VUHI 10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

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.

(Exact name of registrant as specified in its charter)

INDIANA		35-2104850
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)
One Vectren Square, Evansville, Indiana		47708
(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
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

Common- Without Par

None

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. *Yes ý No□

*Utility Holdings is a majority owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer status depends in part on the type of security being registered by the majority-owned subsidiary.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes □ No ý

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 ý. 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. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer □ Accelerated filer □ Non-accelerated filer ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes □ No ý

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, 2005, 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	February 28, 2006
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.

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: One Vectren Square Evansville, Indiana 47708		Phone Number: (812) 491-4000		Investor Relations Contact: Steven M. Schein Vice President, Investor Relations sschein@vectren.com

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Table of Contents

Item				Page
Number				Number
Part I
	1		Business		4
	1A		Risk Factors		8
	1B		Unresolved Staff Comments		11
	2		Properties		11
	3		Legal Proceedings		12
	4		Submission of Matters to Vote of Security Holders		12
Part II
	5		Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		13
	6		Selected Financial Data		14
	7		Management's Discussion and Analysis of Results of Operations and Financial Condition		15
	7A		Qualitative and Quantitative Disclosures About Market Risk		33
	8		Financial Statements and Supplementary Data		35
	9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		71
	9A		Controls and Procedures		71
	9B		Other Information		71
Part III
	10		Directors and Executive Officers of the Registrant^(A)		71
	11		Executive Compensation^(A)		71
	12		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters^(A).		71
	13		Certain Relationships and Related Transactions^(A)		71
	14		Principal Accountant Fees and Services		72
Part IV
	15	Exhibits and Financial Statement Schedules			73
		Signatures			78

^(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.

Definitions

AFUDC: allowance for funds used during construction	MMBTU: millions of British thermal units
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 Board	NOx: nitrogen oxide
FERC: Federal Energy Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
IDEM: Indiana Department of Environmental Management	PUCO: Public Utilities Commission of Ohio
IURC: Indiana Utility Regulatory Commission	SFAS: Statement of Financial Accounting Standards
MCF / BCF: thousands / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes

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PART I

ITEM 1. BUSINESS

Description of the Business

Vectren Utility Holdings, Inc. (Utility Holdings 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. Utility Holdings also has assets that provide information technology and other services to the utilities.

The Ohio operations provide energy delivery services to approximately 318,000 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, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company organized on June 10, 1999, to effect the merger of Indiana Energy and SIGCORP. On March 31, 2000, Indiana Energy merged with SIGCORP and into Vectren. The transaction involved a tax-free exchange of shares that was accounted for as a pooling-of-interests.

Both Vectren and Utility Holdings are exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.

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 over one million customers. Other Operations primarily provide information technology and other support services to those utility operations.

At December 31, 2005, the Company had $3.4 billion in total assets, with $2.0 billion (60%) attributed to the Gas Utility Services, $1.2 billion (35%) attributed to the Electric Utility Services, and $0.2 billion (5%) attributed to Other Operations. Net income for the year ended December 31, 2005, was $95.1 million with $85.3 million attributed to regulated operations and $9.8 million attributed to other operations. Net income for the year ended 2004 was $83.1 million.

For further information, refer to Note 12 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 not significant.

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Gas Utility Services

At December 31, 2005, the Company supplied natural gas service to approximately 992,000 Indiana and Ohio customers, including 906,000 residential, 84,000 commercial, and 2,000 industrial and other contract customers. This represents customer base growth of 1.3% compared to 2004.

The Company’s service area contains diversified manufacturing and agriculture-related enterprises. The principal industries served include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, and coal mining. The largest Indiana communities served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington, Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and Richmond. The largest community served outside of Indiana is Dayton, Ohio.

Revenues

For the year ended December 31, 2005, gas utility revenues were approximately $1,359.7 million, of which residential customers accounted for 66%, commercial 28%, and industrial and other contract customers 6%, 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 200.1 MMDth for the year ended December 31, 2005. Gas transported or sold to residential and commercial customers was 112.9 MMDth representing 56% of throughput. Gas transported or sold to industrial and other contract customers was 87.2 MMDth representing 44% 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 its affiliate, ProLiance Energy, LLC (ProLiance), and with other third party gas service providers 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 2005, the Company purchased 106,449 MDth volumes of gas at an average cost of $9.05 per Dth, of which approximately 95% was purchased from ProLiance and 5% was purchased from other third party providers. As required by a June 2005, PUCO order, VEDO solicited bids for its gas supply/portfolio administration services and selected a third party provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. Prior to October 31, 2005, ProLiance supplied natural gas to all of the Company’s regulated gas utilities.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company’s Indiana utilities through March 2011. The settlement is subject to approval by the IURC. The average cost of gas per Dth purchased for the last five years was: $9.05 in 2005; $6.92 in 2004; $6.36 in 2003; $4.57 in 2002; and $5.83 in 2001.

Electric Utility Services

At December 31, 2005, the Company supplied electric service to approximately 140,000 Indiana customers, including 121,000 residential, and 19,000 commercial, and 150 industrial and other customers. This represents customer base growth of 0.6% compared to 2004. In addition, the Company has firm power commitments to four municipalities and has contingency reserve requirements consistent with Reliability First Corp. standards.

The principal industries served include polycarbonate resin (Lexan®) and plastic products, aluminum smelting and recycling, aluminum sheet products, automotive assembly, steel finishing, appliance manufacturing, pharmaceutical and nutritional products, automotive glass, gasoline and oil products, and coal mining.

Revenues

For the year ended December 31, 2005, retail and firm wholesale electricity sales totaled 6,199.0 GWh, resulting in revenues of approximately $383.4 million. Residential customers accounted for 35% of 2005 revenues; commercial 25%; industrial 31%; and municipal and other 9%. In addition, the Company sold 3,049.2 GWh through wholesale contracts in 2005, generating revenue, net of purchased power costs, of $38.0 million.

Generating Capacity

Installed generating capacity as of December 31, 2005, 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.

In addition to its generating capacity, in 2005, the Company had 34 MW available under firm contracts and 61 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 2005.

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, and the City of Jasper, Indiana, providing the historic ability to simultaneously interchange approximately 500 MW. Utility Holdings also had an interconnection agreement with Wabash Valley Power Association, which was cancelled effective August 31, 2005. 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 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 2001 through 2005 at the time of the system summer peak, and the related reserve margin, is presented below in MW.


Date of summer peak load	7/25/2005	7/13/2004	8/27/2003	8/5/2002	7/31/2001
Total load at peak ⁽¹⁾	1,315	1,222	1,272	1,258	1,234

Generating capability	1,351	1,351	1,351	1,351	1,271
Firm purchase supply	107	105	32	82	82
Interruptible contracts	76	51	95	95	95
Total power supply capacity	1,534	1,507	1,478	1,528	1,448

Reserve margin at peak	17%	23%	16%	21%	17%

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⁽¹⁾

The total load at peak is increased 25 MW in 2005, 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 in those years. On the date of peak in 2004, summer cycler programs were not activated.

The winter peak load for the 2004-2005 season of approximately 932 MW occurred on January 18, 2005. The prior year winter peak load was approximately 928 MW, occurring on January 20, 2004.

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 34 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 2005 was fueled by coal (98.3%) and natural gas (1.7%). Oil was used only for testing of gas/oil-fired peaking units.

There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby Indiana coal mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary of the Company. Approximately 3.6 million tons of coal were purchased for generating electricity during 2005, 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 2001 through 2005 follows:


	Year Ended December 31,
Avg. Cost Per	2005	2004	2003	2002	2001
Ton	$ 30.27	$ 27.06	$ 24.91	$ 23.50	$ 22.48
MWh	14.94	13.06	11.93	11.00	10.53

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 2005 totaled 2,253,502 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, 2005, approximately 71,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than the regulated utility. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting large volume customers to choose their commodity supplier.

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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, 2005, the Company and its consolidated subsidiaries had 1,612 employees, of which 858 are subject to collective bargaining arrangements.

In November 2005, the Company reached a four year agreement with Local 175 of the Utility Workers Union of America, ending October 2009. The agreement includes annual wage increases of 3.5% and market adjustments to healthcare and pensions. The agreement also provides increased flexibility in job assignments and work rules.

In September 2005, the Company reached a four year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2009. The agreement provides for annual wage increases of 3.4%, modifications to the pension and insurance plans, and increased flexibility in operations.

In July 2004, the Company reached 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 reached 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.

ITEM 1A. RISK FACTORS

Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and the Company cannot predict those risks or estimate the extent to which they may affect the Company’s businesses or financial performance.

Utility Holdings is a holding company, and its assets consist primarily of investments in its subsidiaries.

Dividends on the Company’s common stock depend on the earnings, financial condition, and capital requirements of its subsidiaries, Indiana Gas, SIGECO and VEDO, and the distribution or other payment of earnings from those subsidiaries to the Company. Should the earnings, financial condition, or capital requirements of, or legal requirements applicable to, the Company’s subsidiaries restrict the ability of these subsidiaries to pay dividends or make other payments to Utility Holdings, the Company’s ability to pay dividends to its parent could be adversely affected.

The Company operates in an increasingly competitive industry, which may affect its future earnings.

The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies. Increased competition may create greater risks to the stability of the Company’s earnings generally and may in the future reduce its earnings from retail electric and gas sales. Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market. Indiana has not enacted such legislation. Ohio regulation also provides for choice of commodity providers for all gas customers. In 2003, the Company implemented this choice for its gas customers in Ohio. Indiana has not adopted any regulation requiring gas choice except for large-volume customers. The Company cannot provide any assurance that increased competition or other changes in legislation, regulation or policies will not have a material adverse effect on its business, financial condition or results of operations.

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A significant portion of the Company’s gas and electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.

The Company’s gas and electric utility sales are sensitive to variations in weather conditions. Utility Holdings forecasts utility sales on the basis of normal weather, which represents a long-term historical average. Since the Company does not have a weather-normalization mechanism for its electric operations or its Ohio natural gas operations, significant variations from normal weather could have a material impact on its earnings. However, the impact of weather on the gas operations in its Indiana territories has been significantly mitigated through the implementation on October 15, 2005, of a normal temperature adjustment mechanism.

The Company’s gas and electric utility sales are concentrated in the Midwest.

The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, and coal mining.

Risks related to the regulation of the Company’s businesses, including environmental regulation, could affect the rates charged, its costs and its profitability.

Utility Holdings’ businesses are subject to regulation by federal, state and local regulatory authorities. In particular, the Company is subject to regulation by the Federal Energy Regulatory Commission (FERC), the IURC and the PUCO. These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, safety, and the rates that it can charge customers and the rate of return that it is allowed to realize. The Company’s ability to obtain rate increases to maintain its current authorized rate of return depends upon regulatory discretion, and there can be no assurance that Vectren will be able to obtain rate increases or rate supplements or earn its current authorized rate of return.

In addition, its operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. Such emissions from electric generating facilities include particulate matter, sulfur dioxide (SO₂), and nitrogen oxide (NOx), among others.

Environmental legislation also requires that facilities, sites and other properties associated with the Company’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Utility Holding’ current costs to comply with these laws and regulations are significant to its results of operations and financial condition. In addition, claims against the Company under environmental laws and regulations could result in material costs and liabilities. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by the Company subject to environmental regulation, its investment in environmentally compliant equipment has increased and is expected to increase in the future.

From time to time, the Company is subject to material litigation and regulatory proceedings.

The Company may be subject to material litigation and regulatory proceedings from time to time. There can be no assurance that the outcome of these matters will not have a material adverse effect on its business, results of operations or financial condition.

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The Company’s electric operations are subject to various risks.

The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchased power costs. Such operational risks can arise from circumstances such as facility shutdowns due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; and natural disasters.

The Company may experience significantly increased gas costs.

Recently, commodity prices for natural gas purchases have increased and have become more volatile. Subject to regulatory approval, the Company’s subsidiaries are allowed recovery of gas costs from their retail customers through commission-approved gas cost adjustment mechanisms. As a result, profit margins on gas sales are not expected to be impacted. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for various reasons, including but limited to, a finding by the regulator that natural gas was not prudently procured, as an example. In addition, it is possible that as a result of this near term change in natural gas commodity prices, the Company’s subsidiaries may experience increased interest expense due to higher working capital requirements, increased uncollectible accounts expense and unaccounted for gas and some level of price sensitive reduction in volumes sold or delivered.

The impact of MISO participation is uncertain.

On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

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 Day 2 energy market operations, it is difficult to predict near term operational impacts. However, 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.

Wholesale power marketing activities may add volatility to earnings.

The Company’s regulated electric utility engages in wholesale power marketing activities that primarily involve asset optimization strategies. These optimization strategies manage the utilization of available electric generating capacity and include the execution of energy contracts that are integrated with portfolio requirements around power supply and delivery. As part of these strategies, the Company will execute forward contracts and option contracts that may not result in the physical flow of electricity, but hedge, other commitments. While most physical forward positions to sell electricity are hedged with these contracts or with planned unutilized generation capability, the Company does not hedge its entire portfolio from market price volatility. To the extent the Company has unhedged positions or its hedging procedures do not work as planned, fluctuating prices for electricity are likely to cause its net income to be volatile and may lower its net income. Beginning in April 2005, substantially all physically delivered off-system sales occur into the MISO day-ahead market.

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Catastrophic events could adversely affect the Company’s facilities and operations.

Catastrophic events such as fires, explosions, floods, terrorist acts or other similar occurrences could adversely affect the Company’s facilities and operations.

A downgrade in the Company’s credit rating could negatively affect its ability to access capital.

The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:

	Current Rating
		Standard
	Moody’s	& Poor’s
Utility Holdings, Indiana Gas and SIGECO senior unsecured debt	Baa1	A-
Utility Holdings commercial paper program	P-2	A-2

The current outlook of both Moody’s and Standard and Poor’s is stable and are categorized as investment grade. 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 may be required to obtain additional permanent financing (1) to fund its capital expenditures, investments and debt security redemptions and maturities and (2) to further strengthen its capital structure and the capital structures of its subsidiaries. If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or withdraw its ratings, it may significantly limit the Company’s access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase. In addition, Utility Holdings would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Finally, there is no assurance that the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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 145,000 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 12,118 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 3,079 miles of distribution and transmission mains, all of which are located in Indiana.

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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 7.8 million gallons of propane, and the plants can manufacture for delivery 52,187 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 12.0 BCF of storage with a maximum peak day delivery capability of 246,080 MMBTU per day. The Ohio operations’ gas delivery system includes 5,300 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, 2005, was rated at 1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with two units of 500 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with three units of 406 MW of combined 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: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4) 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); and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW. 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. Pursuant to the settlement between the Company, the Department of Justice, and the USEPA, the Company will shut down Culley Unit 1, with generating capacity of 50 MW, effective December 31, 2006.

SIGECO's transmission system consists of 832 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 28 substations with an installed capacity of 4,622.3 megavolt amperes (Mva). The electric distribution system includes 3,226 pole miles of lower voltage overhead lines and 305 trench miles of conduit containing 1,710 miles of underground distribution cable. The distribution system also includes 95 distribution substations with an installed capacity of 1,964.9 Mva and 52,211 distribution transformers with an installed capacity of 2,418.5 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 results of operations, or cash flows. See the notes to the consolidated financial statements regarding investments in unconsolidated affiliates, commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

No matters were submitted during the fourth quarter to a vote of security holders.

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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 Utility Holdings’ common stock are owned by Vectren. Utility Holdings’ common stock is not traded. There are no outstanding options or warrants to purchase Utility Holdings’ common equity or securities convertible into Utility Holdings’ common equity. Additionally, Utility Holdings has no plans to publicly offer its common equity securities.

Dividends Paid to Parent

During 2005, Utility Holdings paid dividends to its parent company of $20.0 million in each of the first, second and third quarters, and $20.7 million in the fourth quarter.

During 2004, Utility Holdings 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.

On January 25, 2006, the board of directors declared an $18.7 million dividend, payable to Vectren on February 28, 2006.

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 ¼% 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
2005	High		Low		2004		High		Low
First Quarter	$	26.74	$	25.44		First Quarter	$	27.44	$	26.25
Second Quarter		26.30		25.40		Second Quarter		27.03		24.05
Third Quarter		26.35		25.05		Third Quarter		26.81		23.03
Fourth Quarter		25.80		25.00		Fourth Quarter		27.00		26.06

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.

	Year Ended December 31,
(In millions)		2005		2004		2003		2002		2001 ⁽¹⁾
Operating Data:
Operating revenues		$	1,781.8	$	1,498.0	$	1,448.8	$	1,236.9	$	1,328.3
Operating income			216.6		196.3		197.2		207.7		131.4
Income before cumulative effect of change
in accounting principle			95.1		83.1		85.6		97.1		43.7
Net income			95.1		83.1		85.6		97.1		44.8

Balance Sheet Data:
Total assets		$	3,391.2	$	3,147.7	$	2,925.1	$	2,780.4	$	2,489.3
Redeemable preferred stock			-		0.1		0.2		0.3		0.5
Long-term debt - net of current maturities
& debt subject to tender			997.8		941.3		960.5		841.2		900.9
Common shareholder's equity			1,023.8		985.4		979.8		768.6		738.9

⁽¹⁾

Merger and integration related costs incurred for the year ended December 31, 2001 were $2.8 million. These costs relate primarily to transaction costs, severance and other merger and acquisition and 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.

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ITEM 7. MANAGMENT 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

For the year ended December 31, 2005, earnings were $95.1 million as compared to $83.1 million in 2004. The 2005 results reflect the impact of a regulatory strategy that includes gas utility base rate increases, the recovery of pollution control investments, and a normal temperature adjustment mechanism implemented in its Indiana gas territories in October 2005, among other initiatives. Gas utility base rate increases added revenues of approximately $33.8 million, or $20.1 million after tax, in 2005 compared to 2004 and $4.7 million, or $2.8 million after tax, in 2004 compared to 2003. Increased revenues associated with recovery of pollution control investments, net of related operating and depreciation expenses, increased operating income $8.7 million, or $5.2 million after tax, in 2005 compared to 2004 and $6.0 million, or $3.6 million after tax, in 2004 compared to 2003. Results for the year ended December 31 2005, also reflect increased margins from generation asset optimization activities. In addition to higher operating costs, depreciation expense, and unfavorable weather, Utility Holdings’ results were impacted by a $4.2 million ($2.5 million after tax) charge recorded pursuant to the disallowance of Ohio gas costs in 2005. In 2003, $1.1 million ($0.7 million after tax) was recorded related to this matter.

Management estimates that the after tax impact of weather on the electric and gas utility businesses, including the effects of the recently implemented normal temperature adjustment mechanism, was unfavorable $3.2 million after tax in 2005, unfavorable $7.1 million after tax in 2004, and unfavorable $2.1 million after tax in 2003.

The $2.5 million decrease in earnings occurring in 2004 compared to 2003 was primarily due to the impact of unfavorable weather, estimated at $5.0 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.

Utility Holdings 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 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.

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. The weather impact in the Company’s Indiana gas utility service territories is mitigated somewhat by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. 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, as well as other tracked expenses 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.

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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)	2005		2004		2003

Gas utility revenues	$ 1,359.7		$ 1,126.2		$ 1,112.3
Cost of gas sold	973.3		778.5		762.5
Total gas utility margin	$ 386.4		$ 347.7		$ 349.8
Margin attributed to:
Residential & commercial customers	$	333.2	$	297.7	$	302.1
Industrial customers		48.3		45.7		43.0
Other customers		4.9		4.3		4.7

Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		112.9		114.5		122.6
Industrial customers		87.2		85.8		86.7
Total sold & transported volumes		200.1		200.3		209.3

Gas utility margins were $386.4 million for the year ended December 31, 2005, an increase of $38.7 million compared to 2004. The increase is primarily due to the favorable impact of gas base rate increases of $33.8 million and additional pass through expenses and revenue taxes recovered in margins of $5.8 million compared to last year. Results for the year ended December 31, 2005, reflect a $4.2 million charge for the impact of the disallowance of Ohio gas costs ordered by the PUCO. For the year ended December 31, 2005, weather was 5% warmer than normal but 4% colder than the prior year. Management estimates that weather, including of the effects of the normal temperature adjustment mechanism, increased margin an estimated $2.5 million compared to 2004. Though estimated to be modest to date and net of customer growth, management has seen evidence of gas customer usage declines in 2005, assumed to be driven primarily by price sensitivity. With the current outlook for continued high gas commodity prices, management expects that trend to continue and/or accelerate in 2006. The average cost per dekatherm of gas purchased was $9.05 in 2005, $6.92 in 2004; and $6.36 in 2003.

Gas utility margins were $347.7 and $349.8 million, respectively, for the years ended December 31, 2004 and 2003. 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 2003. 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.

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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)	2005		2004		2003

Electric utility revenues	$	421.4	$	371.3	$	335.7
Fuel for electric generation		126.3		96.1		86.5
Purchased electric energy		17.8		20.7		16.2
Total electric utility margin	$	277.3	$	254.5	$	233.0
Margin attributed to:
Residential & commercial customers	$	170.8	$	157.3	$	141.1
Industrial customers		66.9		63.7		53.5
Municipalities & other customers		19.8		18.6		20.1
Subtotal: Retail & firm wholesale	$	257.5	$	239.6	$	214.7
Asset optimization	$	19.8	$	14.9	$	18.3

Electric volumes sold in GWh attributed to:
Residential & commercial customers		2,933.2		2,830.9		2,715.8
Industrial customers		2,575.9		2,511.2		2,369.6
Municipal & other customers		689.9		645.9		624.7
Total retail & firm wholesale volumes sold		6,199.0		5,988.0		5,710.1

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margin was $257.5 million for the year ended December 31, 2005, an increase over the prior year of $17.9 million. The recovery of pollution control related investments and associated operating expenses and depreciation expense increased margins $14.3 million compared to 2004. Cooling weather was 9% warmer than normal and 21% warmer than last year. The estimated increase in electric margin related to weather was $4.0 million compared to the prior year ($3.8 million related to cooling weather and $0.2 million related to heating weather).

Electric retail and firm wholesale margin was $239.6 million for the year ended December 31, 2004. This represents a $24.9 million increase over 2003. Additional NOx recoveries increased margin $14.6 million in 2004. Cooling weather for the year was 12% warmer than 2003, 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.

Margin from Asset Optimization Activities

Periodically, generation capacity is in excess of that needed to serve retail 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. Beginning in April 2005, substantially all off-system sales occur into the MISO day-ahead market.

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Following is a reconciliation of asset optimization activity:


	Year Ended December 31,
(In millions)	2005			2004			2003
Beginning of Year Net Balance Sheet Position	$	(0.6	)	$	(0.4	)	$	(0.7	)
Statement of Income Activity
Mark-to-market gains (losses) recognized		0.5			(1.4	)		0.7
Realized gains		19.3			16.3			17.6
Net activity in electric utility margin		19.8			14.9			18.3
Net cash received & other adjustments		(17.9	)		(15.1	)		(18.0	)
End of Year Net Balance Sheet Position	$	1.3		$	(0.6	)	$	(0.4	)

For the year ended December 31, 2005, net asset optimization margins were $19.8 million, which represents an increase of $4.9 million, as compared to 2004. The increase in margin results primarily from the timing of available capacity and mark to market gains. Net asset optimization margins decreased $3.4 million in 2004 as compared to 2003 due to reduced available capacity.

In 2005, the Company experienced increased availability of the generating units. The availability of excess capacity was reduced in 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment. Off system sales totaled 1,208.1 GWh in 2005, compared to 670.4 GWh in 2004 and 739.0 GWh in 2003.

Operating Expenses

Other Operating

Other operating expenses increased $20.9 million for the year ended December 31, 2005, compared to 2004. Amortization of rate case expenses, expenses associated with the Ohio choice program and integrity management programs, and expenses recovered through margin increased $6.5 million. Bad debt expense in the Company’s Indiana service territories was $9.3 million in 2005, an increase of $1.8 million compared to 2004. Compensation and benefit costs increases, including performance and share-based compensation was $6.8 million higher than the prior year, reflective of the return to higher earnings in 2005 as compared to 2004. Higher maintenance, chemical costs, and all other costs account for $5.8 million of the increase.

Other operating expenses increased $8.4 million for the year ended December 31, 2004, 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 environmental compliance-related expenses of $2.8 million recovered in rates and planned turbine maintenance of $1.9 million.

Depreciation & Amortization

Depreciation expense increased $13.5 million in 2005 compared to 2004 and increased $9.9 million in 2004 compared to 2003. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equiptment additions. Depreciation expense associated with environmental compliance equiptment, which is recovered in Electric Utility margins, totaled $12.1 million in 2005, $6.2 million in 2004, and $0.7 million in 2003. Results for 2004 include $1.8 million of lower depreciation due to adjustments of Ohio depreciation rates and amortization of Indiana regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $7.0 million in 2005 compared to 2004, and $1.6 million in 2004 compared to 2003. These increases are primarily attributable to increased collections of utility receipts and excise taxes due to higher revenues.

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Other Income (Expense)

Total other income (expense)-net decreased $1.4 million in 2005 compared to 2004, and increased $1.3 million during 2004 compared to 2003. Lower amounts of AFUDC were recorded in 2005 compared to 2004 and in 2004 compared to 2003 as environmental compliance expenditures were placed in service. Fiscal year 2003 includes operating losses and the write-off of investments in an entity that processed fly ash, totaling $4.2 million.

Interest Expense

Interest expense increased $2.5 million in 2005 compared to 2004. The increase was driven by rising interest rates and higher levels of short term borrowings due in part to higher working capital requirements resulting from the increased gas commodity prices.

In November 2005, the Company completed permanent financing transactions in which approximately $150 million in debt and interest rate swap settlement proceeds were received and used to retire higher coupon long-term debt and other short term borrowings.

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

Federal and state income taxes increased $4.4 million in 2005 compared to 2004 due primarily to increased pre-tax income as compared to the prior year and adjustments to accruals resulting from the conclusion of state tax audits and other adjustments. Income taxes in 2004 were relatively consistent with 2003 with decreased earnings offset by a slightly higher effective rate.

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:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	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

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

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Through December 31, 2005, capital investments approximating the level approved by the IURC have been made. The last SCR was placed into service in May, 2005. Related annual operating expenses, including depreciation expense, were $15.4 million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating expenses could approximate $24 to $27 million once all installed equipment is operational for an entire year.

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.

Clean Air Interstate Rule & Clean Air Mercury Rule

In March of 2005 USEPA finalized two new air emission reduction regulations. The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO₂) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.

In February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s coal-fired plants will be 100% scrubbed for SO₂, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% return on its capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism will operate similar to the rider used to recover NOx-related capital investments and operating expenses. The order also stipulates that SIGECO study renewable energy alternatives and include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives.

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 a 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.

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Under the agreement, SIGECO committed to:

·	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;

·	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;

·	enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions;

·	install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007;

·	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

·	pay a $600,000 civil penalty.

The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003 and is reflected in Other-net.

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. 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. The total costs accrued to date, including investigative costs, have been immaterial.

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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.

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.

Weather Normalization

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.

The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Rate structures in the Company’s Indiana electric territory and Ohio gas territory do not include weather normalization-type clauses.

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Gas Utility 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. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate designs in all three territories 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; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.

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’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.

Indiana and Ohio Decoupling/Conservation Filings

On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana gas service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.

Similarly, on November 28, 2005, Vectren Energy Delivery of Ohio filed with the PUCO for approval of a conservation program and a conservation adjustment rider that would accomplish the same objectives. Discussions with interested parties are ongoing in both states.

MISO

Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case.

On June 1, 2005, the Company, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in the Company’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.

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 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.

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Gas Cost Recovery (GCR) Audit Proceedings

On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. That appeal is pending with briefing scheduled to be completed in February, 2006. In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company is considering whether to appeal that decision.

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 $4.0 million in excess of that included in base rates, and reversed and deferred that amount for future recovery in 2003. In 2005 and 2004, the Company recorded revenues of $5.1 million and $3.3 million, respectively, which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers.

United States Securities and Exchange Commission Inquiry into PUHCA 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 Company has responded fully to the SEC's letter and believes that it and its utility holding company subsidiary, Utility Holdings, remain entitled to exemption under Section 3(a)(1) of PUHCA. The question of the PUHCA exemptions was mooted by the Energy Policy Act of 2005 (Energy Act), which repealed the Public Utility Holding Company Act of 1935 effective February 8, 2006.

The Energy Act enacts a new Public Utility Holding Company Act of 2005 (PUHCA 2005). Vectren and Utility Holdings, are holding companies under PUHCA 2005. Under PUHCA 2005, the FERC is granted authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities to the extent relevant to the rates of FERC-jurisdictional public utilities and natural gas companies that are part of the holding company system. FERC has issued rules implementing PUHCA 2005 that allow companies to seek an exemption or waiver from all or some of FERC’s books and records requirements. Under PUHCA 2005, the Company will be required to notify FERC of its status as a holding company, and, unless an exemption or waiver is obtained, file an annual report, maintain certain books and records and make them available to the FERC. Compliance with these requirements is not expected to materially affect the Company’s financial position or operations.

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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 performs an annual impairment analysis of its goodwill, all of which resides in the Gas Utility Services operating segment, 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 12 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 2005, 2004, and 2003 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 processed fly ash resulted in 2003. No impairments were recorded in 2005 or 2004. At December 31, 2005, the book value of any remaining investments is not significant.

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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 provides 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 2005 periodic benefit cost: a discount rate of 5.75%, an expected return on plan assets of 8.25%, a rate of compensation increase of 3.5%, and an inflation assumption of 3.5%. During 2005, Vectren reduced the discount rate by 25 basis points to value the 2005 ending pension and postretirement obligations due to a decline in benchmark interest rates. In January 2005, Vectren announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment resulted in a decrease to both allocated and direct charge costs of approximately $4.0 million, of which $3.1 million was recognized by Vectren, and almost all of which was passed through to Utility Holdings through reduced allocations 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.

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Impact of Recently Issued Accounting Guidance

SFAS No. 154

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of the direct effects caused by a change in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Further, changes in depreciation, amortization or depletion methods for long-lived, nonfinancial assets are to be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted. The adoption of this standard, beginning in fiscal year 2006, is not expected to have any material effect on the Company’s operating results or financial condition.

FIN 47

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation (ARO) that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $16 million ARO for interim retirements of gas utility pipeline and utility poles and certain asbestos-related issues, the majority of which was already accrued as a cost of removal regulatory liability. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in an increase to Utility plant of approximately $12 million. Because of the effects of regulation, the difference was recorded to Regulatory assets and liabilities.

SFAS 123 (revised 2004) and related interpretations

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all 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. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like Utility Holdings. The Company intends to adopt SFAS 123R using the modified prospective method. The adoption of this standard, and subsequent interpretations of this standard, is not expected to have a material effect on the Company’s operating results or financial condition.

Utility Holdings does not have share-based compensation plans separate from Vectren. An insignificant number of Utility Holdings’ employees participate in Vectren’s share-based compensation plans.

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Financial Condition

Utility Holdings, the parent company, funds the short-term and long-term financing needs of its consolidated operations. Vectren does not guarantee Utility Holdings’ debt. Utility Holdings’ 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 Utility Holdings has no subsidiaries other than the subsidiary guarantors. Utility Holdings’ long-term and short-term obligations outstanding at December 31, 2005, totaled $700.0 million and $226.9 million, respectively. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. Utility Holdings’ operations have historically funded the significant portion of Vectren’s common stock dividends.

The credit ratings on outstanding senior unsecured debt of Utility Holdings, SIGECO and Indiana Gas, at December 31, 2005, 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 secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. Standard and Poor’s revised its current outlook to stable from negative in January 2005 and in March 2005 revised SIGECO’s secured debt rating to A from A- and its unsecured debt to A- from BBB+. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55% of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations. The Company’s equity component was 49% and 51% of long-term capitalization at December 31, 2005, and 2004, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity and any outstanding preferred stock.

In the fourth quarter of 2005, the Company issued $150 million of long-term debt, taking advantage of favorable long-term debt capital markets. Proceeds from the issuance, net of those used to retire called debt, converted approximately $100 million of short-term debt to long-term. This short-term debt had been incurred primarily to support the Company’s capital expenditure programs. In addition to permanently financing these long-lived assets, the issuance of new long-term debt improved the Company’s liquidity position allowing additional capacity on its credit lines to meet expected working capital requirements for 2006 and beyond. Resulting primarily from this issuance, the equity component of long-term capitalization decreased 2% at December 31, 2005, compared to 2004.

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 long-term 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 $32.9 million during 2005 as compared to 2004 and $63.5 million during 2004, compared to 2003. Increased cash flow from operating activities is due to both increased earnings before noncash charges and less cash utilized to support working capital increases. Earnings before noncash charges was $289.2 million in 2005, $269.2 million in 2004, and $242.3 milion in 2003. Cash utilized for working capital increases was $13.0 million in 2005, $24.4 million in 2004, and $64.0 million in 2003.

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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 when accounts receivable balances are at their highest and gas storage is refilled. Additionally, short-term borrowings are required for capital projects and investments until they are financed on a long-term basis.

Cash flow required for financing activities reflects the impact of long-term financing arrangements executed in 2005 and 2003. In 2005, Utility Holdings issued $150 million of senior unsecured securities and received an additional capital contribution from Vectren totaling $20.0 million. Utility Holdings used those proceeds to retire higher coupon long-term debt and refinance certain capital projects originally financed with short-term borrowings. Cash flow provided by financing activities in 2003 includes the effects of long-term financing 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.

Utility Holdings 2005 Debt Issuance

In November 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.779% to yield 6.11% to maturity (2035 Notes).

The notes are guaranteed by Utility Holdings’ 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 Utility Holdings, 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 2015 Notes and 25 basis points for the 2035 Notes.

In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a notional value of $75 million. Upon issuance of the debt, the interest rate swaps were settled resulting in the receipt of approximately $1.9 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 issue maturing on December 2035.

The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million and were used to repay short-term borrowings and to retire approximately $50 million of long-term debt with higher interest rates.

Utility Holdings 2003 Debt Issuance

In July 2003, Utility Holdings 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 the Utility Holdings’ 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 Utility Holdings, 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, Utility Holdings entered into several treasury locks with a total notional amount of $150 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.

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The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million and were used refinance certain capital projects originally financed with short-term borrowings and to retire long-term debt with higher interest rates.

Additional Capital Contributions

During the years ended December 31, 2005, 2004, and 2003, the Company has cumulatively received additional capital of $227.2 million from Vectren. Of that total, Vectren generated $163.2 million from issuances of its common stock, $55.0 million was funded by Vectren’s nonregulated operations, and $9.0 million was funded by new share issues from Vectren’s dividend reinvestment plan.

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. 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 remarketed. During 2005, no debt was put to the Company. In 2004, and 2003, debt totaling $2.5 million, and $0.1 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 Calls

In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2005 and 2004 had stated interest rates of 7.45% and 7.15%, respectively.

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.

Other Company debt totaling $15.0 million in 2004 and $18.5 million in 2003 was retired as scheduled.

Investing Cash Flow

Cash flow required for investing activities was $217.7 million in 2005, $242.7 million in 2004, and $236.3 million in 2003. Capital expenditures are the primary component of investing activities. Capital expenditures were $217.8 million in 2005 compared to $246.2 million in 2004, and $235.2 million in 2003. Expenditures in 2005, 2004 and 2003 include approximately $250.0 million in expenditures for environmental compliance equipment. These expenditures are the primary reason for the changes in capital expenditures over the years presented.

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Available Sources of Liquidity

At December 31, 2005, the Company has $520.0 million of short-term borrowing capacity, of which approximately $293.0 million is available.

In response to higher natural gas prices, Utility Holdings increased its available consolidated short-term borrowing capacity to $520 million, a $165 million increase over previous levels. In addition, Utility Holdings extended the maturity of its largest credit facility, which totals $515 million, through November, 2010.

Vectren periodically issues new common shares to satisfy dividend reinvestment plan and stock option plan requirements and contributes these proceeds to Utility Holdings. 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, 2005:


(In millions)	2006		2007		2008		2009		2010		Thereafter

Long-term debt ⁽¹⁾	$	-	$	6.5	$	-	$	-	$	-	$	1049.2
Short-term debt		226.9		-		-		-		-		-
Long-term debt interest commitments		64.9		64.8		64.5		64.5		64.5		668.2
Utility & nonutility plant purchase commitments ⁽²⁾		13.0		-		-		-		-		-
Total	$	304.8	$	71.3	$	64.5	$	64.5	$	64.5	$	1717.4

⁽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 2005 (in millions) is $53.7 in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010 and $30.0 thereafter.

⁽²⁾	The settlement period of these obligations is estimated.

The Company’s regulated utilities have both firm and non-firm commitments to purchase commodities as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass through costs, generally collected dollar-for-dollar from retail customers through regulator approved cost recovery mechanisms. Because of the pass through nature of these costs and their insignificant implications to earnings, they have not been included in the listing of contractual obligations.

Planned Capital Expenditures

The timing and amount of capital expenditures, including contractual purchase commitments discussed above, for the five-year period 2006 - 2010 are estimated as follows (in millions): $245.8 in 2006, $292.1 in 2007, $358.4 in 2008, $319.1 in 2009, and $244.5 in 2010.

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 of approximately $5 million in 2006 and approximately $15 million in 2007. Utility Holdings may be called upon to fund a portion of these contributions. During 2005, Vectren made contributions of $3.7 million, of which $2.5 million was funded by Utility Holdings.

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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:

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.

·	Increased competition in the energy environment including effects of industry restructuring and unbundling.

·	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.

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.

·	Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.

·	Increased natural gas commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas, and interest expense.

·	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.

The performance of projects undertaken by the Company’s nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company’s coal mining, gas marketing, and broadband strategies.

·	Direct or indirect effects on the Company’s 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.

·	Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages.

·	Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.

·	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.

·	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.

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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

Regulated Operations

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. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for various reasons, including but not limited to, a finding by the regulator that natural gas was not prudently procured, as an example. Although Vectren’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 or delivered. 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.

Recently, commodity prices for natural gas purchases have increased and have become more volatile. Despite hedging strategies, this near term change in natural gas commodity prices may have significant effects on operating results as described above.

Wholesale and Other Operations

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. In addition, the Company may purchase tailored products to mitigate unique risks involving SO₂emission allowances, as an example.

Sales to certain municipalities and large industrial customers are executed pursuant to customer demand. Price risk from forward positions obligating the Company to deliver electricity is mitigated with 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, 2005, and 2004, a 10% adverse change in forward commodity prices would have decreased earnings by $0.3 million and $0.7 million, respectively, based upon open positions existing on the last day of those years.

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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, 2005, debt subject to short-term interest rate volatility as affected by seasonal increases in short-term debt outstanding, represented 20% 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 2005 and 2004, the weighted average combined borrowings under these arrangements were $225.9 million and $142.7 million, respectively. At December 31, 2005, and 2004, combined borrowings under these arrangements were $259.3 million and $340.7 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2005 and 2004, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $2.3 million and $1.4 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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS

Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal controls over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholder's equity, and related footnotes contained herein.

These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.

These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of The Treadway Commission, the Company concluded that its internal control over financial reporting was effective as of December 31, 2005. Management certified this fact in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2005 Form 10-K.

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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, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, 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.

DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2006

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)


	At December 31,
	2005		2004
ASSETS
Current Assets
Cash & cash equivalents	$	11.7	$	5.7
Accounts receivable - less reserves of $2.6 &
$1.9, respectively		170.7		146.5
Receivables due from other Vectren companies		2.2		4.0
Accrued unbilled revenues		212.5		161.2
Inventories		126.2		58.1
Recoverable fuel & natural gas costs		15.4		17.7
Prepayments & other current assets		117.2		134.1
Total current assets		655.9		527.3

Utility Plant
Original cost		3,632.0		3,465.2
Less: accumulated depreciation & amortization		1,380.1		1,309.0
Net utility plant		2,251.9		2,156.2

Investments in unconsolidated affiliates		0.2		0.2
Other investments		21.0		19.6
Non-utility property - net		160.0		149.6
Goodwill - net		205.0		205.0
Regulatory assets		89.9		82.5
Other assets		7.3		7.3
TOTAL ASSETS	$	3,391.2	$	3,147.7

The accompanying notes are an integral part of these consolidated financial statements.

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)


	At December 31,
	2005		2004
LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
Accounts payable	$	131.9	$	97.3
Accounts payable to affiliated companies		140.6		98.8
Payables to other Vectren companies		29.2		15.8
Refundable fuel & natural gas costs		7.6		6.3
Accrued liabilities		130.4		110.0
Short-term borrowings		226.9		308.3
Long-term debt subject to tender		53.7		10.0
Total current liabilities		720.3		646.5

Long-Term Debt - Net of Current Maturities &
Debt Subject to Tender		997.8		941.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		275.5		240.8
Regulatory liabilities		272.9		251.7
Deferred credits & other liabilities		100.9		81.9
Total deferred credits & other liabilities		649.3		574.4
Commitments & Contingencies (Notes 8 - 10)

Cumulative, Redeemable Preferred Stock of a Subsidiary		-		0.1

Common Shareholder's Equity
Common stock (no par value)		612.9		592.9
Retained earnings		406.9		392.5
Accumulated other comprehensive income		4.0		-
Total common shareholder's equity		1,023.8		985.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,391.2	$	3,147.7

The accompanying notes are an integral part of these consolidated financial statements.

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2005		2004		2003
OPERATING REVENUES
Gas utility	$	1,359.7	$	1,126.2	$	1,112.3
Electric utility		421.4		371.3		335.7
Other		0.7		0.5		0.8
Total operating revenues		1,781.8		1,498.0		1,448.8

OPERATING EXPENSES
Cost of gas sold		973.3		778.5		762.5
Fuel for electric generation		126.3		96.1		86.5
Purchased electric energy		17.8		20.7		16.2
Other operating		241.3		220.4		211.9
Depreciation & amortization		141.3		127.8		117.9
Taxes other than income taxes		65.2		58.2		56.6
Total operating expenses		1,565.2		1,301.7		1,251.6

OPERATING INCOME		216.6		196.3		197.2

OTHER INCOME (EXPENSE)
Other - net		5.9		7.1		6.6
Equity in earnings (losses) of unconsolidated affiliates		-		0.2		(0.5	)
Total other income		5.9		7.3		6.1
Interest expense		69.9		67.4		66.1
INCOME BEFORE INCOME TAXES		152.6		136.2		137.2
Income taxes		57.5		53.1		51.6

NET INCOME	$	95.1	$	83.1	$	85.6

The accompanying notes are an integral part of these consolidated financial statements.

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	95.1		$	83.1		$	85.6
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		141.3			127.8			117.9
Deferred income taxes & investment tax credits		33.1			43.0			24.1
Expense portion of pension & postretirement periodic benefit cost		4.0			4.1			4.2
Provision for uncollectible accounts		14.4			10.7			12.2
Other non-cash charges - net		1.3			0.5			(1.7	)
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		(88.1	)		(78.0	)		44.3
Inventories		(68.2	)		(3.5	)		0.9
Recoverable fuel & natural gas costs		3.6			8.9			(1.0	)
Prepayments & other current assets		23.3			(2.9	)		(49.1	)
Accounts payable, including to Vectren companies
& affiliated companies		100.7			37.9			(69.1	)
Accrued liabilities		15.7			13.2			10.0
Changes in noncurrent assets		(8.4	)		(1.9	)		(5.9	)
Changes in noncurrent liabilities		(2.0	)		(10.0	)		(3.0	)
Net cash flows from operating activities		265.8			232.9			169.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs & hedging proceeds		150.0			32.4			202.9
Additional capital contribution		20.0			3.1			204.1
Requirements for:
Dividends to parent		(80.7	)		(80.6	)		(78.0	)
Retirement of long-term debt, including premiums paid		(49.9	)		(70.5	)		(121.9	)
Redemption of preferred stock of subsidiary		(0.1	)		(0.1	)		(0.1	)
Net change in short-term borrowings, including from other
Vectren companies		(81.4	)		123.1			(140.8	)
Other activity		-			-			(1.7	)
Net cash flows from financing activities		(42.1	)		7.4			64.5
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		0.1			3.5			-
Requirements for:
Capital expenditures, excluding AFUDC equity		(217.8	)		(246.2	)		(235.2	)
Unconsolidated affiliate & other investments		-			-			(1.1	)
Net cash flows from investing activities		(217.7	)		(242.7	)		(236.3	)
Net (decrease) increase in cash & cash equivalents		6.0			(2.4	)		(2.4	)
Cash & cash equivalents at beginning of period		5.7			8.1			10.5
Cash & cash equivalents at end of period	$	11.7		$	5.7		$	8.1

Cash paid during the year for:
Interest	$	65.9		$	65.0		$	60.7
Income taxes		43.3			6.1			52.2

The accompanying notes are an integral part of these consolidated financial statements.

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In millions)


						Accumulated
						Other
	Common		Retained			Comprehensive
	Stock		Earnings			Income (Loss)			Total

Balance at January 1, 2003	$	385.7	$	382.4		$	0.5		$	768.6
Comprehensive income:
Net income				85.6						85.6
Cash flow hedges - net of tax							(0.5	)		(0.5	)
Total comprehensive income										85.1
Common stock:
Additional capital contribution		204.1								204.1
Dividends				(78.0	)					(78.0	)
Balance at December 31, 2003		589.8		390.0			-			979.8
Net income and comprehensive income				83.1						83.1
Common stock:
Additional capital contribution		3.1								3.1
Dividends				(80.6	)					(80.6	)
Balance at December 31, 2004	$	592.9	$	392.5		$	-		$	985.4
Comprehensive income:
Net income				95.1						95.1
Cash flow hedges - net of tax							4.0			4.0
Total comprehensive income										99.1
Common stock:
Additional capital contribution		20.0								20.0
Dividends				(80.7	)					(80.7	)
Balance at December 31, 2005	$	612.9	$	406.9		$	4.0		$	1,023.8

The accompanying notes are an integral part of these consolidated financial statements.

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VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Nature of Operations

Vectren Utility Holdings, Inc. (Utility Holdings or the Company), an Indiana corporation, serves as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and the Ohio operations. Utility Holdings also has assets that provide information technology and other services to the utilities. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana. Both Vectren and Utility Holdings are exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.

Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 140,000 electric customers and approximately 112,000 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 318,000 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 generally do business as Vectren Energy Delivery of Ohio.

2.	Summary of Significant Accounting Policies

A.	Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of significant intercompany transactions.

B.	Cash & Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.

C.	Inventories

Inventories consist of the following:

	At December 31,
(In millions)	2005		2004
Gas in storage – at average cost (See Note 4)	$	63.3	$	-
Materials & supplies		29.9		27.3
Gas in storage – at LIFO cost		18.8		18.9
Fuel (coal & oil) for electric generation		14.1		8.8
Other		0.1		3.1
Total inventories	$	126.2	$	58.1

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2005, and 2004, by approximately $117.0 million and $56.4 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost.

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D.	Utility Plant & Depreciation

Utility plant is stated at historical cost, including AFUDC. Depreciation rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At December 31,
(In millions)	2005 2004
		Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Gas utility plant		$	1,879.1		3.5	%	$	1,793.6		3.5	%
Electric utility plant			1,611.4		3.7	%		1,458.1		3.6	%
Common utility plant			44.2		2.6	%		44.2		2.7	%
Construction work in progress			97.3		-			169.3		-
Total original cost		$	3,632.0				$	3,465.2

AFUDC represents the cost of borrowed and equity funds used for construction purposes, and is charged to construction work in progress during the construction period. AFUDC is included in Other - net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:

	Year Ended December 31,
(In millions)		2005		2004		2003
AFUDC – borrowed funds		$	1.6	$	1.6	$	2.1
AFUDC – equity funds			0.3		1.6		2.9
Total AFUDC		$	1.9	$	3.2	$	5.0

Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.

Jointly Owned Plant

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 270 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2005 is $63.2 million with accumulated depreciation totaling $40.2 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

E.	Non-utility Property

Non-utility property, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2005		2004
Computer hardware and software	$	103.3	$	102.1
Land & buildings		43.5		37.2
All other		13.2		10.3
Non-utility property - net	$	160.0	$	149.6

Table of Contecnts

The depreciation of non-utility property is charged against income over its estimated useful life (ranging from 5 to 40 years), using the straight-line method of depreciation or units-of-production method of amortization. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the non-utility property, are charged to expense as incurred. When non-utility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income. Non-utility property is presented net of accumulated depreciation and amortization totaling $92.7 million and $73.3 million as of December 31, 2005, and 2004, respectively. For the years ended December 31, 2005, 2004, and 2003, the Company capitalized interest totaling $0.4 million, $1.4 million, and $0.9 million, respectively, on non-utility plant construction projects.

F.	Impairment Review of Long-Lived Assets

Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144), which the Company adopted on January 1, 2002. SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

Goodwill

Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). The Company adopted SFAS 142 on January 1, 2002. SFAS 142 requires a portion of goodwill be charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2005, no goodwill impairments have been recorded. All of the Company’s goodwill is included in the Gas Utility Services operating segment.

H.	Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company’s results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $16 million ARO for interim retirements of gas utility pipeline and utility poles and certain asbestos-related issues. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in an increase to Utility plant of approximately $12 million. Because of the effects of regulation, the difference was recorded to Regulatory assets and liabilities.

Table of Contecnts

I.	Regulation

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).

Regulatory Assets and Liabilities

Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. 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.

Regulatory liabilities consist of the following:

	At December 31,
(In millions)	2005		2004
Future amounts recoverable from ratepayers:
Income taxes	$	11.1	$	11.5
Asset retirement obligations & other		1.7		1.0
		12.8		12.5
Amounts deferred for future recovery:
Demand side management programs		26.7		25.9
MISO-related costs		9.4		3.1
Other		3.0		4.2
		39.1		33.2
Amounts currently recovered through base rates:
Unamortized debt issue costs		20.2		20.4
Premiums paid to reacquire debt		6.5		7.0
Demand side management programs & other		3.7		3.5
		30.4		30.9
Amounts currently recovered through tracking mechanisms:
Ohio authorized trackers		5.6		6.3
Indiana authorized trackers		2.0		(0.4	)
		7.6		5.9
Total regulatory assets	$	89.9	$	82.5

Of the $30.4 million currently being recovered through base rates charged to customers, $28.6 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 13.6 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Table of Contecnts

Regulatory liabilities consist of the following:

	At December 31,
(In millions)	2005		2004
Cost of removal	$	251.4	$	246.2
Asset retirement obligation timing difference		11.6		-
Interest rate hedging proceeds (See Note 10)		6.8		5.5
MISO-related costs		3.1		-
Total regulatory liabilities	$	272.9	$	251.7

Cost of Removal

The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143

Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased Power

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause 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. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed.

J.	Comprehensive Income

Comprehensive income is a measure of all changes in equity that result from the transactions or other economic events during the period from non-shareholder transactions. This information is reported in the Consolidated Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:


	2003								2004				2005
	Beginning			Changes			End		Changes		End		Changes			End
	of Year			During			of Year		During		of Year		During			of Year
(In millions)	Balance			Year			Balance		Year		Balance		Year			Balance

Cash flow hedges		0.8			(0.8	)		-		-		-		6.7			6.7
Deferred income taxes		(0.3	)		0.3			-		-		-		(2.7	)		(2.7	)
Accumulated other comprehensive income (loss)	$	0.5		$	(0.5	)	$	-	$	-	$	-	$	4.0		$	4.0

Revenues

Revenues are recorded as products and services are delivered to customers. 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.

Table of Contecnts

L.	Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $42.6 million in 2005, $38.3 million in 2004, and $37.1 million in 2003. Excise and utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.

M.	Earnings Per Share

Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren.

N.	Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 10).

O.	Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

P.	Reclassifications

Certain amounts included in prior years’ consolidated balance sheet and the consolidated statements of income and cash flows have been reclassified to conform to the current year presentation. These reclassifications had no effect on reported total assets, liabilities, shareholders’ equity, or net income.

3.	Transactions with Other Vectren Companies

Support Services and Purchases

Vectren provides corporate and general and administrative services to the Company including legal, finance, tax, risk management, human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. Utility Holdings received corporate allocations totaling $48.0 million, $44.5 million, and $43.4 million for the years ended December 31, 2005, 2004, and 2003, respectively.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2005, 2004, and 2003, totaled $96.4 million, $79.0 million, and $77.0 million, respectively.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. 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. 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. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.

For the years ended December 31, 2005, 2004, and 2003, periodic pension costs totaling $4.8 million, $4.8 million, and $5.0 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2005, 2004, and 2003, other periodic postretirement benefit costs totaling $0.8 million, $0.9 million, and $0.9 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2005 and 2004, $49.5 million and $49.8 million, respectively, is included in Deferred credits & other liabilities and represents expense directly charged to the Company that is yet to be funded to Vectren, and $3.0 million and $2.4 million, respectively, is included in Other assets for amounts funded in advance to Vectren.

Table of Contecnts

Cash Management Arrangements

The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks.

Share-Based Incentive Plans

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all 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. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like Utility Holdings. The Company intends to adopt SFAS 123R using the modified prospective method. The adoption of this standard, and subsequent interpretations of the standard, is not expected to have a material effect on the Company’s operating results or financial condition.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Utility Holdings’ current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash.

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In millions)	2005			2004			2003
Current:
Federal	$	15.7		$	3.7		$	15.0
State		8.7			6.4			12.5
Total current taxes		24.4			10.1			27.5
Deferred:
Federal		32.2			40.6			27.4
State		3.3			4.6			(1.1	)
Total deferred taxes		35.5			45.2			26.3
Amortization of investment tax credits		(2.4	)		(2.2	)		(2.2	)
Total income tax expense	$	57.5		$	53.1		$	51.6

Table of Contecnts

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2005			2004			2003
Statutory rate		35.0	%		35.0	%		35.0	%
State and local taxes-net of federal benefit		5.2			5.2			5.4
Amortization of investment tax credit		(1.5	)		(1.6	)		(1.6	)
Adjustment to income tax accruals		(2.2	)		(0.2	)		(0.1	)
All other - net		1.2			0.6			(1.1	)
Effective tax rate		37.7	%		39.0	%		37.6	%

The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)		2005			2004
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences		$	277.5		$	240.9
Regulatory assets recoverable through future rates			19.2			19.2
Demand side management programs			7.7			12.5
Other comprehensive income			2.7			-
Employee benefit obligations			(20.7	)		(21.5	)
Regulatory liabilities to be settled through future rates			(8.1	)		(7.7	)
Other – net			(2.8	)		(2.6	)
Net noncurrent deferred tax liability			275.5			240.8
Current deferred tax liabilities:
Deferred fuel costs - net			7.6			4.5
Net deferred tax liability		$	283.1		$	245.3

At December 31, 2005 and 2004, investment tax credits totaling $11.8 million and $14.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

4.	Transactions with Vectren Affiliates

ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to the Company’s utilities, Citizens Gas, and others. ProLiance’s primary business is optimizing the gas portfolios of utilities and providing services to large end use customers.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2005, 2004, and 2003, totaled $908.9 million, $789.8 million, and $770.7 million, respectively. Amounts owed to ProLiance at December 31, 2005 and 2004, for those purchases were $137.4 million and $97.7 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 95% of its gas through ProLiance in 2005. In 2004 and 2003, all purchases were made through ProLiance. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

Table of Contecnts

As required by a June 2005, PUCO order, VEDO solicited bids for its gas supply/portfolio administration services and selected a third party provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. As a result, delivery services that in the past were paid to ProLiance were used to purchase inventory; therefore, natural gas held in inventory has increased, while Prepaid gas delivery services in Prepayments and other current assets have decreased. See Notes 2-C and 11, respectively.

Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services for the Company. For the years ended December 31, 2005, 2004, and 2003, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled $21.3 million, $31.2 million, and $37.2 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled $3.2 million and $1.1 million at December 31, 2005, and 2004, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.

5.	Borrowing Arrangements

Short-Term Borrowings

At December 31, 2005, Utility Holdings has $520 million of short-term borrowing capacity, of which approximately $293 million is available. The Company increased its short-term credit facility in November 2005, by approximately $165 million in response to increased natural gas costs. Utility Holdings’ credit facilities are primarily used to support its access to the commercial paper market. See the table below for interest rates and outstanding balances.

	Year Ended December 31,
(In millions)	2005			2004			2003
Weighted average commercial paper and bank loans
outstanding during the year	$	193.5		$	133.2		$	219.5
Weighted average interest rates during the year
Commercial paper		3.42	%		1.78	%		1.36	%
Bank loans		-			2.19	%		1.86	%
		At December 31,
(In millions)		2005			2004
Commercial paper	$	226.9		$	308.0
Bank loans		-			0.3
Total short-term borrowings	$	226.9		$	308.3

Table of Contecnts

Long-Term Debt

Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term by subsidiary follow:

	At December 31,
(In millions)	2005		2004
UTILITY HOLDINGS
Senior Unsecured Notes
2011, 6.625%	$	250.0	$	250.0
2013, 5.25%		100.0		100.0
2015, 5.45%		75.0		-
2018, 5.75%		100.0		100.0
2031, 7.25%		100.0		100.0
2035, 6.10%		75.0		-
Total VUHI		700.0		550.0
SIGECO
First Mortgage Bonds
2016, 1986 Series, 8.875%		13.0		13.0
2023, 1993 Environmental Improvement Series B, current adjustable rate 3.70%,
tax exempt, auction rate mode, 2005 weighted average: 2.66%		22.6		22.6
2029, 1999 Senior Notes, 6.72%		80.0		80.0
2015, 1985 Pollution Control Series A, current adjustable rate 3.35%, tax
exempt, auction rate mode, 2005 weighted average: 2.46%		9.8		9.8
2020, 1998 Pollution Control Series B, 4.50%, tax exempt		4.6		4.6
2030, 1998 Pollution Control Series B, 5.00%, tax exempt		22.0		22.0
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt		22.5		22.5
Total first mortgage bonds		174.5		174.5
Senior Secured Bonds to Third Parties:
2025, 1998 Pollution Control Series A, current adjustable rate 4.75%, tax
exempt, next rate adjustment: 2006		31.5		31.5
Senior Unsecured Bonds to Third Parties:
2030, 1998 Pollution Control Series C, current adjustable rate 5.00%, tax
exempt, next rate adjustment: 2006		22.2		22.2
Total SIGECO		228.2		228.2
Indiana Gas
Senior Unsecured Notes
2007, Series E, 6.54%		6.5		6.5
2013, Series E, 6.69%		5.0		5.0
2015, Series E, 7.15%		5.0		5.0
2015, Series E, 6.69%		5.0		5.0
2015, Series E, 6.69%		10.0		10.0
2025, Series E, 6.53%		10.0		10.0
2027, Series E, 6.42%		5.0		5.0
2027, Series E, 6.68%		1.0		1.0
2027, Series F, 6.34%		20.0		20.0
2028, Series F, 6.36%		10.0		10.0
2028, Series F, 6.55%		20.0		20.0
2029, Series G, 7.08%		30.0		30.0
2030, Insured Quarterly, 7.45%		-		49.9
Total Indiana Gas		127.5		177.4

Table of Contecnts

	At December 31,
(In millions)	2005			2004
Total long-term debt outstanding		1,055.7			955.6
Current maturities of long-term debt		-			-
Debt subject to tender		(53.7	)		(10.0	)
Unamortized debt premium & discount - net		(4.2	)		(4.6	)
Other		-			0.3
Total long-term debt-net	$	997.8		$	941.3

Utility Holdings 2005 Issuance

In December 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.799% to yield 6.11% to maturity (2035 Notes).

The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, 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 2015 Notes and 25 basis points for the 2035 Notes.

In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a total notional amount of $75 million. Upon issuance of the debt, the instruments were settled resulting in the receipt of approximately $1.9 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 issue maturing in December 2035.

The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million.

Utility Holdings 2003 Issuance

Shortly before these issues, Utility Holdings 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.

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. 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. No debt was put to the Company in 2005. During 2004 and 2003, debt totaling $2.5 million and $0.1 million, respectively, was put to the Company. Debt which may be put to the Company during the years following 2005 (in millions) is $53.7 in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010, and $30.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

Table of Contecnts

SIGECO and Indiana Gas Debt Call

Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $3.6 million were deferred in Regulatory assets.

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 of debt and the reissuance of new debt at generally the same par value. These bonds are classified in Long-term debt.

Other Company debt totaling $15.0 million in 2004 and $18.5 million in 2003 was retired as scheduled.

Future Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2006 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2006 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2005, $549.4 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $1.9 billion at December 31, 2005.

Consolidated maturities and sinking fund requirements on long-term debt during the five years following 2005 (in millions) are zero in 2006, $6.5 in 2007, and zero in 2008, 2009, and 2010.

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2005, the Company was in compliance with all financial covenants.

6.	Additional Capital Contributions

Table of Contecnts

7.	Commitments & Contingencies

Commitments

Firm purchase commitments for utility and non-utility plant total $13.0 million.

Securities & Exchange Commission Inquiry into PUHCA Exemption

Legal Proceedings

8.	Environmental Matters

Clean Air Act

NOx SIP Call Matter

The IURC has issued orders that approve:

·	the Company’s project to achieve environmental compliance by investing in clean coal technology;

·	a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred;

·	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

·	ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service.

Table of Contecnts

Clean Air Interstate Rule & Clean Air Mercury Rule

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 agreement, SIGECO committed to:

·	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;

·	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;

·	enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions;

·	install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007;

·	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

·	pay a $600,000 civil penalty.

The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was accrued during 2003 and is reflected in Other-net.

Table of Contecnts

Manufactured Gas Plants

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.

Table of Contecnts

Jacobsville Superfund Site

9.	Rate & Regulatory Matters

Gas Utility Base Rate Settlements

Indiana and Ohio Decoupling/Conservation Filing

On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.

Weather Normalization

Table of Contecnts

Gas Cost Recovery (GCR) Audit Proceedings

On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During the fourth quarter of 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

Commodity Prices

Recently, commodity prices for natural gas purchases have increased and have become more volatile. Subject to compliance with applicable state laws, the Company's utility subsidiaries are allowed recovery of such changes in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms, and margin on gas sales are not expected to be impacted. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for a variety of reasons, including, but not limited to, a finding by the regulator that natural gas was not prudently procured. In addition, it is reasonably possible that as a result of this near term change in the natural gas commodity price, the Company’s utility subsidiaries may experience increased interest expense due to higher working capital requirements; increased uncollectible accounts expense and unaccounted for gas; and some level of price sensitive reduction in volumes sold or delivered. In response to higher gas prices, the Company increased its utility-related credit facilities (See Note 5).

MISO

On June 1, 2005, Utility Holdings, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in the Company’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.

Table of Contecnts

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 2003. In 2005 and 2004, the Company recorded revenues of $5.1 and $3.3 million, respectively, which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers.

10.

Derivatives & Other Financial Instruments

Accounting Policy for Derivatives

The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting in four primary areas: asset optimization, SO₂ emission allowance risk management, natural gas procurement, and interest rate management.

Asset Optimization

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 income 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. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Asset optimization contracts are recorded at market value. Beginning in April 2005, substantially all off-system sales occur into the MISO day-ahead market.

At December 31, 2005, asset optimization contracts recorded at market value in Prepayments & other current assets were $1.3 million and were zero in Accrued liabilities. At December 31, 2004, asset optimization contracts recorded at market value approximated $2.5 million in Prepayments & other current assets and $3.1 million in Accrued liabilities.

The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts are recorded in Electric utility revenues. The change in market value is a function of the normal decline in market value as earnings are realized and the fluctuation in market value resulting from price volatility. Net revenues from asset optimization activities totaled $38.0 million in 2005, $23.8 million in 2004, and $26.5 million in 2003.

Table of Contecnts

SO₂ Emission Allowance Risk Management

The Company’s wholesale power marketing operations are exposed to price risk associated with SO₂emission allowances. During 2004 and 2005, emission allowances became more volatile and prices increased. To hedge this risk, the Company executed call options to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2005, a deferred gain of approximately $3.2 million remains in Accumulated comprehensive income which will be recognized in earnings as emission allowances are utilized. At December 31, 2005, outstanding call options hedging a forecasted 2006 transaction, have a fair value of $3.9 million and are recorded in Prepayments and other current assets. Hedge ineffectiveness totaling $0.8 million of expense is included in 2005’s earnings, and the effective portion of outstanding hedges totaling $3.6 million resides in Accumulated comprehensive income.

Natural Gas Procurement Activity

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 such purchases through natural gas and fuel cost adjustment mechanisms. Although Utility Holdings’ 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 volatility 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. At December 31, 2005 and 2004, the market values of these contracts were not significant.

Interest Rate Management

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 has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure. Hedging instruments are recorded at market value. Changes in market value, when effective, are recorded in Accumulated other comprehensive income for cash flow hedges, as an adjustment to the outstanding debt balance for fair value hedges, or as regulatory asset/liability when regulation is involved. Amounts are recorded to interest expense as settled.

At December 31, 2005, approximately $6.8 million remains in Regulatory liabilities related to future interest payments. Of the existing regulatory liability, $0.7 million will be reclassified to earnings in 2006, $0.6 million was reclassified to earnings in 2005, and $0.6 million was reclassified to earnings during 2004.

Fair Value of Other Financial Instruments

The carrying values and estimated fair values of the Company's other financial instruments follow:

	At December 31,
	2005				2004
In millions	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,055.7	$	1,105.2	$	955.6	$	1,108.9
Short-term borrowings		226.9		226.9		308.3		308.3

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.

Table of Contecnts

Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

11.

Additional Balance Sheet & Operational Information

Prepayments and other current assets in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2005		2004
Prepaid gas delivery service (See Note 4)	$	69.3	$	116.9
Prepaid taxes		27.1		12.3
Other prepayments & current assets		20.8		4.9
Total prepayments & other current assets	$	117.2	$	134.1

Accrued liabilities in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2005		2004
Refunds to customers & customer deposits	$	36.4	$	31.0
Accrued taxes		31.5		27.6
Accrued interest		16.2		15.1
Deferred income taxes		7.6		4.5
Accrued salaries & other		38.7		31.8
Total accrued liabilities	$	130.4	$	110.0

Other - net in the Consolidated Statements of Income consists of the following:

	Year Ended December 31,
(In millions)	2005		2004		2003
AFUDC & capitalized interest	$	2.5	$	4.6	$	5.9
Interest income		0.6		0.5		0.6
Gains on sale of investments & assets		-		0.6		-
Other income		2.8		0.8		3.3
Other expense		-		0.6		(3.2	)
Total other – net	$	5.9	$	7.1	$	6.6

12.

Segment Reporting

The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. The Company cross manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. In total, regulated operations supply natural gas and /or electricity to over one million customers. For these regulated operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. For Utility Holdings’ other operations, net income is used as the measure of profitability. In total, there are three operating segments as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131).

Table of Contecnts

Information related to the Company’s business segments is summarized below:

	Year Ended December 31,
(In millions)	2005			2004			2003
Revenues
Gas Utility Services	$	1,359.7		$	1,126.2		$	1,112.3
Electric Utility Services		421.4			371.3			335.7
Other Operations		36.1			32.9			26.5
Eliminations		(35.4	)		(32.4	)		(25.7	)
Total revenues	$	1,781.8		$	1,498.0		$	1,448.8

Profitability Measure
Regulated Operating Income
(Operating Income Less Applicable Income Taxes)
Gas Utility Services	$	74.8		$	70.9		$	74.9
Electric Utility Services		72.4			65.6			63.8
Total regulated operating income		147.2			136.5			138.7
Regulated other income - net		2.0			2.1			5.1
Regulated interest expense & preferred dividends		(63.9	)		(62.7	)		(62.0	)
Regulated Net Income		85.3			75.9			81.8
Other Operations Net Income		9.8			7.2			3.8
Net Income	$	95.1		$	83.1		$	85.6

Table of Contecnts

	Year Ended December 31,
(In millions)		2005		2004			2003
Amounts Included in Profitability Measures
Depreciation & Amortization
Gas Utility Services		$	64.9	$	57.0		$	61.1
Electric Utility Services			56.9		53.3			42.6
Other Operations			19.5		17.5			14.2
Total depreciation & amortization		$	141.3	$	127.8		$	117.9

Interest Expense
Regulated Operations		$	63.9	$	62.7		$	62.0
Other Operations			6.0		4.7			4.1
Total interest expense		$	69.9	$	67.4		$	66.1

Equity in (Earnings )Losses of Unconsolidated Affiliates
Other Operations		$	-	$	0.2		$	(0.5	)
Income Taxes
Gas Utility Services		$	22.3	$	17.5		$	19.5
Electric Utility Services			33.5		30.8			29.8
Other Operations			1.7		4.8			2.3
Total income taxes		$	57.5	$	53.1		$	51.6

Capital Expenditures
Gas Utility Services		$	81.0	$	89.1		$	95.0
Electric Utility Services			100.0		150.6			124.1
Other Operations			29.9		27.9			15.9
Non-cash costs & changes in accruals			6.9		(21.4	)		0.2
Total capital expenditures		$	217.8	$	246.2		$	235.2

	At December 31,
(In millions)	2005			2004
Assets
Utility Group
Gas Utility Services	$	2,030.8		$	1,892.8
Electric Utility Services		1,176.0			1,090.1
Other Operations		188.9			175.0
Eliminations		(4.5	)		(10.2	)
Total assets	$	3,391.2		$	3,147.7

13.

Subsidiary Guarantor and Consolidating Information

The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $520 million in short-term credit facilities, of which $226.9 million is outstanding at December 31, 2005, and Utility Holdings’ $700.0 million unsecured senior notes outstanding at December 31, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Article 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company.

Table of Contecnts

Consolidating Balance Sheet as of December 31, 2005 (in millions):



ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	11.0	$	0.7	$	-		$	11.7
Accounts receivable - less reserves		170.6		0.1		-			170.7
Receivables due from other Vectren companies		0.9		294.7		(293.4	)		2.2
Accrued unbilled revenues		212.5		-		-			212.5
Inventories		126.2		-		-			126.2
Recoverable fuel & natural gas costs		15.4		-		-			15.4
Prepayments & other current assets		104.1		13.7		(0.6	)		117.2
Total current assets		640.7		309.2		(294.0	)		655.9
Utility Plant
Original cost		3,631.6		0.4		-			3,632.0
Less: accumulated depreciation & amortization		1,380.1		-		-			1,380.1
Net utility plant		2,251.5		0.4		-			2,251.9
Investments in consolidated subsidiaries		-		1,085.0		(1,085.0	)		-
Notes receivable from consolidated subsidiaries		-		443.1		(443.1	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		14.9		6.1		-			21.0
Non-utility property - net		5.1		154.9		-			160.0
Goodwill - net		205.0		-		-			205.0
Regulatory assets		83.1		6.8		-			89.9
Other assets		6.3		1.0		-			7.3
TOTAL ASSETS	$	3,206.8	$	2,006.5	$	(1,822.1	)	$	3,391.2


LIABILITIES & SHAREHOLDER'S EQUITY		Subsidiary		Parent
Guarantors				Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	125.7	$	6.2	$	-		$	131.9
Accounts payable to affiliated companies		140.0		0.6		-			140.6
Payables to other Vectren companies		27.8		5.2		(3.8	)		29.2
Refundable fuel & natural gas costs		7.6		-		-			7.6
Accrued liabilities		120.7		10.3		(0.7	)		130.4
Short-term borrowings		-		226.9		-			226.9
Short-term borrowings from
other Vectren companies		289.5		-		(289.5	)		-
Current maturities of long-term debt		-		-		-			-
Long-term debt subject to tender		53.7		-		-			53.7
Total current liabilities		765.0		249.2		(294.0	)		720.3
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		299.9		697.9		-			997.8
Long-term debt due to VUHI		443.1		-		(443.1	)		-
Total long-term debt - net		743.0		697.9		(443.1	)		997.8
Deferred Income Taxes & Other Liabilities
Deferred income taxes		251.6		23.9		-			275.5
Regulatory liabilities		266.2		6.8		-			272.9
Deferred credits & other liabilities		96.0		4.9		-			100.9
Total deferred credits & other liabilities		613.8		35.6		-			649.3
Cumulative, Redeemable Preferred Stock of a Subsidiary		-		-		-			-
Common Shareholder's Equity
Common stock (no par value)		736.3		612.9		(736.3	)		612.9
Retained earnings		344.7		406.9		(344.7	)		406.9
Accumulated other comprehensive income		4.0		4.0		(4.0	)		4.0
Total common shareholder's equity		1,085.0		1,023.8		(1,085.0	)		1,023.8

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,206.8	$	2,006.5	$	(1,822.1	)	$	3,391.2

Table of Contecnts

Consolidating Balance Sheet as of December 31, 2004 (in millions):


ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	4.7	$	1.0	$	-		$	5.7
Accounts receivable - less reserves		146.5		-		-			146.5
Receivables due from other Vectren companies		1.7		327.0		(324.7	)		4.0
Accrued unbilled revenues		161.2		-		-			161.2
Inventories		58.1		-		-			58.1
Recoverable fuel & natural gas costs		17.7		-		-			17.7
Prepayments & other current assets		132.2		4.2		(2.3	)		134.1
Total current assets		522.1		332.2		(327.0	)		527.3
Utility Plant
Original cost		3,465.2		-		-			3,465.2
Less: accumulated depreciation & amortization		1,309.0		-		-			1,309.0
Net utility plant		2,156.2		-		-			2,156.2
Investments in consolidated subsidiaries		-		951.6		(951.6	)		-
Notes receivable from consolidated subsidiaries		-		443.1		(443.1	)		-
Investments in unconsolidated affiliates		0.2		-		-			0.2
Other investments		13.5		6.1		-			19.6
Non-utility property - net		5.3		144.3		-			149.6
Goodwill - net		205.0		-		-			205.0
Regulatory assets		76.8		5.7		-			82.5
Other assets		3.8		3.5		-			7.3
TOTAL ASSETS	$	2,982.9	$	1,886.5	$	(1,721.7	)	$	3,147.7

LIABILITIES & SHAREHOLDER'S EQUITY		Subsidiary		Parent
		Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	87.9	$	9.4	$	-		$	97.3
Accounts payable to affiliated companies		98.6		0.2		-			98.8
Payables to other Vectren companies		26.0		0.6		(10.8	)		15.8
Refundable fuel & natural gas costs		6.3		-		-			6.3
Accrued liabilities		100.8		11.6		(2.4	)		110.0
Short-term borrowings		0.3		308.0		-			308.3
Short-term borrowings from
other Vectren companies		313.8		-		(313.8	)		-
Current maturities of long-term debt		-		-		-			-
Long-term debt subject to tender		10.0		-		-			10.0
Total current liabilities		643.7		329.8		(327.0	)		646.5
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender		393.4		547.9		-			941.3
Long-term debt due to VUHI		443.1		-		(443.1	)		-
Total long-term debt - net		836.5		547.9		(443.1	)		941.3
Deferred Income Taxes & Other Liabilities
Deferred income taxes		226.8		14.0		-			240.8
Regulatory liabilities		246.2		5.5		-			251.7
Deferred credits & other liabilities		78.0		3.9		-			81.9
Total deferred credits & other liabilities		551.0		23.4		-			574.4
Cumulative, Redeemable Preferred Stock of a Subsidiary		0.1		-		-			0.1
Common Shareholder's Equity
Common stock (no par value)		611.3		592.9		(611.3	)		592.9
Retained earnings		340.3		392.5		(340.3	)		392.5
Total common shareholder's equity		951.6		985.4		(951.6	)		985.4

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	2,982.9	$	1,886.5	$	(1,721.7	)	$	3,147.7

Table of Contecnts

Consolidating Statement of Income for the year ended December 31, 2005 (in millions):


	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	1,359.7	$	-	$	-		$	1,359.7
Electric utility		421.4		-		-			421.4
Other		-		36.1		(35.4	)		0.7
Total operating revenues		1,781.1		36.1		(35.4	)		1,781.8
OPERATING EXPENSES
Cost of gas sold		973.3		-		-			973.3
Fuel for electric generation		126.3		-		-			126.3
Purchased electric energy		17.8		-		-			17.8
Other operating		274.4		0.1		(33.2	)		241.3
Depreciation & amortization		121.7		19.3		0.3			141.3
Taxes other than income taxes		64.7		0.4		0.1			65.2
Total operating expenses		1,578.2		19.8		(32.8	)		1,565.2
OPERATING INCOME		202.9		16.3		(2.6	)		216.6
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies		-		85.3		(85.3	)		-
Equity in losses of unconsolidated affiliates		-		-		-			-
Other – net		4.3		37.8		(36.2	)		5.9
Total other income (expense)		4.3		123.1		(121.5	)		5.9
Interest expense		64.4		42.9		(37.4	)		69.9
INCOME BEFORE INCOME TAXES		142.8		96.5		(86.7	)		152.6
Income taxes		57.5		1.4		(1.4	)		57.5

NET INCOME	$	85.3	$	95.1	$	(85.3	)	$	95.1

Consolidating Statement of Income for the year ended December 31, 2004 (in millions):


	Subsidiary			Parent
	Guarantors			Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	1,126.2		$	-	$	-		$	1,126.2
Electric utility		371.3			-		-			371.3
Other		-			32.9		(32.4	)		0.5
Total operating revenues		1,497.5			32.9		(32.4	)		1,498.0
OPERATING EXPENSES
Cost of gas sold		778.5			-		-			778.5
Fuel for electric generation		96.1			-		-			96.1
Purchased electric energy		20.7			-		-			20.7
Other operating		249.8			1.1		(30.5	)		220.4
Depreciation & amortization		110.1			17.5		0.2			127.8
Taxes other than income taxes		57.5			0.6		0.1			58.2
Total operating expenses		1,312.7			19.2		(30.2	)		1,301.7
OPERATING INCOME		184.8			13.7		(2.2	)		196.3
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies		-			67.2		(67.2	)		-
Equity in earnings/losses of unconsolidated affiliates		-			0.2		-			0.2
Other – net		(2.9	)		35.4		(25.4	)		7.1
Total other income (expense)		(2.9	)		102.8		(92.6	)		7.3
Interest expense		62.9			37.5		(33.0	)		67.4
INCOME BEFORE INCOME TAXES		119.0			79.0		(61.8	)		136.2
Income taxes		51.8			4.7		(3.4	)		53.1
NET INCOME	$	67.2		$	74.3	$	(58.4	)	$	83.1

Table of Contecnts

Consolidating Statement of Income for the year ended December 31, 2003 (in millions):


	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	1,112.3	$	-		$	-		$	1,112.3
Electric utility		335.7		-			-			335.7
Other		-		26.5			(25.7	)		0.8
Total operating revenues		1,448.0		26.5			(25.7	)		1,448.8
OPERATING EXPENSES
Cost of gas sold		762.5		-			-			762.5
Fuel for electric generation		86.5		-			-			86.5
Purchased electric energy		16.2		-			-			16.2
Other operating		235.3		0.5			(23.9	)		211.9
Depreciation & amortization		103.7		14.2			-			117.9
Taxes other than income taxes		55.9		0.7			-			56.6
Total operating expenses		1,260.1		15.4			(23.9	)		1,251.6
OPERATING INCOME		187.9		11.1			(1.8	)		197.2
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies		-		81.8			(81.8	)		-
Equity in losses of unconsolidated affiliates		-		(0.5	)		-			(0.5	)
Other – net		5.1		27.9			(26.4	)		6.6
Total other income (expense)		5.1		109.2			(108.2	)		6.1
Interest expense		62.0		32.3			(28.2	)		66.1
INCOME BEFORE INCOME TAXES		131.0		88.0			(81.8	)		137.2
Income taxes		49.2		2.4			-			51.6

NET INCOME	$	81.8	$	85.6		$	(81.8	)	$	85.6

Consolidating Statement of Cash Flows for the year ended December 31, 2005 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated

NET CASH FLOWS FROM OPERATING ACTIVITIES	$	224.0		$	41.8		$	-		$	265.8
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		125.0			20.0			(125.0	)		20.0
Long-term debt - net of issuance costs & hedging proceeds		-			150.0			-			150.0
Requirements for:
Retirement of long-term debt, including premiums paid		(49.9	)		-			-			(49.9	)
Dividends to parent		(80.7	)		(80.7	)		80.7			(80.7	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings, including from other
Vectren companies		(24.6	)		(81.1	)		24.3			(81.4	)
Net cash flows from financing activities		(30.3	)		8.2			(20.0	)		(42.1	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions		-			80.7			(80.7	)		-
Other investing activities		0.1			-			-			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity		(187.5	)		(30.3	)		-			(217.8	)
Consolidated subsidiary investments		-			(125.0	)		125.0			-
Net change in notes receivable from other Vectren companies		-			24.3			(24.3	)		-
Net cash flows from investing activities		(187.4	)		(50.3	)		20.0			(217.7	)
Net (decrease) increase in cash & cash equivalents		6.3			(0.3	)		-			6.0
Cash & cash equivalents at beginning of period		4.7			1.0			-			5.7
Cash & cash equivalents at end of period	$	11.0		$	0.7		$	-		$	11.7

Table of Contecnts

Consolidating Statement of Cash Flows for the year ended December 31, 2004 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated

NET CASH FLOWS FROM OPERATING ACTIVITIES	$	197.6		$	35.3		$	-		$	232.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		-			3.1			-			3.1
Long-term debt - net of issuance costs & hedging proceeds		32.4			-			-			32.4
Requirements for:
Retirement of long-term debt, including premiums paid		(70.5	)		-			-			(70.5	)
Dividends to parent		(80.6	)		(80.6	)		80.6			(80.6	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings, including from other								-
Vectren companies		135.7			123.6			(136.2	)		123.1
Other activity		-			-			-			-
Net cash flows from financing activities		16.9			46.1			(55.6	)		7.4
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions		-			80.6			(80.6	)		-
Other investing activities		1.1			2.4			-			3.5
Requirements for:
Capital expenditures, excluding AFUDC equity		(218.3	)		(27.9	)		-			(246.2	)
Consolidated subsidiary investments		-			-			-			-
Unconsolidated affiliate & other investments		-			-			-			-
Net change in notes receivable from other Vectren companies		-			(136.2	)		136.2			-
Net cash flows from investing activities		(217.2	)		(81.1	)		55.6			(242.7	)
Net (decrease) increase in cash & cash equivalents		(2.7	)		0.3			-			(2.4	)
Cash & cash equivalents at beginning of period		7.4			0.7			-			8.1
Cash & cash equivalents at end of period	$	4.7		$	1.0		$	-		$	5.7

Table of Contecnts

Consolidating Statement of Cash Flows for the year ended December 31, 2003 (in millions):


	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated

NET CASH FLOWS FROM OPERATING ACTIVITIES	$	129.6		$	39.8		$	-		$	169.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution		150.0			204.1			(150.0	)		204.1
Long-term debt - net of issuance costs & hedging proceeds		99.0			202.9			(99.0	)		202.9
Requirements for:
Retirement of long-term debt, including premiums paid		(121.9	)		-			-			(121.9	)
Dividends to parent		(77.9	)		(78.0	)		77.9			(78.0	)
Redemption of preferred stock of subsidiary		(0.1	)		-			-			(0.1	)
Net change in short-term borrowings, including from other
Vectren companies		30.9			(150.1	)		(21.6	)		(140.8	)
Other activity		(1.7	)		-			-			(1.7	)
Net cash flows from financing activities		78.3			178.9			(192.7	)		64.5
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions		-			77.9			(77.9	)		-
Requirements for:
Capital expenditures, excluding AFUDC equity		(219.2	)		(16.0	)		-			(235.2	)
Consolidated subsidiary investments		-			(150.0	)		150.0			-
Unconsolidated affiliate & other investments		-			(1.1	)		-			(1.1	)
Net change in notes receivable from other Vectren companies		8.5			(129.1	)		120.6			-
Net cash flows from investing activities		(210.7	)		(218.3	)		192.7			(236.3	)
Net (decrease) increase in cash & cash equivalents		(2.8	)		0.4			-			(2.4	)
Cash & cash equivalents at beginning of period		10.2			0.3			-			10.5
Cash & cash equivalents at end of period	$	7.4		$	0.7		$	-		$	8.1

14.

Adoption of Other Accounting Standards

SFAS No. 154

Table of Contecnts

15.

Quarterly Financial Data (Unaudited)

Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2005 and 2004 follows:


(In millions)	Q1		Q2		Q3		Q4
2005
Results of Operations:
Operating revenues	$	611.6	$	283.0	$	265.7	$	621.5
Operating income		94.7		28.3		30.7		62.9
Net income		48.1		7.8		8.9		30.3
2004
Results of Operations:
Operating revenues	$	594.2	$	243.4	$	214.7	$	445.7
Operating income		87.3		19.9		21.7		67.4
Net income		44.7		2.8		4.5		31.1

Table of Contecnts

ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended December 31, 2005, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2005, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of December 31, 2005, to ensure that the information required to be disclosed and filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

Vectren’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Nominating and Corporate Governance Committees, and its Code of Ethics covering the Company’s directors, officers and employees are available on the Company’s website, www.vectren.com, and a copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708. The Company intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions on the Company’s website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708.

ITEM 11. EXECUTIVE COMPENSATION

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

Table of Contecnts

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following tabulation shows the audit and non-audit fees incurred and payable to Deloitte & Touche, LLP (Deloitte) for the years ending December 31, 2005, and December 31, 2004. The fees presented below represent total Vectren fees, the majority of which are allocated to Utility Holdings.

	2005		2004
Audit Fees⁽¹⁾	$	1,409,862	$	1,424,910
Audit-Related Fees⁽²⁾		50,000		13,650
Tax Fees⁽³⁾		128,208		103,663
All Other Fees⁽⁴⁾		-		-

Total Fees Paid to Deloitte⁽⁵⁾	$	1,588,070	$	1,542,223

(1)

Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of the Company’s 2005 and 2004 fiscal year annual financial statements and the review of financial statements included in Company’s Forms 10-K or 10-Q filed during the Company’s 2005 and 2004 fiscal years. This includes fees incurred for audit services related to regulatory filings and certain of the Company’s subsidiaries in connection with the audit of the Company’s financial statements. The amount also includes fees related to the attestation to the Company’s assertion pursuant to Section 404 of the Sarbanes Oxley Act of 2002. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $100,262 and $74,185 in 2005 and 2004, respectively.

(2)

Audit related fees consisted principally of reviews related to various financing transactions and consultation on various accounting issues. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $0 and $650 in 2005 and 2004, respectively.

(3)

Tax fees consisted of fees paid to Deloitte for the review of tax returns, consultation on other tax matters of the Company, and tax technical training. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $9,896 and $2,788 in 2005 and 2004, respectively.

(4)	All Other Fees—None.

(5)

Pursuant to its charter, the Audit committee is responsible for selecting, approving professional fees and overseeing the independence, qualifications and performance of the independent registered public accounting firm. The Audit committee has adopted a formal policy with respect to the pre-approval of audit and permissible non-audit services provided by the independent registered public accounting firm. Pre-approval is assessed on a case-by-case basis. In assessing requests for services to be provided by the independent registered public accounting firm, the Audit committee considers whether such services are consistent with the auditors’ independence, whether the independent registered public accounting firm is likely to provide the most effective and efficient service based upon the firm’s familiarity with the Company, and whether the service could enhance the Company’s ability to manage or control risk or improve audit quality. The audit-related, tax and other services provided by Deloitte in the last fiscal year and related fees were approved by the Audit committee in accordance with this policy.

Table of Contecnts

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

List of Documents Filed as Part of This Report

Consolidated Financial Statements

The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K.

Supplemental Schedules

For the years ended December 31, 2005, 2004, and 2003, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein. The report of Deloitte & Touche LLP on the schedule is included in Item 8. All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.

SCHEDULE II

Vectren Utility Holdings, Inc. and Subsidiary Companies

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions
	Balance at		Charged		Charged		Deductions		Balance at
	Beginning		to		to Other		from		End of
Description	Of Year		Expenses		Accounts		Reserves, Net		Year
(In millions)

VALUATION AND QUALIFYING ACCOUNTS:

Year 2005 – Accumulated provision for
uncollectible accounts	$	1.9	$	14.4	$	-	$	13.7	$	2.6
Year 2004 – Accumulated provision for
uncollectible accounts	$	3.1	$	10.7	$	-	$	11.9	$	1.9
Year 2003 – Accumulated provision for
uncollectible accounts	$	5.5	$	12.2	$	-	$	14.6	$	3.1


OTHER RESERVES:

Year 2005 – Restructuring costs	$	2.7	$	-	$	-	$	0.3	$	2.4
Year 2004 – Restructuring costs	$	3.2	$	-	$	-	$	0.5	$	2.7
Year 2003 – Restructuring costs	$	3.6	$	-	$	-	$	0.4	$	3.2

Table of Contecnts

List of Exhibits

The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company attached to this filing filed electronically with the SEC are listed below. Exhibits for the Company are listed in the Index to Exhibits beginning on page 74.

Vectren Utility Holdings, Inc.

2005 Form 10-K

Attached Exhibits

The following Exhibits are included in this Annual Report on Form 10-K.

Exhibit Number	Document

31.1	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The following Exhibits were filed electronically with the SEC with this filing.

Exhibit

Number

Document

12	Ratio of Earnings to Fixed Charges
21	List of Company’s Significant Subsidiaries
23	Consent of Registered Public Accounting Firm

Table of Contecnts

INDEX TO EXHIBITS

2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

2.1

Asset Purchase Agreement dated December 14, 1999 between Indiana Energy, Inc. and The Dayton Power and Light Company and Number-3CHK with a commitment letter for a 364-Day Credit Facility dated December 16,1999. (Filed and designated in Current Report on Form 8-K dated December 28, 1999, File No. 1-9091, as Exhibit 2 and 99.1.)

3. Articles of Incorporation and By-Laws

3.1	Articles of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.1)

3.2	Bylaws of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.2)

4. Instruments Defining the Rights of Security Holders, Including Indentures

4.1

Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) March 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.)

4.2

Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly know as First Trust National Association, which was formerly know as Bank of America Illinois, which was formerly know as Continental Bank, National Association. Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.)

4.3

Indenture dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.2); Second Supplemental Indenture, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indianan Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit 4.1; Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 18, 2005, File No. 1-16739, as Exhibit 4.1).

Table of Contecnts

10. Material Contracts

10.1

Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).

10.2	Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)

10.3	Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group of Management Employees as amended and restated effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.)

10.4	Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective January 1, 1999. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.)

10.5

Indiana Energy, Inc. Executive Restricted Stock Plan as amended and restated effective October 1, 1998. (Filed and designated in Form 10-K for the fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit 10-O.) First Amendment, effective December 1, 1998 (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-I.).

10.6

Indiana Energy, Inc. Director's Restricted Stock Plan as amended and restated effective May 1, 1997. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit 10-B.) First Amendment, effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-J.) Second Amendment, Plan renamed the Vectren Corporation Directors Restricted Stock Plan effective October 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-34.) Third Amendment, effective March 28, 2001. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-35.)

10.7	Vectren Corporation At Risk Compensation Plan effective May 1, 2001. (Filed and designated in Vectren Corporation’s Proxy Statement dated March 16, 2001, File No. 1-15467, as Appendix B.)

10.8	Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)

10.9	Vectren Corporation Employment Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.1.)

10.10

Vectren Corporation Employment Agreement between Vectren Corporation and Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.3.)

10.11

Vectren Corporation Employment Agreement between Vectren Corporation and Carl L. Chapman dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.4.)

10.12

Vectren Corporation Employment Agreement between Vectren Corporation and Ronald E. Christian dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.5.)

10.13

Vectren Corporation Employment Agreement between Vectren Corporation and Richard G. Lynch dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.8.)

10.14

Vectren Corporation Employment Agreement between Vectren Corporation and William S. Doty dated as of April 30, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.43.)

10.15

Vectren Corporation At Risk Compensation Plan specimen Restricted Stock Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99-1.)

10.16

Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99-2.)

10.17

Vectren Corporation specimen employment agreement dated February 1, 2005. (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99-1.)

Table of Contecnts

10.18

Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.)

10.19

Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective September 1, 2002. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.)

10.20

Gas Sales and Portfolio Administration Agreement between Vectren Energy Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.)

10.21

Agreement for the Supply of Coal to F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Sigcorp Fuels, Inc., dated December 17, 1997 and effective January 1, 1998. Portions of the document have been omitted pursuant to a request for confidential treatment in accordance with Exchange Act Rule 24b-2. . (Filed and designated in Form 10-K, for the year ended December 31, 2005, File No. 1-15467, as Exhibit 10-21.) Amendment 1, effective January 1, 2003, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated December 17, 1997. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.19.)

10.22

Coal Supply Agreement for Generating Stations at Yankeetown, Warrick County, Indiana, and West Franklin, Posey County, Indiana between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.20.) Amendment 1, effective January 1, 2004, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.21.)

10.23

Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke Utility, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)

10.24

Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Utility Holdings, Inc., and each of the purchasers named therein. (Filed and designated in Form 10-K, for the year ended December 31, 2005, File No. 1-15467, as Exhibit 10.24.)

12. Ratio of Earnings to Fixed Charges

The Company’s Ratio of Earnings to Fixed Charges is attached hereto as Exhibit 12.

21. Subsidiaries of the Company

The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.

23. Consents of Experts and Counsel

The consent of Deloitte & Touche LLP is attached hereto as Exhibit 23

31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002

Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1

Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as

Exhibit 31.2

32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32.1.

99. Additional Exhibits

99.1	Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000. (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)

99.2	Amended and Restated Code of By-Laws of Vectren Corporation as of October 29, 2003. (Filed and designated in Quarterly Report on Form 10-Q filed November 13, 2003, File No. 1-15467, as Exhibit 3.1.)

99.3	Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467, as Exhibit 4.)

Table of Contecnts

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VECTREN UTILITY HOLDINGS, INC.

Dated March 1, 2006 /s/ Niel C. Ellerbrook

Niel C. Ellerbrook,

Chairman, Chief Executive Officer, and Director

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated.

Signature	Title	Date

/s/ Niel C. Ellerbrook	Chairman, Chief Executive Officer, & Director (Principal Executive Officer)	March 1, 2006
Niel C. Ellerbrook
/s/ Jerome A. Benkert, Jr.	Executive Vice President,	March 1, 2006
Jerome A. Benkert, Jr.	Chief Financial Officer, & Director (Principal Financial Officer)
/s/ M. Susan Hardwick	Vice President & Controller	March 1, 2006
M. Susan Hardwick	(Principal Accounting Officer)
/s/ Ronald E. Christian	Director	March 1, 2006
Ronald E. Christian
/s/ William S. Doty	Director	March 1, 2006
William S. Doty