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

Attached files

file	filename
8-K - 8-K - VECTREN CORP	sig2013reportingpackage8k.htm
EX-99.2 - EXHIBIT 99.2 - VECTREN CORP	exhibit992-2013sigreportin.htm

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2013

Contents



		Page Number

	Audited Financial Statements
	Independent Auditors’ Report	2
	Balance Sheets	3-4
	Statements of Income & Comprehensive Income	5
	Statements of Cash Flows	6
	Statements of Common Shareholder’s Equity	7
	Notes to Financial Statements	8
	Results of Operations	31
	Selected Operating Statistics	36

Additional Information

This annual reporting package provides additional information regarding the operations of Southern Indiana Gas and Electric Company (the Company, SIGECO or Vectren South). This information is supplemental to Vectren Corporation’s (Vectren) annual report for the year ended December 31, 2013, filed on Form 10-K with the Securities and Exchange Commission on February 20, 2014 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 5, 2014. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through its website at www.vectren.com.

Frequently Used Terms



AFUDC: allowance for funds used during construction	MDth / MMDth: thousands / millions of dekatherms
EPA: Environmental Protection Agency	MISO: Midcontinent Independent System Operator (formerly Midwest Independent System Operator
DOT: Department of Transportation	MMBTU: millions of British thermal units
FASB: Financial Accounting Standards Board	MW: megawatts
FERC: Federal Energy Regulatory Commission	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
IDEM: Indiana Department of Environmental Management	NOx: nitrogen oxide
IURC: Indiana Utility Regulatory Commission	OUCC: Indiana Office of the Utility Consumer Counselor
MCF / MMCF / BCF: thousands / millions / billions of cubic feet	Throughput: combined gas sales and gas transportation volumes

INDEPENDENT AUDITORS’ REPORT

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

We have audited the accompanying financial statements of Southern Indiana Gas & Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, Inc.), which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of income and comprehensive income, common shareholder’s equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

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

Auditors’ Responsibility

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

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

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

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2013 and 2012, 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 24, 2014

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



	December 31,
	2013		2012
ASSETS

Utility Plant
Original cost	$	2,899,425	$	2,811,185
Less: Accumulated depreciation & amortization	1,217,288		1,157,559
Net utility plant	1,682,137		1,653,626

Current Assets
Cash & cash equivalents	2,588		3,276
Notes Receivable from Utility Holdings	268		—
Accounts receivable - less reserves of $2,470 &
$2,892 respectively	54,760		44,151
Accrued unbilled revenues	27,759		25,155
Inventories	64,774		97,312
Recoverable fuel & natural gas costs	—		5,227
Prepayments & other current assets	2,195		15,163
Total current assets	152,344		190,284

Investments in unconsolidated affiliates	150		150
Other investments	11,657		13,939
Nonutility plant - net	1,640		1,714
Goodwill - net	5,557		5,557
Regulatory assets	63,104		63,650
Other assets	805		6,377

TOTAL ASSETS	$	1,917,394	$	1,935,297

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



	December 31,
	2013		2012
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	313,290	$	303,256
Retained earnings	468,990		449,235
Accumulated other comprehensive income	17		33
Total common shareholder's equity	782,297		752,524

Long-term debt payable to third parties	266,500		266,339
Long-term debt payable to Utility Holdings	340,411		351,945
Total long-term debt, net	606,911		618,284


Commitments & Contingencies (Notes 5, 7-9)

Current Liabilities
Accounts payable	33,959		25,123
Accounts payable to affiliated companies	—		3,834
Payables to other Vectren companies	16,042		17,725
Refundable fuel & natural gas costs	2,632		—
Accrued liabilities	73,537		55,963
Short-term borrowings payable to Utility Holdings	—		66,995
Total current liabilities	126,170		169,640

Deferred Income Taxes & Other Liabilities
Deferred income taxes	295,808		295,803
Regulatory liabilities	52,895		50,028
Deferred credits & other liabilities	53,313		49,018
Total deferred income taxes & other liabilities	402,016		394,849

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,917,394	$	1,935,297

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF INCOME & COMPREHENSIVE INCOME

(In thousands)



	Year Ended December 31,
	2013			2012
OPERATING REVENUES
Electric utility	$	619,307		$	594,902
Gas utility	95,897			83,842
Total operating revenues	715,204			678,744
OPERATING EXPENSES
Cost of fuel & purchased power	202,935			192,000
Cost of gas sold	47,283			37,224
Other operating	192,619			182,616
Depreciation & amortization	92,280			88,695
Taxes other than income taxes	19,905			18,138
Total operating expenses	555,022			518,673

OPERATING INCOME	160,182			160,071
Other income – net	1,483			1,095
Interest expense	32,399			37,546
INCOME BEFORE INCOME TAXES	129,266			123,620
Income taxes	50,419			50,063
NET INCOME	$	78,847		$	73,557
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges
Reclassifications to net income before tax	(27		)	(19		)
Income taxes	11			8
Cash Flow Hedges, net of tax	(16		)	(11		)
TOTAL COMPREHENSIVE INCOME	$	78,831		$	73,546

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



	Year Ended December 31,
		2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	78,847		$	73,557
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		92,280			88,695
Deferred income taxes & investment tax credits		15,419			41,211
Expense portion of pension & postretirement periodic benefit cost		2,631			2,325
Provision for uncollectible accounts		1,883			2,172
Other non-cash charges - net		889			2,912
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		(15,095		)	5,449
Inventories		32,538			11,241
Recoverable/refundable fuel & natural gas costs		7,859			(2,589		)
Prepayments & other current assets		13,005			(6,937		)
Accounts payable, including to Vectren companies
& affiliated companies		(1,988		)	(3,502		)
Accrued liabilities		2,494			(508		)
Changes in noncurrent assets		9,707			(29,190		)
Changes in noncurrent liabilities		(3,633		)	(7,654		)
Net cash flows from operating activities		236,836			177,182
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Capital contribution from Utility Holdings		10,034			—
Long-term debt, net of issuance costs, payable to Utility Holdings		182,859			—
Requirements for:
Dividends to Utility Holdings		(59,092		)	(42,991		)
Retirement of long-term debt, including premiums paid		(197,031		)	(13		)
Net change in short-term borrowings, including from Utility Holdings		(66,995		)	(10,089		)
Net cash flows from financing activities		(130,225		)	(53,093		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		307			250
Requirements for:
Capital expenditures, excluding AFUDC equity		(107,338		)	(121,844		)
Net change in short-term intercompany notes receivable		(268		)	—
Net cash flows from investing activities		(107,299		)	(121,594		)
Net change in cash & cash equivalents		(688		)	2,495
Cash & cash equivalents at beginning of period		3,276			781
Cash & cash equivalents at end of period		$	2,588		$	3,276

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)



						Accumulated
						Other
	Common		Retained			Comprehensive
	Stock		Earnings			Income			Total

Balance at January 1, 2012	$	303,256	$	418,669		$	44		$	721,969

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

Net income			78,847						78,847
Other comprehensive income						(16		)	(16		)
Common stock:
Capital contribution from Utility Holdings	10,034								10,034
Dividends to Utility Holdings			(59,092		)				(59,092		)
Balance at December 31, 2013	$	313,290	$	468,990		$	17		$	782,297

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

NOTES TO THE FINANCIAL STATEMENTS


1.	Organization & Nature of Operations

Southern Indiana Gas and Electric Company (the Company, SIGECO or Vectren South), an Indiana corporation, provides energy delivery services to approximately 142,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. Of these customers, approximately 83,000 receive combined electric and gas distribution services. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy holding company headquartered in Evansville, Indiana.


2.	Summary of Significant Accounting Policies

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

Subsequent Events Review

Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. The Company’s management has performed a review of subsequent events through March 24, 2014.

Cash & Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

Allowance for Uncollectible Accounts

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

Inventories

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

Plant, Property, & Equipment

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

Utility Plant & Related Depreciation

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

When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC.

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

Nonutility Plant & Related Depreciation

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

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. There were no impairments related to property, plant and equipment during the periods presented.

Goodwill

Goodwill recorded on the Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. As of December 31, 2013, no goodwill impairments have been recorded. All of the Company’s goodwill is included in the Gas Utility Services operating segment.

Intangible Assets

The Company has emission allowances relating to its wholesale power marketing operations totaling $0.4 million and $0.7 million at December 31, 2013 and 2012, respectively. The value of the emission allowances are recognized as they are consumed or sold.

Regulation

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

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

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

Regulatory Assets & Liabilities

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

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

Asset Retirement Obligations

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

Energy Contracts & Derivatives

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

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

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

Revenues

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

MISO Transactions

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

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

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

Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $9.0 million in 2013, and $8.8 million in 2012. 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 the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company has two operating segments: Electric Utility Services and Gas Utility Services.

Fair Value Measurements

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



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

Earnings Per Share

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

Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, 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)	2013				2012
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	2,519,792	3.3	%	$	2,463,607	3.3	%
Gas utility plant	284,924		3.2	%	269,322		3.0	%
Common utility plant	53,434		3.0	%	52,011		3.0	%
Construction work in progress	41,275		—	%	26,245		—	%
Total original cost	$	2,899,425			$	2,811,185

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, 2013, is $186.3 million with accumulated depreciation totaling $84.4 million.


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2013			2012
Amounts currently recovered through customer rates related to:
Demand side management programs	$	2,525		$	4,418
Unamortized debt issue costs	8,929			6,903
Premiums paid to reacquire debt	1,777			2,209
Authorized trackers	7,560			8,400
Other	690			986
	21,481			22,916
Amounts deferred for future recovery related to:
Deferred coal costs	42,410			42,410
Cost recovery riders & other	2,546			1,269
	44,956			43,679

Future amounts recoverable from ratepayers related to:
Net deferred income taxes	(5,962		)	(5,292		)
Asset retirement obligations & other	2,629			2,347
	(3,333		)	(2,945		)
Total regulatory assets	$	63,104		$	63,650

Of the $21.5 million currently being recovered in rates charged to customers, $2.5 million associated with demand side management programs is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $13.9 million, is 15 years. The remainder of the regulatory assets are being recovered timely through

tracking mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory Liabilities

At December 31, 2013 and 2012, the Company has approximately $52.9 million and $50.0 million, respectively, in Regulatory liabilities. Of these amounts, $47.6 million and $43.5 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations.


5.	Transactions with Other Vectren Companies

Vectren Fuels, Inc.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC. Amounts purchased for the years ended December 31, 2013 and 2012, totaled $103.7 million and $115.6 million, respectively. Amounts owed to Vectren Fuels at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, 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. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO's customer's include SIGECO. Fees incurred by SIGECO and its subsidiaries totaled $6.0 million in 2013 and $6.5 million in 2012. Amounts owed to VISCO at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

ProLiance

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities.

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2013 and 2012, totaled $25.3 million and $40.9 million, respectively. The Company did not have any amounts owed to ProLiance for purchases at December 31, 2013 as a result of Proliance exiting the natural gas marketing business. Amounts owed to ProLiance at December 31, 2012, for purchases were $3.8 million and are included in Accounts payable to affiliated companies in the Balance Sheets.

Support Services and Purchases

Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. SIGECO received corporate allocations totaling $51.0 million and $48.2 million for the years ended December 31, 2013, and 2012, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2013, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. Utility Holdings and its subsidiaries, which includes the Company, comprise the vast majority of the participants and retirees covered by these plans.

Vectren satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding commitment and did not contribute to Vectren’s defined benefit pension plans during 2013 or 2012. Such contributions are made to Vectren in total and are not plan specific. The combined funded status of Vectren’s plans was approximately 101 percent at December 31, 2013 and 82 percent at December 31, 2012. Vectren’s management currently anticipates making no contributions to qualified pension plans in 2014, due to the plans being at or above 100 percent funded levels.

Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to subsidiaries at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2013 and 2012, costs totaling $3.8 million and $3.3 million, respectively, were directly charged to the Company. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren and Utility Holdings corporate operations are charged to subsidiaries through the allocation process discussed above based on labor. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As of December 31, 2013 and 2012, $16.1 million and $15.9 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren. As impacted by increased funding of pension plans in 2011, at December 31, 2013 and 2012, the Company has $0.7 million and $4.2 million, respectively, included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs.

Share-Based Incentive Plans and Deferred Compensation Plans

SIGECO does not have share-based or deferred compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to 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, 2013 and 2012, $14.8 million and $11.5 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Cash Management Arrangements

The Company participates in Vectren Utility Holdings’ centralized cash management program. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Guarantees of Parent Company Debt

Utility Holdings’ three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $350 million short-term credit facility, of which approximately $29 million is outstanding at December 31, 2013, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2013. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

SIGECO does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a

separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.

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.

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



	Year Ended December 31,
(In thousands)	2013			2012
Current:
Federal	$	25,025		$	1,292
State	9,975			7,560
Total current tax expense	35,000			8,852
Deferred:
Federal	15,898			39,298
State	37			2,440
Total deferred tax expense	15,935			41,738
Amortization of investment tax credits	(516		)	(527		)
Total income tax expense	$	50,419		$	50,063

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




	Year Ended December 31,
	2013		2012

Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	5.4		5.8
Amortization of investment tax credit	(0.4	)	(0.4	)
Other tax credits	(1.1	)	(0.1	)
Adjustments to federal income tax accruals	(0.5	)	—
All other - net	0.6		0.2
Effective tax rate	39.0	%	40.5	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2013			2012
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	293,974		$	287,195
Regulatory assets recoverable through future rates	13,181			14,193
Other comprehensive income	—			—
Employee benefit obligations	2,755			7,371
Regulatory liabilities to be settled through future rates	(12,405		)	(13,043		)
Other – net	(1,697		)	87
Net noncurrent deferred tax liability	295,808			295,803
Current deferred tax liabilities (assets):
Deferred fuel costs	20,989			18,004
Other	11,437			(293		)
Net current deferred tax liability	32,426			17,711
Net deferred tax liability	$	328,234		$	313,514

At December 31, 2013 and 2012, ITCs totaling $3.0 million and $3.6 million, respectively, are included in Deferred credits & other liabilities. These ITCs are amortized over the lives of the related investments.

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a 2 percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by 0.5 percent each year beginning on July 1, 2012, to the final rate of 6.5 percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment. The remeasurement of these temporary differences at the lower tax rate was recorded as a reduction of a regulatory asset.

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2013 and 2012:



(In thousands)	2013			2012
Unrecognized tax benefits at January 1	$	2,531		$	8,893
Gross increases - tax positions in prior periods	—			160
Gross decreases - tax positions in prior periods	(92		)	(7,701		)
Gross increases - current period tax positions	404			1,179
Unrecognized tax benefits at December 31	$	2,843		$	2,531

Of the change in unrecognized tax benefits during 2013 and 2012, none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was zero at December 31, 2013 and December 31, 2012. As of December 31, 2013, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings. The Company doesn’t expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company’s results of operations or financial condition.

In 2013, the Company recognized no expense related to interest and penalties. In 2012, the Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling $0.6 million. The Company had approximately $0.1 million for the payment of interest and penalties accrued as of December 31, 2013 and 2012.

The net liability on the Balance Sheets for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $2.7 million and $2.4 million, respectively, at December 31, 2013 and 2012.

The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax returns for tax years through December 31, 2008. The primary focus of the 2008 IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for Vectren through 2012. The Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company's results of operations or financial condition. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2008. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2008.

Final Federal Income Tax Regulations

In September 2013, the Internal Revenue Service released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted for 2013 tax years. The Company intends to adopt the guidance for its 2014 tax year. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue guidance with respect to natural gas transmission and distribution assets during 2014. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its financial statements. As of this date, the Company does not expect the adoption of the regulations to have a material impact on its financial statements.


6.	Borrowing Arrangements & Other Financing Transactions

Long-Term Debt

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



	At December 31,
(In thousands)	2013			2012
Senior Unsecured Notes Payable to Utility Holdings:
2015, 5.45%	$	49,432		$	49,432
2018, 5.75%	61,880			61,880
2020, 6.28%	74,596			74,596
2021, 4.67%	54,612			54,612
2028, 3.20%	26,858			—
2035, 6.10%	25,284			25,284
2039, 6.25%	—			86,141
2043, 4.25%	47,749			—
Total long-term debt payable to Utility Holdings	$	340,411		$	351,945

First Mortgage Bonds Payable to Third Parties:
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
2013 weighted average: 0.10%	$	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
2022, 2013 Series C, 1.95%, tax exempt	4,640			—
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	—			22,550
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	—			22,500
2024, 2013 Series D, 1.95%, tax exempt	22,500			—
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
2013 weighted average: 0.10%	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
2030, 1998 Pollution Control Series C, 5.35%, tax exempt	—			22,200
2037, 2013 Series E, 1.95%, tax exempt	22,000			—
2038, 2013 Series A, 4.0%, tax exempt	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
2043, 2013 Series B, 4.05%, tax exempt	39,550			—
Total first mortgage bonds payable to third parties	267,465			267,465
Unamortized debt premium, discount & other - net	(965		)	(1,126		)
Long-term debt payable to third parties - net	$	266,500		$	266,339

SIGECO 2013 Debt Refund and Reissuance

During the second quarter of 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 million of tax-exempt long-term debt was reissued on April 26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million. The terms are $22.2 million at 4.00 percent per annum due in 2038, and $39.6 million at 4.05 percent per annum due in 2043.

The remaining approximately $49 million of the called debt was remarketed on August 13, 2013. The remarketed tax-exempt debt has a fixed interest rate of 1.95 percent per annum until September 13, 2017. SIGECO closed on this remarketing and received net proceeds of $48.3 million on August 28, 2013.

Issuance payable to Utility Holdings

On April 1, 2013, VUHI exercised a call option at par on $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June 5, 2013, with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million, 3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million, 4.25 percent senior guaranteed notes, due June 5, 2043. Total proceeds received from these notes, net of issuance costs, were $44.8 million and $79.6 million, respectively. The notes are unconditionally guaranteed by Indiana Gas, SIGECO and Vectren Energy Delivery of Ohio, Inc. In July 2013, Utility Holdings pushed $75 million of this refinanced debt to SIGECO. Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in its financing arrangements to account for debt issuance costs and any related hedging arrangements.

Long-Term Debt Sinking Fund Requirements & Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2013 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2013 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2013, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated 2.9 billion at December 31, 2013.

Maturities of long-term debt during the five years following 2013 (in millions) are zero in 2014, $59.2 in 2015, $13.0 in 2016, zero in 2017, and $61.9 in 2018.

Long-Term Debt Puts, Calls, and Mandatory Tenders

Certain long-term debt issues contain optional put and call provisions that can be exercised on various dates before maturity. During 2013, the Company had no repayments related to investor put provisions and at December 31, 2013, the only debt with investor puts were two series of variable rate demand bonds, aggregating $41.3 million, with a variable interest rate that is reset weekly. This SIGECO debt is fully supported by letters of credit that are available should any of the debt holders decide to put the debt to SIGECO and the remarketing agent is unable to remarket it to other investors.

Certain other series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017.

In March and April, 2013, the Company notified holders of six issues of SIGECO's tax exempt long-term debt totaling $110.9 million with interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041 of its intent to call this debt. The call options were exercised at par in April and May, 2013.

Covenants

Long-term and borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. As of December 31, 2013, the Company was in compliance with all financial debt covenants.

Short-Term Borrowings

SIGECO relies on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs. Borrowings outstanding at December 31, 2013 and 2012 were zero and $67 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($321 million at December 31, 2013) and is subject to the same terms and conditions as Utility Holdings’ short term borrowing arrangements, including its commercial paper program. Short-term

borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds. See the table below for interest rates and outstanding balances:



	Intercompany Borrowings
(In thousands)	2013			2012
Year End
Balance Outstanding	$	—		$	66,995
Weighted Average Interest Rate	0.30		%	0.40		%
Annual Average
Balance Outstanding	$	47,378		$	72,214
Weighted Average Interest Rate	0.35		%	0.46		%
Maximum Month End Balance Outstanding	$	114,075		$	85,673


7.	Commitments & Contingencies

Purchase Commitments

SIGECO has both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights, and certain contracts are firm commitments under five and ten year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Firm purchase commitments for utility plant total $0.5 million in 2014 and zero in 2015 and thereafter.

Legal Proceedings

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


8.	Rate & Regulatory Matters

Electric Environmental Compliance Filing

On January 17, 2014, the Company filed a request with the IURC for approval of capital investments estimated to be between $70 million and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2016. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address EPA concerns on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as a federally mandated investment under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The company filed its case-in-chief testimony on March 14, 2014 and a hearing is scheduled to begin July 9, 2014.

Electric Base Rate Filing

The IURC issued an order on April 27, 2011, providing for a revenue increase to recover costs associated with approximately $325.0 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent, and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, provided for deferred accounting treatment related to the Company's investment in dense pack technology, of which approximately $28.7 million was spent as of December 31, 2013. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated and is discussed below.

Coal Procurement Procedures

Vectren South submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its 2011 RFP. In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South also contracted with Vectren Fuels, Inc. in 2012 to purchase lower priced spot coal. This spot purchase, which was completed in 2012, was found to be reasonable in a recent fuel adjustment clause (FAC) order issued in July 2012. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and will be recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total deferred balance as of December 31, 2013 was $42.4 million Recovery of this deferred balance began in February 2014.

Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. For the twelve months ended December 31, 2013, the Company recognized Electric revenue of $5 million associated with this approved lost margin recovery mechanism.

FERC Return on Equity Complaint

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. In the event a refund is required upon resolution of the complaint, the parties are seeking a refund calculated as of the filing date of the complaint. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. In addition to the group response, the Company filed a supplemental response, stating that if FERC allows the complaint to go forward, the complaint should not be applied to the Company’s recently completed Gibson-Brown-Reid 345 Kv transmission line investment.

FERC has no deadline for action. This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in

NETO be lowered. In August 2013, a FERC administrative law judge recommended in that proceeding that the return be lowered to 9.7 percent, retroactive to the date of the complaint filing. The FERC has yet to rule on that case.

The Company is unable to predict the outcome of the proceeding. A 100 basis point change in the incentive rate of return would equate to approximately $0.8 million of net income on an annual basis.

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

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

Recovery and Deferral Mechanisms

The Company's last gas utility rate order was received in 2007. This order authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The order provides for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $3.0 million annually. The debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service. At December 31, 2013 and 2012, the Company has regulatory assets totaling $1.4 million and $1.0 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law. This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

Pipeline Safety Law

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

While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.

Requests for Recovery Under Regulatory Mechanisms

The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The filing requests recovery of the capital expenditures associated with the infrastructure

replacement and improvement plan pursuant to the legislation, estimated to be approximately $215 million combined over the seven year period beginning in 2014, along with approximately $3 million annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled to begin May 7, 2014, and an order is expected later in 2014.

Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.


9.	Environmental Matters

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

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO₂ emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO₂and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO₂and NOx emissions.

However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Environmental Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSAPR’s implementation by Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA agreed to reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013.

Notice of Violation for A.B. Brown Power Plant

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were

not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company is currently in discussions with the EPA to resolve this NOV.

Information Request

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common. AGC and SIGECO also share equally in the cost of operation and output of the unit. In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2014. Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Conclusions Regarding Environmental Regulations

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

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

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above. Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and

Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

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

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.

The EPA has promulgated two GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section 111(b). On October 15, 2013, the US Supreme Court agreed to review a focused appeal on the issue of whether the GHG rule applicable to mobile sources triggered PSD permitting for all stationary sources such as Vectren's power plants. A decision is expected in 2014.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO₂ and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. At this time and in the

absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG 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 GHG 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 GHG emissions or expenditures made to control emissions should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 referenced above.

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

Manufactured Gas Plants

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

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

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $20.2 million. The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company has recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2013 and 2012, respectively, approximately $4.4 million and $3.2 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.


10.	Fair Value Measurements

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



	At December 31,
	2013				2012
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	266,500	$	278,499	$	266,339	$	300,586
Long-term debt payable to Utility Holdings	340,411		355,383		351,945		399,287
Short-term borrowings from Utility Holdings	—		—		66,995		66,995
Cash & cash equivalents	2,588		2,588		3,276		3,276

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

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.


11.	Additional Balance Sheet & Operational Information

Inventories consist of the following:



	At December 31,
(In thousands)	2013		2012
Materials & supplies	$	34,687	$	34,205
Fuel (coal and oil) for electric generation	16,543		51,964
Gas in storage – at LIFO cost	13,539		11,132
Other	5		11
Total inventories	$	64,774	$	97,312

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost is less than carrying value at December 31, 2013 by approximately $1.0 million and exceeded that carrying value at December 31, 2012, by approximately $3 million. All other inventories are carried at average cost.

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



	At December 31,
(In thousands)	2013		2012
Prepaid taxes	$	—	$	13,221
Wholesale emission allowances	419		682
Other	1,776		1,260
Total prepayments & other current assets	$	2,195	$	15,163

Accrued liabilities in the Balance Sheets consist of the following:



	At December 31,
(In thousands)	2013		2012
Accrued taxes	$	13,489	$	10,039
Current deferred taxes	32,426		17,711
Customers advances & deposits	16,716		16,997
Accrued interest	4,876		5,754
Tax collections payable	2,619		2,260
Accrued salaries & other	3,411		3,202
Total accrued liabilities	$	73,537	$	55,963

Asset retirement obligations included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets roll forward as follows:




(In thousands)	2013			2012
Asset retirement obligation, January 1	$	12,254		$	10,480
Accretion	606			643
Changes in estimates, net of cash payments	(827		)	1,131
Asset retirement obligation, December 31	$	12,033		$	12,254

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



	Year ended December 31,
(In thousands)	2013			2012
AFUDC – borrowed funds	$	512		$	322
AFUDC – equity funds	377			(1		)
Cash surrender value of life insurance policies	867			681
Other	(273		)	93
Total other income - net	$	1,483		$	1,095

Supplemental Cash Flow Information:



	Year ended December 31,
(In thousands)	2013		2012
Cash paid (received) for:
Income taxes	$	18,854	$	21,035
Interest	33,277		37,520

As of December 31, 2013 and 2012, the Company has accruals related to utility plant purchases totaling approximately $4.8 million and $2.6 million, respectively.


12.	Segment Reporting

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

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



	Year Ended December 31,
(In thousands)	2013			2012
Revenues
Electric Utility Services	$	619,307		$	594,902
Gas Utility Services	95,897			83,842
Total operating revenues	$	715,204		$	678,744


Profitability Measure
Net Income
Electric Utility Services	$	75,754		$	67,959
Gas Utility Services	3,093			5,598
Total net income	$	78,847		$	73,557

Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services	$	84,008		$	81,299
Gas Utility Services	8,272			7,396
Total depreciation & amortization	$	92,280		$	88,695

Interest Expense
Electric Utility Services	$	29,159		$	33,774
Gas Utility Services	3,240			3,772
Total interest expense	$	32,399		$	37,546

Income Taxes
Electric Utility Services	$	48,287		$	46,352
Gas Utility Services	2,132			3,711
Total income taxes	$	50,419		$	50,063

Capital Expenditures
Electric Utility Services	$	99,999		$	108,845
Gas Utility Services	14,150			13,025
Non-cash costs & changes in accruals	(6,811		)	(26		)
Total capital expenditures	$	107,338		$	121,844

	At December 31,
(In thousands)	2013			2012
Assets
Electric Utility Services	$	1,679,007		$	1,705,159
Gas Utility Services	238,387			230,138
Total assets	$	1,917,394		$	1,935,297


13.	Adoption of Other Accounting Standards

Offsetting Assets and Liabilities

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's financial statements.

Accumulated Other Comprehensive Income (AOCI)

In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI. The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts. The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the company's results of operations, cash flows or financial position.

Unrecognized Tax Benefit Presentation

In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist. The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. This update is consistent with how the Company currently presents unrecognized tax benefits, therefore, adoption of this guidance resulted in no material impact on the Company's financial statements.

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

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 2013 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 2013, SIGECO’s earnings were $78.8 million compared to $73.6 million in 2012. The increased earnings in 2013 are primarily driven by higher margin and reduced interest expense associated with recent refinancing activity.

The Regulatory Environment

Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters are regulated by the IURC. The Company’s electric territory received an order in April 2011, effective May 2011, and its gas territory received an order in August 2007. The orders authorize a return on equity of 10.40% on the electric operations and 10.15% for the gas operations. The authorized returns reflect the impact of innovative rate design strategies having been authorized by the state commission. Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns. In addition to timely gas and fuel cost recovery, approximately $25 million of the approximate $193 million in Other operating expenses incurred during 2013 are subject to a recovery mechanism outside of base rates.

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company has implemented conservation programs. In the Company’s natural gas service territory, normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. In the natural gas service territory, the IURC has authorized a bare steel and cast iron replacement program but no rates have been implemented by any Indiana utility as of this date. The Company’s electric service territory currently recovers certain transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives.

Tracked Operating Expenses

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

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

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. The FAC earnings test had some impact on the Company’s 2012 operating results, as discussed below.

Gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery. Certain operating costs, including depreciation, associated with regional electric transmission assets not in base rates are also recovered by mechanisms outside of base rate recovery. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

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

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

Operating Trends

Margin

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

In addition, the Company separately reflects regulatory expense recovery mechanisms within Gas utility margin and Electric utility margin. These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin generated from regulated utility 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)	2013		2012

Electric utility revenues	$	619,307	$	594,902
Cost of fuel & purchased power	202,935		192,000
Total electric utility margin	$	416,372	$	402,902
Margin attributed to:
Residential & commercial customers	$	255,767	$	255,871
Industrial customers	108,757		108,466
Other	4,830		1,634
Regulatory expense recovery mechanisms	10,538		4,830
Subtotal: Retail	$	379,892	$	370,801
Wholesale margin	36,480		32,101
Total electric utility margin	$	416,372	$	402,902
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,722,114		2,731,677
Industrial customers	2,735,188		2,710,523
Municipals & other	21,807		22,552
Total retail volumes sold	5,479,109		5,464,752

Retail

Electric retail utility margins were $379.8 million for the year ended December 31, 2013 and, compared to 2012, increased by $9.0 million. Electric results are not protected by weather normalizing mechanisms. Cooling degree days in 2013 were 103 percent of normal compared to 130 percent of normal in 2012, resulting in lower small customer margin of approximately $1.2 million, largely offset by an increase in customers. Large customer margins for 2013 were relatively flat when compared to 2012. Other margin was higher in 2013 by $3.2 million, due in part to $2.6 million in refunds to customers during 2012 resulting from statutory net operating income limits. Margin from regulatory expense recovery mechanisms increased $5.6 million in 2013 compared to 2012, driven by a corresponding increase in operating expenses associated with the electric state-mandated conservation programs.

On December 3, 2013, SABIC Innovative Plastics (SABIC), a large industrial utility customer of the Company, announced its plans to build a cogeneration (cogen) facility to be operational in mid-2016, in order to generate power to meet a significant portion of its ongoing power needs. Electric service is currently provided to SABIC by the Company under a long-term contract that expires in 2016, which coincides with the expected completion of the new cogen facility. SABIC's historical peak electric usage has been 120 megawatts (MW). The cogen facility is expected to provide 80 MW of capacity. Therefore, the Company will continue to provide all of SABIC's power requirements above the 80 MW capacity of the cogen, which is projected to be between 20 and 30 MW and slightly lower than their peak usage due to expected energy efficiency efforts. The Company also expects to provide back-up power, when required. While the full impact of the lost margin on earnings has not been determined, there should be no impact until mid-2016. The Company is evaluating approaches to mitigate the impact of any lost margin on its future financial results.

Margin from Wholesale Electric Activities

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off-system margin and transmission system margin follows:



	Year Ended December 31,
(In thousands)	2013		2012
Transmission system sales margin	$	29,328	$	26,391
Off-system sales margin	7,152		5,710
Total wholesale margin	$	36,480	$	32,101

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $29.3 million during 2013, compared to $26.4 million in 2012. Increase is primarily due to increased investment in qualifying projects. To date, the Company has invested $157.5 million in qualifying projects. The net plant balance for these projects totaled $146.8 million at December 31, 2013. These projects include an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Although currently being challenged as discussed below, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance, and operating expenses are also recovered. The 345 Kv project is the largest of these qualifying projects, with a cost of $106.6 million that earned the FERC approved equity rate of return, including while under construction. The last segment of that project was placed into service in December 2012.

For the year ended December 31, 2013, margin from off-system sales was $7.2 million, compared to $5.7 million in 2012. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year are shared equally with customers. Results for the periods presented reflect the impact of that sharing. Off-system sales were 514.4 GWh in 2013, compared to 336.7 GWh in 2012. The lower volumes sold in 2012 compared to 2013 from the Company's primarily coal-fired generation result from increased sales of power in MISO from gas-fired electric generation due to lower natural gas prices and more wind generation.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas utility margin and throughput by customer type follows:



	Year Ended December 31,
(In thousands)	2013		2012
Gas utility revenues	$	95,897	$	83,842
Cost of gas sold	47,283		37,224
Total gas utility margin	$	48,614	$	46,618
Margin attributed to:
Residential & commercial customers	$	32,935	$	32,750
Industrial customers	10,020		10,489
Other	1,302		1,239
Regulatory expense recovery mechanisms	4,357		2,140
Total gas utility margin	$	48,614	$	46,618
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	11,162		8,551
Industrial customers	29,830		29,017
Total sold & transported volumes	40,992		37,568

Gas Utility margins were $48.6 million for the year ended December 31, 2013, an increase of $2.0 million compared to 2012. The increase in margin is primarily related to increased volumetric pass through costs in 2013 compared to 2012. With rate designs that substantially limit the impact of weather on margin, heating degree days in 2013 that were 102 percent of normal compared to 79 percent in 2012, had a significant impact on residential and commercial customer volumes sold, but relatively no impact on residential and commercial customer margin.

Operating Expenses

Other Operating

For year ended December 31, 2013, Other operating expenses were $192.6 million, increasing $10.0 million compared to 2012. Excluding operating expenses recovered through margin, operating expenses increased $2.5 million, primarily associated with accelerated maintenance projects from future years that were completed in the current year. Though higher in 2013, operating costs are being managed to be generally flat to the 2012 targeted levels on an annual basis, over time.

Depreciation & Amortization

Depreciation and amortization expense was $92.3 million in 2013, compared to $88.7 million in 2012. The increase in expense resulted from additional utility plant investments placed into service.

Other Income

Total other income – net reflects income of $1.5 million compared to $1.1 million in 2012. The increase in 2013 primarily reflects increased AFUDC in 2013 compared to the prior year.

Interest Expense

Interest expense was $32.4 million in 2013. Interest expense decreased $5.1 million year over year compared to 2012. The decrease is due to refinancing activity, as described in Note 6 of the Financial Statements, yielding favorable interest rates.

Income Taxes

For the year ended December 31, 2013, income taxes increased $0.4 million compared to 2012. The increase is due primarily to increased earnings in 2013 offset by tax credits associated with research and development expenditures.

SELECTED ELECTRIC OPERATING STATISTICS





	For the Year Ended
	December 31,
	2013			2012


OPERATING REVENUES (in thousands):
Residential	206,657			203,115
Commercial	152,318			148,427
Industrial	198,429			192,855
Other	10,408			9,458
Total Retail	567,812			553,855
Net Wholesale Revenues	51,495			41,047
	619,307			594,902

MARGIN (In thousands):
Residential	$	150,065		$	151,415
Commercial	105,702			104,456
Industrial	108,757			108,466
Other	4,830			1,634
Regulatory expense recovery mechanisms	10,538			4,830
Total Retail	379,892			370,801
Wholesale power & transmission system	36,480			32,101
	$	416,372		$	402,902

ELECTRIC SALES (In MWh):
Residential	1,425,790			1,434,348
Commercial	1,296,324			1,297,329
Industrial	2,735,188			2,710,523
Other Sales - Street Lighting	21,807			22,552
Total Retail	5,479,109			5,464,752
Wholesale	514,368			336,715
	5,993,477			5,801,467

AVERAGE CUSTOMERS:
Residential	123,780			123,303
Commercial	18,380			18,297
Industrial	116			115
Other	36			33
	142,312			141,748

WEATHER AS A % OF NORMAL:
Cooling Degree Days	103		%	130		%
Heating Degree Days	102		%	79		%

SELECTED GAS OPERATING STATISTICS



	For the Year Ended
	December 31,
	2013		2012

OPERATING REVENUES (In thousands):
Residential	59,635		51,958
Commercial	25,721		21,250
Industrial	9,239		9,454
Other	1,302		1,180
	95,897		83,842

MARGIN (In thousands):
Residential	$	25,247	$	25,191
Commercial	7,688		7,559
Industrial	10,020		10,489
Other	1,302		1,239
Regulatory expense recovery mechanisms	4,357		2,140
	$	48,614	$	46,618

GAS SOLD & TRANSPORTED (In MDth):
Residential	7,201		5,553
Commercial	3,961		2,998
Industrial	29,830		29,017
	40,992		37,568

AVERAGE CUSTOMERS:
Residential	99,782		99,543
Commercial	10,234		10,128
Industrial	112		111
	110,128		109,782

Attached files

Stock widget

Investing forum

VECTREN CORP Reports