8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, DC   20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) March 14, 2008

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)

Commission File No.	Registrant, State of Incorporation, Address, and Telephone Number	I.R.S Employer Identification No.
1-15467	Vectren Corporation	35-2086905
	(An Indiana Corporation)
	One Vectren Square
	Evansville, Indiana 47708
	(812) 491-4000
1-16739	Vectren Utility Holdings, Inc.	35-2104850
	(An Indiana Corporation)
	One Vectren Square
	Evansville, Indiana 47708
	(812) 491-4000

Former name or address, if changed since last report: N/A

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01.  Regulation FD Disclosure

Included herein are the audited financial statements of Southern Indiana Gas & Electric Company (SIGECO), a wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings).  Utility Holdings is a wholly owned subsidiary of Vectren Corporation (the Company).

The SIGECO financial statements include footnotes thereto, abbreviated analysis of results of operations, segment information and operating statistics.  The financial statements of SIGECO are included as Exhibit 99.1 to this Current Report on Form 8-K.  These financial statements are not intended to comply with Regulation S-X or Regulation S-K as SIGECO is not a registrant.

In accordance with SEC Release No. 33-8176, the information contained in the audited financial statements shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is hereby furnishing cautionary statements identifying important factors that could cause actual results of the Company and its subsidiaries, including Vectren Utility Holdings, Inc and Southern Indiana Gas and Electric Company, to differ materially from those projected in forward-looking statements of the Company and its subsidiaries made by, or on behalf of, the Company and its subsidiaries. These cautionary statements are attached as Exhibit 99.2.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	VECTREN CORPORATION VECTREN UTILITY HOLDINGS, INC.
March 14, 2008
		By:  /s/ M. Susan Hardwick
		M. Susan Hardwick
		Vice President, Controller and Assistant Treasurer

INDEX TO EXHIBITS

The following Exhibits are furnished as part of this Report to the extent described in Item 7.01:

Exhibit Number	Description
99.1	Financial statements of Southern Indiana Gas & Electric Company, Inc.
99.2	Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995

EX-99.1

                     Exhibit 99.1

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2007

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	25
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, 2007.  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 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, 2007 and 2006, 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, 2007 and 2006, 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 19, 2008

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FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2007		2006
ASSETS
Utility Plant
Original cost	$	2,153,031	$	2,025,108
Less:  Accumulated depreciation & amortization		865,947		817,959
Net utility plant		1,287,084		1,207,149
Current Assets
Cash & cash equivalents		1,969		1,063
Accounts receivable - less reserves of $1,509 &
$1,425 respectively		46,902		41,380
Receivables from other Vectren companies		31		37
Accrued unbilled revenues		32,560		24,441
Inventories		58,150		60,990
Recoverable fuel & natural gas costs		-		1,779
Prepayments & other current assets		14,388		15,056
Total current assets		154,000		144,746
Investments in unconsolidated affiliates		150		150
Other investments		9,455		6,969
Nonutility property - net		3,108		3,514
Goodwill - net		5,557		5,557
Regulatory assets		81,820		67,634
Other assets		4,817		5,159
TOTAL ASSETS	$	1,545,991	$	1,440,878

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2007		2006
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	293,263	$	293,263
Retained earnings		294,652		279,699
Accumulated comprehensive income		328		851
Total common shareholder's equity		588,243		573,813
Long-term debt payable to third parties		243,233		226,271
Long-term debt payable to Utility Holdings		223,182		223,182
Total long-term debt, net		466,415		449,453
Commitments & Contingencies (Notes 3, 6, 7 & 8)
Current Liabilities
Accounts payable		36,185		47,741
Accounts payable to affiliated companies		9,914		11,806
Payables to other Vectren companies		17,072		14,205
Refundable fuel & natural gas costs		5,339		-
Accrued liabilities		47,151		30,481
Short-term borrowings payable to Utility Holdings		118,039		51,303
Total current liabilities		233,700		155,536
Deferred Income Taxes & Other Liabilities
Deferred income taxes		136,496		143,285
Regulatory liabilities		60,778		59,117
Deferred credits & other liabilities		60,359		59,674
Total deferred income taxes & other liabilities		257,633		262,076
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,545,991	$	1,440,878

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2007		2006
OPERATING REVENUES
Electric utility	$	487,893	$	422,159
Gas utility		132,195		132,615
Total operating revenues		620,088		554,774
COST OF OPERATING REVENUES
Cost of fuel & purchased power		174,823		151,500
Cost of gas sold		88,964		92,379
Total cost of operating revenues		263,787		243,879
TOTAL OPERATING MARGIN		356,301		310,895
OPERATING EXPENSES
Other operating		137,130		126,026
Depreciation & amortization		71,729		67,363
Taxes other than income taxes		16,809		15,275
Total operating expenses		225,668		208,664
OPERATING INCOME		130,633		102,231
Other income – net		3,349		3,630
Interest expense		33,206		28,595
INCOME BEFORE INCOME TAXES		100,776		77,266
Income taxes		42,664		29,295
NET INCOME	$	58,112	$	47,971

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	58,112		$	47,971
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		71,729			67,363
Deferred income taxes & investment tax credits		3,268			3,232
Expense portion of pension & postretirement periodic benefit cost		1,829			1,913
Provision for uncollectible accounts		2,446			2,290
Other non-cash charges - net		5,742			3,804
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		(16,081	)		23,707
Inventories		2,840			(12,808	)
Recoverable fuel & natural gas costs		7,118			8,632
Prepayments & other current assets		(2,885	)		(4,516	)
Accounts payable, including to Vectren companies
& affiliated companies		(6,334	)		3,528
Accrued liabilities		(10,631	)		(6,955	)
Changes in noncurrent assets		(30	)		(15,149	)
Changes in noncurrent liabilities		(8,712	)		448
Net cash flows from operating activities		108,411			123,460
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt due to Utility Holdings		-			74,717
Long-term debt - net of issuance costs		16,265			-
Additional capital contribution		-			40,000
Requirements for:
Dividends to parent		(43,159	)		(40,512	)
Retirement of long-term debt, including premiums paid		(199	)		(34	)
Net change in short-term borrowings, including from Utility Holdings		66,736			(42,040	)
Net cash flows from financing activities		39,643			32,131
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		700			-
Requirements for:
Capital expenditures, excluding AFUDC equity		(147,043	)		(155,651	)
Other investments		(805	)		-
Net cash flows from investing activities		(147,148	)		(155,651	)
Net change in cash & cash equivalents		906			(60	)
Cash & cash equivalents at beginning of period		1,063			1,123
Cash & cash equivalents at end of period	$	1,969		$	1,063
Cash paid during the year for:
Income taxes	$	34,865		$	30,240
Interest		31,592			28,247

The accompanying notes are an integral part of these financial statements

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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, 2006	$	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
Comprehensive income
Net income				58,112						58,112
Cash flow hedge
Unrealized gain - net of $69 in tax							103			103
Reclassification to net income - net of $413 in tax							(626	)		(626	)
Total comprehensive income										57,589
Common stock:
Dividends to parent				(43,159	)					(43,159	)
Balance at December 31, 2007	$	293,263	$	294,652		$	328		$	588,243

The accompanying notes are an integral part of these financial statements

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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, SIGECO or Vectren South), an Indiana corporation, provides energy delivery services to over 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)	2007		2006
Materials & supplies	$	27,711	$	25,097
Fuel (coal and oil) for electric generation		22,026		23,676
Gas in storage – at LIFO cost		8,396		12,155
Other		17		62
Total inventories	$	58,150	$	60,990

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, 2007, and 2006, by approximately $47 million and $49 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)	2007					2006
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Electric utility plant	$	1,815,775		3.3	%	$	1,685,444		3.4	%
Gas utility plant		199,930		3.0	%		194,213		3.0	%
Common utility plant		45,527		2.8	%		45,216		3.0	%
Construction work in progress		91,799		-			100,235		-
Total original cost	$	2,153,031				$	2,025,108

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.  

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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)	2007		2006
AFUDC – borrowed funds	$	2,562	$	1,789
AFUDC – equity funds		427		1,546
Total AFUDC capitalized	$	2,989	$	3,335

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 owns 50 percent of the 300 MW Unit 4 at the Warrick Power Plant as tenants in common with Alcoa Generating Corporation (AGC), a subsidiary of ALCOA.  SIGECO's share of the cost of this unit at December 31, 2007 is $63.5 million with accumulated depreciation totaling $46.6 million.  The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $56.4 million at December 31, 2007.  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 and Intangible Assets

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
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, 2007, no goodwill impairment has been recorded.  The Company’s goodwill is included in the Gas Utility Services operating segment.

Intangible Assets
The Company has emission allowances relating to its wholesale power marketing operations totaling $2.6 million and $4.2 million at December 31, 2007 and 2006, respectively.  The value of the emission allowances are recognized as they are consumed or sold on the open market.

F.     Regulation

Retail public utility operations 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).

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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)	2007		2006
Amounts currently recovered through customer rates related to:
Demand side management programs	$	27,609	$	1,473
MISO-related costs		20,803		-
Unamortized debt issue costs		5,741		5,375
Premiums paid to reacquire debt		4,399		4,837
Authorized trackers		2,707		948
Other		4,366		303
		65,625		12,936
Amounts deferred for future recovery related to:
Demand side management programs		-		27,708
MISO-related costs		-		17,072
Other		12		2,970
		12		47,750
Future amounts recoverable from ratepayers related to:
Income taxes		5,422		5,124
Asset retirement obligations & other		10,761		1,824
		16,183		6,948
Total regulatory assets	$	81,820	$	67,634

Of the $65.6 million currently being recovered in rates charged to customers, approximately $27.6 million is earning a return with a weighted average recovery period of 6 years.  The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory Liabilities

At December 31, 2007 and 2006, the Company has approximately $60.8 million and $59.1 million, respectively, in regulatory liabilities.  Of these amounts, $55.9 million and $53.6 million relate to cost of removal obligations.  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).

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.

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G.     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).  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.  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.

ARO’s included in Deferred credits and other liabilities total $6.3 million and $8.7 million at December 31, 2007 and 2006, respectively.  At December 31, 2007, a $9.5 million ARO is included in Accrued liabilities.  During 2007, the Company recorded accretion of $0.5 million and increases in estimates of $6.6 million.  During 2006, the Company recorded accretion of $0.5 million with no changes in estimates.

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:

	2006									2007
	Beginning			Changes			End			Changes			End
	of Year			During			of Year			During			of Year
(In thousands)	Balance			Year			Balance			Year			Balance
Cash flow hedges	$	6,809		$	(5,379	)	$	1,430		$	(868	)	$	562
Deferred income taxes		(2,759	)		2,180			(579	)		345			(234	)
Accumulated other comprehensive income	$	4,050		$	(3,199	)	$	851		$	(523	)	$	328

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).

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.

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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 $53.1 million and $46.4 million for the years ended December 31, 2007, and 2006, respectively.

Vectren Fuels, Inc.

Vectren Fuels, Inc. (Fuels), 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, 2007, and 2006, totaled $115.9 million and $116.8 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.  Amounts owed to Fuels at December 31, 2007 and 2006 are included in Payables to other Vectren companies.

Miller Pipeline Corporation

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 $4.1 million in 2007 and $3.1 million in 2006.  Amounts owed to Miller at December 31, 2007 and 2006 are included in Payables to other Vectren 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, comprised of only service cost and interest on that service cost, by subsidiary is determined 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, 2007 and 2006, periodic pension costs totaling $2.2 million and $2.3 million, respectively, was directly charged by Vectren to the Company.  For the years ended December 31, 2007 and 2006, other periodic postretirement benefit costs totaling $0.3 million and $0.4 million, respectively, was directly charged by Vectren to the Company.  As of December 31, 2007 and 2006, $25.6 million and $25.8 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 Vectren’s centralized cash management program.  See Note 5 regarding long-term and short-term intercompany borrowing arrangements.

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.

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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 $386 million is outstanding at December 31, 2007, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2007.  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,
	2007			2006
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		5.8			4.1
Amortization of investment tax credit		(1.0	)		(1.5	)
Adjustments to federal income tax accruals		2.3			(1.1	)
All other - net		0.2			1.4
Effective tax rate		42.3	%		37.9	%

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)	2007			2006
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	133,459		$	132,978
Regulatory assets recoverable through future rates		10,892			11,589
Demand side management		-			8,383
Other comprehensive income		234			579
Employee benefit obligations		(11,955	)		(13,149	)
Regulatory liabilities to be settled through future rates		(5,470	)		(6,465	)
Other – net		9,336			9,370
Net noncurrent deferred tax liability		136,496			143,285
Current deferred tax assets, primarily demand side management
and other regulatory assets		8,476			212
Net deferred tax liability	$	144,972		$	143,497

At December 31, 2007 and 2006, investment tax credits totaling $7.0 million and $8.1 million, respectively, are included in Deferred credits and other liabilities.  These investment tax credits are amortized over the lives of the related investments.  SIGECO also has tax credit carryforwards at December 31, 2007 which are immaterial.

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

	Year Ended December 31,
(In thousands)	2007			2006
Current:
Federal	$	30,527		$	21,757
State		8,869			4,306
Total current taxes		39,396			26,063
Deferred:
Federal		3,990			2,550
State		330			1,846
Total deferred taxes		4,320			4,396
Amortization of investment tax credits		(1,052	)		(1,164	)
Total income tax expense	$	42,664		$	29,295

Accounting for Uncertainty in Income Taxes

On January 1, 2007, the Company adopted 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 adoption of FIN 48 did not have a material impact on the Company.  The liability for gross unrecognized tax benefits of $5.9 million upon adoption generally resulted from the reclassification of Deferred income taxes to Other liabilities.

Following is a reconciliation of the total amount of unrecognized tax benefits as of December 31, 2007:

(in thousands)
Unrecognized tax benefits at January 1, 2007	$	5,876
Gross Increases - tax positions in prior periods		133
Gross Decreases - tax positions in prior periods		(3,065	)
Unrecognized tax benefits at December 31, 2007	$	2,944

Of the change in unrecognized tax benefits during 2007 of $2.9 million, $0.5 million impacted the effective tax rate.  The amount of unrecognized tax benefits, which, if recognized, that would impact the effective tax rate as of December 31, 2007, was $0.1 million.  The remaining unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority.

The Company accrues interest and penalties associated with unrecognized tax benefits in Income taxes.  During the year ended December 31, 2007, the Company recognized expense related to interest and penalties totaling approximately $0.4 million.  The Company had approximately $0.4 million for the payment of interest and penalties accrued as of December 31, 2007.  Prior to the adoption of FIN 48, Vectren’s policy was not to push down interest and penalties to its subsidiaries.

The liability included in Other liabilities on the Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts, which are benefits, totaled $3.0 million at December 31, 2007.

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From time to time, the Company may consider changes to filed positions that could impact its unrecognized tax benefits.  However, it is not expected that such changes would have a significant impact on earnings and would only affect the timing of payments to taxing authorities.

SIGECO does not file federal or state income tax returns separate from those filed by its ultimate parent, Vectren Corporation.  Vectren and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states.  The Internal Revenue Service (IRS) has conducted examinations of the Company’s U.S. federal income tax returns for tax years through December 31, 2004.  The State of Indiana, the Company’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2002.  On February 15, 2008, Vectren was notified by the IRS of their intent to perform a limited scope examination of Vectren’s 2005 consolidated tax return. 

4.     Transactions with ProLiance Holdings, LLC

ProLiance Holdings, 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.  SIGECO purchases all of its natural gas through ProLiance and has regulatory approval from the IURC to continue to do so through March 2011.

Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2007 and 2006, totaled $95.1 million and $107.4 million, respectively.  Amounts owed to ProLiance at December 31, 2007 and 2006, for those purchases were $9.9 million and $11.8 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.

5.      Borrowing Arrangements & Other Financing Transactions

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, 2007 and 2006, were $118.0 million and $51.3 million, respectively.  The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($134 million at December 31, 2007) 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, 2007, 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,
	2007			2006
Weighted average total outstanding during
the year payable to Utility Holdings (in thousands)	$	101,099		$	39,386
Weighted average total outstanding during
the year payable to third parties (in thousands)	$	295		$	593
Weighted average interest rates during the year:
Utility Holdings		5.55	%		4.97	%
Bank loans		5.93	%		5.81	%

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Long-Term Debt

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

		At December 31,
(In thousands)		2007	2006
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	49,432
	2035, 6.10%	25,285	25,285
	Total long-term debt payable to Utility Holdings	$   223,182	$  223,182
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 4.00%, tax exempt,
	auction rate mode, 2007 weighted average: 3.83%	9,775	9,775
	2023, 1993 Environmental Improvement Series B, current adjustable rate 4.61%,
	tax exempt, auction rate mode, 2007 weighted average: 4.13%	22,550	22,550
	2025, 1998 Pollution Control Series A, current adjustable rate 4.00%, tax exempt,
	auction rate mode, 2007 weighted average: 3.90%	31,500	31,500
	2030, 1998 Pollution Control Series C, current adjustable rate 4.77%, tax exempt,
	auction rate mode, 2007 weighted average: 4.15%	22,200	22,200
	2041, 2007 Pollution Control Series, current adjustable rate 5.22%, tax exempt,
	auction rate mode, 2007 weighted average: 4.80%	17,000	-
Total first mortgage bonds payable to third parties		245,165	228,165
	Unamortized debt premium, discount & other - net	(1,932)	(1,894)
	Long-term debt payable to third parties - net	$   243,233	$     26,271

Auction Rate Mode Securities

On December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt long-term debt.  The debt has a life of 33 years, maturing on January 1, 2041.  The initial interest rate was set at 4.50 percent but the rate will be reset every 7 days through an auction process that began December 13, 2007.  This new debt was collateralized through the issuance of first mortgage bonds and the payment of interest and principal was insured through Ambac Assurance Corporation.

A process to convert these notes, as well as other auction rate securities, into another interest rate mode began in February 2008.  SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt that the Company will convert that debt from its current auction rate mode into a daily interest rate mode during March 2008.  The debt will be subject to mandatory tender for purchase on the conversion date at 100 percent of the principal amount plus accrued interest.

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.

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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 2008 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2008 is excluded from Current liabilities in the Balance Sheets.  At December 31, 2007, $836.7 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.

There are no maturities and/or sinking fund requirements on long-term debt during the five years following 2007, 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.  The only debt which may be put to the Company during the years following 2007 is $80.0 million in 2009.  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, 2007, the Company was in compliance with all financial covenants.

6.     Commitments & Contingencies

Commitments

Firm purchase commitment for utility and non-utility plant total $36 million in 2008 and $4 million in 2009.

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/Climate Change

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.  However, on February 8, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAMR regulations.  At this time it is uncertain how this decision will affect Indiana’s recently finalized CAMR implementation program.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990 and to further comply with CAIR and CAMR of 2005, SIGECO has received authority from the IURC to invest in clean coal technology.  Using this authorization, SIGECO invested approximately $258 million in Selective Catalytic Reduction (SCR) systems at its coal fired generating stations.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required.  To further reduce particulate matter emissions, the Company invested approximately $49 million in a fabric filter at its largest generating unit (287 MW).  These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007 (See Note 8).  Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

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Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). The order, as updated with an increased spending level, allows SIGECO to recover an approximate 8 percent return on up to $92 million, excluding AFUDC, in capital investments through a rider mechanism which is updated every six months for actual costs incurred.  The Company may file periodic updates with the IURC requesting modification to the spending authority.  As of December 31, 2007, the Company has invested approximately $53 million in this project.  The Company expects the SO2 scrubber will be operational in 2009.  At that time, operating expenses including depreciation expense associated with the scrubber will also be recovered through a rider mechanism.

Once the SO2 scrubber is operational, SIGECO’s coal fired generating fleet will be 100 percent scrubbed for SO2, 90 percent controlled for NOx, and mercury emissions will be reduced to meet the CAMR mercury reduction standards described in the original 2005 emission reduction regulations.  The use of SCR technology positions the Company to be in compliance with the CAIR deadlines specifying reductions in NOx emissions by 2009 and further reductions by 2015.  SIGECO's investments in scrubber, SCR and fabric filter technology should position it to comply with more stringent mercury reduction requirements should CAMR regulations be further modified.

If legislation requiring reductions in carbon dioxide and other greenhouse gases or mandating energy from renewable sources is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants.  At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. 

SIGECO is studying renewable energy alternatives, and on April 9, 2007, filed a green power rider in order to allow customers to purchase green power and to obtain approval of a contract to purchase 30 MW of power generated by wind energy.  The wind contract has been approved.  Future filings with the IURC with regard to new generation and/or further environmental compliance plans will include evaluation of potential carbon requirements.

Environmental Remediation Efforts

In the past, 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, those that operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

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 October 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 in February 2004.  SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

SIGECO has 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 and/or related to the site subject to the May 2007 lawsuit.  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 $8 million.  With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount approximating the costs it expects to incur.

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Environmental remediation costs related to SIGECO’s manufactured gas plants and other sites 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 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 and those costs may not be subject to PRP or insurance recovery.

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 could be requested by the USEPA at some future date.

8.     Rate & Regulatory Matters

Electric Base Rate Order Received

On August 15, 2007, the Company received an order from the IURC which approved its electric rate case.  The settlement agreement provides for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability.  The settlement provides for, among other things: recovery of ongoing costs and deferred costs associated with the MISO; operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; benefit to customers from the sale of wholesale power by the Company sharing equally with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in past demand side management programs to help encourage conservation during peak load periods; timely recovery of the Company’s investment in certain new electric transmission projects that benefit the MISO infrastructure; an overall rate of return of 7.32 percent on rate base of approximately $1,044 million and an allowed return on equity (ROE) of 10.4 percent.

Gas Base Rate Order Received

On August 1, 2007, the Company received an order from the IURC which approved its gas rate case.  The order provided for a base rate increase of $5.1 million and an ROE of 10.15 percent, with an overall rate of return of 7.20 percent on rate base of approximately $122 million.  The settlement also provides for the recovery of $2.6 million of costs through separate cost recovery mechanisms rather than base rates.

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 allowance for funds used during construction (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 million and the treatment cannot extend beyond three years on each project.

With this order, the Company now has in place for its gas territory weather normalization, a conservation and lost margin recovery 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.

Lost Margin Recovery/Conservation Filings

In December 2006 the IURC approved a settlement agreement that provides for conservation programs and conservation adjustment trackers designed to help customers conserve energy and reduce their annual gas bills.  The programs 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.  These mechanisms are 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 its last general rate case.

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The order was implemented in SIGECO’s service territory on August 1, 2007, as the new base rates went into effect, allowing for recovery of 100 percent of the difference between weather normalized revenues collected and the revenues approved in that rate case.  While most expenses associated with these programs are recoverable, in the first program year the Company incurred $0.3 million in program costs without recovery, of which $0.1 million was expensed in 2007.

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.  

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.  The Company is typically in a net sales position with MISO and is only occasionally in a net purchase position.  Net positions are determined on an hourly basis.  When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power.  The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system.  These revenues are also included in Electric Utility revenues.

Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) were deferred, and those deferred costs are now being recovered through base rates that went into effect on August 15, 2007.  On June 1, 2005, the Company, together with three other Indiana electric utilities, received regulatory authority from the IURC to recover fuel related costs and to defer 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.  During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the Company is following those guidelines.  Other MISO fuel related and non-fuel related administrative costs were deferred, and those deferred costs are now being recovered through base rates that went into effect on August 15, 2007.  The IURC order authorizing new base rates also provides for a tracking mechanism associated with ongoing MISO-related costs and transmission revenues.

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 a pending Day 3 market, where MISO plans to provide bid-based regulation and contingency operating reserve markets, it is difficult to predict near term operational impacts.  MISO has indicated that the Day 3 ancillary services market would begin in June 2008.

The 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 is expected to be significant.  The Company will timely recover its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.

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.

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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.  Contracts with counter-parties subject to master netting arrangements are presented net in the Balance Sheets.  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.  Ineffective portions of hedging arrangements are marked-to-market through earnings.  For fair value hedges, both the derivative and the underlying are 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.

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.  Asset optimization contracts that are derivatives are recorded at market value.

At December 31, 2007 and 2006, no asset optimization derivative contracts were outstanding.  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 $39.8 million in 2007 and $29.8 million in 2006.

SO2 Emission Allowance Risk Management

The Company’s wholesale power marketing operations are exposed to price risk associated with SO2 emission allowances.  To mitigate 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, 2007, a deferred gain of approximately $0.7 million remains in accumulated comprehensive income related to these call options which will be recognized in earnings as emission allowances are utilized.  Hedge ineffectiveness totaled $0.2 million of expense in 2006.  No SO2 emission allowance hedges are outstanding as of December 31, 2007.

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 the Company’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 may mitigate these risks by using derivative contracts.  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, 2007 and 2006, the market values of these contracts were not significant.

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Fair Value of Other Financial Instruments

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

	At December 31,
	2007				2006
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long term debt	$	245,165	$	230,470	$	228,165	$	238,674
Long term debt payable to Utility Holdings		223,182		223,993		223,182		224,466
Short-term borrowings from Utility Holdings		118,039		118,039		51,303		51,303

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

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

	At December 31,
(In thousands)	2007		2006
Wholesale emission allowances	$	2,624	$	4,228
Prepaid taxes and deferred taxes		1,781		6,126
Other		9,983		4,702
Total prepayments & other current assets	$	14,388	$	15,056

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2007		2006
Accrued taxes, including deferred taxes	$	17,456	$	8,705
Asset retirement obligation		9,500		-
Customers advances & deposits		8,683		8,556
Accrued interest		5,529		4,986
Accrued salaries & other		3,914		199
Tax collections payable		2,069		1,910
Refundable emission credit costs		-		6,125
Total accrued liabilities	$	47,151	$	30,481

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

	Year ended December 31,
(In thousands)	2007		2006
AFUDC (See Note 2C)	$	2,989	$	3,335
Other		360		295
Total other - net	$	3,349	$	3,630

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11.   Segment Reporting

The Company has two operating segments: (1) Electric Utility Services and (2) Gas Utility Services as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131).  Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company’s power generating and asset optimization operations.  Gas Utility Services provides natural gas distribution and transportation services in southwestern Indiana, including counties surrounding Evansville.  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.  Net income is the measure of profitability used by management for all operations.  Information related to the Company’s business segments is summarized below:

	Year Ended December 31,
(In thousands)	2007		2006
Revenues
Electric Utility Services	$	487,893	$	422,159
Gas Utility Services		132,195		132,615
Total operating revenues	$	620,088	$	554,774
Profitability Measure
Net Income
Electric Utility Services	$	52,614	$	41,564
Gas Utility Services		5,498		6,407
Total net income	$	58,112	$	47,971

Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	65,988	$	61,813
Gas Utility Services		5,741		5,550
Total depreciation & amortization	$	71,729	$	67,363
Interest Expense
Electric Utility Services	$	29,553	$	25,736
Gas Utility Services	$	3,653	$	2,859
Total interest expense	$	33,206	$	28,595
Income Taxes
Electric Utility Services	$	38,006	$	25,263
Gas Utility Services		4,658		4,032
Total income taxes	$	42,664	$	29,295

Capital Expenditures
Electric Utility Services	$	134,711	$	146,080
Gas Utility Services		9,223		5,987
Non-cash costs & changes in accruals		3,109		3,584
Total capital expenditures	$	147,043	$	155,651

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	At December 31,
(In thousands)	2007		2006
Assets
Electric Utility Services	$	1,369,173	$	1,277,639
Gas Utility Services		176,818		163,239
Total assets	$	1,545,991	$	1,440,878

12.   Adoption of Other Accounting Standards

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.  However, in December 2007, the FASB issued proposed FSP FAS 157-b which would delay the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  This proposed FSP partially defers the effective date of Statement 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP.  The Company adopted SFAS 157 on January 1, 2008, except as it applies to those nonfinancial assets and nonfinancial liabilities as noted in proposed FSP FAS 157-b.  The partial adoption of SFAS 157 did not have a material impact on the Company’s financial position, results of operations or cash flows.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS 159).  SFAS 159 permits entities to measure many financial instruments and certain other items at fair value.  Items eligible for the fair value measurement option include: financial assets and financial liabilities with certain exceptions; firm commitments that would otherwise not be recognized at inception and that involve only financial instruments; nonfinancial insurance contracts and warranties that the insurer can settle by paying a third party to provide those goods or services; and host financial instruments resulting from separation of an embedded financial derivative instrument from a nonfinancial hybrid instrument.  The fair value option may be applied instrument by instrument, with few exceptions, is an irrevocable election and is applied only to entire instruments.  SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007.  The Company adopted SFAS 159 on January 1, 2008, but did not opt to apply the fair value option to any of its eligible items.

SFAS 141 (Revised 2007)

In December 2007, the FASB issued SFAS 141, “Business Combinations” (SFAS 141).  SFAS 141 establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any Noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination.  SFAS 141 applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities.  SFAS 141 applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  Early adoption is not permitted.  The Company will adopt SFAS 141 on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

SFAS 160

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS 160).  SFAS 160 establishes accounting and reporting standards that require that the ownership percentages in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parents ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners.  SFAS 160 applies to all entities that prepare consolidated financial statements, except for non-profit entities.  SFAS 160 is effective for fiscal years beginning after December 31, 2008.  Early adoption is not permitted.  The Company will adopt SFAS 160 on January 1, 2009, and is currently assessing the impact this statement will have on its financial statements and results of operations.

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

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.

In 2007, SIGECO’s earnings were $58.1 million compared to $48.0 million in 2006.  The increase in 2007 compared to 2006 resulted from electric and gas base rate increases, favorable weather, and increased wholesale power marketing margins.  The increase was offset somewhat by increased operating costs including depreciation expense and a lower effective tax rate in 2006.

In the Company’s electric service territory which is not protected by weather normalization mechanisms, management estimates the 2007 margin impact of weather experienced to be favorable $4.7 million after tax compared to 30-year normal temperatures.  In 2006 weather was unfavorable compared to 30-year normal temperatures.  Management estimates the effect of weather compared to normal was unfavorable $2.3 million after tax in 2006.  The 2007 and 2006 weather effect is net of normal temperature adjustment (NTA) mechanism impacts.  The NTA was 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 Cost of gas sold.  Electric Utility margin is calculated as Electric Utility revenues less Cost of fuel & 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

Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather.  Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has increased.  Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold due to weather and changing consumption patterns.  An NTA has been in effect in SIGECO’s natural gas service territory since 2005, and lost margin recovery began when new base rates went into effect August 1, 2007.  SIGECO’s electric service territory does not have an NTA mechanism but has recovery of past demand side management costs. 

Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions.  Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses.  Expenses subject to tracking mechanisms include gas pipeline integrity management costs and costs to fund energy efficiency programs.  Certain operating costs associated with operating environmental compliance equipment were also tracked prior to their recovery in base rates that went into effect on August 15, 2007.  The August base rate orders also provide for the tracking of MISO revenues and costs, as well as the gas cost component of bad debt expense and unaccounted for gas.  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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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 thousands)	2007		2006
Electric utility revenues	$	487,893	$	422,159
Cost of fuel & purchased power		174,823		151,500
Total electric utility margin	$	313,070	$	270,659
Margin attributed to:
Residential & commercial customers	$	194,720	$	162,877
Industrial customers		74,990		70,232
Municipal & other customers		21,771		23,921
Subtotal: Retail & firm wholesale	$	291,481	$	257,030
Asset optimization	$	21,589	$	13,629
Electric volumes sold in MWh attributed to:
Residential & commercial customers		3,042,935		2,789,680
Industrial customers		2,538,495		2,570,373
Municipal & other customers		635,036		644,486
Total retail & firm wholesale volumes sold		6,216,466		6,004,539

Retail & Firm Wholesale Margin

Electric retail and firm wholesale utility margins was $291.5 million for the year ended December 31, 2007.  This represents an increase over the prior year of $34.4 million.  Management estimates the year over year increases in usage by residential and commercial customers due to weather to be $11.8 million.  The base rate increase that went into effect on August 15, 2007, produced incremental margin of $17.9 million.  During 2007, cooling degree days were 33 percent above normal compared to 5 percent below normal in 2006.  Recovery of pollution control investments and expenses increased margin $5.5 million year over year.

Margin from Asset Optimization Activities

Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers.  The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets.  A majority of the margin generated from these activities is associated with wholesale off-system sales, and substantially all off-system sales occur into the MISO Day Ahead market.

Following is a reconciliation of asset optimization activity:

	Year Ended December 31,
(In thousands)	2007		2006
Off-system sales	$	16,929	$	14,227
Transmission system sales		4,660		3,465
Other		-		(4,063	)
Total asset optimization	$	21,589	$	13,629

For the year ended December 31, 2007, net asset optimization margins were $21.6 million, which represents an increase of $8.0 million compared to 2006.  The increase is primarily due to losses on financial contracts experienced in 2006 and higher fourth quarter wholesale prices.  Off-system sales totaled 948.9 GWh in 2007 compared to 889.4 GWh in 2006.

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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 thousands)	2007		2006
Gas utility revenues	$	132,195	$	132,615
Cost of gas sold		88,964		92,379
Total gas utility margin	$	43,231	$	40,236
Margin attributed to:
Residential & commercial customers	$	33,444	$	30,394
Industrial customers		5,362		5,203
Other customers		4,425		4,639
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		10,759		10,207
Industrial customers		17,843		18,288
Total sold & transported volumes		28,602		28,495

Gas Utility margins were $43.2 million for the year ended December 31, 2007, an increase of $3.0 million compared to 2006, and was primarily related to the base rate increase, effective August 1, 2007, which increased margin $3.3 million.  The average cost per dekatherm of gas purchased for the year ended December 31, 2007, was $8.57 compared to $9.10 in 2006.

Operating Expenses

Other Operating

For the year ended December 31, 2007, Other operating expenses were $137.1 million, which represents an increase of $11.1 million, compared to 2006.  Costs directly attributable to the rate cases, including amortization of prior deferred costs, totaled $3.6 million, chemicals increased $1.5 million year over year, and pass through costs increased $0.6 million.  The remaining increase is primarily due to increased wage and benefit costs.

Depreciation & Amortization

Depreciation expense increased $4.4 million in 2007 compared to 2006.  The increases were primarily due to increased utility plant in service.  Expense in 2007 also includes $1.8 million of amortization associated with prior electric demand side management costs pursuant to the August15, 2007, electric base rate order.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1.5 million in 2007 compared to 2006.  The increase is primarily attributable to increased collections of utility receipts taxes due to higher revenues.

Other Income

Total other income – net reflects income of $3.3 million compared to $3.6 million in 2006.  The decrease relates primarily to lower levels of AFUDC related to lower capital expenditures in 2007.

Interest Expense

Interest expense increased $4.6 million in 2007 compared to 2006 due to approximately $60 million of higher short-term borrowings outstanding on a weighted average basis throughout 2007 at higher interest rates.

Income Taxes

For the year ended December 31, 2007, income taxes increased $13.4 million compared to 2006, primarily due to higher pre-tax income in 2007 and a lower effective tax rate in 2006.

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SELECTED ELECTRIC OPERATING STATISTICS:

SIGECO ELECTRIC
SELECTED ELECTRIC UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2007			2006
OPERATING REVENUES (In thousands):
Residential	$	159,193		$	130,589
Commercial		113,279			96,099
Industrial		139,455			128,171
Misc. Revenue		8,153			11,477
Total System		420,080			366,336
Municipals		28,001			26,069
Other Wholesale		39,812			29,754
	$	487,893		$	422,159
MARGIN (In thousands):
Residential	$	117,503		$	96,750
Commercial		77,217			66,127
Industrial		74,990			70,232
Misc. Revenue		7,814			11,144
Total System		277,524			244,253
Municipals		13,957			12,777
Other Wholesale		21,589			13,629
	$	313,070		$	270,659
ELECTRIC SALES (In MWh):
Residential		1,630,502			1,468,786
Commercial		1,412,433			1,320,894
Industrial		2,538,495			2,570,373
Misc. Sales		18,859			20,139
Total System		5,600,289			5,380,192
Municipals		616,177			624,347
Other Wholesale		921,321			898,276
		7,137,787			6,902,815
AVERAGE CUSTOMERS:
Residential		122,162			121,179
Commercial		18,474			18,378
Industrial		109			108
All others		37			36
		140,782			139,701
WEATHER AS A % OF NORMAL:
Cooling Degree Days		133	%		95	%

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SELECTED GAS OPERATING STATISTICS:

SIGECO GAS
SELECTED GAS UTILITY OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2007			2006
OPERATING REVENUES (In thousands):
Residential	$	85,827		$	83,382
Commercial		37,421			40,162
Industrial		5,362			5,202
Misc. Revenue		3,585			3,869
	$	132,195		$	132,615
MARGIN (In thousands):
Residential	$	24,628		$	22,525
Commercial		8,816			7,869
Industrial		5,362			5,203
Misc. Revenue		4,425			4,639
	$	43,231		$	40,236
GAS SOLD & TRANSPORTED (In MDth):
Residential		7,059			6,491
Commercial		3,700			3,716
Industrial		17,843			18,288
		28,602			28,495
AVERAGE CUSTOMERS:
Residential		100,831			100,723
Commercial		10,242			10,292
Industrial		86			79
		111,159			111,094
WEATHER AS A % OF NORMAL:
Heating Degree Days		90	%		88	%

EX-99.2

Exhibit  99.2

Cautionary Statement for Purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995.

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.  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 transportation and storage 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 industry, including the 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, regulatory or 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.

·   Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes 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, aging workforce issues, or work stoppages.

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

·   Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.

·   Changes in federal, state or local legislative requirements, such as changes in tax laws or rates, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other 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.