Vectren Utility 8-K Southern Indiana Gas & Electric Company

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2011

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	29
Selected Operating Statistics	33

Additional Information

This annual reporting package provides additional information regarding the operations of Southern Indiana Gas and Electric Company (SIGECO).  This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2011, filed on Form 10-K with the Securities and Exchange Commission on February 16, 2012 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 2, 2012.  Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through its website at www.vectren.com.

Frequently Used Terms

AFUDC:  allowance for funds used during construction	MDth / MMDth:  thousands / millions of dekatherms
EPA:  Environmental Protection Agency	MISO:  Midwest Independent System Operator
DOT:  Department of Transportation	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	Throughput:  combined gas sales and gas transportation volumes

INDEPENDENT AUDITORS’ REPORT

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

We have audited the accompanying balance sheets of Southern Indiana Gas & Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.) as of December 31, 2011 and 2010, 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, 2011 and 2010, 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. 

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 19, 2012

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FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2011		2010
ASSETS
Utility Plant
Original cost	$	2,710,589	$	2,617,833
Less:  Accumulated depreciation & amortization		1,100,326		1,038,736
Net utility plant		1,610,263		1,579,097
Current Assets
Cash & cash equivalents		781		1,353
Accounts receivable - less reserves of $2,757 &
$1,921 respectively		46,382		48,310
Receivables from other Vectren companies		1		-
Accrued unbilled revenues		30,545		34,898
Inventories		108,553		113,811
Recoverable fuel & natural gas costs		2,638		2,551
Prepayments & other current assets		8,303		43,052
Total current assets		197,203		243,975
Investments in unconsolidated affiliates		150		150
Other investments		13,508		12,828
Nonutility plant - net		1,786		2,166
Goodwill - net		5,557		5,557
Regulatory assets		44,379		40,065
Other assets		7,795		1,864
TOTAL ASSETS	$	1,880,641	$	1,885,702

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,
	2011		2010
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	303,256	$	303,256
Retained earnings		418,669		398,628
Accumulated other comprehensive income		44		56
Total common shareholder's equity		721,969		701,940
Long-term debt payable to third parties		266,178		266,017
Long-term debt payable to Utility Holdings, net of current maturities		351,958		297,584
Total long-term debt, net		618,136		563,601
Commitments & Contingencies (Notes 5, 7-10)
Current Liabilities
Accounts payable		24,718		26,922
Accounts payable to affiliated companies		5,242		9,605
Payables to other Vectren companies		21,028		22,119
Accrued liabilities		39,730		44,123
Short-term borrowings payable to Utility Holdings		77,084		70,968
Current maturities of long-term debt payable to Utility Holdings		-		86,584
Total current liabilities		167,802		260,321
Deferred Income Taxes & Other Liabilities
Deferred income taxes		269,343		258,206
Regulatory liabilities		47,482		49,406
Deferred credits & other liabilities		55,909		52,228
Total deferred income taxes & other liabilities		372,734		359,840
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,880,641	$	1,885,702

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,
	2011		2010
OPERATING REVENUES
Electric utility	$	635,940	$	608,042
Gas utility		95,373		105,597
Total operating revenues		731,313		713,639
OPERATING EXPENSES
Cost of fuel & purchased power		240,465		234,982
Cost of gas sold		48,056		59,925
Other operating		178,589		161,508
Depreciation & amortization		87,378		87,240
Taxes other than income taxes		18,478		19,024
Total operating expenses		572,966		562,679
OPERATING INCOME		158,347		150,960
Other income – net		362		2,023
Interest expense		40,409		40,502
INCOME BEFORE INCOME TAXES		118,300		112,481
Income taxes		48,597		45,059
NET INCOME	$	69,703	$	67,422

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,
		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	69,703		$	67,422
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization			87,378			87,240
Deferred income taxes & investment tax credits			22,414			44,558
Expense portion of pension & postretirement periodic benefit cost			2,108			1,876
Provision for uncollectible accounts			2,953			3,284
Other non-cash charges - net			5,565			8,332
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue			3,330			(6,830	)
Inventories			(12,474	)		(8,613	)
Recoverable fuel & natural gas costs			(87	)		(16,815	)
Prepayments & other current assets			34,651			(27,955	)
Accounts payable, including to Vectren companies
& affiliated companies			(6,212	)		(3,620	)
Accrued liabilities			(1,886	)		5,057
Changes in noncurrent assets			(10,002	)		(5,773	)
Changes in noncurrent liabilities			(8,814	)		(12,441	)
Net cash flows from operating activities			188,627			135,722
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt payable to Utility Holdings			54,613			-
Capital contribution from Utility Holdings			-			3,064
Requirements for:
Dividends to Utility Holdings			(49,662	)		(28,846	)
Retirement of long-term debt, including premiums paid			(86,823	)		(523	)
Other financing activities			(28	)		-
Net change in short-term borrowings, including from Utility Holdings			6,116			15,489
Net cash flows from financing activities			(75,784	)		(10,816	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities			85			2,815
Requirements for:
Capital expenditures, excluding AFUDC equity			(112,750	)		(126,257	)
Other investments			(750	)		(515	)
Net cash flows from investing activities			(113,415	)		(123,957	)
Net change in cash & cash equivalents			(572	)		949
Cash & cash equivalents at beginning of period			1,353			404
Cash & cash equivalents at end of period		$	781		$	1,353

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, 2010	$	300,192	$	360,052		$	70		$	660,314
Comprehensive income
Net income				67,422						67,422
Cash flow hedge
Reclassification to net income - net of $23 in tax							(14	)		(14	)
Total comprehensive income										67,408
Common stock:
Capital contribution from Utility Holdings		3,064								3,064
Dividends to Utility Holdings				(28,846	)					(28,846	)
Balance at December 31, 2010	$	303,256	$	398,628		$	56		$	701,940
Comprehensive income
Net income				69,703						69,703
Cash flow hedge
Reclassification to net income - net of $8 in tax							(12	)		(12	)
Total comprehensive income										69,691
Common stock:
Dividends to Utility Holdings				(49,662	)					(49,662	)
Balance at December 31, 2011	$	303,256	$	418,669		$	44		$	721,969

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 approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  Of these customers, approximately 83,000 receive combined electric and gas distribution services.  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 of 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 issued.  The Company’s management has performed a review of subsequent events through March 19, 2012.

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

In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage is recorded using the Last In – First Out (LIFO) method.  Inventory is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.

Plant, Property, & Equipment

Both the Company’s Utility Plant and Nonutility Plant are 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.

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 income – net in the Statements of Income.

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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.

The Company’s portion of jointly-owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.

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.

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.  There were no impairments related to property, plant and equipment during the periods presented.

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, 2011, 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 $0.9 million and $1.1 million at December 31, 2011 and 2010, 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.

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.

-9-

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.

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.

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.

MISO Transactions

With the IURC’s approval, the Company is 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.  The Company is 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.

-10-

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.

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 $9.4 million in 2011 and $9.3 million in 2010.  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)	2011					2010
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Electric utility plant	$	2,316,857		3.3	%	$	2,258,611		3.4	%
Gas utility plant		260,949		3.0	%		252,544		3.0	%
Common utility plant		51,584		2.9	%		49,683		3.1	%
Construction work in progress		81,199		-			56,995		-
Total original cost	$	2,710,589				$	2,617,833

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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, 2011, is $182.6 million with accumulated depreciation totaling $70.3 million.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  SIGECO's share of operating costs is included in Other operating expenses in the Statements of Income.

4.     Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2011			2010
Amounts currently recovered through customer rates related to:
Demand side management programs	$	6,312		$	9,467
Unamortized debt issue costs		7,452			7,986
Premiums paid to reacquire debt		2,647			3,085
Authorized trackers		5,565			6,717
Other		3,274			-
		25,250			27,255
Amounts deferred for future recovery related to:
Deferred coal costs		17,732			-
Cost recovery riders & other		2,013			495
		19,745			495
Future amounts recoverable from ratepayers related to:
Deferred income taxes		(2,890	)		10,267
Asset retirement obligations & other		2,274			2,048
		(616	)		12,315
Total regulatory assets	$	44,379		$	40,065

Of the $25.3 million currently being recovered in rates charged to customers, approximately $6.3 million is earning a return with a weighted average recovery period of 10 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, 2011 and 2010, the Company has approximately $47.5 million and $49.4 million, respectively, in Regulatory liabilities.  Of these amounts, $42.8 million and $44.4 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, 2011 and 2010, totaled $144.1 million and $152.4 million, respectively.  Amounts owed to Vectren Fuels at December 31, 2011 and 2010 are included in Payables to other Vectren companies.

Miller Pipeline, LLC

Miller Pipeline, LLC (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 incurred by SIGECO totaled $5.9 million in 2011 and $3.5 million in 2010.  Amounts owed to Miller at December 31, 2011 and 2010 are included in Payables to other Vectren companies.

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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 as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On March 17, 2011, an order was received by the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.  SIGECO purchases all of its natural gas through ProLiance with regulatory approval from the IURC.

Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2011 and 2010, totaled $57.7 million and $68.7 million, respectively.  Amounts owed to ProLiance at December 31, 2011 and 2010, for those purchases were $5.2 million and $9.6 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.

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 $49.9 million and $54.7 million for the years ended December 31, 2011, and 2010, respectively.  Amounts owed to Vectren and Utility Holdings at December 31, 2011 and 2010 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2011, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover the Company’s eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  Utility Holdings and its subsidiaries, which includes the Company, comprise the vast majority of the participants and retirees covered by these plans.  In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in defined benefit pension plans accounted for as “multiemployer” plans.  The Company has adopted this guidance for the Company’s 2011 financial statements as required which resulted in expanded disclosures. 

Vectren satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations.   However, the Company has no contractual funding commitment.  For the years ended December 31, 2011 and 2010, the Company contributed approximately $14.1 million and $4.8 million, respectively, to Vectren’s defined benefit pension plans.   Such contributions are made to Vectren in total and are not plan specific.  The combined funded status of Vectren’s plans was 83 percent at both December 31, 2011 and 2010.

Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries.  Periodic cost, comprised of service cost and interest on that service cost, is directly charged to subsidiaries based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method.  For the years ended December 31, 2011 and 2010, costs totaling $3.0 million and $2.7 million, respectively, were directly charged to the Company.  Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren and Utility Holdings corporate operations are charged to subsidiaries through the allocation process discussed above.  Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions.  The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting.  As of December 31, 2011 and 2010, $15.7 million and $17.8 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.  As impacted by increased funding of pension plans in 2011, the Company has $7.3 million included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs.   

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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, 2011 and 2010, $13.2 million and $12.1 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 Utility Holdings’ centralized cash management program.  See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

Utility Holdings’ three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $350 million short-term credit facility, of which approximately $243 million is outstanding at December 31, 2011, and Utility Holdings’ $722 million unsecured senior notes outstanding at December 31, 2011.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

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

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.  SIGECO recognizes 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.  

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.  

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Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2011			2010
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	258,908		$	250,024
Regulatory assets recoverable through future rates		10,602			15,705
Other comprehensive income		15			23
Employee benefit obligations		6,719			(22	)
Regulatory liabilities to be settled through future rates		(6,974	)		(7,637	)
Other – net		73			113
Net noncurrent deferred tax liability		269,343			258,206
Current deferred tax liabilities (assets):
Deferred fuel costs		2,280			2,908
Other		(1,443	)		266
Net deferred tax liability	$	270,180		$	261,380

At December 31, 2011 and 2010, ITCs totaling $4.1 million and $4.6 million, respectively, are included in Deferred credits & other liabilities.  These ITCs 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,
		2011		2010
Statutory rate		35.0	%	35.0	%
State & local taxes, net of federal benefit		6.0		6.0
Amortization of investment tax credit		(0.5)		(0.6)
Adjustments to federal income tax accruals		0.3		(0.5)
All other - net		0.3		0.2
	Effective tax rate	41.1	%	40.1	%

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

	Year Ended December 31,
(In thousands)	2011			2010
Current:
Federal	$	18,118		$	(6,193	)
State		8,065			6,694
Total current taxes		26,183			501
Deferred:
Federal		20,329			42,099
State		2,630			3,118
Total deferred taxes		22,959			45,217
Amortization of investment tax credits		(545	)		(659	)
Total income tax expense	$	48,597		$	45,059

Uncertain Tax Positions

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 files combined, consolidated or unitary income tax returns in various states.  The Internal Revenue Service (IRS) has concluded examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005.  Tax years 2006 and 2008 are currently under IRS exam.  The primary focus of the IRS examination is certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry.  Vectren received Notices of Assessment from the IRS related to these deductions.  Vectren responded to the assessments in January 2012 and continues to follow industry activities in this area.  However, in the event the IRS assessments related to these deductions are upheld, any impact is not expected to be material to the Company’s results of operations or financial condition.  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 income tax have expired with respect to tax years through 2005 and through 2007 for Indiana income tax.

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2011 and 2010:

(In thousands)	2011			2010
Unrecognized tax benefits at January 1	$	5,486			4,765
Gross increases - tax positions in prior periods		3,262			712
Gross decreases - tax positions in prior periods		-			(188	)
Gross increases - current period tax positions		157			128
Settlements		(35	)		-
Lapse of statute of limitations		23			69
Unrecognized tax benefits at December 31	$	8,893		$	5,486

Of the change in unrecognized tax benefits during 2011 and 2010, 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, 2011 and December 31, 2010.  As of December 31, 2011, 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. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.  The Company doesn’t expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company’s results of operations or financial condition.

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The Company recognized expense related to interest and penalties totaling approximately $0.5 million in 2011 and $0.1 in 2010.  The Company had approximately $0.7 million and $0.2 million for the payment of interest and penalties accrued as of December 31, 2011 and 2010, respectively.

The net liability on the Balance Sheets for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $8.7 million and $5.2 million, respectively, at December 31, 2011 and 2010.

6.      Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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

			At December 31,
(In thousands)			2011			2010
Senior Unsecured Notes Payable to Utility Holdings:
		2011, 6.625%	$	-		$	86,584
		2015, 5.45%		49,432			49,432
		2018, 5.75%		61,881			61,881
		2020, 6.28%		74,596			74,596
		2021, 4.77%		54,613			-
		2035, 6.10%		25,285			25,285
		2039, 6.25%		86,151			86,390
Total long-term debt payable to Utility Holdings			$	351,958		$	384,168
	Current maturities			-			(86,584	)
	Long-term debt payable to Utility Holdings - net		$	351,958		$	297,584
First Mortgage Bonds Payable to Third Parties:
	2015, 1985 Pollution Control Series A, current adjustable rate 0.10%, tax exempt,
	2011 weighted average: 0.19%		$	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 0.10%, tax exempt,
	2011 weighted average: 0.19%			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			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			267,465
	Unamortized debt premium, discount & other - net			(1,287	)		(1,448	)
	Long-term debt payable to third parties - net		$	266,178		$	266,017

Issuance payable to Utility Holdings

On November 30, 2011, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due November 30, 2041.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $148.9 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  In November 2011, Utility Holdings pushed $55 million of this debt issuance 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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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 2011 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2011 is excluded from Current liabilities in the Balance Sheets.  SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.7 billion at December 31, 2011.  At December 31, 2011, $1.3 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.

Maturities of long-term debt during the five years following 2011 (in millions) are zero in 2012 through 2014, $59.2 in 2015, and $13.0 in 2016.

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.  Certain instruments can be put to the Company upon the death of the holder (death puts).  During 2011 and 2010, the Company repaid approximately $0.2 million and $0.5 million, respectively, related to death puts.

Covenants

Long-term and 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, 2011, the Company was in compliance with all debt covenants.

Short-Term Borrowings

SIGECO relies on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs.  Borrowings outstanding at December 31, 2011 and 2010 were $77.1 million and $71.0 million, respectively.  The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($107 million at December 31, 2011) 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.  See the table below for interest rates and outstanding balances:

		Intercompany Borrowings
(In thousands)		2011			2010
Year End
	Balance Outstanding	$	77,084		$	70,968
	Weighted Average Interest Rate		0.57	%		0.41	%
Annual Average
	Balance Outstanding	$	66,710		$	56,023
	Weighted Average Interest Rate		0.33	%		0.24	%
Maximum Month End Balance Outstanding		$	77,084		$	70,968

During the periods presented, SIGECO had a third party short-term borrowing agreement with $5 million of capacity which expired on June 30, 2010 and was not renewed.

7.     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 utility plant total $8.4 million in 2012, $3.6 million in 2013, and zero in 2014 and thereafter.

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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.

8.     Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  The direction of those regulations will be based on the results of the studies and reports required or authorized by the new law and may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $1 million annually.  Capital investments, driven by the pipeline safety regulations, are expected to be approximately $25 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  The Company expects to seek recovery of capital investments and operating expenses associated with complying with these federal mandates in accordance with Senate Bill 251 (referenced below).  Operating expenses may also be recoverable pursuant to existing tracking mechanisms.

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law.  This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations.  Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.  Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment.  The impact was not material to results of operations or financial condition as the decrease in Deferred tax liabilities was generally offset by a $10.4 million decrease in Regulatory assets.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law.  While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard. 

The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.  The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.  The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.  The financial incentives include an enhanced return on equity and tracking mechanisms to recover program costs.  In advance of a federal portfolio standard and Senate Bill 251, 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 connected 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.  Before the impacts of efficiency measures, the Company currently stands at approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investments.  The Company continues to evaluate whether to participate in this voluntary program.

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9.   Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO2and NOx emissions.  However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR’s implementation.

On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing schedules be submitted by January 18, 2012, that would allow for completion of briefing and a hearing in April 2012.  Two primary issues are before the Court for review:  (1) EPA’s use of air modeling data (as opposed to exclusive reliance on actual monitoring data) to support state contribution levels, and (2) EPA’s allocation of allowances directly through a federal implementation plan as opposed to setting state caps and providing states the opportunity to submit individual state implementation plans.  In addition, there are initiatives in the Congress that, if adopted, would suspend CSPAR’s implementation.

Utility Hazardous Air Pollutants (HAPs) Rule

On December 21, 2011, the EPA finalized the Utility HAPs rule.  The HAPs Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The HAPs rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (early 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the HAPs Rule.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. 

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Utilization of the Company’s NOx and SO2  allowances can be impacted as these regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the Utility HAPs Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances.  However, it is possible some minor modifications to the control equipment and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded back to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis.  A final rule is expected in 2012.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require some retrofitting or closure of existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA 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 2009, the EPA 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 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions.  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The Company anticipates additional EPA rulemaking related to new generation sources and significant modifications to existing sources, but the timetable remains uncertain.

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.

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Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or 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.  At this time and in the absence of final legislation or rulemaking, 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 control greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses 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 if a cap and trade approach were employed, and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current 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.

The Company has identified its involvement in five manufactured gas plants sites, all of which are currently enrolled in the IDEM’s Voluntary Remediation Program (VRP).  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $18.5 million.  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled.  In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.  SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.1 million of expected insurance recoveries.

The costs the Company expects to incur 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 they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2011 and 2010, respectively, approximately $3.9 million and $2.7 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.

Jacobsville Superfund Site

On July 22, 2004, the EPA 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 EPA 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 EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including the Company’s 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 EPA may request additional soil testing at some future date.

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10.   Rate & Regulatory Matters

Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates.  The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  The IURC issued an order in the case on April 27, 2011.  The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses.  The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent.  The new rates were effective May 3, 2011.  The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below.  Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, did not challenge the results of the RFP and the resulting new contracts.  In March 2012, an order was issued by the IURC affirming the Company’s 2011 RFP and resulting contracts.  In addition, the order requested that the Company provide to the OUCC and IURC annual updates on its coal procurement plan within its Fuel Adjustment Clause (FAC) filing.

Electric Fuel Cost Reduction

On December 5, 2011 within the quarterly Fuel Adjustment Clause (FAC) filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating the impact of lower cost coal contracts to be effective after 2012.  In the spring of 2011, Vectren secured contracts for lower coal costs through a formal bidding process. This lower-priced coal is expected to start being delivered and used at Vectren’s power plants by late 2012 to early 2013 and beyond. The agreement to accelerate savings into early 2012 means that the existing 2012 coal costs that are above the new, lower prices will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  This deferral also includes a reduction to the coal inventory balance at December 31, 2011 of approximately $17.7 million to reflect existing inventory at the new, lower price.  The IURC approved this proposal on January 25, 2012, with an impact to customer’s rates effective February 1, 2012.

Electric Demand Side Management Program Filing

On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  On January 26, 2012, the Company filed with the IURC a proposal for a small customer lost margin recovery mechanism within the existing Demand Side Management Adjustment (DSMA).  The proposal includes a request for recovery of the $1 million deferred in 2011, and a request for continued deferral of lost margins in 2012 until such point as these lost margins are included in DSMA rates.  The procedural schedule has not been set in this filing, but the Company expects an order in 2012.

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Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $19 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  Several parties have intervened in the case and are requesting that the IURC deny recovery of these project costs outside of a base rate proceeding.A hearing was held by the IURC in February 2012 and proposed orders are to be submitted by the parties in March 2012.  An order is expected later in 2012.

Gas Decoupling Extension Filing

On April 14, 2011, the Company filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place and recovery of new conservation program costs through December 2015.

11.   Fair Value Measurements

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

	At December 31,
	2011				2010
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	266,178	$	297,301	$	266,017	$	279,867
Long-term debt payable to Utility Holdings		351,958		396,727		384,168		413,445
Short-term borrowings from Utility Holdings		77,084		77,084		70,968		70,968
Cash & cash equivalents		781		781		1,353		1,353

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.

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.

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12.   Additional Balance Sheet & Operational Information

Inventories consist of the following:

		At December 31,
(In thousands)		2011		2010
Materials & supplies		$	34,566	$	32,634
Fuel (coal and oil) for electric generation			60,635		70,076
Gas in storage – at LIFO cost			13,271		10,797
Other			81		304
	Total inventories	$	108,553	$	113,811

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, 2011 and 2010, by approximately $3 million and $4 million, respectively.  All other inventories are carried at average cost.

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

	At December 31,
(In thousands)	2011		2010
Prepaid taxes	$	1,722	$	35,943
Wholesale emission allowances		866		1,056
Other		5,715		6,053
Total prepayments & other current assets	$	8,303	$	43,052

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2011		2010
Accrued taxes	$	9,916	$	13,634
Current deferred taxes		837		3,174
Customers advances & deposits		17,350		15,675
Accrued interest		5,728		5,649
Tax collections payable		2,537		2,731
Accrued salaries & other		3,362		3,260
Total accrued liabilities	$	39,730	$	44,123

Asset retirement obligations included in the Balance Sheets roll forward as follows:

(In thousands)	2011			2010
Asset retirement obligation, January 1	$	9,892		$	12,079
Accretion		605			569
Increases (decreases) in estimates, net of cash payments		(17	)		(2,756	)
Asset retirement obligation, December 31	$	10,480		$	9,892
Accrued liabilities	$	222		$	239
Deferred credits & other liabilities	$	10,258		$	9,653

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

	Year ended December 31,
(In thousands)	2011			2010
AFUDC – borrowed funds	$	265		$	213
AFUDC – equity funds		114			179
Other		(17	)		1,631
Total other income - net	$	362		$	2,023

Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2011			2010
Cash paid (received) for:
Income taxes	$	(5,032	)	$	21,885
Interest		40,330			40,298

As of December 31, 2011 and 2010, the Company has accruals related to utility plant purchases totaling approximately $6.9 million and $8.2 million, respectively.

13.   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)	2011		2010
Revenues
Electric Utility Services	$	635,940	$	608,042
Gas Utility Services		95,373		105,597
Total operating revenues	$	731,313	$	713,639
Profitability Measure
Net Income
Electric Utility Services	$	65,042	$	60,926
Gas Utility Services		4,661		6,496
Total net income	$	69,703	$	67,422
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	80,240	$	80,392
Gas Utility Services		7,138		6,848
Total depreciation & amortization	$	87,378	$	87,240
Interest Expense
Electric Utility Services	$	36,368	$	36,452
Gas Utility Services		4,041		4,050
Total interest expense	$	40,409	$	40,502
Income Taxes
Electric Utility Services	$	45,272	$	40,846
Gas Utility Services		3,325		4,213
Total income taxes	$	48,597	$	45,059
Capital Expenditures
Electric Utility Services	$	102,243	$	120,068
Gas Utility Services		9,681		7,326
Non-cash costs & changes in accruals		826		(1,137	)
Total capital expenditures	$	112,750	$	126,257

	At December 31,
(In thousands)	2011		2010
Assets
Electric Utility Services	$	1,656,455	$	1,666,507
Gas Utility Services		224,186		219,195
Total assets	$	1,880,641	$	1,885,702

14.   Adoption of Other Accounting Standards

Other Comprehensive Income (OCI)

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI.  The guidance does not change the items that must be reported in OCI.  The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required.  The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  The adoption of this guidance will have no material impacts to the Company’s financial statements.

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Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company’s financial statements.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  The adoption of this guidance is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

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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 2011 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.

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.

Executive Summary of Results of Operations

Operating Results

In 2011, SIGECO’s earnings were $69.7 million compared to $67.4 million in 2010.  The year ended 2011 has been positively impacted by new electric base rates implemented on May 3, 2011 and negatively impacted by summer weather that, while warmer than normal, was cooler than the extreme summer temperatures in 2010.  Earnings in 2011 were also reduced by increased power supply operating expenses associated with planned maintenance activities and environmental remediation efforts related to manufactured gas plant sites.

Margin in the Company’s electric territory is impacted by weather.  Management estimates the impact of weather on electric margin, compared to normal temperatures, to be approximately $3.0 million favorable in 2011.  This compares to 2010, where management estimated a $10.4 million favorable impact on margin compared to normal.  In 2010 summer cooling weather was 34 percent warmer than normal.  Although summer temperatures were warmer than normal in 2011, year over year compared to 2010, there was a decline in earnings of approximately $4.4 million after tax.

The Regulatory Environment

Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters are regulated by the IURC.  The Company’s electric territory received an order in April 2011, effective May 2011, and its gas territory received an order in August 2007.  The orders authorize a return on equity of 10.40% on the electric operations and 10.15% for the gas operations.  The authorized returns reflect the impact of innovative rate design strategies having been authorized by the state commission.  Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns.  In addition to timely gas and fuel cost recovery, approximately $16 million of the approximate $179 million in Other operating expenses incurred during 2011 are subject to a recovery mechanism outside of base rates.  In 2011, an Indiana state law was passed that expands the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding.  Therefore, utilization of these mechanisms will likely increase in the coming years.

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 as more efficient appliances and furnaces are installed, SIGECO has implemented conservation programs, and the price of natural gas has been volatile.  In the Company’s natural gas service territory, normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.  In the natural gas service territory, the IURC has authorized a bare steel and cast iron replacement program.  The Company’s electric service territory currently recovers certain transmission investments outside of base rates.  The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives.

-29-

Tracked Operating Expenses

Gas costs and fuel costs incurred to serve customers are two of the Company’s most significant operating expenses.  Rates charged to natural gas customers contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on historical experience.  Electric rates contain a fuel adjustment clause (FAC) that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel.  The net energy cost of purchased power, subject to an approved variable benchmark based on NYMEX natural gas prices, is also timely recovered through the FAC.

GCA and FAC procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period.  The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred.

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test.  These earnings tests have not had any material impact to the Company’s recent operating results and are not expected to have any material impact in the foreseeable future.

Gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery.  Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also recovered outside of base rates.  Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

See Note 10 to the financial statements for more specific information on significant proceedings involving the Company’s utilities.

Operating Trends

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

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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)	2011		2010
Electric utility revenues	$	635,940	$	608,042
Cost of fuel & purchased power		240,465		234,982
Total electric utility margin	$	395,475	$	373,060
Margin attributed to:
Residential & commercial customers	$	255,773	$	241,276
Industrial customers		101,601		97,134
Other customers		8,528		8,430
Subtotal: Retail	$	365,902	$	346,840
Wholesale margin		29,573		26,220
Total electric utility margin	$	395,475	$	373,060
Electric volumes sold in MWh attributed to:
Residential & commercial customers		2,827,220		2,964,022
Industrial customers		2,744,793		2,630,276
Other customers		22,826		22,570
Total retail volumes sold		5,594,839		5,616,868

Retail

Electric retail utility margins were $365.9 million for the year ended December 31, 2011, and compared to 2010 increased $19.1 million.  The impact of new base rates increased margin $23.7 million.  Management estimates the impact of weather, which was warmer than normal but cooler compared to the prior year, to have decreased residential and commercial margin $7.4 million.  Margin increased $2.4 million year over year due to increased MISO operating costs that are directly recovered in margin.

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.  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)	2011		2010
Transmission system sales margin	$	23,474	$	18,814
Off-system sales margin		6,099		7,406
Total wholesale margin	$	29,573	$	26,220

The Company earns 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, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $23.5 million during 2011, compared to $18.8 million in 2010.  Increases are primarily due to increased investment in qualifying projects.

One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and will connect to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results.  Of the total investment, which is expected to approximate $100 million, the Company has invested approximately $74 million as of December 31, 2011.  The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012. 

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For the year ended December 31, 2011, margin from off-system sales was $6.1 million, compared to $7.4 million in 2010.  The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers.  This compares to a $10.5 million sharing threshold established in 2007.  Results for the periods presented reflect the impact of that sharing.  Off-system sales totaled 586.7 GWh in 2011, compared to 587.6 GWh in 2010.

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)	2011		2010
Gas utility revenues	$	95,373	$	105,597
Cost of gas sold		48,056		59,925
Total gas utility margin	$	47,317	$	45,672
Margin attributed to:
Residential & commercial customers	$	35,382	$	36,212
Industrial customers		9,592		6,984
Other customers		2,343		2,476
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		9,643		10,731
Industrial customers		24,186		20,435
Total sold & transported volumes		33,829		31,166

Gas Utility margins were $47.3 million for the year ended December 31, 2011, an increase of $1.6 million compared to 2010.  Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $2.4 million due primarily to ethanol producers.  This increase was partially offset by a $0.5 million decrease year over year due to lower revenue taxes and operating costs recovered in margin.  The average cost per dekatherm of gas purchased during 2011 was $5.11, compared to $5.76 in 2010.

Operating Expenses

Other Operating

For year ended December 31, 2011, Other operating expenses were $178.6 million, increasing $17.1 million compared to 2010.  Excluding expenses tracked directly in margin, operating expenses increased $14.0 million.  This increase reflects variation in electric power supply operating expenses.  Such expenses increased $10.8 million with $6.9 million attributed to planned outage maintenance and $3.1 million attributed to variable production costs.  The remainder of the increase is primarily associated with environmental remediation efforts associated with manufactured gas plant sites which increased $2.9 million compared to 2010.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $0.5 million in 2011 compared to 2010.  The decrease is primarily attributable to lower property taxes.

Other Income

Total other income – net reflects income of $0.4 million compared to $2.0 million in 2010.  The decrease reflects lower returns associated with investments that fund benefit plans.

Income Taxes

For the year ended December 31, 2011, income taxes increased $3.5 million compared to 2010.  The increase is due primarily to increased earnings in 2011.

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SELECTED ELECTRIC OPERATING STATISTICS

	For the Year Ended
	December 31,
	2011			2010
OPERATING REVENUES (In thousands):
Residential	$	212,205		$	206,479
Commercial		159,692			149,690
Industrial		212,303			199,088
Other Revenue		9,205			9,058
Total Retail		593,405			564,315
Net Wholesale Revenues		42,535			43,727
	$	635,940		$	608,042
MARGIN (In thousands):
Residential	$	150,699		$	144,359
Commercial		105,074			96,917
Industrial		101,601			97,134
Other		8,528			8,430
Total Retail		365,902			346,840
Net Wholesale Margin		29,573			26,220
	$	395,475		$	373,060
ELECTRIC SALES (In MWh):
Residential		1,498,586			1,603,509
Commercial		1,328,634			1,360,513
Industrial		2,744,793			2,630,276
Other Sales - Street Lighting		22,826			22,570
Total Retail		5,594,839			5,616,868
Wholesale		586,675			587,563
		6,181,514			6,204,431
AVERAGE CUSTOMERS:
Residential		122,961			122,857
Commercial		18,274			18,321
Industrial		111			108
Other		33			33
		141,379			141,319
WEATHER AS A % OF NORMAL:
Cooling Degree Days		116	%		134	%
Heating Degree Days		91	%		101	%

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SELECTED GAS OPERATING STATISTICS

	For the Year Ended
	December 31,
	2011		2010
OPERATING REVENUES (In thousands):
Residential	$	59,758	$	69,088
Commercial		24,692		28,207
Industrial		9,593		6,984
Other Revenue		1,330		1,318
	$	95,373	$	105,597
MARGIN (In thousands):
Residential	$	27,046	$	27,732
Commercial		8,336		8,480
Industrial		9,592		6,984
Other		2,343		2,476
	$	47,317	$	45,672
GAS SOLD & TRANSPORTED (In MDth):
Residential		6,291		7,158
Commercial		3,352		3,573
Industrial		24,186		20,435
		33,829		31,166
AVERAGE CUSTOMERS:
Residential		99,654		99,811
Commercial		10,084		10,087
Industrial		105		98
		109,843		109,996

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