million in 2002 compared to 2001. The
primary reason for these changes was favorable changes in working capital
accounts occurring in 2002 due to lower gas prices in that year and higher gas
prices in 2003 and 2001. In 2003, the decrease was partially offset by increased
earnings before non-cash charges.
Financing Cash Flow
Although working capital requirements are generally funded by cash flow from
operations, the Company uses short-term borrowings to supplement working capital
needs. Additionally, short-term borrowings are required for capital projects and
investments until they are permanently financed.
Cash flow provided by financing activities of $64.5 million for the year ended
December 31, 2003, includes the effects of the permanent financing executed
during the current year in which approximately $407 million in capital
contributions from Vectren, third party debt proceeds, and hedging net proceeds
were received and used to retire higher coupon long-term debt and other short
term borrowings. Common stock dividends have increased in 2003 compared to 2002.
Cash flow required for financing activities of $53.6 million for the year ended
December 31, 2002, includes increased borrowings due to financing a portion of
capital expenditures for NOx compliance temporarily with short-term borrowings.
Cash flow provided by financing activities of $33.9 million for the year ended
December 31, 2001, includes $38.1 million of reductions in borrowings and
preferred stock and $91.6 million in dividends paid to Vectren, offset by
additional capital contributions of $164.4 million. During 2001, $508.4 million
of net proceeds from Vectren capital contributions and debt issuances were
utilized to pay down short-term borrowings and strengthen VUHI's balance sheet.
VUHI Debt Issuance
In March 2003, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock as well as senior unsecured notes of
VUHI. In July 2003, VUHI issued senior unsecured notes with an aggregate
principal amount of $200 million in two $100 million tranches. The first tranche
was 10-year notes due August 2013, with an interest rate of 5.25% priced at
99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year
notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield
5.80% to maturity (2018 Notes).
The notes are guaranteed by VUHI's three public utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and several. In
addition, they have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by VUHI, in whole or in part, at any time
for an amount equal to accrued and unpaid interest, plus the greater of 100% of
the principal amount or the sum of the present values of the remaining scheduled
payments of principal and interest, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20
basis points for the 2013 Notes and 25 basis points for the 2018 Notes.
Shortly before these issues, VUHI entered into several treasury locks with a
total notional amount of $150.0 million. Upon issuance of the debt, the treasury
locks were settled resulting in the receipt of $5.7 million in cash, which was
recorded as a regulatory liability pursuant to existing regulatory orders. The
value received is being amortized as a reduction of interest expense over the
life of the issues.
The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million and were used to repay short-term
borrowing and to retire long-term debt with higher interest rates.
Additional Capital Contributions
During 2003, the Company received a $204.1 million equity contribution from
Vectren. Vectren funded $163.2 million of the contribution with proceeds from an
offering of its common stock, $35.0 million was funded by Vectren's nonregulated
operations, and $5.9 million was funded by new share issues from Vectren's
dividend reinvestment plan. These proceeds were used by VUHI and VUHI's
subsidiaries to repay short-term borrowings and to retire long-term debt with
higher interest rates.
SIGECO and Indiana Gas Debt Call
During 2003, the Company called two first mortgage bonds outstanding at SIGECO
and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
had a principal amount of $45.0 million, an interest rate of 7.60%, was
originally due in 2023, and was redeemed at 103.745% of its stated principal
amount. The second SIGECO bond had a principal amount of $20.0 million, an
interest rate of 7.625%, was originally due in 2025, and was redeemed at
103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an
interest rate of 9.375%, was originally due in 2021, and was redeemed at
105.525% of the stated principal amount. The second Indiana Gas note had a
principal amount of $13.5 million, an interest rate of 6.75%, was originally due
in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire these notes
totaling $3.6 million were deferred as a regulatory asset.
Permanent Financing for the Ohio Operations Purchase
In January 2001, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock. In February 2001, the registration
became effective. The net proceeds from the sale of common stock totaled $129.4
million. These proceeds were contributed to VUHI as an additional capital
contribution.
In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission for $350.0 million aggregate principal amount of
unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with
an aggregate principal amount of $100.0 million and an interest rate of 7.25%
(the October Notes), and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.
Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and
several. In addition, these issues have no sinking fund requirements, and
interest payments are due quarterly for the October Notes and semi-annually for
the December Notes. The October Notes are due October 2031, but may be called by
the Company, in whole or in part, at any time after October 2006 at 100% of the
principal amount plus any accrued interest thereon. The December Notes are due
December 2011, but may be called by the Company, in whole or in part, at any
time for an amount equal to accrued and unpaid interest, plus the greater of
100% of the principal amount or the sum of the present values of the remaining
scheduled payments of principal and interest, discounted to the redemption date
on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus
25 basis points.
The net proceeds from the sale of the senior notes and settlement of hedging
arrangements totaled $344.0 million.
The proceeds received from the capital contribution and debt issuance were used
to refinance interim borrowing arrangements used to purchase the Ohio
operations.
Other Financing Transactions
Other Company long-term debt totaling $18.5 million in 2003, $6.5 million in
2001, and $7.6 million in 2001 was retired as scheduled.
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.
Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.
In December 2001, Vectren made an additional equity contribution of $35.0
million with proceeds received from dividends paid by Vectren's nonregulated
operations.
In September 2001, the Company notified holders of SIGECO's 4.80%, 4.75%, and
6.50% preferred stock of its intention to redeem the shares. The 4.80% preferred
stock was redeemed at $110.00 per share, plus $1.35 per share in accrued and
unpaid dividends. Prior to the redemption, there were 85,519 shares outstanding.
The 4.75% preferred stock was redeemed at $101.00 per share, plus $0.97 per
share in accrued and unpaid dividends. Prior to the redemption, there were 3,000
shares outstanding. The 6.50% preferred stock was redeemed at $104.23 per share,
plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption,
there were 75,000 shares outstanding. The total redemption price was $17.7
million.
Investing Cash Flow
Cash required for investing activities of $236.1 million for the year ended
December 31, 2003, includes $235.0 million of requirements for capital
expenditures. Investing activities for 2002 were $218.7 million. The increase
occurring in 2003 principally results from higher capital expenditures.
Cash required for investing activities of $218.7 million for the year ended
December 31, 2002, includes $217.3 million of requirements for capital
expenditures. Investing activities for 2001 were $215.3 million. The $3.4
million increase occurring in 2002 is principally the result of additional
capital expenditures for NOx compliance and investments in deferred compensation
funding arrangements, offset by proceeds received from intercompany notes
receivable.
Available Sources of Liquidity
At December 31, 2003, the Company has $351 million of short-term borrowing
capacity, of which approximately $166 million is available.
Beginning in 2003, Vectren began issuing new shares to satisfy dividend
reinvestment plan requirements. During 2003, proceeds of $5.9 million generated
by the dividend reinvestment plan were contributed to VUHI. Management estimates
such new share issues will add similar liquidity to support VUHI's operations in
succeeding years.
Potential & Future Uses of Liquidity
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2003:
- ------------------------------------------------------------------------------------
(In millions) 2004 2005 2006 2007 2008 Thereafter
- ------------------------------------------------------------------------------------
Long-term debt (1) $ 15.0 $ - $ - $ 6.5 $ - $ 972.0
Short-term debt 185.2 - - - - -
Commodity firm purchase
commitments 105.8 29.3 - - - -
Utility & nonutility plant
purchase commitments (2) 96.8 19.7 1.3 - - -
- ------------------------------------------------------------------------------------
Total $402.8 $49.0 $ 1.3 $ 6.5 $ - $ 972.0
====================================================================================
(1) Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow holders
to put debt back to the Company at face value or the Company to call debt
at face value or at a premium. Long-term debt subject to tender during the
years following 2003 (in millions) is $13.5 in 2004, $10.0 in 2005, $53.7
in 2006, $20.0 in 2007, zero in 2008, and $120.0 thereafter.
(2) The settlement period of these obligations is estimated.
Planned Capital Expenditures
The timing and amount of capital expenditures, including contractual
purchase commitments discussed above, for the five-year period 2004 - 2008 are
estimated as follows (in millions): $252.9 in 2004, $213.8 in 2005, $222.9 in
2006, 216.4 in 2007, and $233.6 in 2008. Included in planned capital
expenditures for NOx compliance is (in millions) $77.4 in 2004, $19.7 in 2005,
and $3.6 in 2006
Pension and Postretirement Funding Obligations
Vectren has not made significant contributions to its qualified pension plans in
recent years. Due to recent market performance, it is likely to be necessary for
Vectren to make contributions to benefits plans in the coming years. Management
currently estimates that qualified pension plans will require Company
contributions of approximately $5 million in 2004 and approximately $10 million
in 2005. VUHI may be called upon to fund a portion of these contributions.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in our credit rating, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
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