Delta Natural Gas (DGAS) 10-Q 2015 Q3 Quarterly report

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, 2015

OR

¨ 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  £    No  x

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, 2015 Delta Natural Gas Company, Inc. had 7,019,859 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 months ended March 31, 2015 and 2014	3
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2015 and June 30, 2014	4
	Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine months ended March 31, 2015 and 2014	6
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2015 and 2014	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	20
PART II -	OTHER INFORMATION	21
ITEM 1.	Legal Proceedings	21
ITEM 1A.	Risk Factors	21
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
ITEM 3.	Defaults Upon Senior Securities	21
ITEM 4.	Mine Safety Disclosures	21
ITEM 5.	Other Information	21
ITEM 6.	Exhibits	22
	Signatures	23

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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,
	2015		2014		2015		2014
OPERATING REVENUES
Regulated revenues	$	23,144,565	$	26,270,729	$	45,390,815	$	48,677,954
Non-regulated revenues	11,940,742		14,164,787		28,891,063		30,609,498
Total operating revenues	$	35,085,307	$	40,435,516	$	74,281,878	$	79,287,452
OPERATING EXPENSES
Regulated purchased natural gas	$	11,913,926	$	14,988,738	$	21,001,704	$	24,267,893
Non-regulated purchased natural gas	9,650,709		10,607,359		23,164,565		22,507,137
Operation and maintenance	3,859,474		3,781,445		10,921,700		10,910,884
Depreciation and amortization	1,640,786		1,548,836		4,732,493		4,661,922
Taxes other than income taxes	734,012		623,015		2,115,853		1,736,425
Total operating expenses	$	27,798,907	$	31,549,393	$	61,936,315	$	64,084,261
OPERATING INCOME	$	7,286,400	$	8,886,123	$	12,345,563	$	15,203,191
OTHER INCOME AND DEDUCTIONS, NET	29,375		27,025		30,565		159,814
INTEREST CHARGES	641,703		659,375		1,958,841		2,011,694
NET INCOME BEFORE INCOME TAXES	$	6,674,072	$	8,253,773	$	10,417,287	$	13,351,311
INCOME TAX EXPENSE	2,518,936		3,080,149		3,916,742		4,963,549
NET INCOME	$	4,155,136	$	5,173,624	$	6,500,545	$	8,387,762
EARNINGS PER COMMON SHARE (Note 11)
Basic and Diluted	$	.59	$	.74	$	.92	$	1.21
DIVIDENDS DECLARED PER COMMON SHARE	$	.20	$	.19	$	.60	$	.57

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

3

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			June 30,
	2015			2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	16,101,702		$	13,675,918
Accounts receivable, less accumulated allowances
for doubtful accounts of $350,000 and $360,000, respectively	12,602,902			6,681,964
Natural gas in storage, at average cost	1,757,673			7,125,499
Regulatory asset - deferred natural gas costs	—			724,923
Materials and supplies, at average cost	493,791			574,699
Prepayments	2,247,005			3,491,257
Deferred income taxes	761,445			—
Total current assets	$	33,964,518		$	32,274,260
PROPERTY, PLANT AND EQUIPMENT	$	234,643,311		$	229,367,319
Less-Accumulated provision for depreciation	(97,483,935		)	(93,551,799		)
Net property, plant and equipment	$	137,159,376		$	135,815,520
OTHER ASSETS
Cash surrender value of life insurance	$	413,618		$	402,147
Prepaid pension	3,922,475			3,291,974
Regulatory assets	13,635,273			13,198,199
Unamortized debt expense	85,304			90,304
Other non-current assets	982,332			952,757
Total other assets	$	19,039,002		$	17,935,381
Total assets	$	190,162,896		$	186,025,161

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

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DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(UNAUDITED)

	March 31,		June 30,
	2015		2014
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,881,371	$	6,706,021
Current portion of long-term debt	1,500,000		1,500,000
Accrued taxes	1,727,139		1,553,670
Customers' deposits	740,347		593,010
Accrued interest on debt	113,886		120,712
Accrued vacation	704,888		752,905
Deferred income taxes	—		39,718
Regulatory liability - refundable natural gas costs	1,643,004		—
Other current liabilities	522,516		591,606
Total current liabilities	$	11,833,151	$	11,857,642
LONG-TERM DEBT	$	52,000,000	$	53,500,000
LONG-TERM LIABILITIES
Deferred income taxes	$	42,219,370	$	40,537,879
Investment tax credits	14,250		24,600
Regulatory liabilities	1,175,741		1,165,260
Asset retirement obligations	3,443,368		3,260,721
Other long-term liabilities	1,033,248		950,707
Total long-term liabilities	$	47,885,977	$	45,939,167
COMMITMENTS AND CONTINGENCIES (Note 8)
Total liabilities	$	111,719,128	$	111,296,809
SHAREHOLDERS' EQUITY
Common shares ($1.00 par value), 20,000,000 shares
authorized, 7,019,859 and 6,942,758 shares
outstanding at March 31, 2015 and June 30,
2014, respectively	$	7,019,859	$	6,942,758
Premium on common shares	48,547,922		47,182,338
Retained earnings	22,875,987		20,603,256
Total shareholders' equity	$	78,443,768	$	74,728,352
Total liabilities and shareholders' equity	$	190,162,896	$	186,025,161

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

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DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(UNAUDITED)

	Nine Months Ended March 31, 2015
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity
Balance, beginning of period	$	6,942,758	$	47,182,338	$	20,603,256		$	74,728,352
Net income	—		—		6,500,545			6,500,545
Issuance of common shares	19,771		378,993		—			398,764
Issuance of common shares under the
incentive compensation plan	57,330		385,251		—			442,581
Share-based compensation expense	—		592,091		—			592,091
Excess tax benefit from share-based compensation	—		9,249		—			9,249
Dividends on common shares	—		—		(4,227,814		)	(4,227,814		)
Balance, end of period	$	7,019,859	$	48,547,922	$	22,875,987		$	78,443,768

	Nine Months Ended March 31, 2014
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity
Balance, beginning of period	$	6,864,253	$	45,523,123	$	17,618,039		$	70,005,415
Net income	—		—		8,387,762			8,387,762
Issuance of common shares	22,197		440,225		—			462,422
Issuance of common shares under the
incentive compensation plan	49,696		299,930		—			349,626
Share-based compensation expense	—		562,648		—			562,648
Excess tax benefit from share-based compensation	—		30,266		—			30,266
Dividends on common shares	—		—		(3,965,227		)	(3,965,227		)
Balance, end of period	$	6,936,146	$	46,856,192	$	22,040,574		$	75,832,912

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

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DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED) 

	Nine Months Ended
	March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	6,500,545		$	8,387,762
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization	4,913,293			4,873,928
Deferred income taxes and investment tax credits	815,773			(151,962		)
Change in cash surrender value of officer's life insurance	(11,471		)	(47,363		)
Share-based compensation	1,034,672			912,274
Excess tax deficiency from share-based compensation	(9,574		)	(8,967		)
Decrease in assets	578,429			2,227,977
Increase in liabilities	341,589			3,208,318
Net cash provided by operating activities	$	14,163,256		$	19,401,967
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(6,402,067	)	$	(5,343,268	)
Proceeds from sale of property, plant and equipment	34,822			170,277
Other	(60,000		)	(60,000		)
Net cash used in investing activities	$	(6,427,245	)	$	(5,232,991	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common shares	$	(4,227,814	)	$	(3,965,227	)
Issuance of common shares	398,764			462,422
Excess tax benefit from share-based compensation	18,823			39,233
Repayment of long-term debt	(1,500,000		)	(1,500,000		)
Borrowing on bank line of credit	126,430			691,157
Repayment of bank line of credit	(126,430		)	(691,157		)
Net cash used in financing activities	$	(5,310,227	)	$	(4,963,572	)
NET INCREASE IN CASH AND CASH EQUIVALENTS	$	2,425,784		$	9,205,404
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	13,675,918			10,360,462
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	16,101,702		$	19,565,866

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

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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 transportation systems are located in central and southeastern Kentucky and we own and 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 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 natural gas and resells it to Delta Resources and to customers not on Delta's system.  Enpro, Inc. ("Enpro") owns and operates natural gas 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, 2015 and 2014 are included.  All such adjustments are accruals of a normal and recurring nature.

The results of operations for the period ended March 31, 2015 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 natural 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, 2014.

(2)     New Accounting Pronouncements

In September, 2013, the Internal Revenue Service ("IRS") issued final regulations regarding the tax treatment of amounts paid to acquire, produce or improve tangible property, which update temporary regulations issued by the IRS in December, 2011. The IRS plans to issue further guidance for specific industry sectors, including natural gas. The final regulations are effective for our tax year beginning July 1, 2014; however, we do not expect compliance with the final regulations and industry specific guidance to have a material impact on our results of operations, financial position or cash flow.

In May, 2014, the Financial Accounting Standards Board issued guidance revising the principles and standards for revenue recognition. The guidance creates a framework for recognizing revenue to improve comparability of revenue recognition practices across entities and industries. The guidance is effective for our quarterly report ended September 30, 2017 and we are evaluating the methods of adoption allowed by the new standard and the effect the standard is expected to have on our results of operations, financial position or cash flow. In April, 2015, the Financial Accounting Standards Board issued proposed guidance that allows for a one-year deferral of the effective date of this guidance.  A final decision on the deferral is subject to the Financial Accounting Standards Board's due process requirement.

In June, 2014, the Financial Accounting Standards Board issued guidance on share-based payments where performance targets can be achieved subsequent to the requisite service period. The guidance, effective for our quarter ending September 30, 2015, is not expected to have a material impact on our results of operations, financial position or cash flow.

In April, 2015, the Financial Accounting Standards Board issued guidance on the presentation of debt issuance costs which requires the debt issuance costs to be recognized as a direct deduction from the carrying amount of the debt liability. The guidance, effective for our quarter ending September, 2015, is not expected to have a material impact on our results of operations, financial position or cash flow.

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(3) 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 securities and exchange traded mutual funds. The securities and 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)	2015	2014
Trust assets
Money market	51	44
U.S. equity securities	389	379
Foreign equity funds	178	167
U.S. fixed income securities	179	121
Foreign fixed income funds	58	53
Absolute return strategy mutual funds	127	143
	982	907

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 long-term debt, as well as current portion of long-term debt, on the Condensed Consolidated Balance Sheets, are stated at historical cost. The 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 3 in the fair value hierarchy.

	March 31,		June 30,
	2015		2014
	Carrying	Fair	Carrying	Fair
($000)	Amount	Value	Amount	Value
4.26% Series A Notes	53,500	56,614	55,000	55,576

(4) Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk.  We purchase our natural gas supply through a combination of requirements contracts with no minimum purchase obligations, monthly spot purchase contracts and forward purchase contracts.  We mitigate price risk related to the sale of natural gas by efforts to balance supply and demand. For our regulated segment, we utilize requirements contracts, spot purchase contracts and our underground storage to meet our regulated customers' natural gas requirements, all of which have minimal price risk because we are permitted to pass these natural gas costs on to our regulated customers through the natural gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.  None of our natural 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.

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(5) Unbilled Revenue

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We bill our customers on a monthly meter reading cycle. At the end of each month, natural 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 natural gas costs include the following:

	March 31,	June 30,
(000)	2015	2014
Unbilled revenues ($)	6,770	1,788
Unbilled natural gas costs ($)	3,717	622
Unbilled volumes (Mcf)	556	63

Unbilled revenues are included in accounts receivable. As of March 31, 2015 and June 30, 2014, unbilled natural gas costs are included in regulatory liability - deferred natural gas costs and regulatory asset - refundable natural gas costs, respectively, on the accompanying Condensed Consolidated Balance Sheets.  Unbilled revenues are included in regulated revenues and unbilled natural gas costs are included in regulated purchased natural gas on the accompanying Condensed Consolidated Statements of Income.

(6)    Defined Benefit Retirement Plan

Net periodic benefit costs for our trusteed, noncontributory defined benefit retirement plan for the periods ended March 31, 2015 and 2014, include the following:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2015		2014		2015		2014
Service cost	247		256		743		768
Interest cost	264		259		793		778
Expected return on plan assets	(428	)	(392	)	(1,284	)	(1,176	)
Amortization of unrecognized net loss	61		86		184		257
Amortization of prior service cost	(22	)	(22	)	(65	)	(66	)
Net periodic benefit cost	122		187		371		561

In October, 2014 we made a discretionary contribution of $1,000,000 to the defined benefit retirement plan.

(7) 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, 2015 and June 30, 2014.  The bank line of credit extends through June 30, 2015 and we anticipate renewal of this line by June 30, 2015.  As of March 31, 2015, the interest rate on the used line of credit is the London Interbank Offered Rate plus 1.15% and the annual cost of the unused bank line of credit is 0.125%.

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Long-Term Debt

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

($000)
2015	—
2016	1,500
2017	1,500
2018	1,500
2019	1,500
Thereafter	47,500
Total long-term debt	53,500

Any additional payment 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.

With our bank line of credit and Series A notes, we have agreed to certain financial and other covenants. We believe we were in compliance with the financial covenants under our bank line of credit and our 4.26% Series A Notes for all periods presented in the condensed consolidated financial statements.

(8) 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 $4.3 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 12 of the Notes to Condensed Consolidated Financial Statements, would immediately vest.

We have entered into forward purchase agreements for a portion of our non-regulated segment's natural gas purchases beginning in April, 2015 and expiring in December, 2016.  The agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements.  The agreements are established in the normal course of business to ensure adequate natural gas supply to meet our non-regulated customers' natural gas requirements.  The agreements have minimum purchase obligations of $114,000, $440,000 and $150,000 for our fiscal years ended June 30, 2015, June 30, 2016 and June 30, 2017, respectively.

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

(9) 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 setting 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 distribution and transportation services.  They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return.  We

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do not have any matters pending before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial position or cash flow.

(10) Operating Segments

Our Company has two reportable segments:  (i) a regulated natural gas distribution and transportation 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 natural 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 demand. In addition, we are exposed to price risk resulting from changes in the market price of natural gas, natural gas liquids and uncommitted natural 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, 2014.  Intersegment 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)	2015		2014		2015		2014
Operating Revenues
Regulated
External customers	23,144		26,271		45,391		48,678
Intersegment	1,355		1,365		3,142		3,303
Total regulated	24,499		27,636		48,533		51,981
Non-regulated
External customers	11,941		14,165		28,891		30,609
Eliminations for intersegment	(1,355	)	(1,365	)	(3,142	)	(3,303	)
Consolidated operating revenues	35,085		40,436		74,282		79,287
Net Income
Regulated	3,814		4,039		5,843		6,236
Non-regulated	341		1,135		658		2,152
Consolidated net income	4,155		5,174		6,501		8,388

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(11)Earningsper Share

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

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2015		2014		2015		2014
Numerator - Basic and Diluted ($000)
Net income	4,155		5,174		6,501		8,388
Dividends paid	(1,411	)	(1,323	)	(4,228	)	(3,965	)
Undistributed earnings	2,744		3,851		2,273		4,423
Allocated to common shares
Percentage allocated to common shares (a)	99.4	%	99.5	%	99.4	%	99.5	%
Undistributed earnings (a)	2,729		3,832		2,261		4,401
Dividends paid	1,403		1,316		4,204		3,945
Earnings allocated to common shares	4,132		5,148		6,465		8,346
Denominator
Basic weighted average common shares	7,014,909		6,929,875		6,996,726		6,912,727
Incremental unvested non-participating shares (b)	13,757		13,035		4,586		4,345
Diluted weighted average common shares	7,028,666		6,942,910		7,001,312		6,917,072
Earnings per Common Share - Basic and Diluted ($)
Basic	.59		.74		.92		1.21
Diluted	.59		.74		.92		1.21

(a) Percentage allocated to weighted average common
shares outstanding:
Common shares outstanding	7,014,909		6,929,875		6,996,726		6,912,727
Unvested participating shares outstanding (c)	39,000		35,000		39,000		35,000
Total	7,053,909		6,964,875		7,035,726		6,947,727
Percentage allocated to common shares	99.4	%	99.5	%	99.4	%	99.5	%

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(b) Under our incentive compensation plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 12 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 below in Note (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, 2015, there were 39,000 unvested non-participating shares outstanding, of which 26,000 were dilutive based on the underlying performance condition being met. As of March 31, 2014, there were 39,000 unvested non-participating shares outstanding, all of which were dilutive as the underlying performance condition had been met.

(c) Certain unvested awards under our incentive compensation plan, as further discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, provide recipients of the awards all the rights of a shareholder of Delta including the right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per common share using the two-class method. As of March 31, 2015 and 2014 there were 39,000 and 35,000 participating shares outstanding, respectively.

(12) Share-Based Compensation

We have a shareholder-approved incentive compensation plan (the "Plan"), that provides for 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 our employees, officers and outside directors who 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 in the aggregate 1,000,000 shares.  As of March 31, 2015, approximately 771,000 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. For the three months ended March 31, 2015 and 2014, share-based compensation expense was $210,000 and $200,000, respectively. For the nine months ended March 31, 2015 and 2014, share-based compensation was $1,035,000 and $912,000, respectively.

For the nine months ended March 31, 2015 and 2014, excess tax benefits of $9,000 and $30,000, respectively, were 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 financial reporting purposes.  These excess tax benefits can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods.

Stock Awards

For the nine months ended March 31, 2015 and 2014, common stock was awarded to virtually all Delta employees and directors having grant date fair values of $443,000 (22,000 shares) and $350,000 (17,000 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.

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Performance Shares

For the nine months ended March 31, 2015 and 2014, performance shares were awarded to the Company's executive officers having grant date fair values of $773,000 (39,000 shares) and $801,000 (39,000 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 in one-third increments each 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, disability or retirement 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.  As of March 31,2015 and 2014, there were 39,000 and 35,000 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. For the three months ended March 31, 2015 and 2014, compensation expense related to the performance shares was $210,000 and $200,000, respectively. For the nine months ended March 31, 2015 and 2014, compensation expense related to the performance shares was $592,000 and $563,000, respectively.

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

YEAR TO DATE MARCH 31, 2015 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 31,2015. Our Company has two segments:  (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related activities, 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 historical average temperatures.

Our non-regulated segment markets natural gas to large-volume customers.  We endeavor to enter sales agreements 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 income per common share of $.92 for the nine months ended March 31, 2015, as compared to our consolidated income per common share of $1.21 for the same period in the prior year, decreased primarily due to decreased revenue, net of gas costs, from the sale of natural gas and natural gas liquids by our non-regulated segment (as further discussed in Results of Operations). However, the results of operations for the period ended March 31, 2015 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 natural gas supply, which we are permitted to pass through to our customers.  We manage remaining expenses through budgeting, approval and review.

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Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large-volume 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 will continue to contribute to our consolidated net income for the remainder of fiscal 2015. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment gross 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 gross margins related to our natural gas production and marketing activities.  We process a portion of the natural gas in our distribution, transmission and storage system to extract liquids, enhancing the reliability and efficiency of our system. The profitability from the sales of the natural gas liquids is dependent on the amount of liquids extracted and the pricing for any such liquids as determined by a national unregulated market. We have experienced a 35% decline in the average sales price of natural gas liquids, which reduced net income by $.07 per common share for the nine months ended March 31, 2015, as compared with the previous year.

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, share-based compensation 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, 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 extends through June 30, 2015 and permits borrowings up to $40,000,000.  We anticipate renewal of this line by June 30, 2015. There were no borrowings outstanding on the bank line of credit as of March 31, 2015 or June 30, 2014.

Cash and cash equivalents were $16,102,000 at March 31, 2015, as compared with $13,676,000 at June 30, 2014.  The changes in cash and cash equivalents are summarized in the following table:

	Nine Months Ended
	March 31,
($000)	2015		2014
Provided by operating activities	14,163		19,402
Used in investing activities	(6,427	)	(5,233	)
Used in financing activities	(5,310	)	(4,964	)
Increase in cash and cash equivalents	2,426		9,205

For the nine months ended March 31, 2015, cash provided by operating activities decreased $5,239,000 (27%), as compared to the same period in the prior year, primarily due to decreased cash received from customers partially offset by an increase in cash paid for natural gas.

The change in cash used in investing activities resulted primarily from the increased level of capital expenditures in the 2014 period.

For the nine months ended March 31, 2015, there was not a significant change in cash used in financing activities as compared to the same period in the prior year.

Cash Requirements

Our capital expenditures result in a continued need for cash. These capital expenditures are being 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 2015 to be approximately $9.7 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 combined with our bank line

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of credit will be sufficient to satisfy our operating and normal capital expenditure requirements, to make our annual long-term debt repayment and to pay dividends for the remainder of fiscal 2015.

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 mature on December 20, 2031.  We are required to make an annual $1,500,000 principal payment on the Series A Notes each December.  Any refinance of the Series A Notes, or any additional prepayments of principal, may be subject to a prepayment penalty.

With our bank line of credit and Series A Notes, we have agreed to certain financial and other 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, 2014.  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 believe we were in compliance with the covenants under our bank line of credit and Series A Notes for all periods presented in the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Operating Revenues and Purchased Natural Gas

Our operating revenues are derived primarily from the sale of natural gas and natural gas liquids and the provision of natural gas transportation services. Our operating revenues are significantly impacted by the price we pay for natural gas. Therefore, 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. We define "gross margins" as natural gas sales less the corresponding purchased natural gas expenses, plus transportation, natural gas liquids and other revenues. Gross margins can be derived directly from our Condensed Consolidated Statements of Income, included in Item 1.  Financial Statements, as follows:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2015		2014		2015		2014
Operating revenues	35,085		40,436		74,282		79,287
Regulated purchased natural gas	(11,914	)	(14,989	)	(21,002	)	(24,268	)
Non-regulated purchased natural gas	(9,651	)	(10,607	)	(23,165	)	(22,507	)
Consolidated gross margins	13,520		14,840		30,115		32,512

Operating Income, as presented in the Condensed Consolidated Statements of Income, is the most directly comparable financial measure 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 prices that we pay for natural gas fluctuate with national supply and demand. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for the impact of forward contracts.

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In the following table we set forth significant variations in our gross margins for the three and nine months ended March 31, 2015 compared with the same periods in the preceding year. The variation amounts and percentages presented in the following table include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Income.

	2015 compared to 2014
	Three Months Ended		Nine Months Ended
($000)	March 31		March 31
Increase (decrease) in gross margins:
Regulated segment
Natural gas sales	(118	)	(172	)
On-system transportation	24		18
Off-system transportation	56		(3	)
Other	(23	)	(25	)
Intersegment elimination (a)	10		161
Total	(51	)	(21	)
Non-regulated segment
Natural gas sales	(1,021	)	(1,382	)
Natural gas liquids	(217	)	(813	)
Other	(20	)	(20	)
Intersegment elimination (a)	(10	)	(161	)
Total	(1,268	)	(2,376	)
Decrease in consolidated gross margins	(1,319	)	(2,397	)
Percentage increase (decrease) in volumes:
Regulated segment
Natural gas sales (Mcf)	(3	)	(2	)
On-system transportation (Mcf)	12		4
Off-system transportation (Mcf)	4		(1	)
Non-regulated segment
Natural gas sales (Mcf)	6		2
Natural gas liquids (gallons)	37		1

(a) Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment

Heating degree days were 118% and 112% of the normal temperatures for the three and nine months ended March 31, 2015, respectively, as compared with 118% and 110% of normal temperatures in the 2014 periods. A heating degree day is each degree that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location. 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.  Normal temperatures are based on historical 30-year average heating degree days, as calculated from data provided by the National Weather Service for the same geographic location.

For the three months ended March 31, 2015, consolidated gross margins decreased $1,319,000 (9%), as compared to the same period in the prior year, due to decreased non-regulated margins on natural gas sales and natural gas liquids. Gross margins on non-regulated natural gas sales decreased due to the prior year sale of our non-regulated segment's production inventory and

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decreased sales prices, partially offset by an increase in volumes sold. Gross margins on the sale of natural gas liquids decreased due to decreased sales prices.

For the nine months ended March 31, 2015, consolidated gross margins decreased $2,397,000 (7%), as compared to the same period in the prior year, due to decreased non-regulated margins on natural gas sales and natural gas liquids. Gross margins on non-regulated natural gas sales decreased due to the prior year sale of our non-regulated segment’s production inventory and decreased sales prices. Gross margins on the sale of natural gas liquids decreased due to decreased sales prices and increased natural gas costs associated with processing the natural gas.

Operating Expenses

For the three and nine months ended March 31, 2015 there were no significant changes in operations and maintenance and depreciation and amortization, as compared to the same periods in the prior year.

For the three and nine months ended March 31, 2015, taxes other than income taxes increased $111,000 (18%) and $380,000 (22%), respectively, primarily due to an increase in property taxes resulting from an increase in the assessed value of our property.

Other Income and Deductions, Net

For the three months ended March 31, 2015, there was not a significant change in other income and deductions, net as compared to the same period in the prior year.

For the nine months ended March 31, 2015, other income and deductions, net decreased $129,000 (81%) due to a decrease in the earnings from both the supplemental retirement trust and the cash surrender value of life insurance. The decrease in the earnings from the supplemental retirement trust was offset by a decrease in operating expense resulting from a corresponding change in the liability of the trust.

Interest Expense

For the three and nine months ended March 31, 2015, there were no significant changes in interest expense, as compared to the same periods in the prior year.

Income Tax Expense

For the three and nine months ended March 31, 2015, income tax expense decreased $561,000 (18%) and $1,047,000 (21%), respectively, due to a decrease in our net income before income taxes. For the three and nine months ended March 31, 2015, there were no significant changes in our effective tax rate, as compared to the same periods in the prior year.

Basic and Diluted Earnings Per Common Share

For the three and nine months ended March 31, 2015, our basic and diluted income per common share changed, as compared to the same period in the prior year, as a result of the 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 12 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. 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, 2015 there were 39,000 unvested non-participating shares outstanding of which 26,000 were dilutive based on the underlying performance condition being met. As of March 31, 2014, there were 39,000 unvested non-participating shares outstanding which were dilutive as underlying performance conditions had been met.

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Certain unvested awards under our incentive compensation plan, as further discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, provide recipients of the awards all the rights of a shareholder of Delta including the right to dividends declared on common shares.  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per common share using the two-class method.  As of March 31, 2015 and 2014, there were 39,000 and 35,000 participating shares outstanding, respectively.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We purchase our natural gas supply primarily through a combination of requirements contracts with no minimum purchase obligation, monthly spot purchase contracts and forward purchase contracts. The price we pay for natural gas acquired under the forward purchase contracts is fixed prior to the delivery of the natural gas.  Additionally, we inject some of our natural gas purchases into our underground natural 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 utilize requirements contracts, spot purchase contracts and our underground storage to meet our regulated customers' natural gas requirements, all of which have minimal price risk because we are permitted to pass these natural gas costs on to our regulated customers through our natural gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for our non-regulated segment 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.  In addition, we are exposed to changes in the market price of natural gas on uncommitted natural gas inventory of our non-regulated segment.  The natural gas liquids sold by our non-regulated segment are priced based upon the pricing determined in the national unregulated market.

None of our natural gas contracts are accounted for using the fair value method of accounting.  While some of our natural gas purchase and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.  As of March 31, 2015, our non-regulated segment had forward purchase contracts for natural gas purchases totaling $704,000 that expire in December, 2016.  The forward purchase contracts are at a fixed price and thus are 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, 2015 or June 30, 2014. For the nine months ended March 31, 2015, we borrowed and repaid $126,000 from the bank line of credit having a weighted average interest rate of 1.4%. A one percent (one hundred bases points) increase in our average interest rate would not have a significant impact on our annual pre-tax net income.

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, 2015, 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

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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, 2015 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.

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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 months ended March, 2015 and 2014;
(iii)	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2015 and 2014;
(iv)	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2015 and June 30, 2014;
(v)	Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine months ended March 31, 2015 and 2014; and
(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 part 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.

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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 5, 2015	/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)

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