VECTREN CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1 SIG 2014 REPORTING PACKAGE

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8-K - 8-K - SIG 2014 REPORTING PACKAGE - VECTREN CORP	sig2014reportingpackage8k.htm
EX-99.2 - EXHIBIT 99.2 SIG 2014 REPORTING PACKAGE - VECTREN CORP	exhibit992-2014sigreportin.htm

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

REPORTING PACKAGE

For the year ended December 31, 2014

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	35

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, 2014, filed on Form 10-K with the Securities and Exchange Commission on February 17, 2015 and Vectren Utility Holdings, Inc.’s (Utility Holdings) 10-K filed on March 5, 2015. 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	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
ASC: Accounting Standards Codification	MDth / MMDth: thousands / millions of dekatherms
EPA: Environmental Protection Agency	MISO: Midcontinent 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)
GAAP: Generally Accepted Accounting Principles	NOx: nitrogen oxide
IDEM: Indiana Department of Environmental Management	OUCC: Indiana Office of the Utility Consumer Counselor
IURC: Indiana Utility Regulatory Commission	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”), which comprise the balance sheets as of December 31, 2014 and 2013, 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, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 24, 2015

FINANCIAL STATEMENTS

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



	December 31,
	2014		2013
ASSETS

Utility Plant
Original cost	$	3,016,637	$	2,899,425
Less: Accumulated depreciation & amortization	1,278,177		1,217,288
Net utility plant	1,738,460		1,682,137
Current Assets
Cash & cash equivalents	1,526		2,588
Notes Receivable from Utility Holdings	—		268
Accounts receivable - less reserves of $1,883 &
$2,470 respectively	48,462		54,760
Receivables from other Vectren companies	599		—
Accrued unbilled revenues	29,910		27,759
Inventories	84,470		64,774
Prepayments & other current assets	24,732		2,195
Total current assets	189,699		152,344
Investments in unconsolidated affiliates	150		150
Other investments	10,622		11,657
Nonutility plant - net	1,580		1,640
Goodwill - net	5,557		5,557
Regulatory assets	50,513		63,104
Other assets	435		805
TOTAL ASSETS	$	1,997,016	$	1,917,394

The accompanying notes are an integral part of these financial statements

SOUTHERN INDIANA GAS & ELECTRIC COMPANY

BALANCE SHEETS

(In thousands)



	December 31,
	2014		2013
LIABILITIES & SHAREHOLDER'S EQUITY
Common shareholder's equity
Common stock (no par value)	$	313,290	$	313,290
Retained earnings	494,172		468,990
Accumulated other comprehensive income	9		17
Total common shareholder's equity	807,471		782,297
Long-term debt payable to third parties	266,661		266,500
Long-term debt payable to Utility Holdings - net of current maturities	315,820		340,411
Total long-term debt	582,481		606,911
Commitments & Contingencies (Notes 5, 7-10)
Current Liabilities
Accounts payable	49,385		33,959
Payables to other Vectren companies	11,164		16,042
Refundable fuel & natural gas costs	2,537		2,632
Accrued liabilities	54,583		73,537
Short-term borrowings payable to Utility Holdings	12,941		—
Current maturities long-term debt payable to Utility Holdings	49,432		—
Total current liabilities	180,042		126,170
Deferred Income Taxes & Other Liabilities
Deferred income taxes	311,414		295,808
Regulatory liabilities	56,039		52,895
Deferred credits & other liabilities	59,569		53,313
Total deferred income taxes & other liabilities	427,022		402,016
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,997,016	$	1,917,394

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,
	2014			2013
OPERATING REVENUES
Electric utility	$	624,771		$	619,307
Gas utility	111,359			95,897
Total operating revenues	736,130			715,204
OPERATING EXPENSES
Cost of fuel & purchased power	201,797			202,935
Cost of gas sold	62,839			47,283
Other operating	197,376			192,619
Depreciation & amortization	93,723			92,280
Taxes other than income taxes	19,280			19,905
Total operating expenses	575,015			555,022
OPERATING INCOME	161,115			160,182
Other income – net	4,553			1,483
Interest expense	32,593			32,399
INCOME BEFORE INCOME TAXES	133,075			129,266
Income taxes	50,117			50,419
NET INCOME	$	82,958		$	78,847
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges
Reclassifications to net income before tax	(13		)	(27		)
Income taxes	5			11
Cash Flow Hedges, net of tax	(8		)	(16		)
TOTAL COMPREHENSIVE INCOME	$	82,950		$	78,831

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,
		2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	82,958		$	78,847
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		93,723			92,280
Deferred income taxes & investment tax credits		2,735			15,419
Expense portion of pension & postretirement periodic benefit cost		2,094			2,631
Provision for uncollectible accounts		1,706			1,883
Other non-cash charges - net		154			889
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue		1,842			(15,095		)
Inventories		(19,696		)	32,538
Recoverable/refundable fuel & natural gas costs		(95		)	7,859
Prepayments & other current assets		(22,167		)	13,005
Accounts payable, including to Vectren companies
& affiliated companies		4,707			(1,988		)
Accrued liabilities		(1,643		)	2,494
Changes in noncurrent assets		4,734			9,707
Changes in noncurrent liabilities		(7,984		)	(3,633		)
Net cash flows from operating activities		143,068			236,836
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Capital contribution from Utility Holdings		—			10,034
Long-term debt, net of issuance costs		87,218			182,859
Requirements for:
Dividends to Utility Holdings		(57,776		)	(59,092		)
Retirement of long-term debt, including premiums paid		(63,575		)	(197,031		)
Net change in short-term borrowings, including from Utility Holdings		12,941			(66,995		)
Net cash flows from financing activities		(21,192		)	(130,225		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities		—			307
Requirements for:
Capital expenditures, excluding AFUDC equity		(123,206		)	(107,338		)
Net change in short-term intercompany notes receivable		268			(268		)
Net cash flows from investing activities		(122,938		)	(107,299		)
Net change in cash & cash equivalents		(1,062		)	(688		)
Cash & cash equivalents at beginning of period		2,588			3,276
Cash & cash equivalents at end of period		$	1,526		$	2,588

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, 2013	$	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
Net income			82,958						82,958
Other comprehensive income						(8		)	(8		)
Common stock:
Dividends to Utility Holdings			(57,776		)				(57,776		)
Balance at December 31, 2014	$	313,290	$	494,172		$	9		$	807,471

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 or SIGECO), an Indiana corporation, provides energy delivery services to approximately 143,000 electric customers and over 110,000 gas customers located near Evansville in southwestern Indiana. Of these customers, approximately 84,000 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, 2015.

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, 2014, no goodwill impairments have been recorded.

Intangible Assets

The Company has emission allowances relating to its wholesale power marketing operations totaling $0.3 million and $0.4 million at December 31, 2014 and 2013, 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 $9.4 million in 2014, and $9.0 million in 2013. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes.

Fair Value Measurements

Certain assets and liabilities are valued and/or disclosed at fair value. 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)	2014				2013
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Electric utility plant	$	2,602,548	3.3	%	$	2,519,792	3.3	%
Gas utility plant	324,571		2.7	%	284,924		3.2	%
Common utility plant	54,277		3.2	%	53,434		3.0	%
Construction work in progress	35,241		—	%	41,275		—	%
Total original cost	$	3,016,637			$	2,899,425

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, 2014, is $188.0 million with accumulated depreciation totaling $93.5 million.


4.	Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2014			2013
Amounts currently recovered through customer rates related to:
Demand side management programs	$	631		$	2,525
Unamortized debt issue costs	9,432			8,929
Premiums paid to reacquire debt	1,347			1,777
Deferred coal costs	35,342			—
Authorized trackers	9,723			7,560
Other	394			690
	56,869			21,481
Amounts deferred for future recovery related to:
Deferred coal costs	—			42,410
Cost recovery riders & other	5,038			2,546
	5,038			44,956
Future amounts recoverable/(refundable) from ratepayers related to:
Net deferred income taxes	(11,394		)	(5,962		)
Asset retirement obligations & other	—			2,629
	(11,394		)	(3,333		)
Total regulatory assets	$	50,513		$	63,104

Of the $56.9 million currently being recovered in rates charged to customers, $0.6 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 $11.8 million, is 19 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, 2014 and 2013, the Company has approximately $56.0 million and $52.9 million, respectively, in Regulatory liabilities. Of these amounts, $46.0 million and $47.6 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.

On August 29, 2014, Vectren closed on a transaction to sell its wholly-owned coal mining subsidiary, Vectren Fuels, Inc. (Vectren Fuels), to Sunrise Coal, LLC (Sunrise), an Indiana-based wholly-owned subsidiary of Hallador Energy Company. Prior to the sale date, SIGECO purchased coal used for electric generation from Vectren Fuels. Amounts purchased for the years ended December 31, 2014 and 2013, totaled $98.6 million and $103.7 million, respectively. No amounts were owed to Vectren Fuels at December 31, 2014 and amounts owed as of December 31, 2013 were included in Payables to other Vectren companies. After the exit of the coal mining business by Vectren, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO's customers include SIGECO and fees incurred by SIGECO totaled $14.3 million in 2014 and $6.0 million in 2013. Amounts owed to VISCO at December 31, 2014 and 2013 are included in Payables to other Vectren companies.

ProLiance Holdings, LLC (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.

The Company had no purchases from ProLiance for resale and for injections into storage for the year ended December 31, 2014, as a result of ProLiance exiting the natural gas marketing business. For the year ended December 31, 2013, the Company had purchases totaling $25.3 million. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 84 percent is from a single third party for the year ended December 31, 2014.

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 $52.6 million and $51.0 million for the years ended December 31, 2014, and 2013, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2014 and 2013 are included in Payables to other Vectren companies.

Retirement Plans & Other Postretirement Benefits

At December 31, 2014, 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 2014 or 2013. The combined funded status of Vectren’s plans was approximately 87 percent at December 31, 2014 and 101 percent at December 31, 2013. Vectren's management has made contributions of $20 million to the qualified plans in 2015.

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, 2014 and 2013, costs totaling $3.0 million and $3.8 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, 2014 and 2013, $16.4 million and $16.1 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, at December 31, 2014 and 2013, the Company has zero and $0.7 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, 2014 and 2013, $17.6 million and $14.8 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 $156 million is outstanding at December 31, 2014, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2014. 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 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 Utility Holdings 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)	2014			2013
Current:
Federal	$	34,311		$	25,025
State	13,071			9,975
Total current tax expense	47,382			35,000
Deferred:
Federal	5,050			15,898
State	(1,809		)	37
Total deferred tax expense	3,241			15,935
Amortization of investment tax credits	(506		)	(516		)
Total income tax expense	$	50,117		$	50,419

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




	Year Ended December 31,
	2014		2013

Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	5.0		5.4
Amortization of investment tax credit	(0.4	)	(0.4	)
Domestic production deduction	(1.6	)	—
Other tax credits	(0.1	)	(1.1	)
All other - net	(0.2	)	0.1
Effective tax rate	37.7	%	39.0	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2014			2013
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	313,258		$	293,974
Regulatory assets recoverable through future rates	17,952			13,181
Employee benefit obligations	208			2,755
Regulatory liabilities to be settled through future rates	(18,134		)	(12,405		)
Other – net	(1,870		)	(1,697		)
Net noncurrent deferred tax liability	311,414			295,808
Current deferred tax liabilities (assets):
Deferred fuel costs	18,537			20,989
Other	(748		)	11,437
Net current deferred tax liability	17,789			32,426
Net deferred tax liability	$	329,203		$	328,234

At December 31, 2014 and 2013, ITCs totaling $2.4 million and $3.0 million, respectively, are included in Deferred credits & other liabilities. During 2014, the Company reversed a portion of deferred tax liabilities as a result of the adoption of tangible property repair regulations. This reversal is reflected in Other - Current deferred tax liabilities (assets).

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the two years ended December 31, 2014 and 2013:



(In thousands)	2014			2013
Unrecognized tax benefits at January 1	$	2,843		$	2,531
Gross increases - tax positions in prior periods	—			—
Gross decreases - tax positions in prior periods	(2,843		)	(92		)
Gross increases - current period tax positions	—			404
Unrecognized tax benefits at December 31	$	—		$	2,843

Of the change in unrecognized tax benefits during 2014 and 2013, 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, 2014 and 2013.

The Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.1 million in 2014. In 2013, the Company recognized no expense related to interest and penalties. The Company had no accruals for the payment of interest and penalties as of December 31, 2014, and $0.1 million for the payment of interest and penalties accrued as of December 31, 2013.

The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of the Company's U.S. federal income tax returns for tax years through December 31, 2008. The IRS is currently examining the 2009-2012 federal income tax returns as part of a routine review by the Joint Committee on Taxation. The State of Indiana, the Company'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, and will be adopted on the 2014 federal income tax return. 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 updated or new guidance with respect to electric and natural gas transmission and distribution assets during 2015. 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.

Indiana Senate Bill 1

In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.


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)	2014			2013
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
2023, 3.72%	24,847			—
2028, 3.20%	26,856			26,858
2035, 6.10%	25,284			25,284
2043, 4.25%	47,745			47,749
Total long-term debt payable to Utility Holdings	$	365,252		$	340,411
Current maturities	(49,432		)	—
Total long-term debt payable to Utility Holdings - net	$	315,820		$	340,411

First Mortgage Bonds Payable to Third Parties:
2015, 1985 Pollution Control Series A, tax exempt,
2013 weighted average: 0.10%	$	—		$	9,775
2016, 1986 Series, 8.875%	13,000			13,000
2022, 2013 Series C, 1.95%, tax exempt	4,640			4,640
2024, 2013 Series D, 1.95%, tax exempt	22,500			22,500
2025, 1998 Pollution Control Series A, tax exempt,
2013 weighted average: 0.10%	—			31,500
2025, 2014 Series B, current adjustable rate 0.722%, tax-exempt	41,275			—
2029, 1999 Senior Notes, 6.72%	80,000			80,000
2037, 2013 Series E, 1.95%, tax exempt	22,000			22,000
2038, 2013 Series A, 4.0%, tax exempt	22,200			22,200
2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	—			22,300
2043, 2013 Series B, 4.05%, tax exempt	39,550			39,550
2044, 2014 Series A, 4.00%, tax exempt	22,300			—
Total first mortgage bonds payable to third parties	267,465			267,465
Unamortized debt premium, discount & other - net	(804		)	(965		)
Long-term debt payable to third parties - net	$	266,661		$	266,500

SIGECO Debt Refund and Issuance

On September 24, 2014, SIGECO issued two new series of tax-exempt debt totaling $63.6 million. Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest. The principal terms of the two new series of tax-exempt debt are: (i) $22.3 million sold in a public offering and bear interest at 4.00 percent per annum, due September 1, 2044 and (ii) $41.3 million, due July 1, 2025, sold in a private placement at variable rates through September 2019.

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 SIGECO, Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. In July 2013, Utility Holdings reloaned $75 million of this refinanced debt to SIGECO.

On August 22, 2013, VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023. The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013, the VUHI received net proceeds of $149.1 million from the issuance of the senior guaranteed notes which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes. In January 2014, $24.8 million of this debt was reloaned to SIGECO.

Mandatory Tenders

At December 31, 2014, certain series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017. Additionally, SIGECO Bond Series 2014B, in the amount of $41.3 million, with a variable interest rate that is reset monthly, is subject to mandatory tender in September 2019.

Future Long-Term Debt Sinking Fund Requirements and 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 2014 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2014 is excluded from Current liabilities in the Balance Sheets. At December 31, 2014, $1.3 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 $3.0 billion at December 31, 2014.

Maturities of long-term debt during the five years following 2014 (in millions) are $49.4 in 2015, $13.0 in 2016, zero in 2017, $61.9 in 2018, and zero in 2019.

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, 2014, 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, 2014 and 2013 were $12.9 million and zero, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($194 million at December 31, 2014) 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)	2014			2013
Year End
Balance Outstanding	$	12,941		$	—
Weighted Average Interest Rate	0.50		%	0.30		%
Annual Average
Balance Outstanding	$	361		$	47,378
Weighted Average Interest Rate	0.38		%	0.35		%
Maximum Month End Balance Outstanding	$	12,941		$	114,075


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 $0.2 million in 2015, $0.2 million in 2016, $0.2 million in 2017, and zero thereafter.

Legal Proceedings

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


8.	Electric Rate & Regulatory Matters

Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. Although the Company and the Commission acknowledge that these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investment under Senate Bill 251, the Order approves the Company’s request for deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts. The accounting treatment, includes the 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 initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016.

Coal Procurement Procedures

Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units. During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all

such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding. In December 2014, the Commission determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

On December 5, 2011 within the quarterly FAC filing, SIGECO 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 new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 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 balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $35.3 million remains as of December 31, 2014.

Electric Demand Side Management Program Filing

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric 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. For the twelve months ended December 31, 2014 and December 31, 2013, the Company recognized Electric utility revenue of $8.7 million and $5.0 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015.

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. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of December 31, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $143.6 million at December 31, 2014.

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. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a methodology set out in its June 19, 2014 decision.

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. As of January 2015, a settlement was not reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which will define a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.

On January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015.

9. Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company is currently engaged in programs to replace bare steel and cast iron infrastructure and other activities to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws were passed in Indiana that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

In April 2011, Indiana Senate Bill 251 (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 is deferred for future recovery in the utility's next general rate case.

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, 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 current 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 is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

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 million annually. The debt-related post-in-service carrying costs are recognized in the 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, 2014 and 2013, the Company has regulatory assets totaling $1.9 million and $1.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

Requests for Recovery Under Indiana Regulatory Mechanisms

On August 27, 2014, the Commission issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to update the seven-year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. On January 28, 2015, the OUCC filed its appellate brief raising an issue regarding the treatment of retired assets within the recovery mechanism. An appeal was also filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560

electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of either appeal and the implications to the Company’s Order, if any, cannot be determined.

On January 14, 2015, the Commission issued an Order approving the Company’s initial request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the Commission approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $200 million, an increase of $5 million from the previous plan. The plan also includes approximately $5 million of annual operating costs associated with pipeline safety rules.

Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at the gas utility company and recovery of new conservation program costs through December 2015. On March 2, 2015, the Company and the OUCC filed a joint settlement agreement for approval by the Commission to extend the decoupling mechanism through 2020.

10. Environmental Matters

Indiana Senate Bill 251

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations. The Company continues with its ongoing evaluation of 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

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. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.

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. Reductions are to be achieved within three years of publication of the final rule in the Federal Register (April 2015). 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. Legal challenges to the MATS Rule continue. In July, a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with a decision expected later in 2015.

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 generating station. The NOV asserts that when the facility 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 reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.

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.

Ozone NAAQS

On November 26, 2014, the U.S. EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on 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. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million. 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, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The 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. The 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 however the rule is not yet finalized. 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 Air and Water Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, 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. 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 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.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.

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.

In December 2014 the U.S. EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). At this time the final rule has not been published in the Federal Register and as such is not yet effective. Under the final rule the Company will be required to commence an enhanced groundwater monitoring program to determine whether its existing ash ponds must be closed or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to beneficially reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states in lieu of citizen suits.

The Company originally estimated capital expenditures to comply with the alternatives in the proposal could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives was selected. As the less stringent Subtitle D program was selected by U.S. EPA in the final rule, the Company expects capital expenditures to comply in the lower end of this range. 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 cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.

The EPA has finalized two sets of 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, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.

While the Company has no plans to invest in new coal-fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June

2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.

Under the proposal, all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent, Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9^th lowest reduction requirement. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The state of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans. That litigation has been set for argument before the U.S. Court of Appeals for the D.C. circuit in April of 2015, with a decision expected later in the summer.

With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:

(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).

(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.

(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).

(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.

Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5^th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to renewable generation, 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 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown

If the regulations referenced above are finalized by the EPA, 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 were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will continue to remain engaged with the state to develop a plan for compliance and have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates 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 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.

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, 2014 and 2013, respectively, approximately $2.8 million and $4.4 million of accrued, but not yet spent, costs are included in Other Liabilities related to these sites.

11. 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,
	2014				2013
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt payable to third parties	$	266,661	$	292,160	$	266,500	$	278,499
Long-term debt payable to Utility Holdings	365,252		400,482		340,411		355,383
Short-term borrowings payable to Utility Holdings	12,941		12,941		—		—
Cash & cash equivalents	1,526		1,526		2,588		2,588

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

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

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

12. Additional Balance Sheet & Operational Information

Inventories in the Balance Sheets consist of the following:



	At December 31,
(In thousands)	2014		2013
Materials & supplies	$	33,122	$	34,687
Fuel (coal and oil) for electric generation	33,753		16,543
Gas in storage – at LIFO cost	17,589		13,539
Other	6		5
Total inventories	$	84,470	$	64,774

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, 2014 and 2013 by approximately $3 million and $1 million, respectively. All other inventories are carried at average cost. Increased fuel inventory primarily relates to higher levels of coal inventory at December 31, 2014 driven by weather variations throughout 2014.

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



	At December 31,
(In thousands)	2014		2013
Prepaid taxes	$	23,329	$	—
Wholesale emission allowances	250		419
Other	1,153		1,776
Total prepayments & other current assets	$	24,732	$	2,195

The increase in prepaid taxes in 2014 was due to the timing of passage of the federal legislation that extended bonus depreciation retroactively for the year.

Accrued liabilities in the Balance Sheets consist of the following:



	At December 31,
(In thousands)	2014		2013
Accrued taxes	$	10,202	$	13,489
Current deferred taxes	17,789		32,426
Customers advances & deposits	15,853		16,716
Accrued interest	4,738		4,876
Tax collections payable	2,794		2,619
Accrued salaries & other	3,207		3,411
Total accrued liabilities	$	54,583	$	73,537

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




(In thousands)	2014		2013
Asset retirement obligation, January 1	$	12,033	$	12,254
Accretion	597		606
Changes in estimates, net of cash payments	5,541		(827		)
Asset retirement obligation, December 31	$	18,171	$	12,033

The increase in the asset retirement obligation during the year related to changes in estimates, net of cash payments, is primarily driven by a change in the methodology of how sections of gas pipeline are replaced.

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



	Year ended December 31,
(In thousands)	2014			2013
AFUDC – borrowed funds	$	1,951		$	512
AFUDC – equity funds	2,518			377
Cash surrender value of life insurance policies	317			867
Other	(233		)	(273		)
Total other income - net	$	4,553		$	1,483

Supplemental Cash Flow Information:



	Year ended December 31,
(In thousands)	2014		2013
Cash paid (received) for:
Income taxes	$	73,584	$	18,854
Interest	32,730		33,277

As of December 31, 2014 and 2013, the Company has accruals related to utility plant purchases totaling approximately $10.6 million and $4.8 million, respectively.

13. Adoption of Other Accounting Standards

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.

Financial Reporting of Discontinued Operations

In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company is currently evaluating the impact of this guidance, if any.

Financial Reporting of Going Concern

In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

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The following discussion and analysis provides additional information regarding SIGECO’s results of operations that is supplemental to the information provided in Vectren Corporation’s and Utility Holdings’ management’s discussion and analysis of results of operations and financial condition contained in those 2014 annual reports filed on Form 10-K, which includes 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 2014, SIGECO’s earnings were $83.0 million compared to $78.8 million in 2013. The increased earnings in 2014 are primarily driven by higher electric margin and an increase in allowance for funds used during construction (AFUDC).

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.

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 residential and commercial customers due to weather and changing consumption patterns. In addition to these mechanisms, the Commission has authorized specific bare steel and cast iron replacement programs and an expanded gas infrastructure replacement program, which allow for recovery of these investments outside of a base rate case proceeding. Further, rates charged to natural gas customers contain a gas cost adjustment (GCA) clause and electric rates contain a fuel adjustment clause (FAC). Both of these cost tracker mechanisms allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel. The Company utilizes similar mechanisms for other material operating costs, which allow for changes in revenue outside of a base rate case. The implementation of these various mechanisms has allowed the Company to avoid regulatory proceedings to increase base rates since 2011 for its electric business and 2007 for its gas business.

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company’s utilities have implemented conservation programs. In the Company’s natural gas service territory, normal temperature adjustment 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 Company's natural gas service territory, the Commission has authorized bare steel and cast iron replacement programs. State laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. The Company has received approval to implement these mechanisms.

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 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 and subject to caps that are based on historical experience. Electric rates contain a fuel adjustment clause 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 The New York Mercantile Exchange (NYMEX) natural gas prices, is also timely recovered through the FAC.

GCA and FAC procedures involve periodic filings and IURC hearings to establish 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 last time the Company was impacted by this earnings test was in the electric FAC in 2012.

Gas pipeline integrity management operating 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 typical base rate recovery. In addition, certain operating costs, including depreciation, associated with federally mandated investments, gas distribution and transmission infrastructure replacement investments, and regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery.

Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

Base Rate Orders

The Company's electric territory received an order in April 2011, with rates effective May 2011, and its gas territory received an order and implemented rates 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 rate design strategies that have been authorized by the IURC.

See Notes 8 and 9 to the financial statements for more specific information on the 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)	2014		2013

Electric utility revenues	$	624,771	$	619,307
Cost of fuel & purchased power	201,797		202,935
Total electric utility margin	$	422,974	$	416,372
Margin attributed to:
Residential & commercial customers	$	260,782	$	255,767
Industrial customers	111,176		108,757
Other	5,520		4,830
Regulatory expense recovery mechanisms	11,609		10,538
Subtotal: Retail	$	389,087	$	379,892
Wholesale margin	33,887		36,480
Total electric utility margin	$	422,974	$	416,372
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,762,234		2,722,114
Industrial customers	2,804,598		2,735,188
Municipals & other	22,627		21,807
Total retail volumes sold	5,589,459		5,479,109

Retail

Electric retail utility margins were $389.1 million for the year ended December 31, 2014 and, compared to 2013, increased by $9.2 million. As energy conservation initiatives continue, the Company's lost revenue recovery contributed increased margin of $3.9 million related to electric conservation programs compared to the prior year. Electric results, which are not protected by weather normalizing mechanisms, experienced a $1.8 million increase from weather in small customer margin as heating degree days were 107 percent of normal in 2014 compared to 102 percent of normal in 2013 and cooling degree days were 104 percent of normal in 2014 compared to 103 percent of normal in 2013. Results also reflect increased large customer usage, which had a favorable margin impact of $2.0 million. Margin from regulatory expense recovery mechanisms increased $1.1 million driven primarily by a corresponding increase in operating expenses associated with MISO costs.

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)	2014		2013
Transmission system sales margin	$	26,109	$	29,328
Off-system sales margin	7,778		7,152
Total wholesale margin	$	33,887	$	36,480

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $26.1 million during 2014, compared to $29.3 million in 2013. Results in 2014 reflect lower returns on transmission investments due to a reserve recorded associated with a pending FERC ROE complaint. To date, the Company has invested $157.7 million in qualifying projects. The net plant balance for these projects totaled $143.6 million at December 31, 2014. These projects include an interstate 345 Kv transmission line that connects the Company’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 the allowed return is currently being challenged as discussed below in Rate and Regulatory Matters, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance. Operating expenses are also recovered. As mentioned above, the Company has established a reserve pending the outcome of this complaint. The 345 Kv project is the largest of these qualifying projects, with a cost of $106.8 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, 2014, margin from off-system sales was $7.8 million, compared to $7.2 million in 2013. 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 651.1 GWh in 2014, compared to 514.4 GWh in 2013. The increase in volumes sold for the years presented from the Company's primarily coal-fired generation result from lower costs to generate due to a decrease in coal prices.

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)	2014		2013
Gas utility revenues	$	111,359	$	95,897
Cost of gas sold	62,839		47,283
Total gas utility margin	$	48,520	$	48,614
Margin attributed to:
Residential & commercial customers	$	33,079	$	32,935
Industrial customers	8,302		10,020
Other	1,370		1,302
Regulatory expense recovery mechanisms	5,769		4,357
Total gas utility margin	$	48,520	$	48,614
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	12,211		11,162
Industrial customers	30,211		29,830
Total sold & transported volumes	42,422		40,992

Gas Utility margins were $48.5 million for the year ended December 31, 2014, a decrease of $0.1 million compared to 2013. With rate designs that substantially limit the impact of weather on margin, heating degree days in 2014 that were 107 percent of normal compared to 102 percent in 2013, had a significant impact on residential and commercial customer volumes sold, but relatively no impact on residential and commercial customer margin. The decrease in margin attributed to industrial customers is primarily driven by the expiration of a customer demand charge in the fourth quarter of 2013.

Operating Expenses

Other Operating

For year ended December 31, 2014, Other operating expenses were $197.4 million, increasing $4.8 million compared to 2013. Excluding operating expenses recovered through margin, operating expenses increased $3.0 million, primarily associated with an increase in performance-based compensation expense and increased expenses related to gas system maintenance largely due to the harsh winter weather in the first half of 2014.

Depreciation & Amortization

Depreciation and amortization expense was $93.7 million in 2014, compared to $92.3 million in 2013. The increase in expense resulted from additional utility plant investments placed into service.

Other Income

Total other income – net reflects income of $4.6 million compared to $1.5 million in 2013. The increase in 2014 primarily reflects increased AFUDC in 2014 compared to the prior year. The higher AFUDC reflects an increased AFUDC rate as well as increased capital expenditures related to infrastructure replacement investments.

SELECTED ELECTRIC OPERATING STATISTICS





	For the Year Ended
	December 31,
	2014			2013


OPERATING REVENUES (in thousands):
Residential	$	212,222		$	206,657
Commercial	154,945			152,318
Industrial	199,327			198,429
Other	5,379			10,408
Total Retail	571,873			567,812
Net Wholesale Revenues	52,898			51,495
	$	624,771		$	619,307

MARGIN (In thousands):
Residential	$	153,247		$	150,065
Commercial	107,535			105,702
Industrial	111,176			108,757
Other	5,520			4,830
Regulatory expense recovery mechanisms	11,609			10,538
Total Retail	389,087			379,892
Wholesale power & transmission system	33,887			36,480
	$	422,974		$	416,372

ELECTRIC SALES (In MWh):
Residential	1,455,292			1,425,790
Commercial	1,306,942			1,296,324
Industrial	2,804,598			2,735,188
Other Sales - Street Lighting	22,627			21,807
Total Retail	5,589,459			5,479,109
Wholesale	651,125			514,368
	6,240,584			5,993,477

AVERAGE CUSTOMERS:
Residential	124,301			123,780
Commercial	18,454			18,380
Industrial	117			116
Other	38			36
	142,910			142,312

WEATHER AS A % OF NORMAL:
Cooling Degree Days	104		%	103		%
Heating Degree Days	107		%	102		%

SELECTED GAS OPERATING STATISTICS



	For the Year Ended
	December 31,
	2014		2013

OPERATING REVENUES (In thousands):
Residential	72,315		59,635
Commercial	29,788		25,721
Industrial	7,888		9,239
Other	1,368		1,302
	111,359		95,897

MARGIN (In thousands):
Residential	$	25,336	$	25,247
Commercial	7,743		7,688
Industrial	8,302		10,020
Other	1,370		1,302
Regulatory expense recovery mechanisms	5,769		4,357
	$	48,520	$	48,614

GAS SOLD & TRANSPORTED (In MDth):
Residential	7,823		7,201
Commercial	4,388		3,961
Industrial	30,211		29,830
	42,422		40,992

AVERAGE CUSTOMERS:
Residential	100,047		99,782
Commercial	10,242		10,234
Industrial	117		112
	110,406		110,128

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