Vectren Utility 8-K Southern Indiana Gas & Electric Company

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2009

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	27
Selected Operating Statistics	31

Additional Information

This annual reporting package provides additional information regarding the operations of Southern Indiana Gas and Electric Company (SIGECO) that is supplemental to the information contained in the 2009 annual reports filed on Form 10-K of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of  SIGECO.  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	MMBTU:  millions of British thermal units
FASB:  Financial Accounting Standards Board	MW:  megawatts
FERC:  Federal Energy Regulatory Commission	MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
IDEM:  Indiana Department of Environmental Management	NOx:  nitrogen oxide
IURC:  Indiana Utility Regulatory Commission	OUCC:  Indiana Office of the Utility Consumer Counselor
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
MISO:  Midwest Independent System Operator

-1-

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, 2009 and 2008, 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, 2009 and 2008, 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

March 15, 2010

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FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2009		2008
ASSETS
Utility Plant
Original cost	$	2,503,333	$	2,335,725
Less:  Accumulated depreciation & amortization		975,544		914,788
Net utility plant		1,527,789		1,420,937
Current Assets
Cash & cash equivalents		404		4,490
Accounts receivable - less reserves of $2,027 &
$1,780 respectively		46,322		56,729
Receivables from other Vectren companies		-		1,037
Accrued unbilled revenues		33,340		37,628
Inventories		105,198		60,377
Recoverable fuel & natural gas costs		-		3,060
Prepayments & other current assets		15,139		4,142
Total current assets		200,403		167,463
Investments in unconsolidated affiliates		150		150
Other investments		14,208		9,160
Nonutility plant - net		2,366		2,683
Goodwill - net		5,557		5,557
Regulatory assets		45,106		44,376
Other assets		2,695		5,470
TOTAL ASSETS	$	1,798,274	$	1,655,796

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,
	2009		2008
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	300,192	$	293,263
Retained earnings		360,052		307,798
Accumulated comprehensive income		70		104
Total common shareholder's equity		660,314		601,165
Long-term debt payable to third parties		224,581		122,119
Long-term debt payable to Utility Holdings		384,692		311,502
Total long-term debt, net		609,273		433,621
Commitments & Contingencies (Notes 3, 9-11)
Current Liabilities
Accounts payable		22,450		54,819
Accounts payable to affiliated companies		8,030		11,741
Payables to other Vectren companies		31,693		15,524
Refundable fuel & natural gas costs		14,264		-
Accrued liabilities		41,521		45,614
Short-term borrowings		-		400
Short-term borrowings payable to Utility Holdings		55,479		149,425
Long-term debt subject to tender		41,275		80,000
Total current liabilities		214,712		357,523
Deferred Income Taxes & Other Liabilities
Deferred income taxes		209,361		151,176
Regulatory liabilities		49,996		55,837
Deferred credits & other liabilities		54,618		56,474
Total deferred income taxes & other liabilities		313,975		263,487
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,798,274	$	1,655,796

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,
	2009		2008
OPERATING REVENUES
Electric utility	$	528,536	$	524,245
Gas utility		110,622		159,654
Total operating revenues		639,158		683,899
COST OF OPERATING REVENUES
Cost of fuel & purchased power		194,257		182,925
Cost of gas sold		66,662		114,411
Total cost of operating revenues		260,919		297,336
		378,239		386,563
OPERATING EXPENSES
Other operating		160,225		165,499
Depreciation & amortization		83,605		74,142
Taxes other than income taxes		16,283		18,599
Total operating expenses		260,113		258,240
OPERATING INCOME		118,126		128,323
Other income – net		2,856		1,100
Interest expense		38,709		36,817
INCOME BEFORE INCOME TAXES		82,273		92,606
Income taxes		30,019		36,208
NET INCOME	$	52,254	$	56,398

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,
		2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$                             52,254			$                           56,398
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization			83,605			74,142
Deferred income taxes & investment tax credits			54,148			13,494
Expense portion of pension & postretirement periodic benefit cost			1,813			919
Provision for uncollectible accounts			2,995			2,842
Other non-cash charges - net			7,697			10,748
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue			12,738			(18,744	)
Inventories			(44,821	)		(4,773	)
Recoverable fuel & natural gas costs			17,324			(8,399	)
Prepayments & other current assets			(10,833	)		7,290
Accounts payable, including to Vectren companies
& affiliated companies			(5,124	)		14,393
Accrued liabilities			4,474			1,525
Changes in noncurrent assets			(11,954	)		19,690
Changes in noncurrent liabilities			(21,729	)		(12,164	)
Net cash flows from operating activities			142,587			157,361
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt payable to Utility Holdings			74,596			88,878
Long-term debt payable to third parties - net of issuance costs			61,846			59,914
Additional capital contribution			6,929			-
Requirements for:
Dividends to parent			-			(43,252	)
Retirement of long-term debt, including premiums paid			(1,406	)		(103,583	)
Net change in short-term borrowings, including from Utility Holdings			(94,346	)		31,786
Net cash flows from financing activities			47,619			33,743
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities			-			2,096
Requirements for:
Capital expenditures, excluding AFUDC equity			(191,114	)		(187,904	)
Other investments			(3,178	)		(2,775	)
Net cash flows from investing activities			(194,292	)		(188,583	)
Net change in cash & cash equivalents			(4,086	)		2,521
Cash & cash equivalents at beginning of period			4,490			1,969
Cash & cash equivalents at end of period		$	404		$	4,490

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			Total
Balance at January 1, 2008	$	293,263	$	294,652		$	328		$	588,243
Comprehensive income
Net income				56,398						56,398
Cash flow hedge
Reclassification to net income - net of $179 in tax							(224	)		(224	)
Total comprehensive income										56,174
Common stock:
Dividends to parent				(43,252	)					(43,252	)
Balance at December 31, 2008	$	293,263	$	307,798		$	104		$	601,165
Comprehensive income
Net income				52,254						52,254
Cash flow hedge
Reclassification to net income - net of $55 in tax							(34	)		(34	)
Total comprehensive income										52,220
Common stock:
Additional capital contribution		6,929								6,929
Balance at December 31, 2009	$	300,192	$	360,052		$	70		$	660,314

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 & 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 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets 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

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these financial statements and related footnotes.  Examples of transactions for which estimation techniques are used include unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments.  Estimates also impact the depreciation of utility and nonutility plant and the testing goodwill and other assets for impairment.  Recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Actual results could differ from current estimates.

Subsequent Events Review

Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are available to be issued.  The Company’s management has performed a review of subsequent events through March 15, 2010.

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.  Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

Allowance for Uncollectible Accounts

The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience.  If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.

Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2009		2008
Materials & supplies	$	30,307	$	27,522
Fuel (coal and oil) for electric generation		63,528		22,463
Gas in storage – at LIFO cost		11,076		10,145
Other		287		247
Total inventories	$	105,198	$	60,377

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded that carrying value at December 31, 2009 and 2008, by approximately $6 million and $14 million, respectively.  All other inventories are carried at average cost.

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Plant, Property, & Equipment

Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.  The cost of renewals and betterments that extend the useful life are capitalized.  Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the 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.

Utility Plant & Related Depreciation

The IURC allows the Company to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds.  These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.  The Company reports both the debt and equity components of AFUDC in Other – net in the Statements of Income.

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, resulting in no gain or loss.  Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC.

Nonutility Plant & Related Depreciation

The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation.  When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.

Goodwill

Goodwill recorded on the Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition.  Goodwill is charged to expense only when it is impaired.  The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year.  Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount.  If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations.  Through December 31, 2009, no goodwill impairments have been recorded.  All of 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 $1.3 million and $1.6 million at December 31, 2009 and 2008, respectively.  The value of the emission allowances are recognized as they are consumed or sold.

Regulation

Retail public utility operations are subject to regulation by the IURC.  The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by this agency.

Refundable or Recoverable Gas Costs & 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 a variable benchmark based on NYMEX natural gas prices, 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 and purchased power for electric generation is charged to operating expense when consumed.

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Regulatory Assets & 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 continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations.  Given the current regulatory environment in its jurisdiction, the Company believes such accounting is appropriate.

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.

Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO).  The Company records 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 Company 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, the Company settles the obligation for its recorded amount or incurs a gain or loss.  To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

ARO’s included in Other liabilities total $9.1 million and $8.5 million at December 31, 2009 and 2008, respectively.  ARO’s included in Accrued liabilities total $2.7 million and $7.2 million at December 31, 2009 and 2008, respectively.  During 2009, the Company recorded accretion of $0.5 million and cash payments, net of changes in estimates of $4.1 million.  During 2008, the Company recorded accretion of $0.4 million and cash payments, net of changes in estimates of $0.5 million.

Energy Contracts & Derivatives

The Company occasionally 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.  In most cases, a derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.  Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance Holdings, LLC (Proliance) and others, and wind farm and other electric generating capacity contracts.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts 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 and any associated collateral 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 regulatory accounting treatment.  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 hedged item are marked to market through earnings.  The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability.  Market value for derivative contracts is determined using quoted market prices from independent sources.  The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value.  As of and for the periods presented, related derivative activity is not significant to these financial statements.

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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.

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, which totaled $8.4 million in 2009 and $8.5 million in 2008.  Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

The Company’s chief operating decision maker is comprised of a group of executive management led by the Chief Executive Officer.  The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure.  The Company has two operating segments:  Electric Utility Services and Gas Utility Services.

Fair Value Measurements

Certain financial assets and liabilities as well as certain nonfinancial assets and liabilities, such as the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests, are valued and/or disclosed at fair value.  The Company describes its fair value measurements using a hierarchy of inputs based primarily on the level of public data used.  Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed using internal models, which reflect what a market participant would use to determine fair value. 

Earnings Per Share

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

Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 5).

3.     Utility Plant & Depreciation

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)	2009					2008
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Electric utility plant	$	2,113,254		3.4	%	$	1,884,257		3.3	%
Gas utility plant		234,972		3.0	%		214,653		3.0	%
Common utility plant		48,785		2.9	%		47,956		2.9	%
Construction work in progress		106,322		-			188,859		-
Total original cost	$	2,503,333				$	2,335,725

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  SIGECO's share of the cost of this unit at December 31, 2009, is $178.1 million with accumulated depreciation totaling $53.4 million.  The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $0.7 million at December 31, 2009.  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.

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4.     Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2009		2008
Amounts currently recovered through customer rates related to:
Demand side management programs	$	15,348	$	21,453
Unamortized debt issue costs		8,418		7,178
Premiums paid to reacquire debt		3,523		3,961
Authorized trackers		6,084		(2,444	)
Other		1,078		2,722
		34,451		32,870
Amounts deferred for future recovery related to:
Cost recovery riders & other		308		147
Future amounts recoverable from ratepayers related to:
Deferred income taxes		6,111		2,810
Asset retirement obligations & other		4,236		8,549
		10,347		11,359
Total regulatory assets	$	45,106	$	44,376

Of the $34.5 million currently being recovered in rates charged to customers, approximately $15.3 million is earning a return with a weighted average recovery period of 7 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, 2009 and 2008, the Company has approximately $50.0 million and $55.8 million, respectively, in Regulatory liabilities.  Of these amounts, $44.8 million and $51.8 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations.

5.     Transactions with Other Vectren Companies

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases coal used for electric generation.  The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC.  Amounts paid for such purchases for the years ended December 31, 2009 and 2008, totaled $152.9 million and $119.8 million, respectively.  Amounts owed to Vectren Fuels at December 31, 2009 and 2008 are included in Payables to other Vectren companies.

Miller Pipeline Corporation

Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, 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 $8.8 million in 2009 and $9.5 million in 2008.  Amounts owed to Miller at December 31, 2009 and 2008 are included in Payables to other Vectren companies.

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and 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 at cost.  SIGECO received corporate allocations totaling $59.3 million and $57.2 million for the years ended December 31, 2009, and 2008, respectively.   Amounts owed to Vectren and Utility Holdings at December 31, 2009 and 2008 are included in Payables to other Vectren companies.

-12-

Retirement Plans & Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting in accordance with FASB guidance related to employers’ accounting for defined benefit pension and other postretirement plans.  An allocation of cost is determined, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date.  These costs are directly charged to individual subsidiaries.  Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above.  Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions.  Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets.  This allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting.

For the years ended December 31, 2009 and 2008, periodic pension costs totaling $2.3 million and $1.3 million, respectively, were directly charged by Vectren to the Company.  For the year ended December 31, 2009, other periodic postretirement benefit costs totaling $0.3 million was directly charged by Vectren to the Company.  Insignificant amounts were charged in 2008.  As of December 31, 2009 and 2008, $21.0 million and $27.3 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.

Share-Based Incentive Plans and Deferred Compensation Plans

SIGECO does not have share-based compensation plans separate from Vectren.  The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to SIGECO.  As of December 31, 2009 and 2008, $11.2 million and $10.2 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in Vectren’s centralized cash management program.  See Note 7 regarding long-term and short-term intercompany borrowing arrangements.

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 $16 million is outstanding at December 31, 2009, and Utility Holdings’ $920 million unsecured senior notes outstanding at December 31, 2009.  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, Utility Holdings’ current and deferred tax expense is computed on a separate company basis.  Current taxes payable/receivable are settled with Vectren in cash.

Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements.  Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse.  The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate.  Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties.  A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.  

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Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.  The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.

Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property in accordance with the regulatory treatment.  Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.  

Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2009			2008
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	207,474		$	153,970
Regulatory assets recoverable through future rates		15,774			17,063
Other comprehensive income		33			56
Employee benefit obligations		(4,759	)		(12,575	)
Regulatory liabilities to be settled through future rates		(9,171	)		(12,500	)
Other – net		10			5,162
Net noncurrent deferred tax liability		209,361			151,176
Current deferred tax liabilities, primarily demand side management
and other regulatory assets		3,436			7,625
Net deferred tax liability	$	212,797		$	158,801

At December 31, 2009 and 2008, investment tax credits totaling $5.3 million and $6.2 million, respectively, are included in Deferred credits and other liabilities.  These investment tax credits are amortized over the lives of the related investments.

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

		Year Ended December 31,
		2009		2008
Statutory rate		35.0	%	35.0	%
State & local taxes, net of federal benefit		5.3		6.4
Amortization of investment tax credit		(1.1)		(0.9)
Adjustments to federal income tax accruals		(2.0)		(0.9)
All other - net		(0.7)		(0.5)
	Effective tax rate	36.5	%	39.1	%

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

	Year Ended December 31,
(In thousands)	2009			2008
Current:
Federal	$	(24,996	)	$	13,871
State		867			8,843
Total current taxes		(24,129	)		22,714
Deferred:
Federal		48,622			13,963
State		6,396			369
Total deferred taxes		55,018			14,332
Amortization of investment tax credits		(870	)		(838	)
Total income tax expense	$	30,019		$	36,208

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2009 and 2008:

(in thousands)	2009			2008
Unrecognized tax benefits at January 1	$	515			2,944
Gross increases - tax positions in prior periods		1,162			-
Gross decreases - tax positions in prior periods		(1,582	)		(2,429	)
Gross increases - current period tax positions		4,376			-
Lapse of statute of limitations		294			-
Unrecognized tax benefits at December 31	$	4,765		$	515

Of the change in unrecognized tax benefits during 2009 and 2008, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was insignificant at December 31, 2009 and 2008.

As of December 31, 2009, the 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 recognized expense related to interest and penalties totaling approximately $0.1 million in 2008 and none in 2009.  The Company had approximately $0.1 million and $0.2 million for the payment of interest and penalties accrued as of December 31, 2009 and 2008, respectively.

Unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes, totaled $4.5 million and $0.7 million, respectively, at December 31, 2009 and 2008.

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 parent, Vectren Corporation.  Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file returns in various states.  The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005.  Subsequent to the year ended December 31, 2009, Vectren received a notice from the IRS that year ended December 31, 2008 is under audit.  The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007.  The statutes of limitations for assessment of federal and Indiana income tax have expired with respect to tax years through 2002.   

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6.     Transactions with ProLiance

ProLiance, a nonutilityenergy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities.  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, 2009 and 2008, totaled $74.9 million and $133.0 million, respectively.  Amounts owed to ProLiance at December 31, 2009 and 2008, for those purchases were $8.0 million and $11.7 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.

7.      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, 2009 and 2008, were $55.5 million and $149.8 million, respectively.  The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($462 million at December 31, 2009) and is subject to the same terms and conditions as Utility Holdings’ short term borrowing arrangements, including its commercial paper program.  Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds.  Additionally, at December 31, 2009, the Company has available approximately $5.0 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements, of which all was available.  See the table below for interest rates and outstanding balances:

	Year ended December 31,
	2009			2008
Weighted average total outstanding during
the year payable to Utility Holdings (in thousands)	$	83,876		$	108,868
Weighted average total outstanding during
the year payable to third parties (in thousands)	$	115		$	121
Weighted average interest rates during the year:
Utility Holdings		0.71	%		3.56	%
Bank loans		1.35	%		3.25	%

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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)			2009			2008
Senior Unsecured Notes Payable to Utility Holdings:
		2011, 6.625%		$                86,584			$                86,584
		2015, 5.45%		49,432			49,432
		2018, 5.75%		61,881			61,881
		2020, 6.28%		74,596			-
		2035, 6.10%		25,285			25,285
		2039, 6.25%		86,914			88,320
	Total long-term debt payable to Utility Holdings			$            384,692			$            311,502
First Mortgage Bonds Payable to Third Parties:
	2015, 1985 Pollution Control Series A, current adjustable rate 0.27%, tax exempt,
	2009 weighted average: 0.37%			$                  9,775			$                  9,775
	2016, 1986 Series, 8.875%			13,000			13,000
	2020, 1998 Pollution Control Series B, 4.50%, tax exempt			4,640			4,640
	2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt			22,550			22,550
	2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt			22,500			22,500
	2025, 1998 Pollution Control Series A, current adjustable rate 0.27%, tax exempt,
	2009 weighted average: 0.44%			31,500			31,500
	2029, 1999 Senior Notes, 6.72%			80,000			80,000
	2030, 1998 Pollution Control Series B, 5.00%, tax exempt			22,000			22,000
	2030, 1998 Pollution Control Series C, 5.35%, tax exempt			22,200			22,200
	2040, 2009 Environmental Improvement Series, 5.40%, tax exempt			22,300			-
	2041, 2007 Pollution Control Series, 5.45%, tax exempt			17,000			17,000
Total first mortgage bonds payable to third parties				267,465			245,165
	Debt subject to tender			(41,275	)		(80,000	)
	Treasury Debt			-			(41,275	)
	Unamortized debt premium, discount & other - net			(1,609	)		(1,771	)
	Long-term debt payable to third parties - net			$              24,581			$            122,119

Issuance payable to Utility Holdings

In April 2009, the Company issued a note payable to Utility Holdings.  The term of the note is identical to the terms of the notes issued by Utility Holdings in April 2009.  These notes issued by Utility Holdings have an aggregate principal amount of $100 million, with an interest rate of 6.28%, and are due April 7, 2020.  These notes have no sinking fund requirements, and interest payments are due semi-annually. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million, of which $74.6 was issued to SIGECO.  Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in it financing arrangements to account for debt issuance costs and any related hedging arrangements.

In March 2008, the Company issued a note payable to Utility Holdings. The term of the note is identical to the terms of notes issued by Utility Holdings in March 2008.  These notes issued by Utility Holdings have an aggregate principal amount of $125 million, are priced at par with an interest rate of 6.25%, and are due April 1, 2039.  The notes have no sinking fund requirements, and interest payments are due monthly.  The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest.  Utility Holdings entered into several interest rate hedges with an $80 million notional amount.  Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders.  The value paid is being amortized as an increase to interest expense over the life of the issue.  The proceeds from the sale of these notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million, of which $88.3 million was issued to SIGECO.  Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in it financing arrangements to account for debt issuance costs and any related hedging arrangements.

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SIGECO 2009 Debt Issuance

On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity.  The bonds mature in 2040.  The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.

Auction Rate Securities

In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode.  In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest.  During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million.  The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041.

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, receiving proceeds, net of issuance costs of approximately $40.6 million.  The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit backed by Utility Holdings’ $515 million short-term credit facility.  The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.  The initial interest rate paid to investors was 0.55 percent.  The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees, approximated 1 percent.  Since Utility Holdings’ short-term facility has a remaining term of less than one year, these obligations are classified as Long-term debt subject to tender in current liabilities.

Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 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 2010 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2010 is excluded from Current liabilities in the Balance Sheets.  At December 31, 2009, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.  SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.5 billion at December 31, 2009.

Maturities of long-term debt during the five years following 2009 (in millions) are zero in 2010, $86.6 in 2011, zero in 2012, 2013, and 2014.

Long-Term Debt Put & Call Provisions

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements.  During 2009 and 2008, the Company repaid approximately $1.4 million and $0.6 million, respectively, related to death puts.  

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, 2009, the Company was in compliance with all financial covenants.

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8.     Accumulated Other Comprehensive Income

Comprehensive income is a measure of all changes in equity that result from the 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 for the past two years follows:

	2008									2009
	Beginning			Changes			End			Changes			End
	of Year			During			of Year			During			of Year
(In thousands)	Balance			Year			Balance			Year			Balance
Cash flow hedges	$	562		$	(403	)	$	159		$	(89	)	$	70
Deferred income taxes		(234	)		179			(55	)		55			-
Accumulated other comprehensive income	$	328		$	(224	)	$	104		$	(34	)	$	70

9.     Commitments & Contingencies

Purchase Commitments

SIGECO has both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights.  Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.  Firm purchase commitments for other commodities total zero in 2010 and 2011, $5.3 million in 2012, $5.5 million in 2013, $5.7 million in 2014, and zero thereafter.

Legal Proceedings

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

10.   Environmental Matters

Clean Air Act

The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions from coal-burning power plants in NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 Order.  Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance.  It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and is positioned to comply with SO2 reductions effective January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised; however, most of these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR).  CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008.  In response to the court decision, USEPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2010.  It is uncertain what emission limit the USEPA is considering, and whether they will address hazardous pollutants in addition to mercury.  It is also possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.

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To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007.  Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

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 allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense.  The Company has invested approximately $100 million in this project.  The scrubber was placed into service on January 1, 2009.  Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009.  With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing on January 1, 2010.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.

Climate Change

The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program in which there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases, a federal renewable portfolio standard, and utility energy efficiency targets.  Current proposed legislation also requires local natural gas distribution companies to hold allowances for the benefit of their customers.  As of the date of this filing, the Senate has not passed a bill, and the House bill is not law.  The U.S. Senate is currently debating a cap and trade proposal that is similar in structure to the House bill.

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord, and in its completed 2009 session, the state’s legislature debated, but did not pass, a renewable energy portfolio standard.

In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system.  In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy.  These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December of 2009, and is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The USEPA has recently finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The USEPA has also recently proposed a revision to the PSD (Prevention of Significant Deterioration) and Title V permitting rules which would require facilities that emit 25,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  If these proposed rules were adopted, they would apply to SIGECO’s generating facilities.

Impact of Legislative Actions & Other Initiatives is Unknown

If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses.  Further, any legislation would likely impact the Company’s generation resource planning decisions.  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.  The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers.  Approximately 20 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers.  As such, reductions in these volumes in 2009 coupled with the flexibility to further modify the level of these transactions in future periods may help with compliance if emission targets are based on pre-2008 levels.

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Ash Ponds & Coal Ash Disposal Regulations

The USEPA is considering additional regulatory measures affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  Additional laws and regulations under consideration more stringently regulate these byproducts, including the potential for coal ash to be considered a hazardous waste in certain circumstances.  The USEPA has indicated that it intends to propose a rule during 2010.  At this time, the Company is unable to predict the outcome any such revised regulations might have on operating results, financial position, or liquidity.

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.  Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels.  At this time, it is anticipated that the USEPA may request only additional soil testing at some future date.

Environmental Remediation Efforts

In the past, SIGECO 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 owned or 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 Voluntary Remediation Program  (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 waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, in an October 2009 court decision, SIGECO was found to be a PRP at the site.  However, the Court must still determine whether such costs should be allocated among a number of PRPs, including the former owners of the site.  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.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters totaling approximately $11.1 million.  However, given the uncertainty surrounding the allocation of PRP responsibility associated with the May 2007 lawsuit and other matters, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has settled with certain of its known insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million; negotiations are ongoing with others.  SIGECO has undertaken significant remediation efforts at two MGP sites.

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Environmental remediation costs related manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate potentially responsible party (PRP) and insurance settlement recoveries.  Such cumulative costs are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  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.  As of December 31, 2009 and December 31, 2008, approximately $3.4 million and $3.6 million of accrued, but not yet spent, remediation costs are included in Other Liabilities related to these sites.

11.   Rate & Regulatory Matters

Electric Base Rate Filing

On December 11, 2009, the Company filed a request with the IURC to adjust its electric base rates.  The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between the Company and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  In total the request approximated $54 million.  The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service.  Most of the remainder of the request is to account for the now lower overall sales levels resulting from the recession.  A portion of the request reflects a slight increase in annual operating and maintenance costs since the last rate case, nearly four years ago.  The rate design proposed in the filing would break the link between customers’ consumption and the utility’s rate of return, thereby aligning the utility’s and customers’ interests in using less energy.  The request assumes an overall rate of return of 7.62 percent on rate base of approximately $1,294 million and an allowed return on equity (ROE) of 10.7 percent.  Based upon timelines prescribed by the IURC at the start of these proceedings, a decision is expected to be issued at the end of 2010.

MISO

Since 2002 and with the IURC’s approval, the Company has been a member of the 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.  Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in MISO’s tariff or a material interpretation thereof.  Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets.  The Company also has municipal customers served through the MISO and for which the Company transmits power to the MISO for delivery to those customers.  Net revenues from wholesale activities, inclusive of revenues associated with these municipal contracts, totaled $20.8 million in 2009 and $57.6 million in 2008 and are recorded in Electric utility revenues.  The base rate case effective August 17, 2007, requires that wholesale margin (net revenues less the cost of fuel and purchased power) inclusive of this MISO wholesale activity earned above or below $10.5 million be shared equally with retail customers as measured on a fiscal year ending in August.

Recently, MISO market prices have fallen and the Company has more frequently been a net purchaser.  In addition, the Company also receives power through the MISO associated with its wind and other power purchase agreements.  Including these power purchase agreements, the Company purchased energy from the MISO totaling $34.2 million in 2009 and $16.6 million in 2008.  To the extent these power purchases are used for retail load, they are included in FAC filings.

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.  Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.

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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 Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts.  The IURC has approved the Company’s participation in the ASM and has granted authority to recover costs associated with ASM.  To date impacts from the ASM have been minor.

The need to expend capital for improvements to the regional 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.  Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.  Such revenues recorded in Electric utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $9.1 million in 2009 and $4.8 million in 2008.

12.   Fair Value Measurements

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

	At December 31,
	2009				2008
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long term debt	$	267,465	$	275,785	$	245,165	$	230,360
Long term debt payable to Utility Holdings		384,692		401,545		311,502		273,366
Short-term borrowings		-		-		400		400
Short-term borrowings from Utility Holdings		55,479		55,479		149,425		149,425
Cash & cash equivalents		404		404		4,490		4,490

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 and cash & cash equivalents, those carrying amounts approximate fair value.  Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

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.

13.   Additional Balance Sheet & Operational Information

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

	At December 31,
(In thousands)	2009		2008
Wholesale emission allowances	$	1,298	$	1,585
Prepaid taxes and deferred taxes		13,607		265
Other		234		2,292
Total prepayments & other current assets	$	15,139	$	4,142

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Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2009		2008
Accrued taxes	$	12,118	$	9,564
Current deferred taxes		3,436		7,625
Asset retirement obligation		2,657		7,175
Customers advances & deposits		11,963		9,604
Accrued interest		5,444		4,935
Accrued salaries & other		3,496		3,670
Tax collections payable		2,407		3,041
Total accrued liabilities	$	41,521	$	45,614

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

	Year ended December 31,
(In thousands)	2009		2008
AFUDC – borrowed funds	$	503	$	1,740
AFUDC – equity funds		365		125
Other		1,988		(765	)
Total other - net	$	2,856	$	1,100

Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2009			2008
Cash paid (received) for:
Income taxes	$	(12,806	)	$	21,997
Interest		38,199			34,245

As of December 31, 2009 and 2008, the Company has accruals related to utility plant purchases totaling approximately $5.7 million and $22.6 million, respectively.

14.   Segment Reporting

The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment.  Electric Utility Services provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Gas Utility Services provides natural gas distribution and transportation services in southwestern Indiana, including counties surrounding Evansville.  The Company manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and wholesale power operations.  Net income is the measure of profitability used by management for all operations.

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

	Year Ended December 31,
(In thousands)	2009		2008
Revenues
Electric Utility Services	$	528,536	$	524,245
Gas Utility Services		110,622		159,654
Total operating revenues	$	639,158	$	683,899
Profitability Measure
Net Income
Electric Utility Services	$	48,257	$	50,694
Gas Utility Services		3,997		5,704
Total net income	$	52,254	$	56,398
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	77,471	$	68,457
Gas Utility Services		6,134		5,685
Total depreciation & amortization	$	83,605	$	74,142
Interest Expense
Electric Utility Services	$	34,838	$	32,000
Gas Utility Services		3,871		4,817
Total interest expense	$	38,709	$	36,817
Income Taxes
Electric Utility Services	$	27,402	$	32,009
Gas Utility Services		2,617		4,199
Total income taxes	$	30,019	$	36,208
Capital Expenditures
Electric Utility Services	$	154,152	$	172,014
Gas Utility Services		23,125		21,077
Non-cash costs & changes in accruals		13,837		(5,187	)
Total capital expenditures	$	191,114	$	187,904

Assets
Electric Utility Services	$	1,592,375	$	1,462,090
Gas Utility Services		205,899		193,706
Total assets	$	1,798,274	$	1,655,796

15.   Adoption of Other Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s).  This new guidance is effective for annual reporting periods beginning after November 15, 2009.  This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE.  Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE.  The Company adopted this guidance on January 1, 2010. The Company does not expect the adoption will have a material impact on the financial statements.

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Fair Value Measurements & Disclosures

In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value.  This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value.  The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets.  This guidance is effective for the first reporting period beginning after December 15, 2009.  The Company will adopt this guidance in its first quarter 2010 reporting.  The Company does not expect the adoption will have a material impact on the financial statements.

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

The following discussion and analysis  provides additional information regarding SIGECO’s results of operations that is supplemental to the information provided in Vectren Corporation’s and Utility Holdings’ management’s discussion and analysis of results of operations and financial condition contained in those 2009 annual reports filed on Forms 10-K, which  include forward looking statement disclaimers.  The following discussion and analysis should be read in conjunction with SIGECO’s financial statements and notes thereto.

Executive Summary of Results of Operations

SIGECO generates revenue primarily from the delivery of natural gas and electric service to its customers, and SIGECO’s 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.   SIGECO has in place a disclosure committee that consists of senior management as well as financial management.  The committee is actively involved in the preparation and review of SIGECO’s financial statements.

Operating Results

In 2009, SIGECO’s earnings were $52.3 million compared to $56.4 million in 2008.  The $4.1 million decrease in 2009 compared to 2008 reflects lower large customer usage and lower wholesale power sales, both due to the recession, mild cooling weather, and an increase in depreciation expense associated with rate base growth.  Increased revenues associated with regulatory initiatives, lower operating expenses, and the return of market values associated with investments related benefit plans partially offset these declines.

In the Company’s electric service territory which is not protected by weather normalization mechanisms, management estimates the margin impact of weather to be approximately $4.8 million unfavorable or $2.9 million after tax compared to 30-year normal temperatures in 2009.  In 2008, management estimates a $0.4 million favorable impact on margin compared to normal or $0.2 million after tax.

Significant Fluctuations

Margin

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used.  Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold.  Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power.  The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.

Rate Design Strategies

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 been volatile.  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 to these customers due to weather and changing consumption patterns.  SIGECO’s natural gas territory has an NTA since 2005 and lost margin recovery since 2007.  SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms; however, rate designs proposed in a recently filed rate case requests a lost margin recovery mechanism that works in tandem with conservation initiatives and other initiatives that are similar to rate designs undertaken in SIGECO's gas service territory that mitigate the impacts of both weather and conservation. 

Tracked Operating Expenses

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 costs to fund Indiana energy efficiency programs, MISO transmission revenues and costs, as well as the gas cost component of uncollectible accounts expense based on historical experience and unaccounted for gas.  Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also tracked.

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Recessionary Impacts

Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products.  The recent recession has had and may continue to have some negative impact on sales to and usage by both gas and electric large customers.  This impact has included, and may continue to include, tempered growth, significant conservation measures, and increased plant closures and bankruptcies.  While no one industrial customer comprises 10 percent of revenues, the top five industrial electric customers comprise approximately 12 percent of electric utility margin for the year ended December 31, 2009, and therefore any significant decline in their collective margin could adversely impact operating results.  Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.  Further, resulting from the lower power prices, decreased demand for electricity and higher coal prices associated with contracts negotiated last year, the Company’s coal fired generation has been dispatched less often by the MISO.  This has resulted in lower wholesale sales, more power being purchased from the MISO for native load requirements, and larger coal inventories.

Following is a discussion and analysis of margin generated from operations.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)

Electric utility margin and volumes sold by customer type follows:

	Year Ended December 31,
(In thousands)	2009		2008
Electric utility revenues	$	528,536	$	524,245
Cost of fuel & purchased power		194,257		182,925
Total electric utility margin	$	334,279	$	341,320
Margin attributed to:
Residential & commercial customers	$	222,845	$	218,607
Industrial customers		85,294		82,871
Municipal & other customers		5,495		7,367
Subtotal: Retail & firm wholesale	$	313,634	$	308,845
Wholesale margin		20,645		32,475
Total electric utility margin	$	334,279	$	341,320
Electric volumes sold in MWh attributed to:
Residential & commercial customers		2,760,752		2,850,451
Industrial customers		2,258,942		2,409,115
Municipal & other customers		19,979		63,862
Total retail & firm wholesale volumes sold		5,039,673		5,323,428

Retail

Electric retail utility margin was $313.6 million for the year ended December 31, 2009, and compared to 2008 increased $4.8 million.  Increased margin among the customer classes associated with returns on pollution control equipment and other investments totaled $4.5 million year over year, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $10.3 million .  Management estimates weather, driven primarily by cooling weather 10 percent milder than the prior year, decreased residential and commercial margin $5.2 million compared to 2008.  Industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, decreased approximately $4.9 million due primarily to the weak economy.  The industrial decreases are due primarily to lower usage; however, usage began to stabilize during the third and fourth quarters.

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Margin from Wholesale Electric Activities

Periodically, generation capacity is in excess of native load.  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 and Real Time markets.

Further detail of Wholesale activity follows:

	Year Ended December 31,
(In thousands)	2009		2008
Off-system sales	$	6,050	$	23,178
Transmission system sales		14,595		9,297
Total wholesale margin	$	20,645	$	32,475

For the year ended December 31, 2009, wholesale margin was $20.6 million, representing a decrease of $11.8 million, compared to 2008.  Of the decrease, $17.1 million relates to lower margin retained by the Company from off-system sales.  The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs.  Off-system sales totaled 603.6 GWh in 2009, compared to 1,512.9 GWh in 2008.  The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August.  Results in 2008 and 2009 reflect the impact of that sharing.

Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans.  Margin associated with these projects and other transmission system operations increased $5.3 million in 2009 compared to 2008.

Purchased Power

The Company’s mix of generated and purchased electricity changed during 2009 compared to prior years.  For the years ended December 31, 2009 and 2008, respectively, the Company purchased approximately 1,159 GWh and 372 GWh of power from the MISO and other sources.  The total cost associated with these volumes of purchased power is approximately $43 million and $26 million in 2009 and 2008 respectively, and is included in the Cost of fuel & purchased power.

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)	2009		2008
Gas utility revenues	$	110,622	$	159,654
Cost of gas sold		66,662		114,411
Total gas utility margin	$	43,960	$	45,243
Margin attributed to:
Residential & commercial customers	$	37,115	$	37,886
Industrial customers		4,761		4,930
Other customers		2,084		2,427
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		10,644		11,651
Industrial customers		15,263		16,986
Total sold & transported volumes		25,907		28,637

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Gas Utility margins were $44.0 million for the year ended December 31, 2009, a decrease of $1.3 million compared to 2008.  Management estimates a $0.4 million year over year decrease in margin associated with lower industrial volumes sold, and slightly lower residential and commercial customer counts.  The impact of operating costs, including revenue and usage taxes, recovered in margin was unfavorable $0.2 million year over, reflecting lower revenue taxes offset by higher pass through operating expenses.  The remaining decrease primarily relates to lower recovery of the gas cost portion of uncollectible accounts expense.  The lower revenue and usage taxes and gas cost recovery correlate with lower year over year gas costs.  The average cost per dekatherm of gas purchased for the year ended December 31, 2009, was $6.36 compared to $9.43 in 2008.

Operating Expenses

Other Operating

For year ended December 31, 2009, other operating expenses were $160.2 million, decreasing $5.3 million compared to 2008.  Lower power supply costs, including chemical and maintenance costs, resulted in a $17.6 million decrease in Other operating expenses compared to the prior year.  Offsetting this decrease were approximately $4.5 million of increased costs directly recovered through utility margin.  Examples of such tracked costs include pipeline integrity management costs, costs to fund energy efficiency programs, and MISO transmission revenues and costs, among others.  Increases in other operating expenses in 2009, not directly recovered in margin, include an approximate $6.3 million increase in administrative costs, including certain compensation costs and charges for the use of shared assets and a $1.5 million increase in accruals associated with environmental matters.  Despite significantly lower gas costs due to the recession, uncollectible accounts expense was slightly unfavorable compared to 2008.

Depreciation & Amortization

Depreciation expense increased $9.5 million in 2009 compared to 2008.  The increase in depreciation is due to plant additions.  Plant additions include the approximate $100 million SO2 scrubber placed into service January 1, 2009, for which depreciation totaling $5.6 million is directly recovered in electric utility margin.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $2.3 million in 2009 compared to 2008.  The decrease is primarily attributable to decreased property taxes.

Other Income

Total other income – net reflects income of $2.9 million compared to $1.1 million in 2008.  The increase is primarily due to the return of market values associated with investments related to benefit plans.

Interest Expense

Interest expense was $38.7 million for the year ended December 31, 2009, which represents an increase of $1.9 million, compared to 2008.  The increase reflects the impact of two long-term financing transactions completed in 2009 and the remarketing of $41.3 million held in treasury at December 31, 2008.  These transactions involved the second quarter issuance by Vectren Utility Holdings, Inc. (VUHI) of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent to institutional investors, of which $74.6 million was pushed down to SIGECO, and the third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.  The year ended December 31, 2009 reflects lower short-term interest rates and lower average short-term debt balances that have been impacted favorably by lower gas prices and the issuance of new long-term debt.

Income Taxes

For the year ended December 31, 2009, income taxes decreased $6.2 million compared to 2008, primarily due to lower pre-tax income and a lower effective tax rate in 2009.

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SELECTED ELECTRIC OPERATING STATISTICS

	For the Year Ended
	December 31,
	2009			2008
OPERATING REVENUES (In thousands):
Residential	$	181,889		$	170,997
Commercial		139,443			127,137
Industrial		165,829			150,475
Misc. Revenue		5,963			7,708
Total System		493,124			456,317
Firm Municipal		-			1,015
Other Wholesale		35,412			66,913
	$	528,536		$	524,245
MARGIN (In thousands):
Residential	$	130,191		$	128,975
Commercial		92,654			89,632
Industrial		85,294			82,871
Misc. Revenue		5,495			7,367
Total System		313,634			308,845
Other Wholesale		20,645			32,475
	$	334,279		$	341,320
ELECTRIC SALES (In MWh):
Residential		1,451,707			1,513,784
Commercial		1,309,045			1,336,667
Industrial		2,258,942			2,409,115
Misc. Sales		19,979			19,571
Total System		5,039,673			5,279,137
Firm Municipal		-			44,291
Other Wholesale		603,639			1,512,901
		5,643,312			6,836,329
AVERAGE CUSTOMERS:
Residential		122,380			122,522
Commercial		18,357			18,422
Industrial		105			103
All others		33			34
		140,875			141,081
WEATHER AS A % OF NORMAL:
Cooling Degree Days		90	%		100	%

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SELECTED GAS OPERATING STATISTICS

	For the Year Ended
	December 31,
	2009			2008
OPERATING REVENUES (In thousands):
Residential	$	73,216		$	103,978
Commercial		31,603			49,330
Industrial		4,761			4,930
Misc. Revenue		1,042			1,416
	$	110,622		$	159,654
MARGIN (In thousands):
Residential	$	27,991		$	28,478
Commercial		9,124			9,408
Industrial		4,761			4,930
Misc. Revenue		2,084			2,427
	$	43,960		$	45,243
GAS SOLD & TRANSPORTED (In MDth):
Residential		6,781			7,589
Commercial		3,863			4,062
Industrial		15,263			16,986
		25,907			28,637
AVERAGE CUSTOMERS:
Residential		99,758			100,337
Commercial		10,109			10,182
Industrial		90			88
		109,957			110,607
WEATHER AS A % OF NORMAL:(1)
Heating Degree Days		96	%		102	%

(1) The impact of weather on residential and commercial customers is mitigated by an NTA mechanism.

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