Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

______________

FORM 10-Q

______________

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

Commission File No. 0-8788

______________

DELTA NATURAL GAS COMPANY, INC .

(Exact name of registrant as specified in its charter)

______________

Kentucky	61-0458329
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

3617 Lexington Road, Winchester, Kentucky	40391
(Address of principal executive offices)	(Zip code)

859-744-6171
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or Section 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer £	Accelerated filer x
Non-accelerated filer £ (Do not check if a smaller reporting company)	Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
As of March 31, 2013, Delta Natural Gas Company, Inc. had 6,855,973 shares of Common Stock outstanding.

DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

PART I -	FINANCIAL INFORMATION	3

ITEM 1.	Financial Statements	3

	Condensed Consolidated Statements of Income (Unaudited) for the three and nine month periods ended March 31, 2013 and 2012	3

	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2013 and June 30, 2012	4

	Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine month periods ended March 31, 2013 and 2012	6

	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2013 and 2012	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8

ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	20

ITEM 4.	Controls and Procedures	21

PART II -	OTHER INFORMATION	22

ITEM 1.	Legal Proceedings	22

ITEM 1A.	Risk Factors	22

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22

ITEM 3.	Defaults Upon Senior Securities	22

ITEM 4.	Mine Safety Disclosures	22

ITEM 5.	Other Information	22

ITEM 6.	Exhibits	22

	Signatures	24

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2013		2012		2013		2012

OPERATING REVENUES
Regulated revenues	$	19,140,556	$	16,927,971	$	38,181,030	$	35,529,294
Non-regulated revenues		11,992,793		9,788,099		26,511,323		26,609,449
Total operating revenues	$	31,133,349	$	26,716,070	$	64,692,353	$	62,138,743

OPERATING EXPENSES
Regulated purchased gas	$	8,654,059	$	7,205,406	$	15,036,956	$	13,491,470
Non-regulated purchased gas		9,166,269		7,065,624		19,977,804		20,252,696
Operation and maintenance		3,820,751		3,426,405		10,648,735		9,806,549
Depreciation and amortization		1,525,365		1,488,472		4,553,924		4,430,190
Taxes other than income taxes		643,841		558,192		1,768,068		1,635,471

Total operating expenses	$	23,810,285	$	19,744,099	$	51,985,487	$	49,616,376

OPERATING INCOME	$	7,323,064	$	6,971,971	$	12,706,866	$	12,522,367

OTHER INCOME (DEDUCTIONS), NET		61,596		69,694		119,234		47,514

INTEREST EXPENSE		676,968		760,206		1,192,858		3,540,988

NET INCOME BEFORE INCOME TAXES	$	6,707,692	$	6,281,459	$	11,633,242	$	9,028,893

INCOME TAX EXPENSE		2,465,015		2,356,164		4,300,093		3,388,485

NET INCOME	$	4,242,677	$	3,925,295	$	7,333,149	$	5,640,408

EARNINGS PER COMMON SHARE (Note 10) Basic	$	.62	$	.58	$	1.07	$	.83
Diluted	$	.62	$	.58	$	1.07	$	.83

DIVIDENDS DECLARED PER COMMON SHARE	$	.18	$	.175	$	.54	$	.525

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			June 30,
	2013			2012
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	12,039,203		$	9,740,502
Accounts receivable, less accumulated allowances for doubtful accounts of $422,000 and $157,000, respectively		14,697,475			8,028,937
Gas in storage, at average cost		1,309,966			6,932,807
Deferred gas costs		2,867,532			3,386,292
Materials and supplies, at average cost		548,312			557,118
Prepayments		1,262,763			2,393,674
Total current assets	$	32,725,251		$	31,039,330

PROPERTY, PLANT AND EQUIPMENT	$	221,923,483		$	217,172,542
Less-Accumulated provision for depreciation		(87,105,062	)		(82,835,542	)
Net property, plant and equipment	$	134,818,421		$	134,337,000

OTHER ASSETS
Cash surrender value of life insurance	$	329,566		$	307,125
Regulatory assets		17,170,950			16,517,812
Unamortized debt expense		98,804			104,104
Other non-current assets		727,496			589,992
Total other assets	$	18,326,816		$	17,519,033

Total assets	$	185,870,488		$	182,895,363

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(UNAUDITED)

	March 31,		June 30,
	2013		2012

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable	$	6,701,805	$	4,325,653
Current portion of long-term debt		1,500,000		1,500,000
Accrued taxes		1,806,942		4,154,064
Customers' deposits		836,196		853,061
Accrued interest on debt		137,005		1,026,387
Accrued vacation		707,151		736,856
Deferred income taxes		1,195,309		1,130,581
Other current liabilities		472,359		436,281
Total current liabilities	$	13,356,767	$	14,162,883

LONG-TERM DEBT	$	55,000,000	$	56,500,000

LONG-TERM LIABILITIES
Deferred income taxes	$	40,038,488	$	37,732,457
Investment tax credits		46,125		62,700
Regulatory liabilities		1,293,947		1,380,838
Accrued pension		242,568		2,307,260
Asset retirement obligations		4,022,169		3,823,724
Other long-term liabilities		845,763		705,094
Total long-term liabilities	$	46,489,060	$	46,012,073

COMMITMENTS AND CONTINGENCIES (Note 7)
Total liabilities	$	114,845,827	$	116,674,956

SHAREHOLDERS' EQUITY
Common shares ($1.00 par value), 20,000,000 shares
authorized, 6,855,973 and 6,803,941 shares
outstanding at March 31, 2013 and June 30,
2012, respectively	$	6,855,973	$	6,803,941
Premium on common shares		45,178,491		44,048,201
Retained earnings		18,990,197		15,368,265
Total shareholders' equity	$	71,024,661	$	66,220,407

Total liabilities and shareholders' equity	$	185,870,488	$	182,895,363

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

( UNAUDITED )


	Nine Months Ended March 31, 2013
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity

Balance, beginning of period	$	6,803,941	$	44,048,201	$	15,368,265		$	66,220,407
Net income		—		—		7,333,149			7,333,149
Issuance of common shares		20,156		389,434		—			409,590
Issuance of common shares under the
incentive compensation plan		31,876		232,226		—			264,102
Share-based compensation expense		—		482,464		—			482,464
Excess tax benefit from share-based compensation		—		26,166		—			26,166
Dividends on common shares		—		—		(3,711,217	)		(3,711,217	)

Balance, end of period	$	6,855,973	$	45,178,491	$	18,990,197		$	71,024,661


	Nine Months Ended March 31, 2012
	Common Shares		Premium on Common Shares			Retained Earnings			Shareholders' Equity

Balance, beginning of period	$	6,732,344	$	42,688,316		$	14,346,524		$	63,767,184
Net income		—		—			5,640,408			5,640,408
Issuance of common shares		28,756		458,574			—			487,330
Issuance of common shares under the
incentive compensation plan		22,000		315,040			—			337,040
Share-based compensation expense		10,668		308,518			—			319,186
Excess tax benefit from share-based compensation		—		(21,562	)		—			(21,562	)
Dividends on common shares		—		—			(3,568,692	)		(3,568,692	)

Balance, end of period	$	6,793,768	$	43,748,886		$	16,418,240		$	66,960,894

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended
	March 31,
	2013			2012

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	7,333,149		$	5,640,408
Adjustments to reconcile net income to net cash used in operating activities
Depreciation and amortization		4,806,424			4,756,462
Deferred income taxes and investment tax credits		2,265,706			389,450
Change in cash surrender value of officer's life insurance		(22,441	)		(7,463	)
Share-based compensation		746,566			613,102
Excess tax deficiency from share-based compensation		(8,946	)		—
Decrease (increase) in assets		431,954			(3,292,076	)
Increase (decrease) in liabilities		(3,556,139	)		300,130

Net cash provided by operating activities	$	11,996,273		$	8,400,013

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(4,924,459	)	$	(4,913,175	)
Proceeds from sale of property, plant and equipment		53,402			151,725
Other		(60,000	)		(60,000	)
Net cash used in investing activities	$	(4,931,057	)	$	(4,821,450	)

CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common shares	$	(3,711,217	)	$	(3,568,692	)
Issuance of common shares		409,590			487,330
Debt issuance costs		—			(107,904	)
Issuance of long-term debt		—			58,000,000
Excess tax benefit from share-based compensation		35,112			21,562
Repayment of long-term debt		(1,500,000	)		(57,951,006	)
Borrowing on bank line of credit		—			17,697,829
Repayment of bank line of credit		—			(17,697,829	)

Net cash used in financing activities	$	(4,766,515	)	$	(3,118,710	)

INCREASE IN CASH AND CASH EQUIVALENTS	$	2,298,701		$	459,853

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		9,740,502			7,340,192

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	12,039,203		$	7,800,045

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)	Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. ("Delta" or "the Company") distributes or transports natural gas to approximately 36,000 customers. Our distribution and transmission pipeline systems are located in central and southeastern Kentucky, and we operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system and sell liquids extracted from natural gas in our storage field and on our pipeline systems. We have three wholly-owned subsidiaries. Delta Resources, Inc. ("Delta Resources") buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. ("Delgasco") buys gas and resells it to Delta Resources and to customers not on Delta's system. Enpro, Inc. ("Enpro") owns and operates production properties and undeveloped acreage.

All subsidiaries of Delta are included in the condensed consolidated financial statements. Intercompany balances and transactions have been eliminated. All adjustments necessary for a fair presentation of the unaudited results of operations for the three and nine months ended March 31, 2013 and 2012 are included. All such adjustments are accruals of a normal and recurring nature other than the amounts disclosed in Note 7 related to the Utility Gross Receipts License Tax assessment.

The results of operations for the period ended March 31, 2013 are not necessarily indicative of the results of operations to be expected for the full fiscal year. Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably. Most construction activity and gas storage injections take place during these warmer months.

The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the financial statements, and the notes thereto, included in our Annual Report on Form 10-K for the year ended June 30, 2012.

(2)	Fair Value Measurements

Our financial assets and liabilities measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in other non-current assets on the Condensed Consolidated Balance Sheets. Contributions to the trust are presented in other investing activities on the Condensed Consolidated Statements of Cash Flows. The assets of the trust are recorded at fair value and consist of exchange traded mutual funds. The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy. The fair value of the trust assets are as follows:

	March 31,	June 30,
($000)	2013	2012

Trust assets
Money market	6	6
U.S. equity securities	472	364
U.S. fixed income securities	249	220
	727	590

The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value.

Our Series A Notes, presented as current portion of long-term debt and long-term debt on the Condensed Consolidated Balance Sheets, are stated at historical cost. Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate. The credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date. The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy.

	March 31,		June 30,
	2013		2012
	Carrying	Fair	Carrying	Fair
($000)	Amount	Value	Amount	Value

4.26% Series A Notes	56,500	59,835	58,000	59,027

(3)	Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk. We purchase our gas supply through a combination of spot market and forward purchases. We mitigate commodity price risk by efforts to balance supply and demand. For our regulated segment, we have minimal price risk resulting from these forward natural gas purchases because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission. None of our gas contracts are accounted for using the fair value method of accounting. While some of our natural gas purchase contracts and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

(4)	Unbilled Revenue

We bill our customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled.

Unbilled revenues and gas costs include the following:

	March 31,	June 30,
(000)	2013	2012

Unbilled revenues ($)	4,954	1,358
Unbilled gas costs ($)	2,466	392
Unbilled volumes (Mcf)	457	46

Unbilled revenues are included in accounts receivable and unbilled gas costs are included in deferred gas costs on the accompanying Condensed Consolidated Balance Sheets. Unbilled revenues are included in regulated revenues and unbilled gas costs are included in regulated purchased gas on the accompanying Condensed Consolidated Statements of Income.

(5)	Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, noncontributory defined benefit pension plan for the periods ended March 31 include the following:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2013		2012		2013		2012

Service cost	279		228		837		690
Interest cost	228		231		685		691
Expected return on plan assets	(394	)	(367	)	(1,183	)	(1,105	)
Amortization of unrecognized net loss	154		50		461		150
Amortization of prior service cost	(22	)	(21	)	(65	)	(65	)
Net periodic benefit cost	245		121		735		361

For the nine months ended March 31, 2013, we made discretionary contributions of $2,800,000 to the defined benefit pension plan.

(6)	Debt Instruments

Notes Payable

The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available as of March 31, 2013 and June 30, 2012. The bank line of credit extends through June 30, 2013. We have received regulatory approval to renew the line of credit through June 30, 2015 from the Kentucky Public Service Commission and anticipate renewal of this line by June 30, 2013. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.15%. The annual cost of the unused bank line of credit is .125%.

We were not in default on our bank line of credit during any period presented in the Condensed Consolidated Financial Statements.

Long-Term Debt

Our Series A Notes are unsecured, bearing interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031. Each December, we are required to make an annual $1,500,000 principal payment on the Series A Notes. The following table summarizes the remaining contractual maturities of our Series A Notes by fiscal year:

($000)
2013		—
2014		1,500
2015		1,500
2016		1,500
2017		1,500
Thereafter		50,500
Total Series A Notes		56,500

Any additional prepayment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with a maturity equal to the remaining average life of the Series A Notes.

We were not in default on any covenants on our long-term debt during any period presented in the Condensed Consolidated Financial Statements.

(7)	Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in control agreements with our other four officers. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company. In the event all of these agreements were exercised in the form of lump sum payments, approximately $4.0 million would be paid in addition to continuation of specified benefits for up to five years. Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements, would immediately vest.

Our June 30, 2012 Condensed Consolidated Balance Sheet includes accrued taxes and interest related to an assessment of a license tax levied on the gross receipts of Delta Resources' customers over the period of July, 2005 through September, 2011, as further discussed in Note 13 of the Notes to Consolidated Financial Statements in our 2012 Annual Report on Form 10-K. As reflected in our December 31, 2012 Quarterly Report on Form 10-Q, the assessment was resolved in February, 2013 and $923,000 of previously accrued interest was reversed. Delta Resources billed its customers their proportionate share of the assessment, as Delta Resources has a contractual right to seek reimbursement from its customers. As of March 31, 2013, the net receivable from Delta Resources' customers was $1,418,000. We will continue to pursue collection of the taxes from these customers and to monitor the amount of the receivable to be realized. Included in the receivable is $174,000 due from a Delta Resources' customer that is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the Condensed Consolidated Balance Sheets, the receivable from Delta Resources' customers is included in accounts receivable. On the June 30, 2012 Condensed Consolidated Balance Sheet, the liability for taxes was included in accrued taxes, and the liability for interest was included in accrued interest on debt. In the Condensed Consolidated Statements of Income, the change in the interest accrued is included in interest expense.

We are not a party to any material pending legal proceedings.

We have entered into forward purchase agreements beginning in April, 2013 and expiring at various dates through December, 2013. These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements. These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements. These agreements have aggregate minimum purchase obligations of $115,000 and $211,000 for our fiscal years ended June 30, 2013 and June 30, 2014, respectively.

(8)	Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. Their regulation of our business includes approving the rates we are permitted to charge our regulated customers. We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services. They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return. We do not have any matters pending before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial positions or cash flows.

(9)	Operating Segments

Our Company has two segments: (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment that participates in related ventures, consisting of natural gas marketing, natural gas production and sales of natural gas liquids. Virtually all of the revenues recorded under both segments come from the sale or transportation of natural gas or related sales of natural gas liquids. The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky. Price risk for the regulated segment is mitigated through our gas cost recovery clause, approved quarterly by the Kentucky Public Service Commission. Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict our demand. In addition, we are exposed to price risk resulting from changes in the market price of natural gas, natural gas liquids and uncommitted gas inventory of our non-regulated companies.

The reportable segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements that are included in our Annual Report on Form 10-K for the year ended June 30, 2012. Intersegment transportation revenues and expenses represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates. Operating expenses, taxes and interest are allocated to the non-regulated segment.

Segment information is shown in the following table:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2013		2012		2013		2012
Operating Revenues
Regulated
External customers	19,140		16,928		38,181		35,530
Intersegment	1,432		1,090		3,307		2,918
Total regulated	20,572		18,018		41,488		38,448
Non-regulated
External customers	11,993		9,788		26,511		26,609
Eliminations for intersegment	(1,432	)	(1,090	)	(3,307	)	(2,918	)
Consolidated operating revenues	31,133		26,716		64,692		62,139

Net Income
Regulated	3,797	3,125	5,861	4,768
Non-regulated	446	800	1,472	872
Consolidated net income	4,243	3,925	7,333	5,640

(10) Earnings per Common Share

The following table sets forth the computation of basic and diluted earnings per share:

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
Numerator – basic and diluted
Net income ($000)		4,243			3,925			7,333			5,640
Dividends paid ($000)		(1,238	)		(1,192	)		(3,711	)		(3,569	)

Undistributed earnings ($000)		3,005			2,733			3,622			2,071
Percentage allocated to common shares (a)		99.6	%		99.7	%		99.6	%		99.7	%

Undistributed earnings allocated to common shares ($000)		2,992			2,725			3,607			2,065
Dividends declared allocated to common shares ($000)		1,233			1,188			3,696			3,558

Net income available to common shares ($000)		4,225			3,913			7,303			5,623

Denominator – (b) (d)
Basic – weighted-average common shares		6,851,533			6,788,307			6,838,283			6,770,438
Incremental unvested non-participating shares		12,126			—			4,042			—
Diluted – weighted-average common shares		6,863,659			6,788,307			6,842,325			6,770,438

Earnings per common share ($)
Basic		.62			.58			1.07			.83
Diluted		.62			.58			1.07			.83

(a) Percentage allocated to common shares – weighted average
Common shares outstanding	6,851,533		6,788,307		6,838,283		6,770,438
Unvested participating shares (c)	28,667		21,332		28,667		21,332
Total	6,880,200		6,809,639		6,866,950		6,791,770
Percentage allocated to common shares	99.6	%	99.7	%	99.6	%	99.7	%

(b)

Under our incentive compensation plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end, as further discussed in (c). The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. As of March 31, 2013, 39,000 unvested non-participating shares are included in the diluted earnings per share calculation using the treasury stock method. As of March 31, 2012, there were 36,000 unvested non-participating shares outstanding, which were not dilutive as the underlying performance condition has not yet been met.

(c)

Certain awards under our incentive compensation plan provide recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. As of March 31, 2013 and 2012 there were 29,000 and 21,000 unvested participating shares outstanding, respectively.

(d)

For the three and nine months ended March 31, 2013 and 2012 there were no antidilutive shares.

(11)	Share-Based Compensation

We have a shareholder approved incentive compensation plan (the "Plan"), which provides for incentive compensation payable in shares of our common stock. The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining which employees, officers and outside directors shall be eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan.

The number of shares of our common stock that may be issued pursuant to the Plan may not exceed 1,000,000 shares in the aggregate. As of March 31, 2013, 889,000 shares of common stock were available for issuance under the Plan, subject to the limitations imposed by our Corporate Governance Guidelines. Shares of common stock may be available from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market.

Compensation expense for share-based compensation is recorded in the non-regulated segment and included in operation and maintenance expense in the Condensed Consolidated Statements of Income based on the fair value of the awards at the grant date and is amortized over the requisite service period. Fair value is the closing price of our common shares at the grant date. The grant date is the date at which our commitment to issue the share-based awards arises, which is generally when the award is approved and the terms of the awards are communicated to the employee or director. We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met.

	Three Months Ended		Nine Months Ended
	March 31,		March 31,
($000)	2013	2012	2013	2012

Share-based compensation expense	175	99	747	613

For the nine months ended March 31, 2013 and 2012, an excess tax benefit of $26,000 and $22,000, respectively, was recognized as an increase to premium on common shares on our Condensed Consolidated Balance Sheets, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation. This excess tax benefit can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods.

Stock Awards

For the nine months ended March 31, 2013 and 2012, common stock was awarded to virtually all Delta employees and directors having grant date fair values of $264,000 (12,000 shares) and $337,000 (22,000 shares), respectively. The recipients vested in the awards shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.

Performance Shares

For the nine months ended March 31, 2013 and 2012, performance shares were awarded to the Company's executive officers having grant date fair values of $844,000 (39,000 shares) and $552,000 (36,000 shares), respectively. The performance share awards vest only if the performance objectives of the awards are met, which are based on the Company's earnings per common share for the fiscal year in which the performance shares are awarded, before any cash bonuses or share-based compensation. Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest equally over a three-year period beginning the August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period. The recipients of the awards also become vested as a result of certain events such as death or disability of the holders. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards. Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

For the three and nine months ended March 31, 2013, compensation expense related to the performance shares was $175,000 and $482,000, respectively. For the three and nine months ended March 31, 2012, compensation expense related to the performance shares was $99,000 and $276,000, respectively. As of March 31, 2013 and 2012, there were 29,000 and 21,000 unvested performance shares outstanding, respectively, for which the performance objectives have been satisfied.

Our performance shares have graded vesting schedules, and each separate annual vesting tranche is treated as a separate award for expense recognition. Compensation expense is amortized over the vesting period of the individual awards based on the probable outcome of meeting the performance objectives.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

YEAR TO DATE MARCH 31, 2013 OVERVIEW AND FUTURE OUTLOOK

The following is a discussion of the segments we operate, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during the nine months ended March 31, 2013. Our Company has two segments: (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing, natural gas production and the sale of liquids extracted from natural gas.

Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors. Regulated sales volumes are temperature-sensitive and in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes. The impact of winter temperatures on our revenues is partially reduced by our ability to adjust our winter rates for residential and small non-residential customers based on the degree to which actual winter temperatures deviate from normal.

Our non-regulated segment markets natural gas to large-use customers both on and off our regulated system. We endeavor to enter sales agreements to matching supply with estimated demand while providing an acceptable gross margin. The non-regulated segment also produces natural gas and sells liquids extracted from natural gas.

Our consolidated net income per common share for the nine months ended March 31, 2013, increased $.24 per share, as compared to the same period in the prior year. The increase is primarily due to decreased interest expense resulting from the resolution of a tax assessment issued to Delta Resources (as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements) and decreased interest expense on our long-term debt due to the refinancing of our 7% Debentures and 5.75% Insured Quarterly Notes in December, 2011 by the issuance of our 4.26% Series A Notes.

The results of operations for the period ended March 31, 2013 are not necessarily indicative of the results of operations to be expected for the full fiscal year. Because of the seasonal nature of our sales, we generate a significant proportion of our operating revenues during the heating months (December – April) when our sales volumes increase considerably.

Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers. The Kentucky Public Service Commission sets these rates, and we monitor our need to file rate cases with the Kentucky Public Service Commission for a general rate increase for our regulated services. The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers. We manage remaining expenses through budgeting, approval and review.

Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large use customers and the market prices of natural gas and natural gas liquids, all of which are beyond our control. We anticipate our non-regulated segment to continue to contribute to our consolidated net income for the remainder of fiscal 2013. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production and marketing activities. However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities. We anticipate continued extraction and sales of natural gas liquids in fiscal 2013. The profitability of such sales is dependent on the quantity of liquids extracted and the pricing for any such liquids as determined in the national unregulated market.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of our net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital. Our sales and cash requirements are seasonal. The largest portion of our sales occurs during the heating months whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months. Therefore, in periods when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit. The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of March 31, 2013 or June 30, 2012.

Cash and cash equivalents were $12,039,000 at March 31, 2013, as compared with $9,741,000 at June 30, 2012. The changes in cash and cash equivalents are summarized in the following table:

	Nine Months Ended
	March 31,
($000)	2013		2012

Provided by operating activities	11,996		8,400
Used in investing activities	(4,931	)	(4,821	)
Used in financing activities	(4,766	)	(3,119	)
Increase in cash and cash equivalents	2,299		460

For the nine months ended March 31, 2013, cash provided by operating activities increased $3,596,000 (43%). Cash paid for natural gas decreased $10,209,000 as a result of decreases in natural gas purchased for storage and the market price of natural gas purchased. The decrease was partially offset by a $2,546,000 tax payment (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements), and $2,800,000 in discretionary contributions to our defined benefit pension plan to maintain the fully-funded status of the plan.

Changes in cash used in investing activities result primarily from changes in the level of capital expenditures between years.

For the nine months ended March 31, 2013, cash used in financing activities increased $1,647,000 (53%) due to a $1,500,000 repayment on our 4.26% Series A Notes.

Cash Requirements

Our capital expenditures result in a continued need for capital. These capital expenditures are made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2013 to be approximately $7.5 million.

Sufficiency of Future Cash Flows

Our ability to maintain liquidity, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated rates we charge our customers. The Kentucky Public Service Commission sets these rates and we monitor our need to file for rate increases for our regulated segment. Our regulated base rates were most recently adjusted in our 2010 rate case and became effective in October, 2010. We expect that cash provided by operations will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the remainder of fiscal 2013.

To the extent that internally generated cash is not sufficient to satisfy seasonal operating and capital expenditure requirements and to pay dividends, we will rely on our bank line of credit. Our current available bank line of credit with Branch Banking and Trust Company extends through June 30, 2013 and permits borrowings up to $40,000,000. We have received regulatory approval to renew the line of credit through June 30, 2015 from the Kentucky Public Service Commission and intend to renew our bank line of credit prior to June 30, 2013.

In December, 2011, we issued $58,000,000 of Series A Notes that are unsecured, bear interest at a fixed rate of 4.26% per annum that is payable quarterly, and which mature on December 30, 2013. We are required to make an annual $1,500,000 principal payment on the Series A Notes each December.

Any additional prepayment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with maturities equal to the remaining average life of the Series A Notes.

The Agreement for the Series A Notes contains a private shelf facility that extends through December, 2013. We may, with mutual agreement between us and the purchasers or their affiliates, issue them additional long-term unsecured promissory notes of the Company in an aggregate principal amount of $17,000,000.

With our bank line of credit and Series A Notes, we have agreed to certain financial, affirmative and negative covenants. Noncompliance with these covenants can make the obligation immediately due and payable, as further discussed in our Annual Report on Form 10-K for the year ended June 30, 2012. A default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with our bank line of credit and the Series A Notes. We were not in default on our bank line of credit or Series A Notes during any period presented in the Condensed Consolidated Financial Statements.

RESULTS OF OPERATIONS

Gross Margins

Our operating revenues are derived primarily from the sale of natural gas and natural gas liquids and the provision of natural gas transportation services. We define "gross margin" as gas sales less the corresponding purchased gas expenses, plus transportation, natural gas liquids and other revenues. We view gross margins as an important performance measure of the core profitability of our operations and believe that investors benefit from having access to the same financial measures that our management uses. Gross margin can be derived directly from our Condensed Consolidated Statements of Income as follows:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2013		2012		2013		2012

Operating revenues (a)	31,133		26,716		64,692		62,139
Regulated purchased gas (a)	(8,654	)	(7,205	)	(15,037	)	(13,491	)
Non-regulated purchased gas (a)	(9,166	)	(7,066	)	(19,978	)	(20,253	)

Consolidated gross margin	13,313		12,445		29,677		28,395

(a)	Amounts derived from the Condensed Consolidated Statements of Income included in Item 1. Financial Statements.

Operating Income, as presented in the Condensed Consolidated Statements of Income, is the most directly comparable financial measure to gross margin calculated and presented in accordance with accounting principles generally accepted in the United States ("GAAP"). Gross margin is a "non-GAAP financial measure", as defined in accordance with SEC rules.

Natural gas prices are determined by an unregulated national market. Therefore, the price that we pay for natural gas fluctuates with national supply and demand. See Item 3 for the impact of forward contracts.

In the following table we set forth variations in our gross margins for the three and nine months ended March 31, 2013 compared with the same periods in the preceding year. The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Income.

	2013 compared to 2012
	Three Months		Nine Months
	Ended		Ended
($000)	March 31		March 31

Increase (decrease) in regulated gross margins: Regulated segment
Gas sales	708		1,010
On-system transportation	194		321
Off-system transportation	200		163
Other	3		—
Intersegment elimination (a)	(342	)	(389	)
Total	763		1,105

Non-regulated segment Natural gas sales	(265	)	(549	)
Natural gas liquids	37		386
Other	(9	)	(49	)
Intersegment elimination (a)	342		389
Total	105		177

Increase in consolidated gross margins	868		1,282

Percentage increase in volumes:
Regulated segment
Natural gas sales (Mcf)	38	24
On-system transportation (Mcf)	9	6
Off-system transportation (Mcf)	24	6

Non-regulated segment
Natural gas sales (Mcf)	50	21
Natural gas liquids (gallons)	66	129

(a)	Intersegment eliminations represent the tariffed transportation fee charged by the regulated segment to the non-regulated segment for its natural gas sales.

Heating degree days were 108% and 105% of normal thirty year average temperatures for the three and nine months ended March 31, 2013, respectively, as compared with 78% and 84% of normal temperatures in the 2012 periods. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to estimate the demand for natural gas. A heating degree day is the equivalent for each degree that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location. Normal degree days are based on the historical 30-year average National Weather Service data for the same geographic location.

For the three months ended March 31, 2013, consolidated gross margins increased $868,000 (7%), as compared to the same period in the prior year, due to increased regulated and non-regulated gross margins of $763,000 and $105,000, respectively. Regulated gross margins increased due to a 38% increase in volumes sold to our regulated customers as a result of colder weather, as compared to the same period in the prior year. Partially offsetting this increase are decreased rates billed through our weather normalization tariff. Our non-regulated gross margins increased as a result of increased natural gas sales, net of intersegment transportation fees, resulting from an increase in our non-regulated customers' gas requirements. The increase was partially offset by a decline in sales prices for our non-regulated gas sales.

For the nine months ended March 31, 2013, consolidated gross margins increased $1,282,000 (5%), as compared to the same period in the prior year, due to increased regulated and non-regulated gross margins of $1,105,000 and $177,000, respectively. Regulated gross margins increased due to a 24% increase in volumes sold to our regulated customers as a result of colder weather, as compared to the same period in the prior year. Partially offsetting this increase are decreased rates billed through our weather normalization tariff. Our non-regulated gross margins increased due to the sale of liquids extracted from the natural gas in our system. The increase was partially offset by a decline in sales prices for our non-regulated gas sales.

Operation and Maintenance

For the three months ended March 31, 2013, operation and maintenance increased $395,000 (12%) as compared to the same period in the prior year, due to a $227,000 increase in uncollectible accounts resulting from the collections of a tax assessment from Delta Resources' customers (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements) and a $115,000 increase in net periodic benefit cost for our defined benefit pension plan.

For the nine months ended March 31, 2013, there were no significant changes in operation and maintenance, as compared to the same period in the prior year.

Depreciation and Amortization

For the three and nine month periods ended March 31, 2013, there were no significant changes in depreciation and amortization, as compared to the same periods in the prior year.

Taxes Other than Income Taxes

For the three and nine month periods ended March 31, 2013, there were no significant changes in taxes other than income taxes, as compared to the same periods in the prior year.

Other Income (Deductions), Net

For the three and nine month periods ended March 31, 2013, there were no significant changes in other income (deductions), net, as compared to the same periods in the prior year.

Interest Expense

For the three months ended March 31, 2013, there were no significant changes in interest expense, as compared to the same period in the prior year.

For the nine months ended March 31, 2013, interest expense decreased $2,348,000 (66%) due to a $1,708,000 decrease in interest accrued for a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements). Additionally, interest expense decreased $604,000 as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures in December, 2011.

Income Tax Expense

For the three months ended March 31, 2013, there were no significant changes in income tax expense, as compared to the same period in the prior year.

For the nine months ended March 31, 2013, income tax expense increased $912,000 (27%), as compared to the same period in the prior year. The increase is due to an increase in our net income before income taxes. There were no significant changes to our effective tax rate for the nine month period ended March 31, 2013, as compared to the same period in the prior year.

Basic and Diluted Earnings Per Common Share

For the three and nine months ended March 31, 2013, our basic and diluted earnings per common share changed as a result of a change in our net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our Dividend Reinvestment and Stock Purchase Plan as well as those shares awarded through our incentive compensation plan.

Under our incentive compensation plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end, as further discussed in (d). The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. As of March 31, 2013, 39,000 unvested non-participating shares are included in the diluted earnings per share calculation using the treasury stock method. As of March 31, 2012, there were 36,000 unvested non-participating shares outstanding, which were not dilutive as the underlying performance condition has not yet been met.

For the three and nine months ended March 31, 2013 and 2012 there were no antidilutive shares.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We purchase our natural gas supply through a combination of spot market and forward purchases. The price of spot market gas is based on the market price at the time of delivery. The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the natural gas. Additionally, we inject some of our gas purchases into a gas storage facility in the non-heating months and withdraw this natural gas from storage for delivery to customers during the heating months. For our regulated segment, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through our gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for our non-regulated gas sales is mitigated by efforts to balance supply and demand. However, there are greater risks because of the practical limitations on the ability to perfectly predict demand. We are exposed to changes in the market price of gas on uncommitted gas inventory of our non-regulated segment. The natural gas liquids sold by our non-regulated segment is priced based upon the pricing determined in the national unregulated market.

None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales. As of March 31, 2013, we had forward purchase contracts totaling $326,000 that have various terms with the last contract expiring December, 2013. These forward purchase contracts are at a fixed price and not impacted by changes in the market price of natural gas.

When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates. The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate. There were no borrowings outstanding on our bank line of credit as of March 31, 2013 or June 30, 2012.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of March 31, 2013, and, based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended March 31, 2013 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS

	We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.

ITEM 1A.	RISK FACTORS

	No material changes.

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

	None.

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

	None.

ITEM 4.	MINE SAFETY DISCLOSURES

	None.

ITEM 5.	OTHER INFORMATION

	None.

ITEM 6.	EXHIBITS

	31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.INS		XBRL Instance Document
	101.SCH		XBRL Taxonomy Extension Schema
	101.CAL		XBRL Taxonomy Extension Calculation Linkbase
	101.DEF		XBRL Taxonomy Extension Definition Database
	101.LAB		XBRL Taxonomy Extension Label Linkbase
	101.PRE		XBRL Taxonomy Extension Presentation Linkbase

	Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL):
	(i)		Document and Entity Information
	(ii)		Condensed Consolidated Statements of Income (Unaudited) for the three and nine month periods ended March 31, 2013 and 2012;

(iii)		Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2013 and 2012; and
(iv)		Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2013 and June 30, 2012
(v)		Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine month periods ended March 31, 2013 and 2012;
(vi)		Notes to Condensed Consolidated Financial Statements (Unaudited).
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or port of a registration statement or prospects for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DATE: May 7, 2013		/s/Glenn R. Jennings
		Glenn R. Jennings Chairman of the Board, President and Chief Executive Officer (Duly Authorized Officer)


		/ s/John B. Brown
		John B. Brown Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer)