Exhibit 99.1 - 2013 IGC Reporting Package

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



AFUDC: allowance for funds used during construction	IURC: Indiana Utility Regulatory Commission
DOT: Department of Transportation	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
EPA: Environmental Protection Agency	MDth / MMDth: thousands / millions of dekatherms
FASB: Financial Accounting Standards Board	OUCC: Indiana Office of the Utility Consumer Counselor
FERC: Federal Energy Regulatory Commission	Throughput: combined gas sales and gas transportation volumes
IDEM: Indiana Department of Environmental Management

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

Management is responsible for the preparation and fair presentation of these consolidated 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 consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. and subsidiary company as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.



	December, 31
	2013		2012
ASSETS
Utility Plant
Original cost	$	1,777,413	$	1,700,112
Less: accumulated depreciation & amortization	750,166		708,000
Net utility plant	1,027,247		992,112

Current Assets
Cash & cash equivalents	3,622		4,092
Accounts receivable - less reserves of $2,503 &
$2,098, respectively	41,478		27,828
Accrued unbilled revenues	58,070		46,273
Inventories	23,499		15,075
Recoverable natural gas costs	5,490		20,118
Prepayments & other current assets	33,571		33,487
Total current assets	165,730		146,873

Other investments	7,927		9,847
Regulatory assets	37,045		37,237
Other assets	23,646		25,543
TOTAL ASSETS	$	1,261,595	$	1,211,612



	December 31,
		2013		2012
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)		$	259,536	$	259,536
Retained earnings		123,461		112,847
Total common shareholder's equity		382,997		372,383
Long-term debt payable to third parties - net of current maturities		116,000		116,000
Long-term debt payable to Utility Holdings		137,282		133,948
Total long-term debt, net		253,282		249,948
Commitments & Contingencies (Notes 5, 7-9)
Current Liabilities
Accounts payable		67,141		36,202
Accounts payable to affiliated companies		—		25,860
Payables to other Vectren companies		12,593		10,606
Accrued liabilities		53,932		55,722
Short-term borrowings payable to Utility Holdings		62,024		46,916
Current maturities of long-term debt		—		5,000
Total current liabilities		195,690		180,306
Deferred Income Taxes & Other Liabilities
Deferred income taxes		179,289		174,441
Regulatory liabilities		225,495		213,340
Deferred credits & other liabilities		24,842		21,194
Total deferred income taxes & other liabilities		429,626		408,975

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY		$	1,261,595	$	1,211,612



	Year Ended December 31,
	2013		2012

OPERATING REVENUES	$	577,617	$	522,187
OPERATING EXPENSES
Cost of gas sold	300,174		255,346
Other operating	115,789		103,362
Depreciation & amortization	61,563		59,255
Taxes other than income taxes	16,311		16,062
Total operating expenses	493,837		434,025

OPERATING INCOME	83,780		88,162

Other income - net	1,212		2,040

Interest expense	16,197		17,333

INCOME BEFORE INCOME TAXES	68,795		72,869

Income taxes	28,121		29,459

NET INCOME	$	40,674	$	43,410



	Year Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	40,674		43,410
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	61,563			59,255
Deferred income taxes & investment tax credits	1,263			13,393
Expense portion of pension & postretirement periodic benefit cost	1,328			1,207
Provision for uncollectible accounts	3,043			1,120
Other non-cash charges - net	207			1,217
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies
& accrued unbilled revenue	(28,489		)	(1,711		)
Inventories	(8,424		)	7,101
Recoverable/refundable natural gas costs	14,628			(10,351		)
Prepayments & other current assets	(84		)	11,226
Accounts payable, including to Vectren companies
& affiliated companies	4,222			(11,688		)
Accrued liabilities	3,308			(2,100		)
Changes in noncurrent assets	5,622			(4,819		)
Changes in noncurrent liabilities	(4,407		)	(4,948		)
Net cash flows from operating activities	94,454			102,312
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt	24,869			—
Requirements for:
Dividend to Utility Holdings	(30,060		)	(22,768		)
Retirement of long-term debt	(26,535		)	(3		)
Net change in short-term borrowings, including from Utility Holdings	15,108			(16,562		)
Net cash flows from financing activities	(16,618		)	(39,333		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	218			—
Requirements for capital expenditures,
excluding AFUDC equity	(78,524		)	(61,975		)
Net cash flows from investing activities	(78,306		)	(61,975		)
Net change in cash & cash equivalents	(470		)	1,004
Cash & cash equivalents at beginning of period	4,092			3,088
Cash & cash equivalents at end of period	$	3,622		$	4,092



	Common		Retained
	Stock		Earnings			Total

Balance at January 1, 2012	$	259,536	$	92,205		$	351,741

Net income & comprehensive income			43,410			43,410
Common stock:
Dividends to Utility Holdings			(22,768		)	(22,768		)
Balance at December 31, 2012	$	259,536	$	112,847		$	372,383
Net income & comprehensive income			40,674			40,674
Common stock:
Dividends to Utility Holdings			(30,060		)	(30,060		)
Balance at December 31, 2013	$	259,536	$	123,461		$	382,997

Indiana Gas Company, Inc. and subsidiary company (the Company, Indiana Gas or Vectren North), an Indiana corporation, provides energy delivery services to approximately 570,000 natural gas customers located in central and southern Indiana. Indiana Gas 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). Indiana Gas generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy holding company headquartered in Evansville, Indiana.

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated 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 plant and testing of 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.

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.

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.

The Company’s Utility Plant is 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.

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 Consolidated Statements of Income.

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.

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. The Company records any under-or-over-recovery resulting from the gas adjustment clause 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.

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.

A portion of removal costs related to interim retirements of gas utility pipeline 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.

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 Consolidated 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 consolidated 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 consolidated financial statements.

Certain assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in 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.

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



	At and For the Year Ended December 31,
(In thousands)	2013				2012
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,767,176	3.8	%	$	1,684,812	3.9	%
Construction work in progress	10,237		—		15,300		—
Total original cost	$	1,777,413			$	1,700,112

Regulatory assets consist of the following:



	At December 31,
(In thousands)	2013			2012
Amounts currently recovered through customer rates related to:
Authorized trackers	$	23,244		$	24,287
Unamortized debt issue costs & premiums paid to reacquire debt	3,251			3,802
	26,495			28,089
Amounts deferred for future recovery	10,702			7,476
Future amounts recoverable from ratepayers related to:
Net deferred income taxes	138			1,397
Other	(290		)	275
Total regulatory assets	$	37,045		$	37,237

Indiana Gas is not earning a return on the $26.5 million currently being recovered through rates. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $3.3 million, is 17 years. The remainder of the regulatory assets is being timely recovered through tracking mechanisms. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

VISCO, a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO’s customers include Indiana Gas. Fees incurred by Indiana Gas totaled $30.7 million in 2013 and $23.9 million in 2012. Amounts owed to VISCO at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

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

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2013 and 2012 totaled $167.1 million and $233.5 million, respectively. The Company did not have any amounts owed to ProLiance for purchases at December 31, 2013, and amounts owed to ProLiance at December 31, 2012 were $25.9 million and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.

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. Indiana Gas received corporate allocations totaling $54.3 million and $52.2 million for the years ended December 31, 2013, and 2012, respectively. Amounts owed to Vectren and Utility Holdings at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

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

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

Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to subsidiaries at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2013 and 2012, costs totaling $1.9 million and $1.7 million, respectively, were directly charged to the

Company. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren and Utility Holdings corporate operations are charged to subsidiaries through the allocation process discussed above 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. At December 31, 2013 and 2012, the Company has $23.4 million and $25.3 million, respectively, included in Other assets representing defined benefit funding by the Company that is yet to be reflected in costs.

Indiana Gas 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 Indiana Gas. As of December 31, 2013 and 2012, $10.5 million and $8.5 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

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

Indiana Gas does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Indiana Gas’ current and deferred tax expense is computed on a separate company basis. 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 consolidated 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. Indiana Gas 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 Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.

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



	Year Ended December 31,
(In thousands)	2013			2012
Current:
Federal	$	19,618		$	11,365
State	7,239			4,701
Total current tax expense	26,857			16,066
Deferred:
Federal	1,992			12,004
State	(674		)	1,472
Total deferred taxes	1,318			13,476
Amortization of investment tax credits	(54		)	(83		)
Total income tax expense	$	28,121		$	29,459

Significant components of the net deferred tax liability follow:



	At December 31,
(In thousands)	2013			2012
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	164,920		$	157,128
Regulatory assets recoverable through future rates	9,653			9,347
Regulatory liabilities to be settled through future rates	(6,271		)	(5,321		)
Employee benefit obligations	3,976			7,233
Other – net	7,011			6,054
Net non-current deferred tax liability	179,289			174,441

Current deferred tax liabilities (assets):
Deferred fuel costs - net	1,902			7,727
Other – net	179			(547		)
Net current deferred tax liability	2,081			7,180
Net deferred tax liability	$	181,370		$	181,621

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

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



(in thousands)	2013			2012
Unrecognized tax benefits at January 1	$	800		$	1,194
Gross increases - tax positions in prior periods	—			40
Gross decreases - tax positions in prior periods	(122		)	(944		)
Gross increases - current period tax positions	396			510
Unrecognized tax benefits at December 31	$	1,074		$	800

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

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

In September 2013, the Internal Revenue Service released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted for 2013 tax years. The Company intends to adopt the guidance for its 2014 tax year. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue guidance with respect to natural gas transmission and distribution assets during 2014. The Company continues to evaluate the impact adoption of the

Indiana Gas relies entirely on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs. Borrowings outstanding at December 31, 2013 and 2012 were $62.0 million and $46.9 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($321 million at December 31, 2013) and is subject to the same terms and conditions as Utility Holdings’ short-term borrowing arrangements, including its commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds.

See the table below for interest rates and outstanding balances:



	Intercompany Borrowings
(In thousands)	2013			2012
Year End
Balance Outstanding	$	62,024		$	46,916
Weighted Average Interest Rate	0.30		%	0.40		%
Annual Average
Balance Outstanding	$	21,662		$	18,428
Weighted Average Interest Rate	0.34		%	0.47		%
Maximum Month End Balance Outstanding	$	62,024		$	46,916



	At December 31,
(In thousands)	2013		2012
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2015, 5.45%	24,716		24,716
2018, 5.75%	37,128		37,128
2028, 3.20%	8,953		—
2035, 6.10%	50,569		50,569
2039, 6.25%	—		21,535
2043, 4.25%	15,916		—
Total long-term debt payable to Utility Holdings	$	137,282	$	133,948

Fixed Rate Senior Unsecured Notes Payable to Third Parties:
2013, Series E, 6.69%	—		5,000
2015, Series E, 7.15%	5,000		5,000
2015, Series E, 6.69%	5,000		5,000
2015, Series E, 6.69%	10,000		10,000
2025, Series E, 6.53%	10,000		10,000
2027, Series E, 6.42%	5,000		5,000
2027, Series E, 6.68%	1,000		1,000
2027, Series F, 6.34%	20,000		20,000
2028, Series F, 6.36%	10,000		10,000
2028, Series F, 6.55%	20,000		20,000
2029, Series G, 7.08%	30,000		30,000
Total long-term debt outstanding payable to third parties	$	116,000	$	121,000
Current maturities	—		(5,000		)
Long-term debt payable to third parties - net of debt subject to tender	$	116,000	$	116,000

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 the Company, Southern Indiana Gas and Electric Company, and Vectren Energy Delivery of Ohio, Inc. In July 2013, Utility Holdings pushed $25 million of this refinanced debt to Indiana Gas. Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in its financing arrangements to account for debt issuance costs and any related hedging arrangements.

The Company has both firm and non-firm commitments to purchase natural gas, 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. Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.

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.

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

The Company received an order in 2008 associated with the most recent base rate case. 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 $20 million annually. The debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to four years after being placed into service. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2013 and 2012, the Company has regulatory assets totaling $10.7 million and $7.5 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

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

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

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

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

The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $650 million over the seven year period beginning in 2014, along with approximately $10 million in annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled to begin May 7, 2014, and an order is expected later in 2014.

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company

employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Vectren North that allowed Vectren North to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.

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

The existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to 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 $23.2 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, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company has recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2013 and 2012, approximately $1.3 million and $1.4 million, respectively, of accrued, but not yet spent, costs are included in Other liabilities related to these sites.



	At December 31,
	2013				2012
(In thousands)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt due to third parties	$	116,000	$	136,459	$	121,000	$	147,228
Long-term debt due to Utility Holdings	137,282		146,052		133,948		145,451
Short-term debt due to Utility Holdings	62,024		62,024		46,916		46,916
Cash & cash equivalents	3,622		3,622		4,092		4,092

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.

Accrued liabilities in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In thousands)	2013		2012
Customer advances & deposits	$	26,392	$	27,708
Accrued gas imbalance	2,594		2,457
Accrued taxes	12,462		8,775
Accrued interest	2,998		3,132
Deferred income taxes	2,081		7,180
Tax collections payable	4,818		3,821
Accrued salaries & other	2,587		2,649
Total accrued liabilities	$	53,932	$	55,722

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including

bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's consolidated financial statements.

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

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

The following discussion and analysis provides additional information regarding Indiana Gas’ results of operations that is supplemental to the information provided in Vectren Corporation’s and Utility Holdings’ management’s discussion and analysis of results of operations and financial condition contained in those 2013 annual reports filed on Forms 10-K, which include forward looking statement disclaimers. The following discussion and analysis should be read in conjunction with Indiana Gas’ consolidated financial statements and notes thereto.

In 2013, Indiana Gas had $40.7 million in net income compared to net income of $43.4 million in 2012. Though customer margin increased in 2013 from customer growth and usage, increased operating costs more than offset those margin increases. The increased operating costs were primarily the result of the acceleration of maintenance projects from future years that were completed in the current year. Depreciation expense also increased, reflecting the additions of plant in service. Interest expense was favorably impacted by financing transactions completed in 2013.

Gas operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters are regulated by the IURC. The Company obtained its most recent base rate order in February of 2008. The order authorizes a return on equity of 10.2%. The authorized return reflects the impact of innovative rate design strategies having been authorized by the IURC. Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns. In addition to timely gas and fuel cost recovery, approximately $13 million of the approximate $116 million in Other operating expenses incurred during 2013 are subject to a recovery mechanism outside of base rates.

Sales of natural gas to residential and commercial customers are largely seasonal and are impacted by weather. Trends in average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company has implemented conservation programs. Normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. The IURC has authorized a bare steel and cast iron replacement program but no rates have been implemented by any Indiana utility as of this date.

Gas costs incurred to serve customers is the Company’s most significant operating expense. Rates charged to natural gas customers contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on actual experience, subject to caps that are based on historical experience. GCA procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between

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

Gas pipeline integrity management costs, costs to fund energy efficiency programs, and the gas cost component of uncollectible accounts expense based on historical experience are 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 costs.

Throughout this discussion, the term Gas Utility margin is used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold. The Company believes Gas Utility margin is a better indicator of relative contribution than revenues since gas prices can be volatile and are generally collected on a dollar-for-dollar basis from customers. Following is a discussion and analysis of margin generated from operations.

Gas Utility margin and throughput by customer type follows:



	Year Ended December 31,
(In thousands)	2013		2012

Gas utility revenues	$	577,617	$	522,187
Cost of gas	300,174		255,346
Total gas utility margin	$	277,443	$	266,841
Margin attributed to:
Residential & commercial customers	$	219,099	$	216,879
Industrial customers	31,360		28,961
Other	5,867		5,743
Regulatory expense recovery mechanisms	21,117		15,258
Total gas utility margin	$	277,443	$	266,841
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	65,980		52,835
Industrial customers	59,961		55,027
Total sold & transported volumes	125,941		107,862

Gas utility margins were $277.4 million for the year ended December 31, 2013, and compared to 2012, increased $10.6 million. Customer margin increased approximately $4.6 million in 2013 from customer growth. The impact of higher natural gas prices and colder weather on revenue taxes, late and reconnect fees, and volumetric pass through costs increased gas utility margin $6.0 million in 2013 compared to 2012. With rate designs that substantially limit the impact of weather on margin, heating degree days in 2013 that were 102 percent of normal compared to 79 percent in 2012, had a significant impact on residential

For the year ended December 31, 2013, Other operating expenses were $115.8 million, which is an increase of $12.4 million, compared to 2012. Excluding operating expenses recovered through margin, expenses increased $8.2 million, primarily associated with additional maintenance projects that were completed in the current year. Though higher in 2013, operating costs are being managed to be generally flat to the 2012 targeted levels on an annual basis, over time.



	For the Year Ended
	December 31,
	2013		2012

OPERATING REVENUES (In thousands):
Residential	$	391,784	$	355,568
Commercial	145,349		128,890
Industrial	34,571		32,022
Other	5,913		5,707
	$	577,617	$	522,187

MARGIN (In thousands):
Residential	$	169,571	$	168,432
Commercial	49,528		48,447
Industrial	31,360		28,961
Other	5,867		5,743
Regulatory expense recovery mechanisms	21,117		15,258
	$	277,443	$	266,841

GAS SOLD & TRANSPORTED (In MDth):
Residential	45,137		36,303
Commercial	20,843		16,532
Industrial	59,961		55,027
	125,941		107,862

AVERAGE CUSTOMERS:
Residential	519,026		515,649
Commercial	50,448		49,359
Industrial	899		888
	570,373		565,896



		Page Number

	Audited Financial Statements
	Independent Auditors’ Report	2
	Consolidated Balance Sheets	3-4
	Consolidated Statements of Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Statements of Common Shareholder’s Equity	7
	Notes to Consolidated Financial Statements	8
	Results of Operations	23
	Selected Operating Statistics	26



	Year Ended December 31,
	2013		2012
Statutory rate	35.0	%	35.0	%
State & local taxes, net of federal benefit	5.7		5.9
Amortization of investment tax credit	—		(0.1	)
Adjustment to federal income tax accruals & other, net	0.2		(0.4	)
Effective tax rate	40.9	%	40.4	%



	At December 31,
(In thousands)	2013		2012
Gas in storage - at LIFO cost	$	19,672	11,222
Materials & supplies	2,805		2,760
Other	1,022		1,093
Total inventories	$	23,499	$	15,075



(In thousands)	2013		2012
Asset retirement obligation, January 1	$	10,345	$	15,072
Accretion	699		969
Changes in estimates, net of cash payments	779		(5,696		)
Asset retirement obligation, December 31	$	11,823	$	10,345



	Year Ended December 31,
(In thousands)	2013			2012
AFUDC - borrowed funds	$	1,277		$	1,588
AFUDC - equity funds	408			421
Other income	695			702
Regulatory expenses	(1,168		)	(671		)
Total other income – net	$	1,212		$	2,040


1.	Organization and Nature of Operations


2.	Summary of Significant Accounting Policies


5.	Transactions with Other Vectren Companies & Affiliates


6.	Borrowing Arrangements & Other Financing Transactions