Delta Natural Gas (DGAS) 10-Q 2016 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, 2016

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  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, 2016, Delta Natural Gas Company, Inc. had 7,082,184 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, 2016 and 2015	3
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2016 and 2015	4
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2016 and June 30, 2015	5
	Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine months ended March 31, 2016 and 2015	7
	Notes to Condensed Consolidated Financial Statements (Unaudited)	8
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
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	23
	Signatures	24

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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,
	2016		2015		2016			2015
OPERATING REVENUES
Regulated revenues	$	17,193,029	$	23,144,565	$	33,900,724		$	45,390,815
Non-regulated revenues	9,009,433		11,940,742		19,368,508			28,891,063
Total operating revenues	$	26,202,462	$	35,085,307	$	53,269,232		$	74,281,878
OPERATING EXPENSES
Regulated purchased natural gas	$	5,955,375	$	11,913,926	$	10,013,224		$	21,001,704
Non-regulated purchased natural gas	6,929,237		9,650,709		14,973,544			23,164,565
Operation and maintenance	3,913,345		3,859,474		10,817,796			10,921,700
Depreciation and amortization	1,615,928		1,640,786		4,828,587			4,732,493
Taxes other than income taxes	704,309		734,012		2,205,884			2,115,853
Total operating expenses	$	19,118,194	$	27,798,907	$	42,839,035		$	61,936,315
OPERATING INCOME	$	7,084,268	$	7,286,400	$	10,430,197		$	12,345,563
OTHER INCOME (EXPENSE), NET	5,551		29,375		(29,362		)	30,565
INTEREST EXPENSE	624,722		641,703		1,906,592			1,958,841
NET INCOME BEFORE INCOME TAXES	$	6,465,097	$	6,674,072	$	8,494,243		$	10,417,287
INCOME TAX EXPENSE	2,481,656		2,518,936		3,231,908			3,916,742
NET INCOME	$	3,983,441	$	4,155,136	$	5,262,335		$	6,500,545
EARNINGS PER COMMON SHARE (Note 11)
Basic and Diluted	$	.56	$	.59	$	.74		$	.92
DIVIDENDS DECLARED PER COMMON SHARE	$	.205	$	.20	$	.615		$	.60

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	5,262,335		$	6,500,545
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization	5,004,487			4,913,293
Deferred income taxes and investment tax credits	1,168,847			815,773
Change in cash surrender value of officer's life insurance	15,605			(11,471		)
Share-based compensation	383,482			1,034,672
Excess tax deficiency from share-based compensation	(7,581		)	(9,574		)
Decrease in assets	1,477,572			578,429
(Decrease) increase in liabilities	(1,424,599		)	341,589
Net cash provided by operating activities	$	11,880,148		$	14,163,256
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(4,943,907	)	$	(6,402,067	)
Proceeds from sale of property, plant and equipment	249,163			34,822
Other	(60,000		)	(60,000		)
Net cash used in investing activities	$	(4,754,744	)	$	(6,427,245	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common shares	$	(4,364,616	)	$	(4,227,814	)
Issuance of common shares	483,996			398,764
Excess tax benefit from share-based compensation	2,073			18,823
Payment of minimum tax withholdings on share-based compensation	(263,044		)	—
Repayment of long-term debt	(1,500,000		)	(1,500,000		)
Borrowing on bank line of credit	—			126,430
Repayment on bank line of credit	—			(126,430		)
Net cash used in financing activities	$	(5,641,591	)	$	(5,310,227	)
NET INCREASE IN CASH AND CASH EQUIVALENTS	$	1,483,813		$	2,425,784
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	16,924,278			13,675,918
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	18,408,091		$	16,101,702

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

(UNAUDITED)

	March 31,			June 30,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	18,408,091		$	16,924,278
Accounts receivable, less accumulated allowances
for doubtful accounts of $324,000 and $258,000, respectively	9,060,367			5,760,550
Natural gas in storage, at average cost	467,913			4,634,162
Deferred natural gas costs	366,937			—
Materials and supplies, at average cost	520,771			543,563
Prepayments	2,205,174			3,347,187
Total current assets	$	31,029,253		$	31,209,740
PROPERTY, PLANT AND EQUIPMENT	$	240,785,838		$	236,780,490
Less-Accumulated provision for depreciation	(102,963,115		)	(98,741,351		)
Net property, plant and equipment	$	137,822,723		$	138,039,139
OTHER ASSETS
Cash surrender value of life insurance	$	405,578		$	421,183
Prepaid pension	2,036,985			2,145,969
Regulatory assets	15,189,801			14,917,823
Unamortized debt expense	78,804			83,704
Other non-current assets	1,010,615			977,312
Total other assets	$	18,721,783		$	18,545,991
Total assets	$	187,573,759		$	187,794,870

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,
	2016		2015
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,654,106	$	5,426,395
Current portion of long-term debt	1,500,000		1,500,000
Accrued taxes	1,472,654		1,472,401
Customers' deposits	724,898		600,788
Accrued interest on debt	124,325		112,296
Accrued vacation	726,586		749,031
Deferred income taxes	262,954		140,929
Regulatory liability - refundable natural gas costs	—		756
Other current liabilities	592,626		610,238
Total current liabilities	$	9,058,149	$	10,612,834
LONG-TERM DEBT	$	50,500,000	$	52,000,000
LONG-TERM LIABILITIES
Deferred income taxes	$	43,096,888	$	41,989,138
Regulatory liabilities	1,145,524		1,137,758
Asset retirement obligations	3,997,219		3,795,590
Other long-term liabilities	1,057,680		1,037,896
Total long-term liabilities	$	49,297,311	$	47,960,382
COMMITMENTS AND CONTINGENCIES (Note 8)
Total liabilities	$	108,855,460	$	110,573,216
SHAREHOLDERS' EQUITY
Common shares ($1.00 par value), 20,000,000 shares
authorized; 7,082,184 and 7,026,500 shares
outstanding at March 31, 2016 and June 30,
2015, respectively	$	7,082,184	$	7,026,500
Premium on common shares	49,278,850		48,735,608
Retained earnings	22,357,265		21,459,546
Total shareholders' equity	$	78,718,299	$	77,221,654
Total liabilities and shareholders' equity	$	187,573,759	$	187,794,870

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, 2016
	Common Shares		Premium on Common Shares			Retained Earnings			Shareholders' Equity
Balance, beginning of period	$	7,026,500	$	48,735,608		$	21,459,546		$	77,221,654
Net income	—		—			5,262,335			5,262,335
Issuance of common shares	22,859		461,137			—			483,996
Issuance of common shares under the
incentive compensation plan, net of cancellations	32,825		(295,869		)	—			(263,044		)
Share-based compensation expense	—		383,482			—			383,482
Excess tax deficiency from share-based compensation	—		(5,508		)	—			(5,508		)
Dividends on common shares	—		—			(4,364,616		)	(4,364,616		)
Balance, end of period	$	7,082,184	$	49,278,850		$	22,357,265		$	78,718,299

	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, net of cancellations	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

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 gas in the open market.  We also transport natural gas on behalf of local producers and customers not on our distribution system and extract liquids from natural gas in our storage field and our pipeline systems that are sold at market prices.  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, 2016 and 2015 are included.  All such adjustments are accruals of a normal and recurring nature.

The results of operations for the period ended March 31, 2016 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, 2015.

(2)     New Accounting Pronouncements

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 quarter ending September 30, 2018 and we are evaluating the methods of adoption allowed by the new guidance and the effect the guidance is expected to have on our results of operations, financial position and cash flows.

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, 2016, is not expected to have a material impact on our results of operations, financial position and cash flows.

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 30, 2016, is not expected to have a material impact on our results of operations, financial position and cash flows.

In May, 2015, the Financial Accounting Standards Board issued guidance simplifying the disclosure of certain investments measured using the net asset value per share of the investment. The guidance no longer requires such investments to be categorized within the fair value hierarchy. The guidance, effective for our quarter ended September 30, 2016, is not expected to have a material impact on our disclosures.

In July, 2015, the Financial Accounting Standards Board issued guidance simplifying the measurement of inventory. The guidance requires inventory to be measured at the lower of cost or net realizable value. The guidance,

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effective for our quarter ending September 30, 2017, is not expected to have a material impact on our results of operations, financial position and cash flows.

                In November, 2015, the Financial Accounting Standards Board issued guidance to simplify the presentation of deferred income taxes on the balance sheet by classifying all deferred tax assets and liabilities as non-current. The guidance, effective for our quarter ending September 30, 2017, is not expected to have a material impact on our results of operations, financial position and cash flows.

                In January, 2016, the Financial Accounting Standards Board issued guidance to improve the recognition, measurement, presentation and disclosure of financial instruments. The improvements include guidance on estimating fair value for financial instruments measured at amortized cost on the balance sheet, the classification of financial assets and liabilities on the balance sheet and reduced disclosure for the fair value of financial instruments recognized on the balance sheet at amortized cost. The guidance, effective for our quarter ending September 30, 2018, is not expected to have a material impact on our results of operations, financial position, cash flows and disclosures.

In February, 2016, the Financial Accounting Standards Board issued guidance revising the principles and standards for recognizing leases. The guidance requires lessees to recognize on the statement of financial position a liability for the lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition and measurement of lease expenses have not significantly changed from previous guidance. The guidance is effective for our quarter ending September 30, 2018 and we are evaluating the impact the guidance is expected to have on our results of operations, financial position and cash flows.

                In March, 2016, the Financial Accounting Standards Board issued guidance simplifying the accounting and disclosure requirements for share-based compensation, including the income tax consequences, classification of the awards as equity or liability and classification on the statement of cash flows. The guidance, effective for our quarter ending September 30, 2017, is not expected to have a material impact on our results of operations, financial position and cash flows.

(3) Fair Value Measurements

Our financial assets 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 is as follows:

	March 31,	June 30,
($000)	2016	2015
Trust assets
Money market	38	27
U.S. equity securities	424	395
Foreign equity funds	167	185
U.S. fixed income funds	219	177
Foreign fixed income funds	19	57
Absolute return strategy mutual funds	144	136
	1,011	977

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 the 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

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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,
	2016		2015
	Carrying	Fair	Carrying	Fair
($000)	Amount	Value	Amount	Value
4.26% Series A Notes	52,000	54,101	53,500	52,935

(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 our natural gas cost recovery tariff.  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.

(5) Unbilled Revenue

We bill our regulated sales of natural gas at tariff rates approved by the Kentucky Public Service Commission. Our customers are billed on a monthly basis; however, the billing cycle for certain classes of customers do not necessarily coincide with the calendar month-end. For these customers, we apply the unbilled method of accounting, where we estimate and accrue revenues applicable to customers but not yet billed. The related natural gas costs are charged to expense. 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 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. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. As of March 31, 2016 and June 30, 2015, unbilled natural gas costs are included in deferred natural gas costs and regulatory liability-refundable natural gas costs on the accompanying Condensed Consolidated Balance Sheets, respectively. Unbilled amounts include the following:

	March 31,	June 30,
(000)	2016	2015
Unbilled revenues ($)	3,909	1,674
Unbilled natural gas costs ($)	1,293	462
Unbilled volumes (Mcf)	316	69

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(6)    Defined Benefit Retirement Plan

Net periodic benefit costs for our trusteed, noncontributory defined benefit retirement plan for the periods ended March 31, 2016 and 2015, include the following:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2016		2015		2016		2015
Service cost	251		247		753		743
Interest cost	289		264		867		793
Expected return on plan assets	(409	)	(428	)	(1,227	)	(1,284	)
Amortization of unrecognized net loss	94		61		282		184
Amortization of prior service cost	(22	)	(22	)	(66	)	(65	)
Net periodic benefit cost	203		122		609		371

In October, 2015 we made a $500,000 discretionary contribution 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, 2016 and June 30, 2015.  The bank line of credit extends through June 30, 2017. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.075%. The annual cost of the unused bank line of credit is 0.125%.

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)
2016	—
2017	1,500
2018	1,500
2019	1,500
2020	1,500
Thereafter	46,000
Total long-term debt	52,000

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. Noncompliance with these covenants can make the obligations immediately due and payable. We were in compliance

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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 $4.5 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 are not a party to any material pending legal proceedings.

As of March 31, 2016, we have entered into forward purchase agreements for a portion of our non-regulated segment's natural gas purchases through May, 2017.  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 aggregate minimum purchase obligations of $243,000 and $612,000 for our fiscal years ended June 30, 2016 and June 30, 2017, respectively.

(9) Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services, which includes approval of our rates and tariffs.  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 on our rate base. Rate base consists primarily of our regulated segment's property plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes.  Our regulated rates were most recently adjusted in our 2010 rate case and became effective in October, 2010. We do not currently have any matters before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial position and cash flows.

(10) Operating Segments

Our Company has two reportable segments:  a regulated segment and a non-regulated segment. Our regulated segment includes our natural gas distribution and transportation services, which are regulated by the Kentucky Public Service Commission. Our non-regulated segment includes our natural gas marketing activities and the sales of natural gas liquids. The non-regulated segment produces a portion of the natural gas it markets to its customers. The division of these segments into separate revenue generating components is based upon regulation, products and services. Both segments operate in the single geographic area of central and southeastern Kentucky. Our chief operating decision maker is our Chief Executive Officer. We evaluate performance based on net income of the respective segment.

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, 2015.  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.

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Segment information is shown in the following table:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2016		2015		2016		2015
Operating Revenues
Regulated
External customers	17,193		23,144		33,900		45,391
Intersegment	1,312		1,355		2,902		3,142
Total regulated	18,505		24,499		36,802		48,533
Non-regulated
External customers	9,009		11,941		19,369		28,891
Eliminations for intersegment	(1,312	)	(1,355	)	(2,902	)	(3,142	)
Consolidated operating revenues	26,202		35,085		53,269		74,282
Net Income
Regulated	3,675		3,814		4,860		5,843
Non-regulated	308		341		402		658
Consolidated net income	3,983		4,155		5,262		6,501

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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,
	2016		2015		2016		2015
Numerator - Basic and Diluted ($000)
Net income	3,983		4,155		5,262		6,501
Dividends paid	(1,456	)	(1,411	)	(4,365	)	(4,228	)
Undistributed earnings	2,527		2,744		897		2,273
Allocated to common shares:
Undistributed earnings (a)	2,517		2,729		894		2,261
Dividends paid	1,451		1,403		4,347		4,204
Earnings allocated to common shares	3,968		4,132		5,241		6,465
Denominator
Basic weighted average common shares	7,076,734		7,014,909		7,061,693		6,996,726
Incremental unvested non-participating shares (b)	—		13,757		—		4,586
Diluted weighted average common shares	7,076,734		7,028,666		7,061,693		7,001,312
Earnings per Common Share ($)
Basic	.56		.59		.74		.92
Diluted	.56		.59		.74		.92

(a) Percentage allocated to weighted average common shares outstanding:
Common shares outstanding	7,076,734		7,014,909		7,061,693		6,996,726
Unvested participating shares outstanding (c)	27,664		39,000		27,664		39,000
Total	7,104,398		7,053,909		7,089,357		7,035,726
Percentage allocated to common shares	99.6	%	99.4	%	99.6	%	99.4	%
Undistributed earnings ($000)	2,527		2,744		897		2,273
Allocated to common shares	2,517		2,729		894		2,261

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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, 2016, there were 39,000 unvested non-participating shares outstanding, which were not dilutive as the underlying performance condition has not been met. As of March 31, 2015, there were 39,000 unvested shares outstanding, of which 26,000 were dilutive based on the underlying performance condition being met.

(c) Certain awards under our shareholder approved 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 share using the two-class method unless the effect of including such shares would be antidilutive. As of March 31, 2016 and 2015 there were 28,000 and 39,000 unvested 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, 2016, approximately 747,000 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. Upon vesting, the plan allows for withholding a number of shares equal in fair value to the taxes required to satisfy minimum statutory withholding requirements.

Compensation expense for share-based compensation is recorded in the non-regulated segment's 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, 2016 and 2015, share-based compensation expense was $69,000 and $210,000, respectively. For the nine months ended March 31, 2016 and 2015, share-based compensation expense was $383,000 and $1,035,000, respectively.

To the extent the cumulative deduction for income tax purposes exceeds the cumulative compensation expense recognized for financial reporting purposes, the excess tax benefits can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods. For the nine months ended March 31, 2016 and 2015, immaterial differences between compensation expense for financial reporting purposes and income tax purposes were recognized.

Stock Awards

For the nine months ended March 31, 2016, common stock was awarded to Delta's directors having grant date fair values of $169,000 (8,400 shares).  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, 2016 and 2015, performance shares were awarded to the Company's executive officers having grant date fair values of $787,000 (39,000 shares) and $773,000 (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.  Unvested shares of executive officers while still employed by the Company will fully vest upon them attaining the age of sixty-seven. 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.  As of March 31,2016 and 2015, there were 28,000 and 39,000 unvested performance shares outstanding, respectively, for which the performance objectives have been satisfied. In January, 2016, approximately 1,600 shares, net of cancellations, were issued to an executive officer obtaining the age of sixty-seven.

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, 2016 and 2015, compensation expense related to the performance shares was $69,000 and $210,000, respectively. For the nine months ended March 31, 2016 and 2015, compensation expense related to the performance shares was $214,000 and $592,000, respectively.

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

YEAR TO DATE MARCH 31, 2016 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 31,2016. Our Company has two segments: a regulated segment, and a non-regulated segment. Our regulated segment includes our natural gas distribution and transportation services, which are regulated by the Kentucky Public Service Commission. Our non-regulated segment includes our natural gas marketing and production activities and the sales of natural gas liquids.

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 produces a portion of its natural gas supply, which is sold when market conditions are favorable. The non-regulated segment also sells liquids extracted from natural gas.

Our consolidated earnings per common share of $.74 for the nine months ended March 31, 2016, as compared to our consolidated earnings per common share of $.92 for the same period in the prior year, decreased due to decreased earnings from both our non-regulated and regulated segments, as further discussed in Results of Operations. Our non-regulated segment experienced decreased revenues, net of gas costs, due to decreased sales prices resulting from decreased market prices for both natural gas and natural gas liquids. Our regulated segment is not exposed to the same price risk from market prices as our gas cost recovery tariff allows us to pass the cost of gas through to our regulated customers. However, our regulated segment experienced decreased revenues, net of gas costs, resulting from a decline in volumes sold due to the weather being 27% warmer than the prior year, which is partially offset by amounts recovered from our residential and small non-residential customers through our weather

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normalization tariff. The results of operations for the period ended March 31, 2016 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.  They have historically utilized cost-of-service rate making where our base rates are established to recover normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. Rate base consists primarily of our regulated segment's property, plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes. 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.

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 2016. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated gross margins related to our natural gas marketing activities.  However, if natural gas prices decrease, we would expect a decrease in our non-regulated gross margins related to our natural gas 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 prices for any such liquids as determined by a national unregulated market.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of 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 occur during the heating months (December - April), 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, 2017 and permits borrowings up to $40,000,000.  There were no borrowings outstanding on the bank line of credit as of March 31, 2016 or June 30, 2015.

Cash and cash equivalents were $18,408,000 at March 31, 2016, as compared with $16,924,000 at June 30, 2015.  The changes in cash and cash equivalents are summarized in the following table:

	Nine Months Ended
	March 31,
($000)	2016		2015
Provided by operating activities	11,880		14,163
Used in investing activities	(4,754	)	(6,427	)
Used in financing activities	(5,642	)	(5,310	)
Increase in cash and cash equivalents	1,484		2,426

                For the nine months ended March 31, 2016, cash provided by operating activities decreased $2,283,000 (16%) due to a $18,610,000 decrease in cash received from customers partially offset by a $15,741,000 decrease in cash paid for natural gas, as further discussed in Results of Operations. Additionally, cash paid for operations and maintenance expense decreased due to a decrease in discretionary contributions to our defined benefit retirement plan and decreased cash paid for property taxes due to the timing of payments.

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

For the nine months ended March 31, 2016, there were no significant changes in cash used in financing activities, as compared to the same period in the prior year.

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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 2016 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 combined with our bank line of credit will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months.

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.  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 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, 2015.  A default on the performance of 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 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 and delivery of natural gas, the sale of 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)	2016		2015		2016		2015
Operating revenues	26,202		35,085		53,269		74,282
Regulated purchased natural gas	(5,955	)	(11,914	)	(10,013	)	(21,002	)
Non-regulated purchased natural gas	(6,929	)	(9,651	)	(14,974	)	(23,165	)
Consolidated gross margins	13,318		13,520		28,282		30,115

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 discussion of our 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, 2016 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.

	2016 compared to 2015
	Three Months Ended		Nine Months Ended
($000)	March 31		March 31
Increase (decrease) in gross margins:
Regulated segment
Natural gas sales	(55	)	(708	)
Natural gas transportation	19		10
Other	1		(43	)
Intersegment elimination (a)	43		240
Total	8		(501	)
Non-regulated segment
Natural gas sales	(83	)	(496	)
Natural gas liquids	(73	)	(541	)
Other	(11	)	(55	)
Intersegment elimination (a)	(43	)	(240	)
Total	(210	)	(1,332	)
Decrease in consolidated gross margins	(202	)	(1,833	)
Percentage increase (decrease) in volumes:
Regulated segment
Natural gas sales (Mcf)	(18	)	(24	)
Natural gas transportation (Mcf)	7		4
Non-regulated segment
Natural gas sales (Mcf)	5		1
Natural gas liquids (gallons)	(2	)	(25	)

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

Heating degree days were 92% and 81% of the normal temperatures for the three and nine months ended March 31, 2016, respectively, as compared with 118% and 112% of normal temperatures in the 2015 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 thirty-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, 2016, consolidated gross margins decreased $202,000 (1%), as compared to the same period in the prior year, due to decreased non-regulated gross margins. Non-regulated gross margins decreased as a result of decreased gross margins on natural gas sales and natural gas liquids. Gross margins on non-regulated natural gas sales decreased due to decreased sales prices partially offset by decreased natural gas costs. Gross margins on the sale of natural gas liquids decreased due to decreased sales prices. Although our regulated segment experienced decreased volumes sold as a result of warmer weather, this decrease was partially offset by increased rates billed through our weather normalization tariff and our pipe replacement program tariff.

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For the nine months ended March 31, 2016, consolidated gross margins decreased $1,833,000 (6%), as compared to the same period in the prior year, due to decreased non-regulated and regulated gross margins. Non-regulated gross margins decreased as a result of decreased gross margins on natural gas liquids and natural gas sales. Gross margins on the sale of natural gas liquids decreased due to decreased sales prices and decreased volumes of natural gas liquids sold resulting from an outage for repairs and maintenance at our processing plant. Gross margins on non-regulated natural gas sales decreased due to decreased sales prices partially offset by decreased natural gas costs. Regulated gross margins decreased as a result of decreased volumes sold to our regulated customers due to warmer weather. Partially offsetting the decreased volumes are increased rates billed through both our weather normalization tariff and our pipe replacement program tariff.

Operating Expenses

For the three and nine months ended March 31, 2016, there were no significant changes in operation and maintenance, depreciation and amortization, taxes other than income taxes, other income and deductions, net, and interest expense, as compared to the same periods in the prior year.

Income Tax Expense

For the nine months ended March 31, 2016, income taxes decreased $685,000 (17%), as compared to the same period in the prior year, due to a decrease in our net income before income taxes. For the nine months ended March 31, 2016, there were no significant changes in our effective tax rate, 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, 2016, our basic and diluted earnings 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. Our computation of basic and diluted earnings per common share is set forth in Note 11 of the Notes to Condensed Consolidated Financial Statements.

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 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 tariff.

Price risk for our 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 changes in the market price of natural gas on uncommitted natural gas inventory of our non-regulated segment. The pricing of the natural gas liquids sold by our non-regulated segment is 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, 2016, we had forward purchase contracts through May, 2017 totaling $855,000, which are at fixed prices 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, 2016 or June 30, 2015, nor did we have any borrowings on our bank line of credit during the nine months ended March 31, 2016.

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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 in the SEC'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, 2016 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, 2016 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles.

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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 31, 2016 and 2015;
(iii)	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2016 and 2015;
(iv)	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2016 and June 30, 2015;
(v)	Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the nine months ended March 31, 2016 and 2015; 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 6, 2016	/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 Operating Officer, Treasurer and Secretary (Principal Financial Officer)

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