VECTREN CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

Attached files

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EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	exhibit992-2012sigreportin.htm
8-K - 8-K - VECTREN CORP	sig2012reportingpackage8k.htm

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2012

Contents



		Page Number

	Audited Financial Statements
	Independent Auditors’ Report	2
	Balance Sheets	3-4
	Statements of Income & Comprehensive Income	5
	Statements of Cash Flows	6
	Statements of Common Shareholder’s Equity	7
	Notes to Financial Statements	8
	Results of Operations	30
	Selected Operating Statistics	35

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, 2012, filed on Form 10-K with the Securities and Exchange Commission on February 15, 2013 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K/A filed on March 1, 2013. 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 financial statements of Southern Indiana Gas & Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.), which comprise the balance sheets as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, common shareholder’s equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2012 and 2011, 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 18, 2013

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



			December 31,
			2012		2011
ASSETS

Utility Plant
Original cost			$	2,811,185	$	2,710,589
Less: Accumulated depreciation & amortization			1,157,559		1,100,326
Net utility plant			1,653,626		1,610,263

Current Assets
	Cash & cash equivalents		3,276		781
	Accounts receivable - less reserves of $2,892 &
		$2,757 respectively	44,151		46,382
	Accrued unbilled revenues		25,155		30,545
	Inventories		97,312		108,553
	Recoverable fuel & natural gas costs		5,227		2,638
	Prepayments & other current assets		15,163		8,304
		Total current assets	190,284		197,203

Investments in unconsolidated affiliates			150		150
Other investments			13,939		13,508
Nonutility plant - net			1,714		1,786
Goodwill - net			5,557		5,557
Regulatory assets			63,650		44,379
Other assets			6,377		7,795

TOTAL ASSETS			$	1,935,297	$	1,880,641

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



				December 31,
				2012		2011
LIABILITIES & SHAREHOLDER'S EQUITY
	Common shareholder's equity
		Common stock (no par value)		$	303,256	$	303,256
		Retained earnings		449,235		418,669
		Accumulated other comprehensive income		33		44
			Total common shareholder's equity	752,524		721,969

	Long-term debt payable to third parties			266,339		266,178
	Long-term debt payable to Utility Holdings			351,945		351,958
			Total long-term debt, net	618,284		618,136


Commitments & Contingencies (Notes 5, 7-9)

Current Liabilities
	Accounts payable			25,123		24,718
	Accounts payable to affiliated companies			3,834		5,242
	Payables to other Vectren companies			17,725		21,028
	Accrued liabilities			55,963		39,730
	Short-term borrowings payable to Utility Holdings			66,995		77,084
		Total current liabilities		169,640		167,802

Deferred Income Taxes & Other Liabilities
	Deferred income taxes			295,803		269,343
	Regulatory liabilities			50,028		47,482
	Deferred credits & other liabilities			49,018		55,909
		Total deferred income taxes & other liabilities		394,849		372,734

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY				$	1,935,297	$	1,880,641

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME & COMPREHENSIVE INCOME

(In thousands)



			Year Ended December 31,
			2012			2011
OPERATING REVENUES
	Electric utility		$	594,902		$	635,940
	Gas utility		83,842			95,373
		Total operating revenues	678,744			731,313
OPERATING EXPENSES
	Cost of fuel & purchased power		192,000			240,465
	Cost of gas sold		37,224			48,056
	Other operating		182,616			178,589
	Depreciation & amortization		88,695			87,378
	Taxes other than income taxes		18,138			18,478
		Total operating expenses	518,673			572,966

OPERATING INCOME			160,071			158,347
Other income – net			1,095			362
Interest expense			37,546			40,409
INCOME BEFORE INCOME TAXES			123,620			118,300
Income taxes			50,063			48,597
NET INCOME			$	73,557		$	69,703
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges
	Reclassifications to net income before tax		(19		)	(20		)
	Income Taxes		8			8
		Cash Flow Hedges, net of tax	(11		)	(12		)
TOTAL COMPREHENSIVE INCOME			$	73,546		$	69,691

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



					Year Ended December 31,
						2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income					$	73,557		$	69,703
	Adjustments to reconcile net income to cash from operating activities:
		Depreciation & amortization				88,695			87,378
		Deferred income taxes & investment tax credits				41,211			22,414
		Expense portion of pension & postretirement periodic benefit cost				2,325			2,108
		Provision for uncollectible accounts				2,172			2,953
		Other non-cash charges - net				2,912			5,565
		Changes in working capital accounts:
			Accounts receivable, including to Vectren companies
				& accrued unbilled revenue		5,449			3,330
			Inventories			11,241			(12,474		)
			Recoverable fuel & natural gas costs			(2,589		)	(87		)
			Prepayments & other current assets			(6,937		)	34,651
			Accounts payable, including to Vectren companies
				& affiliated companies		(3,502		)	(6,212		)
			Accrued liabilities			(508		)	(1,886		)
		Changes in noncurrent assets				(29,190		)	(10,002		)
		Changes in noncurrent liabilities				(7,654		)	(8,814		)
				Net cash flows from operating activities		177,182			188,627
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from:
		Long-term debt payable to Utility Holdings				—			54,613
	Requirements for:
		Dividends to Utility Holdings				(42,991		)	(49,662		)
		Retirement of long-term debt, including premiums paid				(13		)	(86,823		)
		Other financing activities				—			(28		)
	Net change in short-term borrowings, including from Utility Holdings					(10,089		)	6,116
				Net cash flows from financing activities		(53,093		)	(75,784		)
CASH FLOWS FROM INVESTING ACTIVITIES
	Proceeds from other investing activities					250			85
	Requirements for:
	Capital expenditures, excluding AFUDC equity					(121,844		)	(112,750		)
	Other investments					—			(750		)
				Net cash flows from investing activities		(121,594		)	(113,415		)
Net change in cash & cash equivalents						2,495			(572		)
Cash & cash equivalents at beginning of period						781			1,353
Cash & cash equivalents at end of period						$	3,276		$	781

The accompanying notes are an integral part of these financial statements

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, 2011		$	303,256	$	398,628		$	56		$	701,940

Net income				69,703						69,703
Other comprehensive income							(12		)	(12		)
Common stock:
	Dividends to Utility Holdings			(49,662		)				(49,662		)
Balance at December 31, 2011		$	303,256	$	418,669		$	44		$	721,969

Net income				73,557						73,557
Other comprehensive income							(11		)	(11		)
Common stock:
	Dividends to Utility Holdings			(42,991		)				(42,991		)
Balance at December 31, 2012		$	303,256	$	449,235		$	33		$	752,524

The accompanying notes are an integral part of these financial statements

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 142,000 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 18, 2013.

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.

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. As of December 31, 2012, 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 $0.7 million and $0.9 million at December 31, 2012 and 2011, 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.

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 will periodically execute 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. 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 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 material 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 in Accrued Unbilled Revenues.

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.

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 $8.8 million in 2012 and $9.4 million in 2011. 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 members 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 assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:



Level 1	Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.
Level 2	Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3	Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

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)		2012				2011
		Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant		$	2,463,607	3.3	%	$	2,316,857	3.3	%
Gas utility plant		269,322		3	%	260,949		3	%
Common utility plant		52,011		3	%	51,584		2.9	%
Construction work in progress		26,245		—		81,199		—
	Total original cost	$	2,811,185			$	2,710,589

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, 2012, is $185.9 million with accumulated depreciation totaling $78.9 million.


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



		At December 31,
(In thousands)		2012			2011
Amounts currently recovered through customer rates related to:
	Demand side management programs	$	4,418		$	6,312
	Unamortized debt issue costs	6,903			7,452
	Premiums paid to reacquire debt	2,209			2,647
	Authorized trackers	8,400			5,565
	Other	986			3,274
		22,916			25,250
Amounts deferred for future recovery related to:
	Deferred coal costs	42,410			17,732
	Cost recovery riders & other	1,269			2,013
		43,679			19,745

Future amounts recoverable from ratepayers related to:
	Deferred income taxes	(5,292		)	(2,890		)
	Asset retirement obligations & other	2,347			2,274
		(2,945		)	(616		)
	Total regulatory assets	$	63,650		$	44,379

Of the $22.9 million currently being recovered in rates charged to customers, $4.4 million associated with demand side management programs is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $14.5 million, is 10 years. The remainder of the regulatory assets is being recovered timely through tracking mechanisms. 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, 2012 and 2011, the Company has approximately $50.0 million and $47.5 million, respectively, in Regulatory liabilities. Of these amounts, $43.5 million and $42.8 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations.


5.	Transactions with Other Vectren Companies

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns 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 purchased for the years ended December 31, 2012 and 2011, totaled $115.6 million and $144.1 million, respectively. Amounts owed to Vectren Fuels at December 31, 2012 and 2011 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 $4.6 million in 2012 and $5.9 million in 2011. Amounts owed to Miller at December 31, 2012 and 2011 are included in Payables to other Vectren companies.

Minnesota Limited, Inc.

Minnesota Limited, Inc. (Minnesota Limited), a wholly owned subsidiary of Vectren through an acquisition on March 31, 2011, provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. Minnesota Limited’s customers include SIGECO. Fees incurred by SIGECO totaled $1.9 million in 2012. There were no transactions with Minnesota Limited prior to 2012. Amounts owed to Minnesota Limited at December 31, 2012 and 2011 are included in Payables to other Vectren companies.

ProLiance

ProLiance, a nonutility energy 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. 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. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2012 and 2011, totaled $40.9 million and $57.7 million, respectively. Amounts owed to ProLiance at December 31, 2012 and 2011, for those purchases were $3.8 million and $5.2 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets.

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates certain 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 are 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 $48.2 million and $49.9 million for the years ended December 31, 2012, and 2011,

respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2012 and 2011 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2012, 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 a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, 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.

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 and did not contribute to Vectren’s defined benefit pension plans during 2012. For the year ended December 31, 2011, the Company contributed approximately $14.1 million 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 approximately 82 percent at December 31, 2012 and 83 percent at December 31, 2011.

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 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, 2012 and 2011, costs totaling $3.3 million and $3.0 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 based on labor. 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, 2012 and 2011, $15.9 million and $15.7 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, at December 31, 2012 and 2011, the Company has $4.2 million and $7.3 million, respectively, included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs.

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, 2012 and 2011, $11.5 million and $13.2 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in Vectren 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 $117 million is outstanding at December 31, 2012, and Utility Holdings’ $822 million unsecured senior notes outstanding at December 31, 2012. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

SIGECO does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file 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 have recently been examined by the IRS, and such examination resulted in no assessments but is in IRS Joint Committee review currently. The primary focus of the IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for Vectren through 2012. To the extent IRS guidance changes in this area, any impact is not expected to be material to the Company’s result 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 2008 for Indiana income tax.

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.

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.

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



		Year Ended December 31,
(In thousands)		2012			2011
Current:
	Federal	$	1,292		$	18,118
	State	7,560			8,065
Total current taxes		8,852			26,183
Deferred:
	Federal	39,298			20,329
	State	2,440			2,630
Total deferred taxes		41,738			22,959
Amortization of investment tax credits		(527		)	(545		)
	Total income tax expense	$	50,063		$	48,597

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




		Year Ended December 31,
		2012			2011

Statutory rate		35.0		%	35.0		%
State & local taxes, net of federal benefit		5.8			6.0
Amortization of investment tax credit		(0.4	)		(0.5	)
Adjustments to federal income tax accruals		—			0.3
All other - net		0.1			0.3
	Effective tax rate	40.5		%	41.1		%

Significant components of the net deferred tax liability follow:



			At December 31,
(In thousands)			2012			2011
Noncurrent deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences		$	287,195		$	258,908
	Regulatory assets recoverable through future rates		14,193			10,602
	Other comprehensive income		—			15
	Employee benefit obligations		7,371			6,719
	Regulatory liabilities to be settled through future rates		(13,043		)	(6,974		)
	Other – net		87			73
		Net noncurrent deferred tax liability	295,803			269,343
Current deferred tax liabilities (assets):
	Deferred fuel costs		18,004			2,280
	Other		(293		)	(1,443		)
		Net current deferred tax liability	17,711			837
		Net deferred tax liability	$	313,514		$	270,180

At December 31, 2012 and 2011, ITCs totaling $3.6 million and $4.1 million, respectively, are included in Deferred credits & other liabilities. These ITCs are amortized over the lives of the related investments.

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2012 and 2011:



(In thousands)	2012			2011
Unrecognized tax benefits at January 1	$	8,893		5,486
Gross increases - tax positions in prior periods	160			3,262
Gross decreases - tax positions in prior periods	(7,701		)	—
Gross increases - current period tax positions	1,179			157
Settlements	—			(35		)
Lapse of statute of limitations	—			23
Unrecognized tax benefits at December 31	$	2,531		$	8,893

Of the change in unrecognized tax benefits during 2012 and 2011, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was zero at December 31, 2012 and December 31, 2011. As of December 31, 2012, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not 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.

The Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling $0.6 million in 2012 and recognized expense related to interest and penalties totaling approximately $0.5 million in 2011. The Company had approximately $0.1 million and $0.7 million for the payment of interest and penalties accrued as of December 31, 2012 and 2011, 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 $2.4 million and $8.7 million, respectively, at December 31, 2012 and 2011.


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)		2012			2011
Senior Unsecured Notes Payable to Utility Holdings:
	2015, 5.45%	$49,432			$49,432
	2018, 5.75%	61,880			61,881
	6/28/2020	74,596			74,596
	2021, 4.67%	54,612			54,613
	6/10/2035	25,284			25,285
	6/25/2039	86,141			86,151
Total long-term debt payable to Utility Holdings		$351,945			$351,958

First Mortgage Bonds Payable to Third Parties:
	2015, 1985 Pollution Control Series A, current adjustable rate 0.15%, tax exempt,
	2012 weighted average: 0.17%	$	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 0.15%, tax exempt,
	2012 weighted average: 0.16%	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	(1,126		)	(1,287		)
	Long-term debt payable to third parties - net	$	266,339		$	266,178

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 December 2, 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 $149 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.

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 2012 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2012 is excluded from Current liabilities in the Balance Sheets. SIGECO’s

gross utility plant balance subject to the Mortgage Indenture approximated $2.8 billion at December 31, 2012. At December 31, 2012, $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 2012 (in millions) are zero in 2013 through 2014, $59.2 in 2015, $13.0 in 2016, and zero in 2017.

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. As an example, certain instruments can be put to the Company upon the death of the holder (death puts) or at specific dates. During 2012, the Company repaid an insignificant amount related to death puts. During 2011, the Company repaid approximately $0.2 million related to death puts. On February 4, 2013, Utility Holdings notified holders of Utility Holdings $121.6 million 6.25 percent senior unsecured notes due 2039, which contained both a put and call provision, of its intent to call the debt at par on April 1, 2013. A portion of these notes had been pushed down to SIGECO and were the only issue outstanding at December 31, 2012 with a put provision.

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, among other restrictions. As of December 31, 2012, 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, 2012 and 2011 were $67.0 million and $77.1 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($233 million at December 31, 2012) 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)		2,012			2,011
Year End
	Balance Outstanding	$	66,995		$	77,084
	Weighted Average Interest Rate	0.4		%	0.57		%
Annual Average
	Balance Outstanding	$	72,214		$	66,710
	Weighted Average Interest Rate	0.46		%	0.33		%
Maximum Month End Balance Outstanding		$	85,673		$	77,084


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 $3.8 million in 2013 and zero in 2014 and thereafter.

Legal Proceedings

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


8.	Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company is currently engaged in replacement programs, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. In 2011, a law in Indiana was passed that expand the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding. Utilization of this recovery mechanism is discussed below.

Recovery and Deferral Mechanisms

The Company received an order in 2007 associated with the most recent base rate cases. This order authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The order provides for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $3 million annually. For USGAAP accounting purposes only the debt-related post in service carrying costs are recognized in the Statements of Income currently. Such deferral is limited by individual qualifying project to three years after being placed into service. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2012 and 2011, the Company has USGAAP regulatory assets totaling $1.0 million and $0.7 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case. To date, the Company has not initiated a filing requesting authority to recover costs using the Senate Bill 251 approach and continues to study its applicability to expenditures associated with its natural gas distribution operations.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $1 million annually. The Company expects to seek recovery under Senate Bill 251, or such costs may be recoverable through current tracking mechanisms. Capital investments, associated with the Pipeline Safety Law, are expected to be significant. The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251.

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 provided for a 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, provided for deferred accounting treatment related to the Company's estimated $32 million investment in dense pack technology, of which approximately $25.5 million has been invested as of December 31, 2012. In addition, the IURC 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 (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South 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 2011 RFP. In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South has also contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower-priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price. Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of December 31, 2012, to the expected level of $42.4 million.

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 were 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 complied 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 $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier.

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.


9.	Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting the Company’s electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability to the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was 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 SO₂emissions 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, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO₂and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS 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 MATS 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 (April 2015). Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

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 SO₂scrubber 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.

Utilization of the Company’s NOx and SO₂allowances can be impacted as 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 the MATS Rule and the 2015 requirement imposed by CAIR. Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment. However, it is possible some operational modifications to the control equipment will be required. Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements. While the Company has not yet quantified what the additional costs may be associated with these efforts, because the compliance is required by government regulation the Company believes that such additional costs, if incurred, should be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements. At this time the Company is reviewing the potential impact this NOV could have on capital expenditures and operating costs. To the extent costs to comply increase, they should be recoverable under Indiana law.

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 2013. Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. EPA is under an April 19, 2013 deadline to complete its rule proposal. It is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 modification to, 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 should qualify as federally mandated regulatory requirements and be recovered 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. EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards for greenhouse gases for new electric generating facilities under Clean Air Act Section 111(b). While standards for new sources are not yet final, EPA has signaled its intent to propose New Source Performance Standards for greenhouse gases for existing electric generating units under Section 111(d), which would be applicable to the Company's existing units. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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.

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 should be recoverable from customers through Senate Bill 251.

Senate Bill 251 also established 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 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 which are defined as

clean energy in the legislation, the Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. The Company continues to evaluate whether to participate in this voluntary program.

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.

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 has incurred or 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 has settlement agreements with all known insurance carriers and has received to date approximately $14 million of the expected $15 million in 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, 2012 and 2011, respectively, approximately $3.2 million and $3.9 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.


10.	Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:



	At December 31,
	2012				2011
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	266,339	$	300,586	$	266,178	$	297,301
Long-term debt payable to Utility Holdings	351,945		399,287		351,958		396,727
Short-term borrowings from Utility Holdings	66,995		66,995		77,084		77,084
Cash & cash equivalents	3,276		3,276		781		781

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.


11.	Additional Balance Sheet & Operational Information

Inventories consist of the following:



		At December 31,
(In thousands)		2012		2011
Materials & supplies		$	34,205	$	34,566
Fuel (coal and oil) for electric generation		51,964		60,635
Gas in storage – at LIFO cost		11,132		13,271
Other		11		81
	Total inventories	$	97,312	$	108,553

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, 2012 and 2011, by approximately $3 million. 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)		2,012		2,011
Prepaid taxes		$	13,221	$	1,722
Wholesale emission allowances		682		866
Other		1,260		5,716
	Total prepayments & other current assets	$	15,163	$	8,304

Accrued liabilities in the Balance Sheets consist of the following:



		At December 31,
(In thousands)		2012		2011
Accrued taxes		$	10,039	$	9,916
Current deferred taxes		17,711		837
Customers advances & deposits		16,997		17,350
Accrued interest		5,754		5,728
Tax collections payable		2,260		2,537
Accrued salaries & other		3,202		3,362
	Total accrued liabilities	$	55,963	$	39,730

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




(In thousands)		2012		2011
Asset retirement obligation, January 1		$	10,480	$	9,892
Accretion		643		605
Changes in estimates, net of cash payments		1,131		(17		)
Asset retirement obligation, December 31		$	12,254	$	10,480
	Accrued liabilities	—		$	222
	Deferred credits & other liabilities	$	12,254	$	10,258

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



		Year ended December 31,
(In thousands)		2012			2011
AFUDC – borrowed funds		$	322		$	265
AFUDC – equity funds		(1		)	114
Cash surrender value of life insurance policies		681			14
Other		93			(31		)
	Total other income - net	$	1,095		$	362

Supplemental Cash Flow Information:



	Year Ended December 31,
(In thousands)	2012		2011
Cash paid (received) for:
Income taxes	$	21,035	$	(5,032	)
Interest	37,520		40,330

As of December 31, 2012 and 2011, the Company has accruals related to utility plant purchases totaling approximately $2.6 million and $6.9 million, respectively.


12.	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.

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



				Year Ended December 31,
(In thousands)				2012			2011
Revenues
	Electric Utility Services			$	594,902		$	635,940
	Gas Utility Services			83,842			95,373
		Total operating revenues		$	678,744		$	731,313


Profitability Measure
	Net Income
		Electric Utility Services		$	67,959		$	65,042
		Gas Utility Services		5,598			4,661
			Total net income	$	73,557		$	69,703

Amounts Included in Profitability Measures
	Depreciation & Amortization
		Electric Utility Services		$	81,299		$	80,240
		Gas Utility Services		7,396			7,138
			Total depreciation & amortization	$	88,695		$	87,378

	Interest Expense
		Electric Utility Services		$	33,774		$	36,368
		Gas Utility Services		3,772			4,041
			Total interest expense	$	37,546		$	40,409

	Income Taxes
		Electric Utility Services		$	46,352		$	45,272
		Gas Utility Services		3,711			3,325
			Total income taxes	$	50,063		$	48,597

Capital Expenditures
	Electric Utility Services			$	108,845		$	102,243
	Gas Utility Services			13,025			9,681
	Non-cash costs & changes in accruals			(26		)	826
		Total capital expenditures		$	121,844		$	112,750

				At December 31,
(In thousands)				2012			2011
Assets
	Electric Utility Services			$	1,705,159		$	1,656,455
	Gas Utility Services			230,138			224,186
		Total assets		$	1,935,297		$	1,880,641


13.	Adoption of Other Accounting Standards

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance requires 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 adopted this guidance for the quarterly reporting period ended March 31, 2012.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment. The new guidance allows 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 Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

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 Company adopted this guidance for its quarterly reporting period ended March 31, 2012. The adoption of this guidance did not 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 2012 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 2012, SIGECO’s earnings were $73.6 million compared to $69.7 million in 2011. The increased earnings in 2012 reflect, among other things, the impacts of new electric base rates implemented on May 3, 2011 and lower interest expense as a result of refinancing activity completed late in 2011.

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 $18 million of the approximate $183 million in Other operating expenses incurred during 2012 are subject to a recovery mechanism outside of base rates.

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are largely 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 and the Company has implemented conservation programs. In the Company’s natural gas service territory, normal temperature adjustment (NTA) and decoupling 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.

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 actual experience, subject to caps that are 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. The FAC earnings test had some impact on the Company’s 2012 operating results, as discussed below.

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 regional electric transmission assets not in base rates are also recovered by mechanisms outside of base rate recovery. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

In 2011, a state law was passed in Indiana that expands the ability of utilities to recover certain costs of federally mandated projects outside of a base rate proceeding. Utilization of this mechanism will likely increase in the coming years.

See Note 8 to the financial statements for more specific information on significant proceedings involving the Company.

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.

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)			2012		2011

Electric utility revenues			$	594,902	$	635,940
Cost of fuel & purchased power			192,000		240,465
	Total electric utility margin		$	402,902	$	395,475
Margin attributed to:
	Residential & commercial customers		$	258,491	$	255,773
	Industrial customers		103,428		101,601
	Other customers		8,882		8,528
	Subtotal: Retail		$	370,801	$	365,902
	Wholesale margin		32,101		29,573
	Total electric utility margin		$	402,902	$	395,475
Electric volumes sold in MWh attributed to:
	Residential & commercial customers		2,731,677		2,827,220
	Industrial customers		2,710,523		2,744,793
	Other customers		22,552		22,826
		Total retail volumes sold	5,464,752		5,594,839

Retail

Electric retail utility margins were $370.8 million for the year ended December 31, 2012 and, compared to 2011, increased by $4.9 million. The impact year over year of new retail base rates that were effective May 3, 2011 was an increase in margin of approximately $10.0 million. Offsetting a portion of the increase was a decline in small customer usage that lowered margin by $2.6 million in 2012 as a result of energy conservation, net of an approved lost margin recovery mechanism. Weather also impacted margin and, compared to normal temperatures, increased results $2.7 million and $3.0 million, in 2012 and 2011, respectively. Due in part to the favorable weather in both periods, the Company provided refunds to customers in 2012 totaling $2.6 million pursuant to the statutory earnings test. Indiana regulation includes a statutory mechanism that can limit a utility's rolling twelve month net operating income to that authorized in its last general rate order, as adjusted for previous net operating income levels that were below authorized levels. Should weather or other factors continue to increase net operating income in future periods, the full benefit of those favorable impacts on the Company's electric utility may continue to be limited by the statutory earnings test. Finally, though volumes sold to large customers during 2012 decreased, the impact on margin was small as certain large customers have rate structures that include both a daily peak usage component, as well as a volumetric component.

Margin from Wholesale Electric Activities

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 and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off-system margin and transmission system margin follows:



		Year Ended December 31,
(In thousands)		2012		2011
Transmission system sales margin		$	26,391	$	23,474
Off-system sales margin		5,710		6,099
	Total wholesale margin	$	32,101	$	29,573

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $26.4 million during 2012, compared to $23.5 million in 2011. The increase is primarily due to increased investment in qualifying projects. To date, the Company has invested $155 million in qualifying projects. These projects include an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance, and operating expenses are also recovered. The 345 Kv project is the largest of these qualifying projects, with a cost of $107 million that earned the FERC approved equity rate of return while under construction. The last segment of that project was placed into service in December 2012.

For the year ended December 31, 2012, margin from off-system sales was $5.7 million, compared to $6.1 million in 2011. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year 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 336.7 GWh in 2012, compared to 586.7 GWh in 2011. The lower volumes sold in 2012 from Vectren South's primarily coal-fired generation result from increased sales of power in MISO from gas-fired electric generation due to low natural gas prices and more wind generation.

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)			2012		2011
Gas utility revenues			$	83,842	$	95,373
Cost of gas sold			37,224		48,056
	Total gas utility margin		$	46,618	$	47,317
Margin attributed to:
	Residential & commercial customers		$	34,857	$	35,382
	Industrial customers		9,454		9,691
	Other customers		2,307		2,244
Sold & transported volumes in MDth attributed to:
	Residential & commercial customers		8,551		9,643
	Industrial customers		29,017		24,186
		Total sold & transported volumes	37,568		33,829

Gas Utility margins were $46.6 million for the year ended December 31, 2012, a decrease of $0.7 million compared to 2011. The impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs decreased gas utility margin $1.0 million in 2012 compared to 2011. The average cost per dekatherm of gas purchased during 2012 was $4.56, compared to $5.11 in 2011. With rate designs that substantially limit the impact of weather on margin, heating temperatures in 2012 that were 79 percent of normal had a significant impact on residential and commercial customer volumes sold, but no impact on residential and commercial customer margin. Large customer volumes in 2012 compared to 2011 significantly increased due to natural gas transported to a natural gas fired power plant that was recently placed into service. Volumes delivered to this customer are based on a monthly fixed charge and began in 2010 when service was initiated.

Operating Expenses

Other Operating

For year ended December 31, 2012, Other operating expenses were $182.6 million, increasing $4.0 million compared to 2011. Excluding expenses tracked directly in margin, operating expenses increased $0.5 million. This increase reflects variation in electric power supply operating expenses which increased $3.1 million in 2012 compared to 2011. Such increased expenses were partially offset by lower environmental remediation costs associated with manufactured gas plant site and lower uncollectible accounts expense driven by lower gas prices increasing the customer’s ability to pay.

Depreciation & Amortization

Depreciation and amortization expense was $88.7 million in 2012, compared to $87.4 million in 2011. The periods presented reflect increased plant investments placed into service. However, regulatory orders allowing for deferral of depreciation on capital investments previously placed into service were received that somewhat offset the impact of plant increases in 2012.

Other Income

Total other income – net reflects income of $1.1 million compared to $0.4 million in 2011. The increase in 2012 primarily reflects increased returns on assets that fund Vectren’s benefit plans.

Interest Expense

Interest expense was $37.5 million in 2012. Interest expense decreased $2.9 year over year compared to 2011. The lower expense reflects fourth quarter of 2011 refinancing activity in which $86 million of long-term debt with a 6.625 percent interest rate matured and was replaced with $55 million of new long-term debt with an interest rate of 4.77 percent and $31 million of short-term borrowings.

Income Taxes

For the year ended December 31, 2012, income taxes increased $1.5 million compared to 2011. The increase is due primarily to increased earnings in 2012.

SELECTED ELECTRIC OPERATING STATISTICS





		For the Year Ended
		December 31,
		2012			2011

OPERATING REVENUES (In thousands):
	Residential	$	203,115		$	212,205
	Commercial	148,427			159,692
	Industrial	192,855			212,303
	Other Revenue	9,458			9,205
	Total Retail	553,855			593,405
	Net Wholesale Revenues	41,047			42,535
		$	594,902		$	635,940
MARGIN (In thousands):
	Residential	$	154,333		$	150,699
	Commercial	104,158			105,074
	Industrial	103,428			101,601
	Other	8,882			8,528
	Total Retail	370,801			365,902
	Net Wholesale Margin	32,101			29,573
		$	402,902		$	395,475
ELECTRIC SALES (In MWh):
	Residential	1,434,348			1,498,586
	Commercial	1,297,329			1,328,634
	Industrial	2,710,523			2,744,793
	Other Sales - Street Lighting	22,552			22,826
	Total Retail	5,464,752			5,594,839
	Wholesale	336,715			586,675
		5,801,467			6,181,514
AVERAGE CUSTOMERS:
	Residential	123,303			122,961
	Commercial	18,297			18,274
	Industrial	115			111
	Other	33			33
		141,748			141,379
WEATHER AS A % OF NORMAL:
	Cooling Degree Days	130		%	116		%
	Heating Degree Days	79		%	91		%

SELECTED GAS OPERATING STATISTICS



		For the Year Ended
		December 31,
		2012		2011

OPERATING REVENUES (In thousands):
	Residential	$	51,958	$	59,758
	Commercial	21,250		24,692
	Industrial	9,454		9,593
	Other Revenue	1,180		1,330
		$	83,842	$	95,373

MARGIN (In thousands):
	Residential	$	26,627	$	27,046
	Commercial	8,230		8,336
	Industrial	9,454		9,691
	Other	2,307		2,244
		$	46,618	$	47,317
GAS SOLD & TRANSPORTED (In MDth):
	Residential	5,553		6,291
	Commercial	2,998		3,352
	Industrial	29,017		24,186
		37,568		33,829

AVERAGE CUSTOMERS:
	Residential	99,543		99,654
	Commercial	10,128		10,084
	Industrial	111		105
		109,782		109,843

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