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

Attached files

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8-K - SIG REPORTING PACKAGE - VECTREN CORP	vvc_8k.htm
EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	ex99_2.htm

Exhbit 99.1

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2010

Contents

		Page Number

	Audited Financial Statements
	Independent Auditors’ Report	2
	Balance Sheets	3-4
	Statements of Income	5
	Statements of Cash Flows	6
	Statements of Common Shareholder’s Equity	7
	Notes to Financial Statements	8
	Results of Operations	27
	Selected Operating Statistics	31

Additional Information

This annual reporting package provides additional information regarding the operations of Southern Indiana Gas and Electric Company (SIGECO). This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2010, filed on Form 10-K with the Securities and Exchange Commission on February 17, 2011 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 4, 2011. 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	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	EPA: United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms	Throughput: combined gas sales and gas transportation volumes
MISO: Midwest Independent System Operator

-1-

INDEPENDENT AUDITORS’ REPORT

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

We have audited the accompanying balance sheets of Southern Indiana Gas & Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.) as of December 31, 2010 and 2009, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2010 and 2009, 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 15, 2011

-2-

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2010		2009
ASSETS

Utility Plant
Original cost	$	2,617,833	$	2,503,333
Less: Accumulated depreciation & amortization		1,038,736		975,544
Net utility plant		1,579,097		1,527,789

Current Assets
Cash & cash equivalents		1,353		404
Accounts receivable - less reserves of $1,921 &
$2,027 respectively		48,310		46,322
Accrued unbilled revenues		34,898		33,340
Inventories		113,811		105,198
Recoverable fuel & natural gas costs		2,551		-
Prepayments & other current assets		43,052		15,139
Total current assets		243,975		200,403

Investments in unconsolidated affiliates		150		150
Other investments		12,828		14,208
Nonutility plant - net		2,166		2,366
Goodwill - net		5,557		5,557
Regulatory assets		40,065		45,106
Other assets		1,864		2,695
TOTAL ASSETS	$	1,885,702	$	1,798,274

The accompanying notes are an integral part of these financial statements

-3-

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)

	December 31,
	2010		2009
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	303,256	$	300,192
Retained earnings		398,628		360,052
Accumulated other comprehensive income		56		70
Total common shareholder's equity		701,940		660,314

Long-term debt payable to third parties		266,017		224,581
Long-term debt payable to Utility Holdings, net of current maturities		297,584		384,692
Total long-term debt, net		563,601		609,273


Commitments & Contingencies (Notes 5, 8-10)

Current Liabilities
Accounts payable		26,922		22,450
Accounts payable to affiliated companies		9,605		8,030
Payables to other Vectren companies		22,119		31,693
Refundable fuel & natural gas costs		-		14,264
Accrued liabilities		44,123		41,521
Short-term borrowings payable to Utility Holdings		70,968		55,479
Current maturities of long-term debt payable to Utility Holdings		86,584		-
Long-term debt subject to tender		-		41,275
Total current liabilities		260,321		214,712

Deferred Income Taxes & Other Liabilities
Deferred income taxes		258,206		209,361
Regulatory liabilities		49,406		49,996
Deferred credits & other liabilities		52,228		54,618
Total deferred income taxes & other liabilities		359,840		313,975
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,885,702	$	1,798,274

The accompanying notes are an integral part of these financial statements

-4-

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2010		2009
OPERATING REVENUES
Electric utility	$	608,042	$	528,536
Gas utility		105,597		110,622
Total operating revenues		713,639		639,158
OPERATING EXPENSES
Cost of fuel & purchased power		234,982		194,257
Cost of gas sold		59,925		66,662
Other operating		161,508		160,225
Depreciation & amortization		87,240		83,605
Taxes other than income taxes		19,024		16,283
Total operating expenses		562,679		521,032

OPERATING INCOME		150,960		118,126

Other income – net		2,023		2,856

Interest expense		40,502		38,709
INCOME BEFORE INCOME TAXES		112,481		82,273
Income taxes		45,059		30,019
NET INCOME	$	67,422	$	52,254

The accompanying notes are an integral part of these financial statements

-5-

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
		2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	67,422		$	52,254
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization			87,240			83,605
Deferred income taxes & investment tax credits			44,558			54,148
Expense portion of pension & postretirement periodic benefit cost			1,876			1,813
Provision for uncollectible accounts			3,284			2,995
Other non-cash charges - net			8,332			7,697
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue			(6,830	)		12,738
Inventories			(8,613	)		(44,821	)
Recoverable fuel & natural gas costs			(16,815	)		17,324
Prepayments & other current assets			(27,955	)		(10,833	)
Accounts payable, including to Vectren companies
& affiliated companies			(3,620	)		(5,124	)
Accrued liabilities			5,057			4,474
Changes in noncurrent assets			(5,773	)		(11,954	)
Changes in noncurrent liabilities			(12,441	)		(21,729	)
Net cash flows from operating activities			135,722			142,587
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt payable to Utility Holdings			-			74,596
Long-term debt payable to third parties - net of issuance costs			-			61,846
Capital contribution from Utility Holdings			3,064			6,929
Requirements for:
Dividends to Utility Holdings			(28,846	)		-
Retirement of long-term debt, including premiums paid			(523	)		(1,406	)
Net change in short-term borrowings, including from Utility Holdings			15,489			(94,346	)
Net cash flows from financing activities			(10,816	)		47,619
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities			2,815			-
Requirements for:
Capital expenditures, excluding AFUDC equity			(126,257	)		(191,114	)
Other investments			(515	)		(3,178	)
Net cash flows from investing activities			(123,957	)		(194,292	)
Net change in cash & cash equivalents			949			(4,086	)
Cash & cash equivalents at beginning of period			404			4,490
Cash & cash equivalents at end of period		$	1,353		$	404

The accompanying notes are an integral part of these financial statements

-6-

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

							Accumulated
							Other
		Common		Retained			Comprehensive
		Stock		Earnings			Income			Total
Balance at January 1, 2009	$	293,263	$	307,798		$	104		$	601,165

Comprehensive income
Net income				52,254						52,254
Cash flow hedge
Reclassification to net income - net of $55 in tax							(34	)		(34	)
Total comprehensive income										52,220
Common stock:
Capital contribution from Utility Holdings		6,929								6,929
Balance at December 31, 2009	$	300,192	$	360,052		$	70		$	660,314

Comprehensive income
Net income				67,422						67,422
Cash flow hedge
Reclassification to net income - net of $23 in tax							(14	)		(14	)
Total comprehensive income										67,408
Common stock:
Capital contribution from Utility Holdings		3,064								3,064
Dividends to Utility Holdings				(28,846	)					(28,846	)
Balance at December 31, 2010	$	303,256	$	398,628		$	56		$	701,940

The accompanying notes are an integral part of these financial statements

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SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS

1.	Organization & Nature of Operations

Southern Indiana Gas and Electric Company (the Company, SIGECO or Vectren South), an Indiana corporation, provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 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.

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.

-8-

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.

Goodwill

Goodwill recorded on the Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2010, no goodwill impairments have been recorded. All of the Company’s goodwill is included in the Gas Utility Services operating segment.

Intangible Assets

The Company has emission allowances relating to its wholesale power marketing operations totaling $1.1 million and $1.3 million at December 31, 2010 and 2009, respectively. The value of the emission allowances are recognized as they are consumed or sold.

Regulation

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

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.

Regulatory Assets & Liabilities

Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdiction, the Company believes such accounting is appropriate.

-9-

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.

Asset Retirement Obligations

A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

Energy Contracts & Derivatives

The Company occasionally executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. In most cases, a derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.

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

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not significant to these financial statements.

Revenues

Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.

MISO Transactions

With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

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

-10-

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from/refunded to retail customers through tracking mechanisms.

Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $9.3 million in 2010 and $8.4 million in 2009. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

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

Fair Value Measurements

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

Earnings Per Share

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

Other Significant Policies

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

3.	Utility Plant & Depreciation

The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows:


	At and For the Year Ended December 31,
(In thousands)	2010					2009
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	2,258,611		3.4	%	$	2,113,254		3.4	%
Gas utility plant		252,544		3.0	%		234,972		3.0	%
Common utility plant		49,683		3.1	%		48,785		2.9	%
Construction work in progress		56,995		-			106,322		-
Total original cost	$	2,617,833				$	2,503,333

-11-

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, 2010, is $176.2 million with accumulated depreciation totaling $59.2 million. The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $3.1 million at December 31, 2010. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Statements of Income.

4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:


	At December 31,
(In thousands)	2010		2009
Amounts currently recovered through customer rates related to:
Demand side management programs	$	9,467	$	15,348
Unamortized debt issue costs		7,986		8,418
Premiums paid to reacquire debt		3,085		3,523
Authorized trackers		6,717		6,084
Other		-		1,078
		27,255		34,451
Amounts deferred for future recovery related to:
Cost recovery riders & other		495		308

Future amounts recoverable from ratepayers related to:
Deferred income taxes		10,267		6,111
Asset retirement obligations & other		2,048		4,236
		12,315		10,347
Total regulatory assets	$	40,065	$	45,106

Of the $27.3 million currently being recovered in rates charged to customers, approximately $9.5 million is earning a return with a weighted average recovery period of 8 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory Liabilities

At December 31, 2010 and 2009, the Company has approximately $49.4 million and $50.0 million, respectively, in Regulatory liabilities. Of these amounts, $44.4 million and $44.8 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations.

5.	Transactions with Other Vectren Companies

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC. Amounts paid for such purchases for the years ended December 31, 2010 and 2009, totaled $152.4 million and $152.9 million, respectively. Amounts owed to Vectren Fuels at December 31, 2010 and 2009 are included in Payables to other Vectren companies.

Miller Pipeline Corporation

Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include SIGECO. Fees paid by SIGECO totaled $4.2 million in 2010 and $8.8 million in 2009. Amounts owed to Miller at December 31, 2010 and 2009 are included in Payables to other Vectren companies.

-12-

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 and nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company through March 2011. On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLiance’s continued provision of gas supply services to the Company and Citizens Gas for the period of April 1, 2011 through March 31, 2016. The settlement has been agreed to by all of the representatives that were parties to the prior settlement. An order is anticipated during the first quarter of 2011. SIGECO purchases all of its natural gas through ProLiance with regulatory approval from the IURC.

Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2010 and 2009, totaled $68.7 million and $74.9 million, respectively. Amounts owed to ProLiance at December 31, 2010 and 2009, for those purchases were $9.6 million and $8.0 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. SIGECO received corporate allocations totaling $54.7 million and $59.3 million for the years ended December 31, 2010, and 2009, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2010 and 2009 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

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

For the years ended December 31, 2010 and 2009, periodic pension costs totaling $2.4 million and $2.3 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2010 and 2009, other periodic postretirement benefit costs totaling $0.3 million and $0.3 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2010 and 2009, $17.8 million and $21.0 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.

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, 2010 and 2009, $12.1 million and $11.2 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.

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Guarantees of Parent Company Debt

Vectren’s three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $350 million short-term credit facility and Utility Holdings’ $919 million unsecured senior notes outstanding at December 31, 2010. As impacted by the borrowings and cash positions of its subsidiaries, approximately $47 million of short-term borrowings were outstanding at December 31, 2010. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

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

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

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

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

Significant components of the net deferred tax liability follow:


	At December 31,
(In thousands)	2010			2009
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	250,024		$	207,474
Regulatory assets recoverable through future rates		15,705			15,774
Other comprehensive income		23			33
Employee benefit obligations		(22	)		(4,759	)
Regulatory liabilities to be settled through future rates		(7,637	)		(9,171	)
Other – net		113			10
Net noncurrent deferred tax liability		258,206			209,361
Current deferred tax liabilities, primarily demand side management
and other regulatory assets		3,174			3,436
Net deferred tax liability	$	261,380		$	212,797

At December 31, 2010 and 2009, ITCs totaling $4.6 million and $5.3 million, respectively, are included in Deferred credits & other liabilities. These ITCs are amortized over the lives of the related investments.

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


	Year Ended December 31,
	2010			2009
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.0			5.3
Amortization of investment tax credit		(0.6	)		(1.1	)
Adjustments to federal income tax accruals		(0.5	)		(2.0	)
All other - net		0.2			(0.7	)
Effective tax rate		40.1	%		36.5	%

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


	Year Ended December 31,
(In thousands)	2010			2009
Current:
Federal	$	(6,193	)	$	(24,996	)
State		6,694			867
Total current taxes		501			(24,129	)
Deferred:
Federal		42,099			48,622
State		3,118			6,396
Total deferred taxes		45,217			55,018
Amortization of investment tax credits		(659	)		(870	)
Total income tax expense	$	45,059		$	30,019

Uncertain Tax Positions

SIGECO does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren files combined, consolidated or unitary income tax returns in various states. The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005. Tax years 2006 and 2008 are currently under IRS exam. The 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 2006 for Indiana income tax.

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2010 and 2009:


(In thousands)	2010			2009
Unrecognized tax benefits at January 1	$	4,765			515
Gross increases - tax positions in prior periods		712			1,162
Gross decreases - tax positions in prior periods		(188	)		(1,582	)
Gross increases - current period tax positions		128			4,376
Lapse of statute of limitations		69			294
Unrecognized tax benefits at December 31	$	5,486		$	4,765

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Of the change in unrecognized tax benefits during 2010 and 2009, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was insignificant at December 31, 2010 and December 31, 2009. As of December 31, 2010, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.

The Company recognized expense related to interest and penalties totaling approximately $0.1 million in 2010 and none in 2009. The Company had approximately $0.2 million and $0.1 million for the payment of interest and penalties accrued as of December 31, 2010 and 2009, 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 $5.2 million and $4.5 million, respectively, at December 31, 2010 and 2009.

6.	Borrowing Arrangements & Other Financing Transactions

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, 2010 and 2009 were $71.0 million and $55.5 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($303 million at December 31, 2010) 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 millions)		2010			2009
Year End
	Balance Outstanding	$	71.0		$	55.5
	Weighted Average Interest Rate		0.41	%		0.25	%
Annual Average
	Balance Outstanding	$	56.0		$	83.9
	Weighted Average Interest Rate		0.24	%		0.71	%
Maximum Month End Balance Outstanding		$	71.0		$	148.6

During the periods presented, SIGECO had a third party short-term borrowing agreement with $5 million of capacity. The arrangement expired on June 30, 2010 and was not renewed. During 2010 and 2009, insignificant borrowings were outstanding during the year and none were outstanding at December 31, 2010 or 2009. In 2010, the annual weighted average interest rate was 2.04% with a maximum month end balance outstanding of $0.2 million. In 2009, the annual weighted average interest rate was 1.34% with a maximum month end balance outstanding of $3.3 million and an annual average balance outstanding of $0.1 million.

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Long-Term Debt

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


		At December 31,
(In thousands)		2010			2009
Senior Unsecured Notes Payable to Utility Holdings:
	2011, 6.625%	$	86,584		$	86,584
	2015, 5.45%		49,432			49,432
	2018, 5.75%		61,881			61,881
	2020, 6.28%		74,596			74,596
	2035, 6.10%		25,285			25,285
	2039, 6.25%		86,390			86,914
Total long-term debt payable to Utility Holdings		$	384,168		$	384,692
	Current maturities		(86,584	)		-
	Long-term debt payable to Utility Holdings - net	$	297,584		$	384,692

First Mortgage Bonds Payable to Third Parties:
	2015, 1985 Pollution Control Series A, current adjustable rate 0.33%, tax exempt,
	2010 weighted average: 0.27%	$	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 0.33%, tax exempt,
	2010 weighted average: 0.27%		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
	Debt subject to tender		-			(41,275	)
	Unamortized debt premium, discount & other - net		(1,448	)		(1,609	)
	Long-term debt payable to third parties - net	$	266,017		$	224,581

Issuance payable to Utility Holdings

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

SIGECO 2009 Debt Issuance

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

Auction Rate Securities

In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity. On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.

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Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2010 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2010 is excluded from Current liabilities in the Balance Sheets. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.6 billion at December 31, 2010. At December 31, 2010, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.

Maturities of long-term debt during the five years following 2010 (in millions) are $86.6 in 2011, zero in 2012 through 2014, and $59.2 in 2015.

Long-Term Debt Put & Call Provisions

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2010 and 2009, the Company repaid approximately $0.5 million and $1.4 million, respectively, related to death puts.

Covenants

Long-term and borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2010, the Company was in compliance with all financial covenants.

7.	Accumulated Other Comprehensive Income

Comprehensive income is a measure of all changes in equity that result from the non-shareholder transactions. This information is reported in the Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past two years follows:


	2009								2010
	Beginning			Changes			End		Changes			End
	of Year			During			of Year		During			of Year
(In thousands)	Balance			Year			Balance		Year			Balance

Cash flow hedges	$	159		$	(89	)	$	70	$	9		$	79
Deferred income taxes		(55	)		55			-		(23	)		(23	)
Accumulated other comprehensive income	$	104		$	(34	)	$	70	$	(14	)	$	56

8.	Commitments & Contingencies

Purchase Commitments

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

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Legal Proceedings

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

9.	Environmental Matters

Clean Air Act

The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while EPA revises it per the Court’s guidance. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised. 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.

Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. In response to the court decision, EPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2011. It is uncertain what emission limit the EPA is considering, and whether they will address hazardous pollutants in addition to mercury.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA. On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment. The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utilization of currently granted SO2 and NOx allowances. The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.

Climate Change

Numerous competing 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 slowed. While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.

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

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In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the 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 of 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 of 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. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The EPA has also recently 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.

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. Further, any legislation or regulatory actions taken by the EPA or other agencies would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to 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 recovery should be timely reflected in rates charged to customers. Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Ash Ponds & Coal Ash Disposal Regulations

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 EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations. The alternatives include regulating coal combustion by-products as hazardous waste. At this time, the majority of the Company’s ash is being beneficially reused. The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances. 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.

Clean Water Act

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures. In April of 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 facilities. The regulation was remanded back to the EPA for further consideration. Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.

Jacobsville Superfund Site

On July 22, 2004, the EPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The EPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. The Company’s property has not been named as a source of the lead contamination. The Company's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels. At this time, it is anticipated that the EPA may request only additional soil testing at some future date.

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Environmental Remediation Efforts

In the past, SIGECO operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s Voluntary Remediation Program (VRP). In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site. SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the recently settled lawsuit. In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $15.8 million. However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation. While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.2 million in proceeds have been received.

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 SIGECO 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 recovery from potentially responsible parties or from insurance. As of December 31, 2010 and 2009, respectively, approximately $2.7 million and $3.4 million of accrued, but not yet spent, costs are included in Deferred credits & other liabilities related to these sites.

10.	Rate & Regulatory Matters

Electric Base Rate Filing

On December 11, 2009, the Company filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates 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. On July 30, 2010, the Company revised downward its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues. The rate design proposed in the filing would break the link between small residential and commercial customers’ consumption and the utility’s margin, thereby aligning the utility’s and customers’ interests in using less energy. The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent. The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively. Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory. Hearings on all matters in the case were held in early March and late August 2010. An order is anticipated in the first half of 2011.

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Electric Fuel Adjustment Filings

As stated above, electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy charges to reflect changes in the cost of fuel and purchased power. The FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South’s fuel and purchased power costs.

During 2010, as part of its FAC testimony, the OUCC requested the IURC require the Company to renegotiate its term coal contracts because they were priced higher than prevailing spot prices. This request was repeated by the OUCC in the Company’s base rate proceeding referred to above. The Company purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of Vectren Corporation) under coal contracts entered into in 2008. The Company states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties. Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volumes in 2011, with further price negotiation to occur in 2011 under the terms of the contracts. The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.

The OUCC also raised concerns regarding the Company’s generating unit “must run” policy. Under that policy, for reliability reasons, the Company instructs the MISO that certain units must be dispatched regardless of current market conditions. The OUCC is reviewing data related to the Company’s “must run” policy.

The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above. An order establishing the sub docket was issued by the IURC on July 28, 2010. On November 30, 2010, in response to a joint motion filed by the OUCC and the Company, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending electric base rate case.

Electric Demand Side Management Program Filing

On August 16, 2010, the Company filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including 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.

In its August filing, the Company proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC. The Company requested recovery of these program costs under a current tracking mechanism. In addition, the Company proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC. This performance incentive would also be recovered in the same tracking mechanism. Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending electric base rate case. On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company’s programs and lost margin recovery from large customers. A hearing was held on March 8, 2011 involving all parties to this proceeding. The parties will submit proposed orders and by April 26, 2011 the issue will be fully briefed. The Commission will issue a final order in this case some time thereafter.

MISO Transactions

The Company is a member of the MISO, a FERC approved regional transmission organization. When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Electric utility revenues. When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Cost of fuel & purchased power. Net positions are determined on an hourly basis.

The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively. These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.

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11.	Fair Value Measurements

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


	At December 31,
	2010				2009
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	266,017	$	279,867	$	265,856	$	275,785
Long-term debt payable to Utility Holdings		384,168		413,445		384,692		401,545
Short-term borrowings from Utility Holdings		70,968		70,968		55,479		55,479
Cash & cash equivalents		1,353		1,353		404		404

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.

12.	Additional Balance Sheet & Operational Information

Inventories consist of the following:


	At December 31,
(In thousands)	2010		2009
Materials & supplies	$	32,634	$	30,307
Fuel (coal and oil) for electric generation		70,076		63,528
Gas in storage – at LIFO cost		10,797		11,076
Other		304		287
Total inventories	$	113,811	$	105,198

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, 2010 and 2009, by approximately $4 million and $6 million, respectively. All other inventories are carried at average cost.

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


	At December 31,
(In thousands)	2010		2009
Prepaid taxes	$	35,943	$	13,607
Wholesale emission allowances		1,056		1,298
Other		6,053		234
Total prepayments & other current assets	$	43,052	$	15,139

Accrued liabilities in the Balance Sheets consist of the following:


	At December 31,
(In thousands)	2010		2009
Accrued taxes	$	13,634	$	12,118
Current deferred taxes		3,174		3,436
Customers advances & deposits		15,675		11,963
Accrued interest		5,649		5,444
Accrued salaries & other		3,260		3,496
Tax collections payable		2,731		5,064
Total accrued liabilities	$	44,123	$	41,521

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


(In thousands)	2010			2009
Asset retirement obligation, January 1	$	12,079		$	15,681
Accretion		569			481
Increases (decreases) in estimates, net of cash payments		(2,756	)		(4,083	)
Asset retirement obligation, December 31	$	9,892		$	12,079

Accrued liabilities	$	239		$	2,995
Deferred credits & other liabilities	$	9,653		$	9,084

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


	Year ended December 31,
(In thousands)	2010		2009
AFUDC – borrowed funds	$	213	$	503
AFUDC – equity funds		179		365
Other		1,631		1,988
Total other income - net	$	2,023	$	2,856

Supplemental Cash Flow Information:

	Year Ended December 31,
(In thousands)	2010		2009
Cash paid (received) for:
Income taxes	$	21,885	$	(12,806	)
Interest		40,298		38,199

As of December 31, 2010 and 2009, the Company has accruals related to utility plant purchases totaling approximately $8.2 million and $5.7 million, respectively.

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13.	Segment Reporting

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

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


	Year Ended December 31,
(In thousands)	2010			2009
Revenues
Electric Utility Services	$	608,042		$	528,536
Gas Utility Services		105,597			110,622
Total operating revenues	$	713,639		$	639,158


Profitability Measure
Net Income
Electric Utility Services	$	60,926		$	48,257
Gas Utility Services		6,496			3,997
Total net income	$	67,422		$	52,254

Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	80,392		$	77,471
Gas Utility Services		6,848			6,134
Total depreciation & amortization	$	87,240		$	83,605

Interest Expense
Electric Utility Services	$	36,452		$	34,838
Gas Utility Services		4,050			3,871
Total interest expense	$	40,502		$	38,709

Income Taxes
Electric Utility Services	$	40,846		$	27,402
Gas Utility Services		4,213			2,617
Total income taxes	$	45,059		$	30,019

Capital Expenditures
Electric Utility Services	$	120,068		$	154,152
Gas Utility Services		7,326			23,125
Non-cash costs & changes in accruals		(1,137	)		13,837
Total capital expenditures	$	126,257		$	191,114

	At December 31,
(In thousands)	2010		2009
Assets
Electric Utility Services	$	1,666,507	$	1,592,375
Gas Utility Services		219,195		205,899
Total assets	$	1,885,702	$	1,798,274

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14.	Adoption of Other Accounting Standards

Variable Interest Entities

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

Fair Value Measurements & Disclosures

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

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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 2010 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 2010, SIGECO’s earnings were $67.4 million compared to $52.3 million in 2009. The $15.1 million increase in 2010 compared to 2009 reflects the return of large customer usage, summer cooling weather that was significantly warmer than normal and the prior year, and higher margin from wholesale transmission activities. Increased depreciation and interest expense associated with rate base growth and an increase in the effective tax rate partially offset this increase.

Margin in the Company’s electric territory is impacted by weather. During 2010, cooling weather was 34 percent warmer than normal and 49 percent warmer than the prior year. Due primarily to the extreme cooling weather, management estimates the margin impact of weather to be approximately $10.4 million favorable compared to normal temperatures. Compared to 2009 which was impacted by mild cooling weather, the margin impact is estimated to be $14.2 million. Management estimates the impact of weather based on an assumption of weather sensitive sales per degree day at current rates.

Trends in Operations

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 has obtained base rate orders at each of its utilities in August of 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.

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, SIGECO has implemented conservation programs, and the price of natural gas has been volatile. In the Company’s natural gas service territory, normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. In the natural gas service territory, the IURC has authorized bare steel and cast iron replacement programs. The Company’s electric service territory currently recovers certain environmental investments and other transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs proposed in the current rate proceeding before the IURC and other related filings would limit weather risk and provide for a decoupling and/or 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 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.

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

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

In addition to timely gas and fuel cost recovery, just over $17 million of the Company’s approximate $160 million in other operating expenses incurred during 2010 are subject to a recovery mechanism outside of base rates. Gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery. Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also recovered outside of base rates. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

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

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)	2010		2009

Electric utility revenues	$	608,042	$	528,536
Cost of fuel & purchased power		234,982		194,257
Total electric utility margin	$	373,060	$	334,279
Margin attributed to:
Residential & commercial customers	$	241,218	$	224,664
Industrial customers		97,108		81,748
Other customers		8,514		7,222
Subtotal: Retail	$	346,840	$	313,634
Wholesale margin		26,220		20,645
Total electric utility margin	$	373,060	$	334,279

Electric volumes sold in MWh attributed to:
Residential & commercial customers		2,964,022		2,760,752
Industrial customers		2,630,276		2,258,942
Other customers		22,570		19,979
Total retail volumes sold		5,616,868		5,039,673

-28-

Retail

Electric retail utility margins were $346.8 million for the year ended December 31, 2010, and compared to 2009 increased $33.2 million. Management estimates the impact of warmer than normal weather to have increased residential and commercial margin $14.2 million year over year. Management also estimates industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, to have increased approximately $12.8 million year to date due primarily to increased volumes. Margin among the customer classes associated with returns on pollution control investments increased $3.4 million, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $4.1 million.

Margin from Wholesale Electric Activities

Periodically, generation capacity is in excess of native load. The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets. Further detail of Wholesale activity follows:

Further detail of Wholesale activity follows:


	Year Ended December 31,
(In thousands)	2010		2009
Transmission system sales margin	$	18,814	$	14,595
Off-system sales margin		7,406		6,050
Total wholesale margin	$	26,220	$	20,645

Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $18.8 million during 2010, compared to $14.6 million in 2009. The increase in these transmission system sales is principally due to the increased investment in qualifying projects.

For the year ended December 31, 2010, margin from off-system sales was $7.4 million, compared to $6.1 million in 2009. In 2010 and 2009, the Company experienced lower wholesale power marketing margins compared to historical trends due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs. Off-system sales totaled 587.6 GWh in 2010, compared to 603.6 GWh in 2009. The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August. Results for the periods presented reflect the impact of that sharing.

Purchased Power

The Company’s mix of generated and purchased electricity has been more volatile in recent years due to changing commodity prices and the presence of wind farm purchased power agreements. For the years ended December 31, 2010 and 2009, respectively, the Company purchased approximately 1,287 GWh and 1,159 GWh of power from the MISO and other sources. The total cost associated with these volumes of purchased power is approximately $56 million and $43 million in 2010 and 2009, respectively, and is included in the Cost of fuel & purchased power.

-29-

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)	2010		2009
Gas utility revenues	$	105,597	$	110,622
Cost of gas sold		59,925		66,662
Total gas utility margin	$	45,672	$	43,960
Margin attributed to:
Residential & commercial customers	$	36,544	$	37,115
Industrial customers		7,049		4,761
Other customers		2,079		2,084

Sold & transported volumes in MDth attributed to:
Residential & commercial customers		10,731		10,644
Industrial customers		20,435		15,263
Total sold & transported volumes		31,166		25,907

Gas Utility margins were $45.7 million for the year ended December 31, 2010, an increase of $1.7 million compared to 2009. Industrial customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $2.4 million due primarily to increased volumes sold. Margin decreased $0.3 million due to lower miscellaneous revenues and other revenues associated with lower gas costs. In addition, margin decreased $0.3 million due to lower operating expenses and revenue taxes directly recovered in margin. The average cost per dekatherm of gas purchased during 2010 was $5.76, compared to $6.36 in 2009.

Operating Expenses

Other Operating

For year ended December 31, 2010, Other operating expenses were $161.5 million, increasing $1.3 million compared to 2009. Excluding expenses tracked directly in margin, operating costs decreased $2.4 million. The primary driver of the decrease is related to the $2.3 million in costs for environmental matters related to manufactured gas plant site clean-up incurred in 2009.

Depreciation & Amortization

Depreciation expense increased $3.6 million in 2010 compared to 2009. The increase over the periods presented is due largely to utility capital expenditures placed into service.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2.7 million in 2010 compared to 2009. The increase is consistent with higher electric utility revenues during 2010 and an increase in property taxes attributable to higher rate base.

Other Income

Total other income – net reflects income of $2.0 million compared to $2.9 million in 2009. The higher earnings in 2009 reflect the partial recovery from the 2008 market declines associated with investments related to benefit plans.

Interest Expense

Interest expense was $40.5 million for the year ended December 31, 2009, which represents an increase of $1.8 million, compared to 2009. The $1.8 million increase in 2010 compared to 2009 reflects the impact of long-term financing transactions completed in 2009. The long-term financing transactions completed in 2009 include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent, of which $74.6 million was pushed down to SIGECO, and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.

Income Taxes

For the year ended December 31, 2010, income taxes increased $15.0 million compared to 2009. The increase is due primarily to increased earnings in 2010 and tax adjustments recorded in 2009.

-30-

SELECTED ELECTRIC OPERATING STATISTICS



	For the Year Ended
	December 31,
	2010			2009

OPERATING REVENUES (In thousands):
Residential	$	206,446		$	183,242
Commercial		149,664			139,909
Industrial		199,062			162,283
Other Revenue		9,143			7,690
Total Retail		564,315			493,124
Net Wholesale Revenues		43,727			35,412
	$	608,042		$	528,536
MARGIN (In thousands):
Residential	$	144,327		$	131,544
Commercial		96,891			93,120
Industrial		97,108			81,748
Other		8,514			7,222
Total Retail		346,840			313,634
Net Wholesale Margin		26,220			20,645
	$	373,060		$	334,279
ELECTRIC SALES (In MWh):
Residential		1,603,509			1,451,707
Commercial		1,360,513			1,309,045
Industrial		2,630,276			2,258,942
Other Sales - Street Lighting		22,570			19,979
Total Retail		5,616,868			5,039,673
Wholesale		587,563			603,639
		6,204,431			5,643,312
AVERAGE CUSTOMERS:
Residential		122,857			122,380
Commercial		18,321			18,357
Industrial		108			105
Other		33			33
		141,319			140,875
WEATHER AS A % OF NORMAL:
Cooling Degree Days		134	%		90	%
Heating Degree Days		101	%		96	%

-31-

SELECTED GAS OPERATING STATISTICS


	For the Year Ended
	December 31,
	2010		2009

OPERATING REVENUES (In thousands):
Residential	$	69,091	$	73,216
Commercial		28,537		31,603
Industrial		7,049		4,761
Other Revenue		920		1,042
	$	105,597	$	110,622

MARGIN (In thousands):
Residential	$	27,735	$	27,991
Commercial		8,809		9,124
Industrial		7,049		4,761
Other		2,079		2,084
	$	45,672	$	43,960
GAS SOLD & TRANSPORTED (In MDth):
Residential		7,158		6,781
Commercial		3,573		3,863
Industrial		20,435		15,263
		31,166		25,907

AVERAGE CUSTOMERS:
Residential		99,811		99,758
Commercial		10,087		10,109
Industrial		98		90
		109,996		109,957

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