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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2004
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from __________________ to ________________________
Commission file number: 1-16739
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 Identification
incorporation or organization) 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, 2004, 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, 2005
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 MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh / GWh: megawatt hours / thousands of
megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of PUCO: Public Utilities Commission of Ohio
Environmental Management
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF/MMCF/BCF: thousands/millions/ USEPA: United States Environmental
billions of cubic feet Protection Agency
MDth/MMDth: thousands/millions of Throughput: combined gas sales and gas
dekatherms transportation volumes
Table of Contents
Item Page
Number Number
Part I
1 Business ..............................................................1
2 Properties ............................................................5
3 Legal Proceedings......................................................6
4 Submission of Matters to Vote of Security Holders......................6
Part II
5 Market for the Company's Common Equity, Related Stockholder
Matters, and Issuer Purchases of Equity Securities ....................6
6 Selected Financial Data................................................7
7 Management's Discussion and Analysis of Results of
Operations and Financial Condition.....................................8
7A Qualitative and Quantitative Disclosures About Market Risk............23
8 Financial Statements and Supplementary Data...........................25
9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................................56
9A Controls and Procedures...............................................56
9B Other Information.....................................................56
Part III
10 Directors and Executive Officers of the Registrant(A).................56
11 Executive Compensation(A).............................................56
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters(A).........................56
13 Certain Relationships and Related Transactions(A).....................56
14 Principal Accountant Fees and Services................................57
Part IV
15 Exhibits and Financial Statement Schedules............................58
Signatures............................................................63
(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,
including those of Vectren Utility Holdings, Inc., 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,
47702-0209 Investor Relations
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 energy delivery services to approximately 555,000 natural
gas customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 136,000 electric customers and approximately
110,000 natural gas customers located near Evansville in southwestern Indiana.
SIGECO also owns and operates electric generation to serve its electric
customers and optimizes those assets in the wholesale power market. Indiana Gas
and SIGECO generally do business as Vectren Energy Delivery of Indiana.
The Ohio operations provide energy delivery services to approximately 315,000
natural gas customers located near Dayton in west central Ohio. The Ohio
operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio,
Inc. (VEDO), a wholly owned subsidiary, (53% ownership) and Indiana Gas (47%
ownership). The Ohio operations were acquired from The Dayton Power and Light
Company on October 31, 2000. The Ohio operations generally do business as
Vectren Energy Delivery of Ohio.
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.
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.
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 to nearly two-thirds of Indiana and to
west central Ohio. The Electric Utility Services segment includes the operations
of SIGECO's electric transmission and distribution services, which provides
electric distribution services primarily to southwestern Indiana, and includes
the Company's power generating and marketing operations. The Company
collectively refers to its gas and electric operating segments as its regulated
operations. In total, these regulated operations supply natural gas and/or
electricity to nearly one million customers. Other Operations primarily provide
information technology and other support services to those utility operations.
At December 31, 2004, the Company had $3.1 billion in total assets, with $1.9
billion (61%) attributed to the Gas Utility Services, $1.1 billion (35%)
attributed to the Electric Utility Services, and $0.1 billion (3%) attributed to
Other Operations. Net income for the year ended December 31, 2003, was $83.1
million with $75.9 million attributed to regulated operations and $7.2 million
attributed to other operations. Net income for the year ended 2003 was $85.6
million.
For further information, refer to Note 13 regarding the activities and assets of
the Company's operating segments 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
generally not significant.
Gas Utility Services
At December 31, 2004, the Company supplied natural gas service to approximately
980,000 Indiana and Ohio customers, including 895,000 residential, 81,000
commercial, and 4,000 contract and other customers. This represents customer
base growth of 1.2% compared to 2003.
The Company's service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served include
automotive assembly, parts and accessories, feed, flour and grain processing,
metal castings, aluminum products, appliance manufacturing, polycarbonate resin
(Lexan(R)) and plastic products, gypsum products, electrical equipment, metal
specialties, glass, steel finishing, pharmaceutical and nutritional products,
gasoline and oil products, and coal mining. The largest Indiana communities
served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and
Richmond. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2004, gas utility revenues were approximately
$1,126.2 million, of which residential customers accounted for 66%, commercial
25%, and industrial and other 9%, respectively.
The Company receives gas revenues by selling gas directly to customers at
approved rates or by transporting gas through its pipelines at approved rates to
customers that have purchased gas directly from other producers, brokers, or
marketers. Total volumes of gas provided to both sales and transportation
customers (throughput) were 200,343 MDth for the year ended December 31, 2004.
Gas transported or sold to residential and commercial customers was 110,666 MDth
representing 55% of throughput. Gas transported or sold to industrial and other
contract customers was 89,677 MDth representing 45% of throughput. Rates for
transporting gas provide for the same margins generally earned by selling gas
under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company has storage capacity at
seven active underground gas storage fields, six liquefied petroleum air-gas
manufacturing plants, and a propane cavern. The Company also contracts with
ProLiance Energy, LLC (ProLiance) to ensure availability of gas. ProLiance is an
unconsolidated, nonregulated, energy marketing affiliate of Vectren and Citizens
Gas and Coke Utility (Citizens Gas). (See Note 4 in the Company's consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding transactions with ProLiance). Periodically, purchased natural
gas is injected into storage. The injected gas is then available to supplement
contracted and manufactured volumes during periods of peak requirements. In
addition, the Company prepays ProLiance for natural gas delivery services during
the seven months prior to the peak heating season. The volume of gas per day
that can be delivered during peak demand periods for each utility is located in
"Item 2 Properties."
Gas Purchases
In 2004, the Company purchased 112,372 MDth volumes of gas at an average cost of
$6.92 per Dth, all of which was purchased from ProLiance pursuant to contracts
approved by the IURC. The average cost of gas per Dth purchased for the last
five years was: $6.92 in 2004; $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; and
$5.60 in 2000.
Electric Utility Services
At December 31, 2004, the Company supplied electric service to approximately
136,000 Indiana customers, including 119,000 residential, and 17,000 commercial,
industrial, and other customers. This represents customer base growth of 0.9%
compared to 2003. In addition, the Company is obligated to provide for firm
power commitments to four municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.
The principal industries served include polycarbonate resin (Lexan(R)) and
plastic products, aluminum smelting and recycling, aluminum sheet products,
automotive assembly, steel finishing, appliance manufacturing, pharmaceutical
and nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For the year ended December 31, 2004, retail and firm wholesale electricity
sales totaled 6,186,160 MWh, resulting in revenues of approximately $347.5
million. Residential customers accounted for 34% of 2004 revenues; commercial
27%; industrial 31%; and municipal and other 8%. In addition, the Company sold
3,526,005 MWh through wholesale contracts in 2004, generating revenue, net of
purchased power costs, of $23.8 million.
Generating Capacity
Installed generating capacity as of December 31, 2004, was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and natural gas or
oil-fired turbines used for peaking or emergency conditions provide 295 MW.
Peaking capacity of 80 MW fueled by natural gas was added during 2002.
In addition to its generating capacity, in 2004, the Company had 32 MW available
under firm contracts and 51 MW available under interruptible contracts. The
Company also had a firm purchase supply contract for a maximum of 73 MW for the
peak cooling season months during 2004.
The Company has interconnections with Louisville Gas and Electric Company,
Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability has been, and may continue to be, impacted. The
Company, as a member of the Midwest Independent System Operator (MISO), has
turned over operational control of the interchange facilities and its own
transmission assets, like many other Midwestern electric utilities, to the MISO.
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's participation in MISO.
Total load for each of the years 2000 through 2004 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
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Date of summer peak load 7/13/2004 8/27/2003 8/5/2002 7/31/2001 8/17/2000
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Total load at peak (1) 1,222 1,272 1,258 1,234 1,212
Generating capability 1,351 1,351 1,351 1,271 1,256
Firm purchase supply 105 32 82 82 75
Interruptible contracts 51 95 95 95 95
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Total power supply capacity 1,507 1,478 1,528 1,448 1,426
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Reserve margin at peak 23% 16% 21% 17% 18%
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(1) The total load at peak is increased 25 MW in 2003, 2002, and 2001 from the
total load actually experienced. The additional 25 MW represents load that
would have been incurred if summer cycler programs had not been activated.
The 25 MW is also included in the interruptible contract portion of the
Company's total power supply capacity. On the date of peak in 2004 and
2000, summer cycler programs were not activated.
The winter peak load for the 2003-2004 season of approximately 928 MW occurred
on January 20, 2004. The prior year winter peak loadwas approximately 948 MW,
occurring on January 27, 2003.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO, and supplies power requirements to the United States Department of
Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for, any
available power in excess of the DOE contract demand. At the present time, the
DOE contract demand is essentially zero. Because of this decreased demand, the
Company's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.
Such generating capacity is included in firm purchase supply in the chart above.
Fuel Costs and Purchased Power
Electric generation for 2004 was fueled by coal (95.6%) and natural gas (4.4%).
Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of Vectren. Approximately 3.0 million tons of coal were purchased
for generating electricity during 2004, of which substantially all was supplied
by Vectren Fuels, Inc. from its mines and third party purchases. The average
cost of coal consumed in generating electric energy for the years 2000 through
2004 follows:
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Year Ended December 31,
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Avg. Cost Per 2004 2003 2002 2001 2000
------- -------- ------- ------- --------
Ton $ 27.06 $ 24.91 $ 23.50 $ 22.48 $ 22.49
MWh 13.06 11.93 11.00 10.53 10.39
The Company also purchases power as needed from the wholesale market to
supplement its generation capabilities in periods of peak demand; however, the
majority of power purchased through the wholesale market is used to optimize and
hedge the Company's sales to other wholesale customers. Volumes purchased in
2004 totaled 3,469,610 MWh.
Competition
The utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation. Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003. At
December 31, 2004, approximately 73,000 customers in VUHI's Ohio service
territory purchase natural gas from a supplier other than the regulated utility.
Margin earned for transporting natural gas to those customers, who have
purchased natural gas from another supplier, are generally the same as those
earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation
requiring gas choice; however, the Company operates under approved tariffs
permitting large volume customers to choose their commodity supplier.
Regulatory and Environmental Matters
See "Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition" regarding the Company's regulated environment and other
environmental matters.
Personnel
As of December 31, 2004, the Company and its consolidated subsidiaries had
1566 employees, of which 872 are subject to collective bargaining
arrangements.
In July of 2004, the Company signed a three year labor agreement with Local 702
of the International Brotherhood of Electrical Workers, ending June 2007. The
agreement provides a 3% wage increase in the first two years and a 3.5% increase
in the third year of the agreement. The agreement also provides for improvements
in pension benefits and a multi-tiered health plan in which the employees pay
16% of the cost.
In January 2004, the Company signed a five year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America Locals 12213 and 7441. The agreement provides for
annual wage increases of 3%, a multi-tiered health care plan in which the
employees pay 12% to 16% of the premium, and pension enhancements for early
retirees.
The Company's contract with Local 135 of the Teamsters, Chauffeurs,
Warehousemen, and Helpers will expire in September 2005. The Company's contract
with Local 175, Utility Workers Union of America will expire in October 2005.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana
covering 58,130 acres of land with an estimated ready delivery from storage
capability of 5.6 BCF of gas with maximum peak day delivery capabilities of
144,500 MCF per day. Indiana Gas also owns and operates three liquefied
petroleum (propane) air-gas manufacturing plants located in Indiana with the
ability to store 1.5 million gallons of propane and manufacture for delivery
33,000 MCF of manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.8 BCF of storage
with a maximum peak day delivery capability of 299,717 MMBTU per day. Indiana
Gas' gas delivery system includes 12,150 miles of distribution and transmission
mains, all of which are in Indiana except for pipeline facilities extending from
points in northern Kentucky to points in southern Indiana so that gas may be
transported to Indiana and sold or transported by Indiana Gas to ultimate
customers in Indiana.
SIGECO owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
108,000 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 19,166 MMBTU per day. SIGECO's gas delivery system
includes 3,074 miles of distribution and transmission mains, all of which are
located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants and a cavern for propane storage, all of which are located
in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the
plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In
addition to its propane delivery capabilities, the Ohio operations have
contracted for 13.4 BCF of storage with a maximum peak day delivery capability
of 287,684 MMBTU per day. The Ohio operations' gas delivery system includes
5,301 miles of distribution and transmission mains, all of which are located in
Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2004, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick
Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located
in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking
units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two
Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined
capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and an 80 MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. The
Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.
Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally
used only for reserve, peaking, or emergency purposes due to the higher per unit
cost of generation.
SIGECO's transmission system consists of 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 28 substations with an
installed capacity of 4,635.9 megavolt amperes (Mva). The electric distribution
system includes 3,223 pole miles of lower voltage overhead lines and 302 trench
miles of conduit containing 1,688 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,630 distribution transformers with an installed
capacity of 2,388.8 Mva.
SIGECO owns utility property outside of Indiana approximating eight miles of
138,000 volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system at
Cloverport, Kentucky.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture
dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee,
and Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position. See the notes to the consolidated financial statements
regarding commitments and contingencies, environmental matters, and rate and
regulatory matters. The consolidated financial statements are included in "Item
8 Financial Statements and Supplementary Data."
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter to a vote of security
holders.
PART II
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND
ISSUER PURCHASES OF EQUITY SECURITIES
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 2004, VUHI paid dividends to its parent company of $20.0 million in the
first quarter, $19.9 million in the second quarter, $21.1 million in the third
quarter, and $19.6 million in the fourth quarter.
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.
On January 26, 2005, the board of directors declared a $20.0 million dividend,
payable to Vectren on February 28, 2005.
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 Price Range
------------------------- -----------------------------------
2004 High Low 2003 High Low
------------- --------- -------- --------
First Quarter $ 27.44 $ 26.25 First Quarter $ 26.60 $ 25.54
Second Quarter 27.03 24.05 Second Quarter 27.80 25.61
Third Quarter 26.81 23.03 Third Quarter 27.10 25.60
Fourth Quarter 27.00 26.06 Fourth Quarter 27.35 26.00
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K.
Year Ended December 31,
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(In millions) 2004 2003 2002 2001 (1) 2000 (2,3)
- ------------------------------------------------------------------------------------------------------------
Operating Data:
Operating revenues $ 1,498.0 $ 1,448.8 $ 1,236.9 $ 1,328.3 $ 1,129.9
Operating income 198.2 199.0 207.7 131.4 136.1
Income before cumulative effect of change
in accounting principle 83.1 85.6 97.1 43.7 55.9
Net income 83.1 85.6 97.1 44.8 55.9
Balance Sheet Data:
Total assets $ 3,147.7 $ 2,925.1 $ 2,780.4 $ 2,489.3 $ 2,509.0
Redeemable preferred stock 0.1 0.2 0.3 0.5 8.1
Long-term debt - net of current maturities
& debt subject to tender 941.3 960.5 841.2 900.9 572.6
Common shareholder's equity 985.4 979.8 768.6 738.9 624.3
(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 2004, Earnings were $83.1 million as compared to $85.6 million in 2003. The
2004 earnings decline is due to the impact of unfavorable weather, estimated at
$5 million after tax. Margin growth, offsetting the weather impact, results from
the recovery of NOx related environmental expenditures, gas base rate increases
implemented in 2004, and customer growth. The primary expense changes were
higher depreciation and lower bad debt expense in 2003. Bad debt expense in 2003
associated with the Ohio service territory was reversed and deferred for later
recovery under an uncollectible accounts expense rider.
The $11.5 million decrease in earnings occurring in 2003 compared to 2002 was
primarily due to increased operating expenses and the write-off of an
investment, partially offset by increased wholesale power margins and retail
electric rate recovery related to NOx compliance expenditures. An increase in
the Indiana state income tax rate to 8.5% from 4.5% also contributed to the
decrease.
During 2004 and 2003, the Company initiated base rate cases in its three gas
service territories. Orders in its two Indiana service territories were received
in the second half of 2004. An order in the Ohio territory is expected late in
the first quarter of 2005. On an annual basis, the Indiana orders will increase
margins an estimated $30 million, and during 2004 provided additional margin of
$4.7 million. The Company has sought and received regulatory recovery mechanisms
(trackers) affecting electric margin that provide a return on utility plant
constructed for environmental compliance and that allow for recovery of related
operating expenses. After tax earnings associated with the NOx compliance
trackers totaled $9.0 million in 2004, $4.7 million in 2003 and $1.1 million in
2002. The Company has also utilized regulatory trackers affecting gas margin
that recover, on a dollar-for-dollar basis, pipeline integrity management costs
in its Indiana territories and uncollectible accounts expense, operating
expenses related to choice implementation costs, and other costs in its Ohio
service territory.
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.
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. Electric Utility margin is calculated as
Electric utility revenues less Fuel for electric generation and Purchased
electric energy. These measures exclude Other operating expenses, Depreciation
and amortization, and Taxes other than income taxes, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of, operating performance than
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.
Margin
Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in the
Company's service territories. Margin generated from sales to large customers
(generally industrial, other contract, and firm wholesale customers) is
primarily impacted by overall economic conditions. Margin is also impacted by
the collection of state mandated taxes, which fluctuate with gas costs, and is
also impacted by some level of price sensitivity in volumes sold. Electric
generating asset optimization activities are primarily affected by market
conditions, the level of excess generating capacity, and electric transmission
availability. Following is a discussion and analysis of margin generated from
regulated utility operations.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- --------------------------------------------------------------------------------
Residential & Commercial $ 288.3 $ 292.3 $ 282.6
Contract 53.5 51.5 50.5
Other 5.9 6.0 4.1
- --------------------------------------------------------------------------------
Total gas utility margin $ 347.7 $ 349.8 $ 337.2
================================================================================
Sold & transported volumes in MMDth:
To residential & commercial customers 110.7 117.9 111.9
To contract customers 89.7 91.4 95.8
- --------------------------------------------------------------------------------
Total throughput 200.4 209.3 207.7
================================================================================
Gas utility margins were $347.7 million for the year ended December 31, 2004.
This represents a decrease in gas utility margin of $2.1 million compared to
2003. Heating weather for the year ended December 31, 2004, was 8% warmer than
normal and 8% warmer than the prior year. The estimated unfavorable impact on
gas utility margin caused by weather was approximately $9.8 million compared to
2003. Indiana base rate increases added $4.7 million compared to the prior year.
Also offsetting the effects of weather were increased late and reconnect fees,
expense recovery pursuant to Ohio regulatory trackers, and higher revenue taxes
collected from rate payers. Gas sold and transported volumes were 4% less in
2004, compared to the prior year. The decreased throughput was primarily
attributable to weather. The average cost per dekatherm of gas purchased was
$6.92 in 2004; $6.36 in 2003, and $4.57 in 2002.
Gas Utility margin for the year ended December 31, 2003, of $349.8 million
increased $12.6 million, or 4%, compared to 2002. It is estimated that weather
near normal for the year and 6% cooler than the prior year, contributed $8
million in increased residential and commercial margin and was the primary
contributor to increased throughput compared to 2002. The remaining increase is
primarily attributable to $4.5 million in higher revenue taxes on higher gas
costs and volumes sold and $1.8 million in recovery of Ohio customer choice
implementation costs.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric
Generation and Purchased Electric Energy)
Electric Utility margin by revenue type follows:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- --------------------------------------------------------------------------------
Residential & commercial $ 159.7 $ 141.1 $ 145.7
Industrial 62.4 53.5 54.9
Municipalities & other 17.4 20.1 16.9
- --------------------------------------------------------------------------------
Total retail & firm wholesale 239.5 214.7 217.5
Asset optimization 15.0 18.3 12.7
- --------------------------------------------------------------------------------
Total electric utility margin $ 254.5 $ 233.0 $ 230.2
================================================================================
Retail & Firm Wholesale Margin
Native load and firm wholesale margin was $239.5 million for the year ended
December 31, 2004. This represents a $24.8 million increase over 2003.
Additional NOx recoveries increased margin $14.6 million in 2004. Cooling
weather for the year was 12% warmer than last year, increasing margin an
estimated $2.0 million. The remaining increase in margin was attributable to
increased small customer usage and increased sales to industrial customers. Due
to the above factors, volumes sold increased 5% to 6.19 GWh for 2004, compared
to 5.90 GWh in 2003. Volumes sold in 2002 were 6.19 GWh.
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.7 million, a decrease of $2.8 million when compared
to 2002. It is estimated that summer weather, 19% cooler than normal and 34%
cooler than 2002, caused an $8 million decrease in residential and commercial
margin. The effect of weather was partially offset by a $7.4 million increase in
retail electric rates related to recovery of and return on NOx compliance
expenditures and related operating expenses. A slowly recovering economy
continued to negatively impact industrial sales which decreased $1.4 million
compared to 2002. As a result of primarily mild weather and slow economic
conditions, retail and firm wholesale volumes sold decreased 5%.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of the
margin from these activities is generated from contracts that are integrated
with portfolio requirements around power supply and delivery and are short-term
purchase and sale transactions that expose the Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
- --------------------------------------------------------------------------------
(In millions) 2004 2003 2002
- --------------------------------------------------------------------------------
Beginning of Year Net Asset
Optimization Position $ (0.4) $ (0.7) $ 3.3
Statement of Income Activity
Mark-to-market gains (losses)
recognized (1.4) 0.7 (3.6)
Realized gains recognized 16.4 17.6 16.3
- --------------------------------------------------------------------------------
Net activity in electric
utility margin 15.0 18.3 12.7
- --------------------------------------------------------------------------------
Net cash received & other adjustments (15.2) (18.0) (16.7)
- --------------------------------------------------------------------------------
End of Year Net Asset Optimization
Position $ (0.6) $ (0.4) $ (0.7)
================================================================================
Net wholesale margins decreased $3.3 million compared to 2003 due to reduced
available capacity. The availability of excess capacity was impacted by
scheduled outages of owned generation, related to the installation of
environmental compliance equipment and an increase in demand by native load
customers due to both weather and increased usage. The $5.6 million increase in
2003 compared to 2002 was primarily due to price volatility and additional
capacity due to weather.
Operating Expenses
Other Operating
Other operating expenses increased $8.4 million for the year ended December 31,
2004 as compared to 2003. Expense in 2003 reflects the deferral of $4.0 million
relating to the Ohio order allowing the Company to defer for future recovery its
actual bad debt expense in excess of the amount provided in base rates (See Rate
and Regulatory Matters below). Other factors contributing to the increase were
an increase in NOx-related expenses of $2.6 million recovered in rates and
planned turbine maintenance of $1.9 million.
Other operating expense increased $11.5 million in 2003 compared to 2002. The
increase was principally caused by increased distribution, plant, and
transmission operating expenses; power plant and other maintenance; customer
service initiatives; higher insurance premiums; and prior year insurance
recoveries. In addition, operating expenses reflect $1.8 million in amortization
of Ohio choice implementation costs, which are recovered through increased gas
utility margin. The increase in operating expenses was partially offset by the
impact of an Ohio regulatory order, which resulted in the reversal and deferral
of 2003 uncollectible accounts expense of $4.0 million for future recovery.
Depreciation & Amortization
For the year ended December 31, 2004, depreciation expense increased $9.9
million compared to 2003. NOx-related depreciation contributed $4.8 million of
the increase with the remaining increase due primarily to normal additions to
utility plant. The increase of $7.2 million in 2003 compared to 2002 is also due
to normal additions to utility plant. In addition to the NOx scrubbers placed
into service in 2004, other significant expenditures included upgrades of
electric facilities subjected to storm damage, construction of a new substation,
and a new transmission main. Upgrades implemented in 2002 and 2003 now included
in annual depreciation expense include a gas-fired peaker unit, expenditures for
implementing a choice program for Ohio gas customers, customer system upgrades,
and other upgrades to existing transmission and distribution facilities.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1.6 million in 2004 compared to 2003
and $5.9 million in 2003 compared to 2002. Almost all of the 2004 increase and
$4.5 million of the 2003 increase corresponds with increased collections of
utility receipts and excise taxes due to higher revenues. The remaining 2003
increase results principally from higher property taxes.
Other Income (Expense)
Total other income (expense)-net increased $1.1 million during 2004 compared to
2003 and decreased $1.0 million during 2003 compared to 2002. Lower amounts of
AFUDC were recorded in 2004 as NOx expenditures were placed in service. Fiscal
year 2003 includes operating losses and the write-off of investments in an
entity that processes fly ash, totaling $4.2 million. In 2002, the Company
recognized losses associated with those investments totaling $1.5 million.
Interest Expense
In the second half of 2003, the Company completed permanent financing
transactions in which approximately $366 million in equity, debt, and hedging
net proceeds were received and used to retire higher coupon long-term debt and
other short term borrowings. The changes in interest expense in 2004 and 2003
reflect the full impact of that transaction.
Income Taxes
For the year ended December 31, 2004, income taxes were relatively consistent
with 2003 with decreased earnings offset by a slightly higher effective rate. An
increase in the Indiana state income tax rate from 4.5% to 8.5% was the primary
reason for increased tax expense in 2003 compared to 2002.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxide (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible with which to comply.
Clean Air Act
NOx SIP Call Matter
The Company has taken steps to comply with Indiana's State Implementation Plan
(SIP) of the Clean Air Act (the Act). These steps include installing Selective
Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley),
Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and
2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water
using ammonia in a chemical reaction. This technology is known to currently be
the most effective method of reducing nitrogen oxide (NOx) emissions where high
removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an 8% return on
its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances, related to the clean coal technology once the facility
is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost is consistent with amounts approved in the IURC's orders.
Through December 31, 2004, $238 million has been expended, and three of the four
SCR's are operational. Once all equipment is installed and operational, related
annual operating expenses, including depreciation expense, are estimated to be
between $24 million and $27 million. The Company is recovering the operational
costs associated with the SCR's and related technology. The 8% return on capital
investment approximates the return authorized in the Company's last electric
rate case in 1995 and includes a return on equity.
The Company has achieved timely compliance through the reduction of the
Company's overall NOx emissions to levels compliant with Indiana's NOx emissions
budget allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana
entered a consent decree among SIGECO, the Department of Justice (DOJ), and the
USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO.
The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley
Generating Station for (1) making modifications to generating station without
obtaining required permits, (2) making major modifications to the generating
station without installing the best available emission control technology, and
(3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all
challenges of past maintenance and repair activities at the Culley Generating
Station. In reaching the agreement, SIGECO did not admit to any allegations in
the government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO committed to
o either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit 3
by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company notified the USEPA of its intention to shut down Culley Unit 1
effective December 31, 2006. The Company does not believe that implementation of
the settlement will have a material effect to it results from operations or
financial condition. The $600,000 civil penalty was expensed and paid during
2003 and is reflected in Other-net.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Clean Air Act for historical operational information on the
Warrick and A.B. Brown generating stations. SIGECO has provided all information
requested with the most recent correspondence provided on March 26, 2001.
Manufactured Gas Plants
In the past, Indiana Gas, SIGECO, and others operated facilities for the
manufacture of gas. Given the availability of natural gas transported by
pipelines, these facilities have not been operated for many years. Under
currently applicable environmental laws and regulations, Indiana Gas, SIGECO,
and others may now be required to take remedial action if certain byproducts are
found above the regulatory thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and any
necessary remediation costs that SIGECO may accrue under the VRP program. The
total investigative costs, and if necessary, costs of remediation at the four
SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot
be determined at this time.
Jacobsville Superfund Site
On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil
Contamination site in Evansville, Indiana, on the National Priorities List under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA). The USEPA has identified four sources of historic lead contamination.
These four sources shut down manufacturing operations years ago. When drawing up
the boundaries for the listing, the USEPA included a 250 acre block of
properties surrounding the Jacobsville neighborhood, including Vectren's Wagner
Operations Center. Vectren's property has not been named as a source of the lead
contamination, nor does the USEPA's soil testing to date indicate that the
Vectren property contains lead contaminated soils. Vectren's own soil testing,
completed during the construction of the Operations Center, did not indicate
that the Vectren property contains lead contaminated soils. At this time,
Vectren anticipates only additional soil testing, if required by the USEPA.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of
service, accounting matters, issuance of securities, and certain other
operational matters specific to its Indiana customers are regulated by the IURC.
The retail gas operations of the Ohio operations are subject to regulation by
the PUCO.
All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR clauses allow the Company to charge for changes in the cost of purchased
gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows
for adjustment in charges for electric energy to reflect changes in the cost of
fuel. The net energy cost of purchased power, subject to an agreed upon
benchmark, is also recovered through regulatory proceedings. Rate structures in
the Company's territories do not include weather normalization-type clauses that
authorize the utility to recover gross margin on sales established in its last
general rate case, regardless of actual weather patterns.
GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings
to establish the amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any under-or-over-recovery
resulting from gas and fuel adjustment clauses each month in margin. A
corresponding asset or liability is recorded until the under-or-over-recovery is
billed or refunded to utility customers.
The IURC has also applied the statute authorizing GCA and FAC procedures to
reduce rates when necessary to limit net operating income to a level authorized
in its last general rate order through the application of an earnings test. For
the recent past, the earnings test has not affected the Company's ability to
recover costs, and the Company does not anticipate the earnings test will
restrict recovery in the near future.
SIGECO and Indiana Gas Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for
SIGECO's gas distribution business, and on November 30, 2004, approved a $24
million base rate increase for Indiana Gas' gas distribution business. The new
rate designs include a larger service charge, which is intended to address to
some extent earnings volatility related to weather. The base rate change in
SIGECO's service territory was implemented on July 1, 2004, resulting in
additional 2004 revenues of $2.5 million. The base rate change in Indiana Gas'
service territory was implemented on December 1, 2004, resulting in additional
2004 revenues of $2.2 million.
The orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety
Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these
annual caps are to be deferred for future recovery.
VEDO Pending Base Rate Increase Settlement
On February 4, 2005, the Company filed with the PUCO a settlement agreement that
had been entered into with several parties, including the PUCO staff, in its
base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the
settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its
base rates and charges for its gas distribution business serving more than
315,000 customers located in west central Ohio. The settlement provides for a
$15.7 million increase in VEDO's base distribution rates to cover the ongoing
costs of operating, maintaining, and expanding the approximately 5,200-mile
distribution system. The settlement increase includes $1.1 million of funding
for weatherization and conservation programs for low income customers.
Evidentiary hearings were completed in the case on February 9, 2005. Review and
approval by the PUCO is necessary before the settlement is effective. The
proposed new rate design includes a larger service charge, which will address,
to some extent, earnings volatility related to weather. The settlement also
permits VEDO the annual recovery of on-going costs associated with the Pipeline
Safety Improvement Act of 2002. Based upon the PUCO's actions in other
proceedings, the Company would expect an order near the end of the first quarter
of 2005.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
account expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and reversed and deferred that amount for future recovery. In 2004, the
Company recorded revenues of $3.3 million which is equal to the level of
uncollectible accounts expense recognized for Ohio customers.
Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, a two-year audit period ended in November 2002.
That audit period provided the PUCO staff its initial review of the portfolio
administration arrangement between VEDO and ProLiance. The external auditor
retained by the PUCO staff submitted an audit report in the fall of 2003 wherein
it recommended a disallowance of approximately $7 million of previously
recovered gas costs. The Company believes a large portion of the third party
auditor recommendations is without merit. A hearing has been held, and the PUCO
staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor
has recommended an $11.5 million disallowance. For this PUCO audit period, any
disallowance relating to the Company's ProLiance arrangement will be shared by
the Company's joint venture partner. Based on a review of the matters, the
Company has recorded $1.1 million for its estimated share of a potential
disallowance. A PUCO decision on this matter is yet to be issued. The Company is
also unable to determine the effects that a PUCO decision for the audit period
ended in November 2002 may have on results in audit periods beginning after
November 2002.
Other Operating Matters
MISO
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. In December 2001, the IURC approved the Company's request for
authority to transfer operational control over its electric transmission
facilities to the MISO. That transfer occurred on February 1, 2002. Pursuant to
an order from the IURC, certain MISO costs have been deferred for future
recovery.
During 2004, SIGECO together with three other Indiana electric utilities filed a
proceeding with the IURC seeking to recover the anticipated costs associated
with MISO's implementation of the "Day 2 energy market" on April 1, 2005. A
hearing considering this request occurred in February, 2005.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the nature of
MISO's policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around the "Day 2 energy market" operations,
it is difficult to predict near term operational impacts. However, as stated
above, it is believed that MISO's regional operation of the transmission system
will ultimately lead to reliability improvements.
The potential need to expend capital for improvements to the transmission
system, both to SIGECO's facilities as well as to those facilities of adjacent
utilities, over the next several years will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
United States Securities and Exchange Commission Inquiry into PUCHA Exemption
In July 2004, the Company received a letter from the SEC regarding its exempt
status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter
asserts that the Company's out of state electric power sales exceed the amount
previously determined by the SEC to be acceptable in order to qualify for the
exemption. There is pending a request by Vectren and VUHI for an order of
exemption under Section 3(a)(1) of PUHCA. Vectren and VUHI also claim the
benefit of the exemption pursuant to Rule 2 under Section 3(a)(1) of PUHCA by
filing an annual statement on SEC Form U-3A-2. The Company has responded to the
SEC inquiry and filed an amended Form U-3A-2 for the year ended December 31,
2003. The amendment changed the method of aggregating wholesale power sales and
purchases outside of Indiana from that previously reported. The new method is to
aggregate by delivery point. The amendment also submitted clarifications as to
activity outside of Indiana related to gas utility operations.
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 13 to the consolidated financial statements. An impairment test
performed in accordance with SFAS 142 requires that a reporting unit's fair
value be estimated. The Company used a discounted cash flow model to estimate
the fair value of its Gas Utility Services operating segment, and that estimated
fair value was compared to its carrying amount, including goodwill. The
estimated fair value was in excess of the carrying amount in 2004, 2003, and
2002 and therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and
requires significant judgment in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also would have resulted in no impairment charge.
Impairment Review of Investments
The Company will occasionally make equity investments in companies 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 judgment concerning
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
investments in an entity that processes fly ash resulted in 2003. No impairments
were recorded in 2004.
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 share-based
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 SFAS
87/106 liability is allocated to individual subsidiaries since these assets and
obligations are derived from corporate level decisions. 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 2004 periodic benefit cost: a
discount rate of 6.0%, an expected return on plan assets of 8.5%, a rate of
compensation increase of 3.5%, and a health care cost trend rate of 10% in 2004
declining to 5% in 2009. During 2004, Vectren reduced the discount rate by 25
basis points to value 2004 ending pension and postretirement obligations due to
a decline in benchmark interest rates. In addition, Vectren used the following
weighted average assumptions to develop 2004 periodic benefit cost: a discount
rate of 6.0%, an expected return on plan assets of 8.5%, a rate of compensation
increase of 3.5%, and a health care cost trend rate of 10% in 2004 declining to
5% in 2009. In January 2005, Vectren announced the amendment of certain
postretirement benefit plans, effective January 1, 2006. The amendment will
result in a decrease of allocated costs that may approximate $3 million
annually, a portion of which will be recognized in 2005. Two of the unions that
represent bargaining employees at the Company's regulated subsidiaries have
advised Vectren that it is their position that these changes are not permitted
under the existing collective bargaining agreements which govern the
relationship between the employees and the affected subsidiaries. With
assistance from legal counsel, management has analyzed the unions' position and
continues to believe that the Company has reserved the right to amend the
affected plans and that changing these benefits for retirees is not a mandatory
subject of bargaining. Future changes in health care costs, work force
demographics, interest rates, or plan changes could significantly affect the
estimated cost of these future benefits.
Impact of Recently Issued Accounting Guidance
SFAS 123 (revised 2004)
In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based
Payments" (SFAS 123R) that will require compensation costs related to
share-based payment transactions to be recognized in the financial statements.
With limited exceptions, the amount of compensation cost will be measured based
on the grant-date fair value of the equity or liability instruments issued. In
addition, liability awards will be remeasured each reporting period.
Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123,
"Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25,
"Accounting for Stock Issued to Employees." The effective date of SFAS 123R for
the Company is July 1, 2005. SFAS 123R provides for multiple transition methods,
and the Company is still evaluating potential methods for adoption. VUHI does
not have share-based compensation plans separate from Vectren. An insignificant
number of VUHI's employees participate in Vectren's share-based compensation
plans. The adoption of this standard is not expected to have any material effect
on the Company's operating results or financial condition.
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, 2004,
totaled $550.0 million and $308.0 million, respectively. Additionally, prior to
VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and
therefore, have long-term debt outstanding funded solely by their operations.
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, 2004, are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's Investors Service (Moody's), respectively.
SIGECO's credit ratings on outstanding senior unsecured debt are BBB+/Baa1.
SIGECO's credit ratings on outstanding secured debt are A-/A3. VUHI's commercial
paper has a credit rating of A-2/P-2. The ratings of Moody's and Standard and
Poor's are categorized as investment grade and are unchanged from December 31,
2003. Moody's current outlook is stable. During January 2005, Standard and
Poor's changed its current outlook to stable from negative. A security rating is
not a recommendation to buy, sell, or hold securities. The rating is subject to
revision or withdrawal at any time, and each rating should be evaluated
independently of any other rating. Standard and Poor's and Moody's lowest level
investment grade rating is BBB- and Baa3, respectively.
The Company's consolidated equity capitalization objective is 50-55% of
permanent capitalization. This objective may have varied, and will vary,
depending on particular business opportunities, capital spending requirements,
and seasonal factors that affect the Company's operations. The Company's equity
component was 51% and 50% of permanent capitalization at December 31, 2004, and
2003, respectively. Permanent capitalization includes long-term debt, including
current maturities and debt subject to tender, as well as common shareholders'
equity and any outstanding preferred stock.
The Company expects the majority of its capital expenditures, investments, and
debt security redemptions to be provided by internally generated funds. However,
due to significant capital expenditures, the Company may require additional
permanent financing.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities increased $85.1 million during the year ended December 31, 2004,
compared to 2003 primarily as a result of favorable changes in working capital
accounts and increased earnings before non-cash charges. Cash flow from
operating activities decreased during the year ended December 31, 2003, compared
to 2002 by $108.4 million. The primary reason for this change was favorable
changes in working capital accounts occurring in 2002 due to lower gas prices in
that year and higher gas prices in 2003.
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 required for financing activities of $7.4 million for the year ended
December 31, 2004, includes a net increase of short-term borrowings of $123.1
million and the net retirement of $38.1 million of long-term debt. 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 paid to Vectren have increased in 2004 compared to 2003
and in 2003 compared to 2002.
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.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. Other than those described below
related to ratings triggers, the put or call provisions are not triggered by
specific events, but are based upon dates stated in the note agreements, such as
when notes are re-marketed. During 2004, 2003, and 2002, debt totaling $2.5
million, $0.1 million, and $5.2 million, respectively, was put to the Company.
Debt that may be put to the Company within one year is classified as Long-term
debt subject to tender in current liabilities.
SIGECO and Indiana Gas Debt Call
During 2004, the Company called $20.0 million of insured quarterly senior
unsecured notes outstanding at Indiana Gas. The notes, originally due in 2015,
were called at par.
During 2003, the Company called two first mortgage bonds outstanding at SIGECO
and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
had a principal amount of $45.0 million, an interest rate of 7.60%, was
originally due in 2023, and was redeemed at 103.745% of its stated principal
amount. The second SIGECO bond had a principal amount of $20.0 million, an
interest rate of 7.625%, was originally due in 2025, and was redeemed at
103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an
interest rate of 9.375%, was originally due in 2021, and was redeemed at
105.525% of the stated principal amount. The second Indiana Gas note had a
principal amount of $13.5 million, an interest rate of 6.75%, was originally due
in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire these notes
totaling $3.6 million were deferred as a regulatory asset.
Other Financing Transactions
During 2004, the Company remarketed two first mortgage bonds outstanding at
SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate
debt into variable rate debt where interest rates reset weekly. One bond, due in
2023, had a principal amount of $22.8 million and an interest rate of 6%. The
other bond, due in 2015, had a principal amount of $10.0 million and an interest
rate of 4.3%. These remarketing efforts resulted in the extinguishment and
reissuance of debt at generally the same par value.
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate.
Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.
Other Company debt totaling $15.0 million in 2004, $18.5 million in 2003, and
$6.5 million in 2002 was retired as scheduled.
Investing Cash Flow
Cash flow required for investing activities was $264.1 million in 2004, $236.1
million in 2003, and $218.7 million in 2002. Capital expenditures are the
primary component of investing activities. Capital expenditures were $267.6
million in 2004 compared to $235.0 million in 2003 and $217.3 million in 2002.
The increases are primarily driven by expenditures for environmental compliance.
Available Sources of Liquidity
At December, 31, 2004, the Company has $355 million of short-term borrowing
capacity, of which approximately $47 million is available.
VUHI's short-term credit facility was renewed on June 24, 2004 at $350 million,
a slight increase from the previous year's renewal level of $346 million.
Instead of the traditional 364-day facility, the facility was renewed for a
5-year period ending June 2009.
Vectren periodically issues new shares to satisfy dividend reinvestment plan and
stock option plan requirements and contributes those proceeds to VUHI. During
2004 and 2003, these new issuances added additional liquidity of $3.1 million
and $5.9 million, respectively.
Potential & Future Uses of Liquidity
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2004:
- ---------------------------------------------------------------------------------------------------------
(In millions) 2005 2006 2007 2008 2009 Thereafter
- ---------------------------------------------------------------------------------------------------------
Long-term debt (1) $ - $ - $ 6.5 $ - $ - $ 949.1
Short-term debt 308.3 - - - -
Commodity firm purchase commitments 99.1 - - - - -
Utility & nonutility plant purchase
commitments (2) 20.5 - - - -
- ---------------------------------------------------------------------------------------------------------
Total $427.9 $ - $ 6.5 $ - $ - $ 949.1
=========================================================================================================
(1) Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow holders
to put debt back to the Company at face value or the Company to call debt
at face value or at a premium. Long-term debt subject to tender during the
years following 2004 (in millions) is $10.0 in 2005, zero in 2006, $20.0 in
2007, zero in 2008, $80.0 in 2009, and $40.0 thereafter.
(2) The settlement period of these obligations is estimated.
Planned Capital Expenditures
The timing and amount of capital expenditures, including contractual purchase
commitments discussed above, for the five-year period 2005 - 2009 are estimated
as follows (in millions): $205.2 in 2005, $219.4 in 2006, $259.2 in 2007, $251.9
in 2008, and $206.4 in 2009.
Pension and Postretirement Funding Obligations
Vectren believes making contributions to its qualified pension plans in the
coming years will be necessary. Management currently estimates that the
qualified pension plans will require Company contributions in the range of $5
million to $10 million in both 2005 and 2006. VUHI may be called upon to fund a
portion of these contributions. During 2004, Vectren funded $7.7 million in
contributions of which $4.6 million in contributions were funded by VUHI.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, commodity prices, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in credit ratings, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee or contractor workforce factors including changes in key
executives, collective bargaining agreements with union employees, or work
stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but not
limited to, those described in Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o Changes in Federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business risks associated with commodity
prices, interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company's risk management program includes, among other
things, the use of derivatives. The Company also executes derivative contracts
in the normal course of operations while buying and selling commodities to be
used in operations and optimizing its generation assets.
The Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The committee is
actively involved in identifying risks as well as reviewing and authorizing risk
mitigation strategies.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations, which subject to compliance with those
regulations, allow for recovery of the cost of such purchases through natural
gas and fuel cost adjustment mechanisms.
Electric sales and purchases in the wholesale power market and sales of
electricity to certain municipalities and large industrial customers are exposed
to commodity price risk associated with fluctuating commodity prices. Open
positions in terms of price, volume, and specified delivery points may occur and
are managed using methods described below with frequent management reporting.
The Company's wholesale power marketing activities include asset optimization
strategies that manage the utilization of available electric generating
capacity. Execution of asset optimization strategies require entering into
energy contracts that commit the Company to purchase and sell electricity in the
future. Commodity price risk results from forward positions that commit the
Company to deliver electricity. The Company mitigates price risk exposure with
planned unutilized generation capability and offsetting forward purchase
contracts. The Company accounts for asset optimization contracts that are
derivatives at fair value with the offset marked to market through earnings.
Sales to certain municipalities and large industrial customers are executed to
meet customer demand. Price risk from forward positions obligating the Company
to deliver commodities is mitigated using generating capability and offsetting
forward purchase contracts. These contracts are expected to be settled by
physical receipt or delivery of the commodity.
Market risk resulting from commodity contracts is measured by management using
the potential impact on pre-tax earnings caused by the effect a 10% adverse
change in forward commodity prices might have on market sensitive derivative
positions outstanding on specific dates. For the years ended December 31, 2004,
and 2003, a 10% adverse change in forward commodity prices would have decreased
earnings by $0.7 million and $3.0 million, respectively, based upon open
positions existing on the last day of those years.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The Company
manages this risk by allowing 20% and 30% of its total debt to be exposed to
short-term interest rate volatility. However, there are times when this targeted
range of interest rate exposure may not be attained. To manage this exposure,
the Company may use derivative financial instruments. At December 31, 2004, such
debt obligations, as affected by seasonal increases in short-term debt
outstanding, represented 27% of the Company's total debt portfolio.
Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2004 and 2003, the weighted average combined
borrowings under these arrangements were $142.7 million and $226.9 million,
respectively. At December 31, 2004, and 2003, combined borrowings under these
arrangements were $340.7 million and $185.2 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2004 and 2003, an increase of 100 basis points (one percentage point) in the
rates would have increased interest expense by $1.4 million and $2.3 million,
respectively.
Other Risks
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages exposure to counter-party credit risk by entering into
contracts with companies that can be reasonably expected to fully perform under
the terms of the contract. Counter-party credit risk is monitored regularly and
positions are adjusted appropriately to manage risk. Further, tools such as
netting arrangements and requests for collateral are also used to manage credit
risk. Market risk is the adverse effect on the value of a financial instrument
that results from a change in commodity prices or interest rates. The Company
attempts to manage exposure to market risk associated with commodity contracts
and interest rates by establishing parameters and monitoring those parameters
that limit the types and degree of market risk that may be undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits or refunds
cash deposits based on that review.
Although the Company's regulated operations are exposed to limited commodity
price risk, volatile natural gas prices can result in higher working capital
requirements; increased expenses including unrecoverable interest costs,
uncollectible accounts expense, and unaccounted for gas; and some level of price
sensitive reduction in volumes sold. The Company mitigates these risks by
executing derivative contracts that manage the price of forecasted natural gas
purchases. These contracts are subject to regulation, which allows for
reasonable and prudent hedging costs to be recovered through rates. When
regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and Board of Directors of Vectren Utility Holdings, Inc.:
We have audited the accompanying consolidated balance sheets of Vectren Utility
Holdings, Inc. and subsidiaries (the "Company") as of December 31, 2004 and
2003, and the related consolidated statements of income, shareholder's equity,
and cash flows for each of the three years in the period ended December 31,
2004. Our audits also included the financial statement schedule listed in the
Index at Item 15. These financial statements and financial statement schedule
are the responsibility of the Company's management. Our responsibility is to
express an opinion on the financial statements and financial statement schedule
based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Vectren Utility Holdings, Inc. and
subsidiaries as of December 31, 2004 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.
/s/ DELOITTE & TOUCHE LLP
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DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 23, 2005
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
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2004 2003
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ASSETS
Current Assets
Cash & cash equivalents $ 5.7 $ 8.1
Accounts receivable - less reserves of $1.9 &
$3.1, respectively 147.5 114.0
Receivables due from other Vectren companies 4.0 1.7
Accrued unbilled revenues 161.2 128.7
Inventories 53.0 55.1
Recoverable fuel & natural gas costs 17.7 20.3
Prepayments & other current assets 138.2 131.3
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Total current assets 527.3 459.2
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Utility Plant
Original cost 3,465.2 3,250.7
Less: accumulated depreciation & amortization 1,309.0 1,247.0
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Net utility plant 2,156.2 2,003.7
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Investments in unconsolidated affiliates 0.2 1.8
Other investments 19.6 20.6
Non-utility property - net 149.6 141.3
Goodwill - net 205.0 205.0
Regulatory assets 82.5 89.6
Other assets 7.3 3.9
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TOTAL ASSETS $ 3,147.7 $ 2,925.1
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The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31,
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2004 2003
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LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable $ 97.3 $ 63.0
Accounts payable to affiliated companies 98.8 80.3
Payables to other Vectren companies 15.8 13.3
Accrued liabilities 116.3 93.9
Short-term borrowings 308.3 185.2
Current maturities of long-term debt - 15.0
Long-term debt subject to tender 10.0 13.5
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Total current liabilities 646.5 464.2
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Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender 941.3 960.5
Deferred Income Taxes & Other Liabilities
Deferred income taxes 240.8 201.5
Regulatory liabilities 251.7 235.0
Deferred credits & other liabilities 81.9 83.9
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Total deferred credits & other liabilities 574.4 520.4
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Commitments & Contingencies (Notes 8 - 10)
Cumulative, Redeemable Preferred Stock of a
Subsidiary 0.1 0.2
Common Shareholder's Equity
Common stock (no par value) 592.9 589.8
Retained earnings 392.5 390.0
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Total common shareholder's equity 985.4 979.8
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TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 3,147.7 $ 2,925.1
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The accompanying notes are an integral part of these consolidated financial
statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
Year Ended December 31,
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2004 2003 2002
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OPERATING REVENUES
Gas utility $ 1,126.2 $ 1,112.3 $ 908.0
Electric utility 371.3 335.7 328.6
Other 0.5 0.8 0.3
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Total operating revenues 1,498.0 1,448.8 1,236.9
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OPERATING EXPENSES
Cost of gas sold 778.5 762.5 570.8
Fuel for electric