Exhibit 99.1

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2006

Contents

	Page Number
Audited Financial Statements
Independent Auditors’ Report	2
Balance Sheets	3-4
Statements of Income	5
Statements of Cash Flows	6
Statements of Common Shareholder’s Equity	7
Notes to Financial Statements	8
Results of Operations	24
Selected Operating Statistics	28

Additional Information

This annual reporting package should be read in conjunction with the annual reports of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of SIGECO, filed on report Form 10-K for the year ended December 31, 2006. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through Vectren’s website at www.vectren.com.

Frequently Used Terms

AFUDC: allowance for funds used during construction	MISO: Midwest Independent Transmission System Operator
APB: Accounting Principles Board	MMBTU: millions of British thermal units
EITF: Emerging Issues Task Force	MW: megawatts
FASB: Financial Accounting Standards Board	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FERC: Federal Energy Regulatory Commission	NOx: nitrogen oxide
IDEM: Indiana Department of Environmental Management	OUCC: Indiana Office of the Utility Consumer Counselor
IURC: Indiana Utility Regulatory Commission	SFAS: Statement of Financial Accounting Standards
MCF / MMCF / BCF: thousands / millions / billions of cubic feet	USEPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput:combined gas sales and gas transportation volumes

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors of Southern Indiana Gas & Electric Company:

We have audited the accompanying balance sheets of Southern Indiana Gas & Electric Company (the “Company”) as of December 31, 2006 and 2005, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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 financial statements present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 

DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2007

March 15, 2007 (as to Note 8)

2

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2006		2005
ASSETS
Utility Plant
Original cost	$	2,025,108	$	1,899,535
Less: Accumulated depreciation & amortization		817,959		798,727
Net utility plant		1,207,149		1,100,808
Current Assets
Cash & cash equivalents		1,063		1,123
Accounts receivable - less reserves of $1,425 &
$1,290 respectively		41,380		50,756
Receivables from other Vectren companies		37		374
Accrued unbilled revenues		24,441		40,725
Inventories		60,990		48,182
Recoverable fuel & natural gas costs		1,779		10,411
Prepayments & other current assets		15,056		18,393
Total current assets		144,746		169,964
Investments in unconsolidated affiliates		150		150
Other investments		6,969		6,768
Nonutility property - net		3,514		3,367
Goodwill - net		5,557		5,557
Regulatory assets		67,634		56,256
Other assets		5,159		912
TOTAL ASSETS	$	1,440,878	$	1,343,782

The accompanying notes are an integral part of these financial statements

3

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2006		2005
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	293,263	$	253,263
Retained earnings		279,699		272,240
Accumulated comprehensive income		851		4,050
Total common shareholder's equity		573,813		529,553
Long-term debt payable to third parties - net of  current maturities &
debt subject to tender		226,271		226,144
Long-term debt payable to Utility Holdings		223,182		148,465
Total long-term debt, net		449,453		374,609
Commitments & Contingencies (Notes 3, 6, 7 & 8)
Current Liabilities
Accounts payable		47,741		34,489
Accounts payable to affiliated companies		11,806		21,780
Payables to other Vectren companies		14,205		7,467
Accrued liabilities		30,481		40,755
Short-term borrowings payable to Utility Holdings		51,303		93,343
Total current liabilities		155,536		197,834
Deferred Income Taxes & Other Liabilities
Deferred income taxes		143,285		133,758
Regulatory liabilities		59,117		55,380
Deferred credits & other liabilities		59,674		52,648
Total deferred income taxes & other liabilities		262,076		241,786
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,440,878	$	1,343,782

The accompanying notes are an integral part of these financial statements

4

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2006		2005
OPERATING REVENUES
Electric utility	$	422,159	$	421,362
Gas utility		132,615		132,618
Total operating revenues		554,774		553,980
COST OF OPERATING REVENUES
Cost of fuel & purchased power		151,500		144,007
Cost of gas sold		92,379		97,034
Total cost of operating revenues		243,879		241,041
TOTAL OPERATING MARGIN		310,895		312,939
OPERATING EXPENSES
Other operating		126,026		122,986
Depreciation & amortization		67,363		62,156
Taxes other than income taxes		15,275		14,696
Total operating expenses		208,664		199,838
OPERATING INCOME		102,231		113,101
Other income – net		3,630		2,381
Interest expense		28,595		27,911
INCOME BEFORE INCOME TAXES		77,266		87,571
Income taxes		29,295		35,783
NET INCOME		47,971		51,788
Preferred stock dividends		-		4
NET INCOME APPLICABLE TO COMMON SHAREHOLDER	$	47,971	$	51,784

The accompanying notes are an integral part of these financial statements

5

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47,971		$	51,788
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		67,363			62,156
Deferred income taxes & investment tax credits		3,232			11,834
Expense portion of pension & postretirement periodic benefit cost		1,913			1,814
Provision for uncollectible accounts		2,290			2,220
Other non-cash charges - net		3,804			496
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		23,707			(1,313	)
Inventories		(12,808	)		(6,949	)
Recoverable fuel & natural gas costs		8,632			(16,746	)
Prepayments & other current assets		(4,516	)		(5,637	)
Accounts payable, including to Vectren companies
& affiliated companies		3,528			16,939
Accrued liabilities		(6,955	)		4,057
Changes in noncurrent assets		(15,149	)		(7,595	)
Changes in noncurrent liabilities		448			(649	)
Net cash flows from operating activities		123,460			112,415
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt due to Utility Holdings		74,717			-
Additional capital contribution		40,000			125,000
Requirements for:
Dividends to parent		(40,512	)		(45,479	)
Retirement of long-term debt, including premiums paid		(34	)		(64	)
Redemption of preferred stock		-			(112	)
Dividends on preferred stock		-			(4	)
Net change in short-term borrowings, including from Utility Holdings		(42,040	)		(77,167	)
Net cash flows from financing activities		32,131			2,174
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for capital expenditures		(155,651	)		(118,732	)
Proceeds from other investments		-			3,489
Net cash flows from investing activities		(155,651	)		(115,243	)
Net decrease in cash & cash equivalents		(60	)		(654	)
Cash & cash equivalents at beginning of period		1,123			1,777
Cash & cash equivalents at end of period	$	1,063		$	1,123
Cash paid during the year for:
Income taxes	$	30,240		$	24,057
Interest		28,247			26,810

The accompanying notes are an integral part of these financial statements

6

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

						Accumulated
						Other
	Common		Retained			Comprehensive
	Stock		Earnings			Income (Loss)			Total
Balance at January 1, 2005	$	128,263	$	265,935		$	-		$	394,198
Comprehensive income
Net income				51,788						51,788
Cash flow hedge
Unrealized gains - net of $2,928 in tax							4,297			4,297
Reclassification to net income - net of $169 in tax							(247	)		(247	)
Total comprehensive income										55,838
Common stock:
Additional capital contribution		125,000								125,000
Dividends to parent				(45,479	)					(45,479	)
Preferred stock dividends				(4	)					(4	)
Balance at December 31, 2005	$	253,263	$	272,240		$	4,050		$	529,553
Comprehensive income
Net income				47,971						47,971
Cash flow hedge
Unrealized losses - net of $1,479 in tax							(2,171	)		(2,171	)
Reclassification to net income - net of $701 in tax							(1,028	)		(1,028	)
Total comprehensive income										44,772
Common stock:
Additional capital contribution		40,000								40,000
Dividends to parent				(40,512	)					(40,512	)
Balance at December 31, 2006	$	293,263	$	279,699		$	851		$	573,813

The accompanying notes are an integral part of these financial statements

7

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS

1.     Organization and Nature of Operations

Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides energy delivery services to approximately 141,000 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. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy holding company headquartered in Evansville, Indiana.

2.     Summary of Significant Accounting Policies

A.      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.

B.     Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2006		2005
Materials & supplies	$	25,097	$	26,504
Fuel (coal and oil) for electric generation		23,676		14,060
Gas in storage – at LIFO cost		12,155		7,474
Emission allowances		62		144
Total inventories	$	60,990	$	48,182

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, 2006, and 2005, by approximately $49 million and $70 million, respectively. All other inventories are carried at average cost.

C.     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 and For the Year Ended December 31,
(In thousands)	2006					2005
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	1,685,444		3.7	%	$	1,611,419		3.7	%
Gas utility plant		194,213		3.0	%		183,901		3.0	%
Common utility plant		45,216		2.6	%		44,200		2.6	%
Construction work in progress		100,235		-			60,015		-
Total original cost	$	2,025,108				$	1,899,535

8

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 income (expense) - net in the 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 thousands)	2006		2005
AFUDC – borrowed funds	$	1,789	$	1,384
AFUDC – equity funds		1,546		160
Total AFUDC capitalized	$	3,335	$	1,544

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 and Regulatory liabilities for the cost of removal. 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 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2006 is $63.2 million with accumulated depreciation totaling $43.5 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 Statements of Income.

D.     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). 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 that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that 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.

E.     Goodwill

Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 uses impairment-only approach to account for the effect of goodwill on the operating results.

Goodwill is tested for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. The impairment review consists 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, 2006, no goodwill impairment has been recorded. The Company’s goodwill is included in the Gas Utility Services operating segment.

F.     Asset Retirement Obligations

SFAS No. 143 requires entities to record the fair value of a liability for a legal 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.

Asset retirement obligations total $8.7 million at December 31, 2006 and $8.2 million at December 31, 2005, and are included in Other Liabilities and deferred credits. During 2006, the Company recorded accretion of $0.5 million. In 2005, the Company recorded accretion of less than $0.1 million and recorded additional liabilities of $6.9 million, related to the adoption of FASB Interpretation No. 47.

9

G.     Regulation

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC. The Company’s accounting policies give recognition to the rate-making and accounting practices of this agency 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 assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. 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 ratemaking process. The Company assesses the recoverability of costs recognized as regulatory assets and liabilities 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 assets consist of the following:

	At December 31,
(In thousands)	2006		2005
Amounts currently recovered through base rates:
Unamortized debt issue costs	$	5,375	$	4,826
Premiums paid to reacquire debt		4,837		5,275
Demand side management programs & other		1,776		2,401
		11,988		12,502
Amounts deferred for future recovery:
Demand side management programs		27,708		26,702
MISO-related costs		17,072		9,443
Other		2,970		2,955
		47,750		39,100
Future amounts recoverable from ratepayers:
Income taxes		5,124		3,295
Asset retirement obligations & other		1,824		1,695
		6,948		4,990
Amounts currently recovered through authorized tracking mechanisms		948		(336	)
Total regulatory assets	$	67,634	$	56,256

Of the $12.0 million currently being recovered through base rates, approximately $1.5 million is earning a return with a weighted average recovery period of 14.4 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory liabilities consist of the following:

	At December 31,
(In thousands)	2006		2005
Cost of removal	$	53,572	$	49,681
Asset retirement obligations		2,459		2,542
MISO-related costs		3,086		3,157
Total regulatory liabilities	$	59,117	$	55,380

10

Cost of Removal

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its related interpretations (SFAS 143).

Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The regulatory liability above represents a timing difference between cost recognition described in SFAS 143, and cost recognition established in regulatory proceedings for these obligations.

Refundable or Recoverable Gas Costs and Cost of Fuel & 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.

H.    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 Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income follows:

	2005								2006
	Beginning		Changes			End			Changes			End
	of Year		During			of Year			During			of Year
(In millions)	Balance		Year			Balance			Year			Balance
Cash flow hedges	$	-	$	6,809		$	6,809		$	(5,379	)	$	1,430
Deferred income taxes		-		(2,759	)		(2,759	)		2,180			(579	)
Accumulated other comprehensive income	$	-	$	4,050		$	4,050		$	(3,199	)	$	851

I.        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.

J.Utility Receipts Taxes

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. Utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.

K.    Earnings Per Share

Earnings per share is not presented as SIGECO’s common stock is wholly owned by Vectren Utility Holdings, Inc.

L.     Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 9).

11

M.      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.

3.   Transactions with Other Vectren Companies

Support Services and Purchases

Vectren provides corporate and general and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are based on cost. SIGECO received corporate allocations totaling $46.4 million and $47.7 million for the years ended December 31, 2006, and 2005, respectively.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases much of its fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2006, and 2005, totaled $116.8 million and $96.4 million, respectively. Amounts charged by Vectren Fuels, Inc. are established by supply agreements with the Company that have been reviewed by the OUCC and filed with the IURC.

Effective July 1, 2006, Vectren purchased the remaining 50% ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary of Vectren. Prior to the transaction, Miller was 50% owned by Vectren and was accounted for by Vectren using the equity method of accounting. Miller performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include SIGECO. Fees paid by SIGECO totaled $3.1 million in 2006 and $0.2 million in 2005. Amounts owed to Miller at December 31, 2006 are included in Payables to other Vectren companies and at December 31, 2005 are included in Accounts payable to affiliated companies.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158), which it adopted on December 31, 2006. 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 ending 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, 2006 and 2005, periodic pension costs totaling $2.3 million and $2.1 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2006 and 2005, other periodic postretirement benefit costs totaling $0.4 million in both years, was directly charged by Vectren to the Company. As of December 31, 2006 and 2005, $25.8 million and $28.0 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks. See Note 5 regarding long-term and short-term intercompany borrowing arrangements.

12

Share-Based Incentive Plans

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that required compensation costs related to all share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost is measured based on the grant-date fair value of the equity or liability instruments issued. Compensation cost is recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaced SFAS 123 and superseded APB 25. The Company adopted SFAS 123R using the modified prospective method on January 1, 2006. The adoption of this standard, and subsequent interpretations of the standard, did not have a material effect on the Company’s operating results or financial condition. SIGECO does not have share-based compensation plans separate from Vectren.

Guarantees of Parent Company Debt

Vectren’s three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $270.1 million is outstanding at December 31, 2006, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2006. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

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

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

	Year Ended December 31,
	2006			2005
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		4.1			5.3
Amortization of investment tax credit		(1.5	)		(1.7	)
All other - net		0.3			2.3
Effective tax rate		37.9	%		40.9	%

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 thousands)	2006			2005
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	132,978		$	129,645
Regulatory assets recoverable through future rates		11,589			9,571
Demand side management		8,383			7,687
Other comprehensive income		579			2,759
Employee benefit obligations		(13,149	)		(11,747	)
Regulatory liabilities to be settled through future rates		(6,465	)		(6,276	)
Other – net		9,370			2,119
Net noncurrent deferred tax liability		143,285			133,758
Current deferred tax liability:
Deferred fuel costs - net		1,293			5,693
Other – net		(1,081	)		-
Net deferred tax liability	$	143,497		$	139,451

13

At December 31, 2006 and 2005, investment tax credits totaling $8.1 million and $9.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

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

	Year Ended December 31,
(In thousands)	2006			2005
Current:
Federal	$	21,757		$	18,051
State		4,306			5,898
Total current taxes		26,063			23,949
Deferred:
Federal		2,550			10,308
State		1,846			3,015
Total deferred taxes		4,396			13,323
Amortization of investment tax credits		(1,164	)		(1,489	)
Total income tax expense	$	29,295		$	35,783

4.     Transactions with Vectren Affiliates

ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to SIGECO, other Vectren companies, Citizens Gas and a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage, for the years ended December 31, 2006 and 2005, totaled $107.4 million and $99.7 million, respectively. Amounts owed to ProLiance at December 31, 2006 and 2005, for those purchases were $11.8 million and $21.1 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

SIGECO purchases all of its natural gas through ProLiance. As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreement with the Company was approved and extended through March 31, 2007. Regulatory approval was received on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company through March 2011.

Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that performed facilities locating and meter reading services to the Company. For the years ended December 31, 2006, and 2005, fees for these services paid by the Company to Vectren were not significant. Amounts charged by these affiliates are market based. Amounts owed to affiliated companies other than ProLiance totaled zero and approximately $0.7 million at December 31, 2006, and 2005, respectively.

14

5.     Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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

	At December 31,
(In thousands)	2006			2005
Senior Unsecured Notes Payable to Utility Holdings:
2011, 6.625%	$	86,584		$	86,584
2018, 5.75%		61,881			61,881
2015, 5.45%		49,432			-
2035, 6.10%		25,285			-
Total long-term debt payable to Utility Holdings	$	223,182		$	148,465
First Mortgage Bonds Payable to Third Parties:
2016, 1986 Series, 8.875%	$	13,000		$	13,000
2020, 1998 Pollution Control Series B, 4.50%, tax exempt		4,640			4,640
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt		22,500			22,500
2029, 1999 Senior Notes, 6.72%		80,000			80,000
2030, 1998 Pollution Control Series B, 5.00%, tax exempt		22,000			22,000
2015, 1985 Pollution Control Series A, current adjustable rate 4.06%, tax exempt,
auction rate mode, 2006 weighted average: 3.53%		9,775			9,775
2023, 1993 Environmental Improvement Series B, current adjustable rate 4.11%,
tax exempt, auction rate mode, 2006 weighted average: 3.74%		22,550			22,550
2025, 1998 Pollution Control Series A, current adjustable rate 4.11%, tax exempt,
auction rate mode, 2006 weighted average: 3.08%		31,500			31,500
2030, 1998 Pollution Control Series C, current adjustable rate 4.11%, tax exempt,
auction rate mode, 2006 weighted average: 3.20%		22,200			22,200
Total first mortgage bonds payable to third parties		228,165			228,165
Unamortized debt premium, discount & other - net		(1,894	)		(2,021	)
Long-term debt payable to third parties - net	$	226,271		$	226,144

Issuances payable to Utility Holdings

In March 2006, the Company issued two notes payable to Utility Holdings, one for $49.4 million (2015 Notes) and another for $25.3 million (2035 Notes).

The terms of these notes are identical to the terms of the notes issued by Utility Holdings in October 2005 and October 2006. The 2015 Notes and 2035 Notes have 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.

Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is one percent 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 2007 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2007 is excluded from Current liabilities in the Balance Sheets. At December 31, 2006, $739.1 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.

15

There are no maturities and/or sinking fund requirements on long-term debt during the five years following 2006, except as described above.

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. Debt which may be put to the Company during the years following 2006 (in millions) is zero in 2007 and 2008, $80.0 in 2009, zero in 2010, 2011 and thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

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, 2006, the Company was in compliance with all financial covenants.

Short-Term Borrowings

SIGECO mainly relies on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs. Borrowings, including third party borrowings, outstanding at December 31, 2006 and 2005, were $51.3 million and $93.3 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($245 million at December 31, 2006) and is subject to the same terms and conditions as Utility Holdings’ commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds. Additionally, at December 31, 2006, the Company has available approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements. See the table below for interest rates and outstanding balances:

	Year ended December 31,
	2006			2005
Weighted average total outstanding during
the year payable to Utility Holdings (in thousands)	$	39,386		$	146,467
Weighted average total outstanding during
the year payable to third parties (in thousands)	$	593		$	423
Weighted average interest rates during the year:
Utility Holdings		4.97	%		3.26	%
Bank loans		5.81	%		4.01	%

6.     Commitments & Contingencies

Commitments

Firm purchase commitment for utility and non-utility plant total $56 million in 2007, $108 million in 2008, $115 million in 2009, $70 million in 2010 and $28 million in 2011.

Legal Proceedings

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 7 regarding environmental matters.

7.     Environmental Matters

Clean Air Act

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.

16

In February 2006, the IURC approved a multi-emission compliance plan filed by the Company. 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 up to $110 million in capital investments through a rider mechanism which is updated every six months for actual costs incurred. The Company will also recover through a rider its operating expenses, including depreciation, once the equipment is placed into service. 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. As of December 31, 2006, the Company has made capital investments of approximately $62.2 million related to this environmental requirement.

NOx SIP Call Matter

The Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps included installation 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 issued orders that approved:

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

·   the Company’s investment of $258 million in capital costs;

·   a mechanism whereby, prior to an electric base rate case, the Company recovers 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 now that facilities are placed into service.

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.

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.

17

The Company does not believe that implementation of the settlement will have a material effect on its results of operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003. The Company ceased operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which is included in the $110 million IURC order discussed above, went into service January 1, 2007.

Manufactured Gas Plants

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not 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 imminent and/or substantial risk to human health or the environment.

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. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded costs that it reasonably expects to incur totaling approximately $7.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers in an aggregate amount approximating the costs it expects to incur.

Environmental matters related to SIGECO’s manufactured gas plants have had no material impact on results of operations or financial condition since costs recorded to date approximate PRP and insurance settlement recoveries. While the Company has recorded all costs which they presently expect 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.

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.

Global Climate Change

Global climate change remains a policy issue that is regularly considered for government regulation. If legislation requiring reductions in greenhouses gases is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel plants.

8.     Rate & Regulatory Matters

Lost Margin Recovery/Conservation Filings

In 2005, the Company filed conservation programs and conservation adjustment trackers designed to help customers conserve energy and reduce their annual gas bills. The programs would allow the Company to recover costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism. This mechanism is designed to allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer revenues established in each utility’s last general rate case.

18

In December 2006, the IURC approved a settlement agreement between the Company and the OUCC that provides for a 5-year energy efficiency program to be implemented. The order allows the Company to recover the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism that would provide for recovery of 85% of the difference between revenues actually collected by the Company and the revenues approved in the Company’s most recent rate case. The order will be implemented after the Company’s next general rate case (see below.) While most expenses associated with these programs are recoverable, in the first program year, the Company is required to fund $0.3 million in program costs without recovery.

Electric and Gas Base Rate Filings

On September 1, 2006, SIGECO filed petitions with the IURC to adjust its electric and gas base rates. 

On March 15, 2007, the Company announced that it had reached a settlement agreement with the OUCC and other interveners regarding the gas rate case.  The increase in rates includes a base rate increase of $5.3 million and $2.6 million of costs which will be removed from base rates and be recovered through existing tracking mechanisms.  The settlement also provides for an allowed return on equity (ROE) of 10.15%, with an overall rate of return of 7.20% on rate base of $121.7 million.  

Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.  The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates.  To qualify for this treatment, the annual expenditures are limited to $3.0 million and the treatment cannot extend beyond three years per project.

If the settlement is approved, the Company will have in place for its South gas territory; weather normalization, a conservation and decoupling tariff, tracking of gas cost expense related to bad debts and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity expense.  The return on equity agreed to in the case of 10.15% recognizes these various regulatory mechanisms.  A hearing on the settlement before the IURC will be held March 23, 2007. 

The electric petition requests an increase of $90.4 million in base rates ($76.7 million, net of certain revenue credits proposed) to recover the nearly $120 million additional investment in electric utility infrastructure since its last base rate increase in 1995, which is not currently included in rates charged to customers.  The increase in rates also is required to support system growth, maintenance, reliability and recovery of costs deferred under previous IURC orders.  Initial public hearings have been completed. On February 27, 2007, the OUCC filed testimony proposing an increase of $51.4 million.  Final hearings in the electric rate case will occur in April 2007.

Integrated Gasification Combined Cycle (IGCC) Certificate of Public Convenience and Necessity

On September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana, Inc. filed with the IURC a joint petition for a Certificate of Public Convenience and Necessity (CPCN) for the construction of new electric capacity. Specifically, Vectren requested the IURC approve its construction and ownership of up to 20% of an IGCC project. Vectren's CPCN filing also seeks timely recovery of its 20% portion of the project's construction costs as well as operation and maintenance costs and additional incentives available for the construction of clean coal technology. Initial studies of plant design have already begun, and if the project moves forward as currently designed, plant construction is expected to begin in 2007 and continue through 2011.

Weather Normalization

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

19

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 $15,000 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 electric territory do not include weather normalization-type clauses.

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, which was filed in 2006.

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.

On June 1, 2005, Vectren, 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 Vectren’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, which was filed in 2006. During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the Company is following those guidelines.

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.

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.

9.     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 three primary areas: asset optimization, SO₂ emission allowance risk management, and natural gas procurement.

20

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. These optimization strategies involve the sale of excess generation into the MISO day ahead and real-time markets. As part of these strategies, the Company may execute energy 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 Balance Sheets. Asset optimization contracts that are derivatives are recorded at market value.

At December 31, 2006, no asset optimization contracts remained in Prepayments & other current assets. At December 31, 2005, asset optimization contracts recorded at market value approximated $1.3 million of Prepayments & other current assets.

The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts that are derivatives are recorded in Electric utility revenues. Net revenues from asset optimization activities totaled $29.8 million in 2006 and $38.0 million in 2005.

SO₂ Emission Allowance Risk Management

The Company’s wholesale power marketing operations are exposed to price risk associated with SO₂ emission allowances. Recently, the price for emission allowances has become more volatile. To hedge this risk, the Company executed call options in 2004 and 2005 to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2006, a deferred gain of approximately $1.4 million remains in Accumulated other comprehensive income which will be recognized in earnings as emission allowances are utilized. Hedge ineffectiveness totaled $0.2 million of expense in 2006 and $0.8 million of expense in 2005. No SO₂ emission allowance hedges are outstanding as of December 31, 2006.

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 regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although SIGECO’s 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, 2006 and 2005, the market values of these contracts were not significant.

Fair Value of Other Financial Instruments

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

	At December 31,
	2006				2005
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long term debt	$	228,165	$	238,674	$	228,165	$	241,695
Long term debt payable to Utility Holdings		223,182		224,466		148,465		156,006
Short-term borrowings from Utility Holdings		51,303		51,303		93,343		93,343

21

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.

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. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

10.   Additional Operational & Balance Sheet Information

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

	Year ended December 31,
(In thousands)	2006			2005
AFUDC (See Note 2C)	$	3,335		$	1,544
Interest & other investment income		209			862
Donations		(107	)		(204	)
Other, net		193			179
Total other - net	$	3,630		$	2,381

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

	At December 31,
(In thousands)	2006		2005
Prepaid & deferred taxes	$	6,126	$	1,382
Wholesale emission allowances		4,228		7,136
Fair market value of derivative instruments		-		1,290
Other		4,702		8,585
Total prepayments & other current assets	$	15,056	$	18,393

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2006		2005
Accrued and deferred taxes	$	8,705	$	14,193
Customers advances & deposits		8,556		7,895
Accrued interest		4,986		5,680
Refundable emission credit costs		6,125		4,475
Accrued salaries & other		2,109		8,512
Total accrued liabilities	$	30,481	$	40,755

11.   Segment Reporting

The Company has two operating segments: (1) Gas Utility Services and (2) Electric Utility Services as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131). Gas Utility Services provides natural gas distribution and transportation services in southwestern Indiana, including counties surrounding Evansville. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company’s power generating and marketing operations. For its operations, the Company uses net income as a measure of profitability. The Company cross manages its 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. The Company makes decisions on finance and dividends at the corporate level. Information related to the Company’s business segments is summarized below:

22

	Year Ended December 31,
(In thousands)	2006		2005
Revenues
Electric Utility Services	$	422,159	$	421,362
Gas Utility Services		132,615		132,618
Total operating revenues	$	554,774	$	553,980
Profitability Measure
Net Income
Electric Utility Services	$	41,564	$	50,442
Gas Utility Services		6,407		1,346
Total net income	$	47,971	$	51,788

	Year Ended December 31,
(In thousands)	2006		2005
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	61,813	$	56,868
Gas Utility Services		5,550		5,288
Total depreciation & amortization	$	67,363	$	62,156
Income Taxes
Electric Utility Services	$	25,263	$	33,539
Gas Utility Services		4,032		1,974
Unallocated taxes		-		270
Total income taxes	$	29,295	$	35,783
Capital Expenditures
Electric Utility Services	$	146,080	$	100,009
Gas Utility Services		5,987		9,664
Non-cash costs & changes in accruals		3,584		9,059
Total capital expenditures	$	155,651	$	118,732
		At December 31,
(In thousands)		2006		2005
Assets
Electric Utility Services	$	1,277,639	$	1,176,027
Gas Utility Services		163,239		167,755
Total assets	$	1,440,878	$	1,343,782

12.   Adoption of Other Accounting Standards

SFAS No. 159

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159). SFAS 159 permits entities to choose to measure certain financial assets and financial liabilities at fair value. Fair value measurement would be applied to eligible items at specified election dates with unrealized gains and losses on such items reported in earnings at each subsequent reporting date. The fair value option may be applied instrument by instrument with few exceptions, must be applied to entire instruments and not to portions of thereof, and is irrevocable. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted when certain conditions are met. Application of this standard is prospective, unless it is adopted early, and then retrospective application is allowed. The Company is currently assessing the impact of this standard and does not expect to adopt it early.

23

SFAS No. 158

On December 31, 2006, and after calculating the balance sheet impact of Vectren’s retirement plans using the accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158).  SFAS 158 required Vectren to recognize the funded status of its pension plans and postretirement plans. SFAS 158 defines the funded status of a defined benefit plan as its assets less its projected benefit obligation, which includes projected salary increases, and defines the funded status of a postretirement plan as its assets less its accumulated postretirement benefit obligation. The impacts of adopting this standard were recorded at Vectren and are not reflected at the SIGECO level.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years with early adoption encouraged.The Company is currently assessing the impact this statement will have on its financial statements and results of operations, and does not expect to adopt it early.

FIN 48

In June 2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this standard is not expected to have a material impact on operating results or financial condition.

*******************************************************************************************************************************************

The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and Utility Holdings.

Executive Summary of Results of Operations

SIGECO 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.

For the year ended December 31, 2006, earnings were $48.0 million as compared to $51.8 million in 2005. The decline in 2006 results compared to 2005 is primarily due to wholesale power marketing margins $6.2 million, or $3.7 million after tax, lower than the prior year and weather. Results in 2006 reflect the impact of a constructive regulatory environment. The Company received orders in the fourth quarter of 2006 that authorize lost margin recovery related to the Company’s natural gas customers following the next general rate case, and an order in the fourth quarter of 2005 for a normal temperature adjustment mechanism with respect to the Company’s natural gas customers. The Company also utilizes rider mechanisms to recover capital expenditures associated with compliance with Clean Air Act and Clean Air Mercury requirements, among other costs. In addition, the Company has implemented base rate increases since 2004 and currently has two cases before the IURC where orders are expected in 2007. The revenue increases, including the proposed increases in the two pending cases, are required to offset increased operating and financing costs, the effect on usage from higher commodity prices, and the impact of recent weather unfavorable compared to 30-year normal temperatures.

24

In addition to wholesale power marketing and weather, the decrease in earnings in 2006 was also impacted by higher operating costs, due primarily to a planned outage, and continued declines in customer usage. These declines were mitigated somewhat by volatility in the pricing of unaccounted for gas and a lower effective tax rate.

Management estimates the after tax effect of weather compared to normal was unfavorable $1.3 million in 2006 and favorable $.3 million in 2005. The 2006 weather effect contains the full impact of a normal temperature adjustment (NTA) mechanism implemented in the Company’s natural gas service territories in the fourth quarter of 2005.

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 the Cost of fuel and purchased power. 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 is impacted by weather patterns in the Company’s service territories. The weather impact in the Company’s Indiana gas utility service territories is mitigated 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 or delivered. 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.

Electric Utility margin (Electric utility revenues less Cost of fuel and purchased power)

Electric Utility margin by revenue type follows:

	Year Ended December 31,
(In millions)	2006		2005
Electric utility revenues	$	422,159	$	421,362
Cost of fuel & purchased power		151,500		144,007
Total electric utility margin	$	270,659	$	277,355
Margin attributed to:
Residential & commercial customers	$	162,877	$	170,764
Industrial customers		70,232		66,885
Municipal & other customers		23,921		19,871
Subtotal: Retail & firm wholesale	$	257,030	$	257,520
Asset optimization	$	13,629	$	19,835
Electric volumes sold in MWh attributed to:
Residential & commercial customers		2,789,680		2,933,189
Industrial customers		2,570,373		2,575,925
Municipal & other customers		644,486		689,900
Total retail & firm wholesale volumes sold		6,004,539		6,199,014

25

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margin was $257.0 million for the year ended December 31, 2006 and was generally flat compared to 2005. The recovery of pollution control related investments and associated operating expenses and related depreciation increased margins $2.6 million year over year. Higher demand charges and other items increased industrial customer margin approximately $3.2 million year over year. These increases were offset by decreased residential and commercial usage. The decreased usage was due primarily to mild weather during the peak cooling season. For 2006 compared to 2005, the estimated decrease in margin due to unfavorable weather was $4.6 million ($4.0 million for below normal cooling weather and $0.6 million for heating weather). During 2006, cooling degree days were 5% below normal. In 2005, cooling degree days were 9% above normal.

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. These optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets. As part of these strategies, the Company may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery.

Following is a reconciliation of asset optimization activity:

	Year Ended December 31,
(In millions)	2006			2005
Off-system sales	$	14,227		$	15,309
Transmission system sales		3,465			4,507
Other		(4,063	)		19
Total asset optimization	$	13,629		$	19,835

For the year ended December 31, 2006, net asset optimization margins were $13.6 million, which represents a decrease of $6.2 million compared to 2005. The decrease is due to the effect lower wholesale prices have had on the Company’s optimization portfolio and lower volumes sold off system.

In 2005, the Company experienced increased availability of the generating units. The availability of excess capacity was reduced in 2006 by scheduled outages of owned generation related to the installation of environmental compliance equipment. Off-system sales totaled 889.4 GWh in 2006, compared to 1,208.1 GWh in 2005.

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)	2006		2005
Gas utility revenues	$	132,615	$	132,618
Cost of gas sold		92,379		97,034
Total gas utility margin	$	40,236	$	35,584
Margin attributed to:
Residential & commercial customers	$	30,394	$	29,866
Industrial customers		5,203		4,899
Other customers		4,639		819
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		10,207		11,312
Industrial customers		18,288		18,645
Total sold & transported volumes		28,495		29,957

Gas utility margins were $40.2 million for the year ended December 31, 2006, an increase of $4.6 million compared to 2005. The effects of the normal temperature adjustment mechanism (NTA) implemented in 2005 in the Company’s natural gas service territory and volatility in the pricing of unaccounted for gas more than offset the effects of warm weather and lower usage.

26

For the year ended December 31, 2006, compared to 2005, management estimates that weather 12 percent warmer than normal and 6 percent warmer than prior year would have decreased margins $2.8 million compared to the prior year, had the NTA not been in effect. Weather, net of the NTA, resulted in an approximate $0.6 million year over year increase in gas utility margin. Further, for the year ended December 31, 2006, margin associated with tracked expenses and revenue taxes increased $0.5 million. The average cost per dekatherm of gas purchased for the year ended December 31, 2006, was $9.10 compared to $8.62 in 2005.

Operating Expenses

Other Operating

Other operating expenses increased $3.0 million for the year ended December 31, 2006, compared to 2005, due primarily to a planned outage and higher chemical costs.  These increased costs were partially offset by decreased legal costs.

Depreciation & Amortization

For the year ended December 31, 2006, depreciation expense increased $5.2 million compared to 2005. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equipment additions. Depreciation expense associated with environmental compliance equipment, which is recovered in Electric Utility margins, totaled $14.4 million in 2006 compared to $12.1 million in 2005.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $0.6 million in 2006 compared to 2005. The increase is primarily attributable to increased collections of utility receipts taxes, due to higher revenues and higher real estate taxes.

Other Income

Total other income - net increased $1.2 million in 2006 compared to 2005 due primarily to higher levels of AFUDC related to capital expenditures for environmental compliance equipment.

Interest Expense

Interest expense increased $0.7 million in 2006 compared to 2005 primarily due to rising interest rates.

Income Taxes

For the year ended December 31, 2006, income taxes decreased $6.5 million compared to 2005. Income taxes in 2006 include adjustments to reflect income taxes reported on final state and federal income tax returns.

Equity Infusion

In both March and October 2006, the Company’s parent, Utility Holdings, increased its ownership equity in SIGECO by $20 million in each month. In September 2005, Utility Holdings increased its ownership equity in SIGECO by $125 million. SIGECO used the additional capital to reduce its intercompany short-term borrowings.

27

SELECTED ELECTRIC OPERATING STATISTICS:

SIGECO ELECTRIC
SELECTED ELECTRIC UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2006			2005
OPERATING REVENUES (In thousands):
Residential	$	130,589		$	135,322
Commercial		96,099			95,772
Industrial		128,171			119,462
Misc. Revenue		11,477			7,055
Total System		366,336			357,611
Municipals		26,069			25,786
Other Wholesale		29,754			37,965
	$	422,159		$	421,362
MARGIN (In thousands):
Residential	$	96,750		$	102,978
Commercial		66,127			67,786
Industrial		70,232			66,885
Misc. Revenue		11,144			6,788
Total System		244,253			244,437
Municipals		12,777			13,083
Other Wholesale		13,629			19,835
	$	270,659		$	277,355
ELECTRIC SALES (In MWh):
Residential		1,468,786			1,564,940
Commercial		1,320,894			1,368,249
Industrial		2,570,373			2,575,925
Misc. Sales		20,139			19,563
Total System		5,380,192			5,528,677
Municipals		624,347			670,337
Other Wholesale		898,276			3,049,228
		6,902,815			9,248,242
YEAR END CUSTOMERS:
Residential		121,952			120,679
Commercial		18,879			18,677
Industrial		109			107
All others		47			51
		140,987			139,514
WEATHER AS A % OF NORMAL:
Cooling Degree Days		95	%		109	%

28

SELECTED GAS OPERATING STATISTICS:

SIGECO GAS
SELECTED GAS UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2006			2005
OPERATING REVENUES (In thousands):
Residential	$	83,382		$	84,677
Commercial		40,162			42,989
Industrial		5,202			4,899
Misc. Revenue		3,869			53
	$	132,615		$	132,618
MARGIN (In thousands):
Residential	$	22,525		$	22,274
Commercial		7,869			7,592
Industrial		5,203			4,899
Misc. Revenue		4,639			819
	$	40,236		$	35,584
GAS SOLD & TRANSPORTED (In MDth):
Residential		6,491			7,275
Commercial		3,716			4,037
Industrial		18,288			18,645
		28,495			29,957
YEAR END CUSTOMERS:
Residential		101,565			101,641
Commercial		10,350			10,388
Industrial		82			77
		111,997			112,106
WEATHER AS A % OF NORMAL:
Heating Degree Days		88	%		94	%

29