DELTA NATURAL GAS CO INC - FORM 10-Q

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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 September 30, 2011

¨	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 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 September 30, 2011, Delta Natural Gas Company, Inc. had 3,385,985 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 Loss (Unaudited) for the three months ended September 30, 2011 and 2010	3

	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2011 and June 30, 2011	4

	Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the three months ended September 30, 2011 and 2010	6

	Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended September 30, 2011 and 2010	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.	Removed and Reserved	21

ITEM 5.	Other Information	21

ITEM 6.	Exhibits	21

	SIGNATURES	23

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF LOSS

(UNAUDITED)

	Three Months Ended
	September 30,
		2011		2010

OPERATING REVENUES
Regulated revenues	$	5,622,636		$	4,866,936
Non-regulated revenues		7,273,691			5,149,542
Total operating revenues	$	12,896,327		$	10,016,478

OPERATING EXPENSES
Purchased gas	$	7,206,549		$	5,054,344
Operation and maintenance		3,135,215			3,360,596
Depreciation and amortization		1,460,575			991,367
Taxes other than income taxes		527,887			375,723
Total operating expenses	$	12,330,226		$	9,782,030

OPERATING INCOME	$	566,101		$	234,448

OTHER INCOME (DEDUCTIONS), NET		(74,665	)		51,385

INTEREST CHARGES		1,757,131			1,016,031

NET LOSS BEFORE INCOME TAXES	$	(1,265,695	)	$	(730,198	)

INCOME TAX BENEFIT		(468,569	)		(314,021	)

NET LOSS	$	(797,126	)	$	(416,177	)

LOSS PER COMMON SHARE (Note 11)
Basic and diluted	$	(.24	)	$	(.12	)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic and diluted		3,375,256			3,342,100

DIVIDENDS DECLARED PER COMMON SHARE	$	.35		$	.34

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

		September 30,		June 30,
		2011		2011


ASSETS

	CURRENT ASSETS
	Cash and cash equivalents	$	136,404		$	7,340,192
	Accounts receivable, less accumulated allowances for doubtful accounts of $164,000 and $190,000, respectively		9,742,157			6,540,702
	Gas in storage, at average cost		10,570,118			6,811,260
	Deferred gas costs		5,307,831			3,378,711
	Materials and supplies, at average cost		526,414			555,883
	Prepayments		4,065,708			2,113,224
	Total current assets	$	30,348,632		$	26,739,972

	PROPERTY, PLANT AND EQUIPMENT	$	212,817,119		$	211,409,336
	Less-Accumulated provision for depreciation		(79,286,010	)		(78,232,077	)
	Net property, plant and equipment	$	133,531,109		$	133,177,259

	OTHER ASSETS
	Cash surrender value of life insurance	$	481,884		$	508,808
	Prepaid pension		3,020,891			3,141,116
	Regulatory assets		8,995,625			8,823,310
	Unamortized debt expense		1,945,633			1,994,788
	Other non-current assets		459,228			510,986
	Total other assets	$	14,903,261		$	14,979,008

	Total assets	$	178,783,002		$	174,896,239

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(UNAUDITED)

		September 30,		June 30,
		2011		2011

LIABILITIES AND SHAREHOLDERS’ EQUITY

	CURRENT LIABILITIES
	Accounts payable	$	6,138,111	$	8,201,249
	Notes payable		2,706,552		—
	Current portion of long-term debt		1,200,000		1,200,000
	Accrued taxes		4,432,097		1,447,094
	Customers’ deposits		688,777		643,692
	Accrued interest on debt		1,599,643		852,952
	Accrued vacation		715,982		707,544
	Deferred income taxes		1,771,473		1,092,255
	Other current liabilities		345,998		317,867
	Total current liabilities	$	19,598,633	$	14,462,653

	LONG-TERM DEBT	$	56,665,006	$	56,751,006

	LONG-TERM LIABILITIES
	Deferred income taxes	$	35,307,101	$	35,114,249
	Investment tax credits		80,700		86,700
	Regulatory liabilities		1,471,739		1,507,928
	Asset retirement obligations		2,610,911		2,560,796
	Other long-term liabilities		718,375		645,723
	Total long-term liabilities	$	40,188,826	$	39,915,396

	COMMITMENTS AND CONTINGENCIES (Note 8)
	Total liabilities	$	116,452,465	$	111,129,055

	SHAREHOLDERS’ EQUITY
	Common shares ($1.00 par value), 20,000,000 shares authorized, 3,385,985 and 3,366,172 shares outstanding at September 30, 2011 and June 30, 2011, respectively)	$	3,385,985	$	3,366,172
	Premium on common shares		46,582,805		46,054,488
	Retained earnings		12,361,747		14,346,524
	Total shareholders’ equity	$	62,330,537	$	63,767,184

	Total liabilities and shareholders’ equity	$	178,783,002	$	174,896,239

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(UNAUDITED)


	Three Months Ended September 30, 2011
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders’ Equity

Balance, beginning of period	$	3,366,172	$	46,054,488	$	14,346,524		$	63,767,184
Net loss						(797,126	)		(797,126	)
Issuance of common shares		3,479		108,072		—			111,551
Issuance of common shares under the
Incentive Compensation Plan		11,000		326,040		—			337,040
Share-based compensation expense		5,334		72,643		—			77,977
Tax benefit from share-based compensation		—		21,562		—			21,562
Dividends declared on common shares		—		—		(1,187,651	)		(1,187,651	)

Balance, end of period	$	3,385,985	$	46,582,805	$	12,361,747		$	62,330,537


		Three Months Ended September 30, 2010
		Common Shares		Premium on Common Shares		Retained Earnings			Shareholders’ Equity

Balance, beginning of period	$	3,334,856	$	44,881,401	$	12,543,913		$	60,760,170
Net loss		—		—		(416,177	)		(416,177	)
Issuance of common shares		6,017		165,505		—			171,522
Issuance of common shares under the
Incentive Compensation Plan		9,000		254,970		—			263,970
Share-based compensation expense		—		23,898		—			23,898
Dividends declared on common shares		—		—		(1,137,765	)		(1,137,765	)

Balance, end of period	$	3,349,873	$	45,325,774	$	10,989,971		$	59,665,618

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended
	September 30,
	2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(797,126	)	$	(416,177	)
Adjustments to reconcile net loss to net cash from operating activities
Depreciation and amortization		1,577,831			1,118,152
Deferred income taxes and investment tax credits		836,287			1,439,855
Change in cash surrender value of officers' life insurance		26,924			(15,299	)
Share-based compensation		415,017			287,868
Decrease in assets		(10,783,104	)		(6,123,758	)
Increase (decrease) in liabilities		2,025,760			(719,338	)

Net cash used in operating activities	$	(6,698,411	)	$	(4,428,697	)

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(2,122,327	)	$	(2,361,259	)
Proceeds from sale of property, plant and equipment		50,936			53,920
Other		—			491,897

Net cash used in investing activities	$	(2,071,391	)	$	(1,815,442	)

CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common shares	$	(1,187,651	)	$	(1,137,765	)
Issuance of common shares		111,551			171,522
Excess tax benefit from share-based compensation		21,562			—
Repayment of long-term debt		(86,000	)		(140,000	)
Borrowings on bank line of credit		3,839,409			3,324,757
Repayment of bank line of credit		(1,132,857	)		(487,359	)

Net cash provided by financing activities	$	1,566,014		$	1,731,155

DECREASE IN CASH AND CASH EQUIVALENTS	$	(7,203,788	)	$	(4,512,984	)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		7,340,192			4,639,145

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	136,404		$	126,161

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

DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)	Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 customers. Our distribution and transmission systems are located in central and southeastern Kentucky, and we operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system. We have three wholly-owned subsidiaries. Delta Resources, Inc. ("Delta Resources") buys natural gas and resells it to industrial or other large use customers on Delta’s system. Delgasco, Inc. (“Delgasco”) buys gas and resells it to Delta Resources, Inc. and to customers not on Delta’s system. Enpro, Inc. (“Enpro”) owns and operates production properties and undeveloped acreage.

All subsidiaries of Delta are included in the condensed consolidated financial statements. Intercompany balances and transactions have been eliminated. All adjustments necessary for a fair presentation of the unaudited results of operations for the three months ended September 30, 2011 and 2010 are included. All such adjustments are accruals of a normal and recurring nature other than the amounts accrued by Delta Resources related to an assessment of the Utility Gross Receipts License Tax discussed in Note 8 and the insurance proceeds discussed in Note 13.

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, 2011.

(2) New Accounting Pronouncements

In May, 2011, the Financial Accounting Standards Board issued guidance on fair value measurement and disclosure. The guidance was issued as part of a joint effort between the Financial Accounting Standards Board and the International Accounting Standards Board to converge the two sets of standards into a single conceptual framework which would change how fair value measurement guidance is applied in future periods. The guidance, which will be effective for our quarter ending March 31, 2012, is not expected to have a material impact on our results of operations or financial position.

(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 mutual funds. The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy. The fair value of the trust assets are as follows:

	September 30,	June 30,
($000)	2011	2011

Trust assets	459	511

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

Our Debentures and Insured Quarterly Notes, presented as current portion of long-term debt and long-term debt on the Condensed Consolidated Balance Sheets, are stated at historical cost. Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate. The Insured Quarterly Notes contain insurance that provides for the continuing payment of principal and interest to the holders in the event we default on the Insured Quarterly Notes. Upon default, the insurer would pay interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation would transfer to the insurer. Therefore, the insurance is not considered in the determination of the fair value of the Insured Quarterly Notes.

	September 30, 2011		June 30, 2011
($000)	Carrying Amount	Fair Value	Carrying Amount	Fair Value

7% Debentures	19,410	19,037	19,410	18,988

5.75% Insured Quarterly Notes	38,455	34,397	38,541	34,400

(4)	Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk. We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. We mitigate price risk with our efforts to balance supply and demand. None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase contracts and 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 customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled.

Unbilled revenues and gas costs include the following:

	September 30,	June 30,
(000)	2011	2011

Unbilled revenues ($)	1,398	1,437
Unbilled gas costs ($)	396	410
Unbilled volumes (Mcf)	56	58

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

(6)	Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, noncontributory defined benefit retirement plan for the periods ended September 30 include the following:

	Three Months Ended
	September 30,
($000)	2011		2010

Service cost	231		234
Interest cost	230		213
Expected return on plan assets	(369	)	(269	)
Amortization of unrecognized net loss	50		125
Amortization of prior service cost	(22	)	(21	)
Net periodic benefit cost	120		282

(7)	Debt Instruments

The current bank line of credit with Branch Banking and Trust Company, shown as notes payable on the Condensed Consolidated Balance Sheet, permits borrowings up to $40,000,000, of which $2,707,000 was borrowed as of September 30, 2011, having a weighted average interest rate of 1.4%. As of June 30, 2011, all of the bank line of credit was available. The bank line of credit extends through June 30, 2013. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.15%. The annual cost of the unused bank line of credit is .125%.

Our bank line of credit agreement and the Indentures relating to all of our publicly held Debentures and Insured Quarterly Notes contain defined “events of default” which, among other things, can make the obligations immediately due and payable. Of these, we consider the following covenants to be most restrictive:

Dividend payments cannot be made or our capital stock repurchased unless after giving effect to such dividend payments or repurchases our consolidated shareholders’ equity minus the value of the Company’s intangible assets exceeds $25,800,000 (thus no retained earnings were restricted),

we may not assume any secured indebtedness in excess of $5,000,000 unless we secure our 7% Debentures and 5.75% Insured Quarterly Notes equally with the additional secured indebtedness, and

·	without the consent of the bank that has extended to us our bank line of credit (or paying off and terminating our bank line of credit), we may not:

·	merge with another entity,

·	sell a material portion of our assets other than in the ordinary course of business,

·	issue stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, or

·	permit any person or group of related persons to hold more than twenty percent (20%) of the Company’s outstanding shares of common stock.

Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes. We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during any period presented.

On October 31, 2011, the Kentucky Public Service Commission approved our plans to refinance our 5.75% Insured Quarterly Notes and 7% Debentures through private debt financing. If we proceed with our refinancing plan, we would redeem the 5.75% Insured Quarterly Notes and 7% Debentures from the proceeds of the private debt financing.

(8)	Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and Change of 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 $3.4 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.

The Kentucky Department of Revenue has assessed Delta Resources $5,565,000, which includes $3,013,000 in taxes, $1,963,000 in penalties and $589,000 in interest, for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011. The tax is a 3% license tax levied on the gross receipts derived from furnishing utility services and is passed through to customers. The Kentucky Department of Revenue has not asserted a claim for the tax periods after June, 2011 or interest accrued subsequent to the initial assessments. Regarding the penalties, Kentucky law provides for the assessment of penalties for failure to pay a tax, unless it is shown to the satisfaction of the Kentucky Department of Revenue that the failure to pay is due to reasonable cause. Applicable regulatory authority provides that reasonable cause exists when the tax position is based on advice by a tax advisor on whomo the taxpayer had a reasonable right to rely or substantial legal authority, as we have done in this matter. Therefore, as of September 30, 2011, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,803,000, which includes $3,055,000 in taxes and $747,000 in interest.

We protested the assessment with the Kentucky Department of Revenue. Our position with the Department is that the Utility Gross Receipts License Tax applies only to utilities regulated by the Kentucky Public Service Commission. Delta Resources is a natural gas marketer which is not regulated by the Kentucky Public Service Commission and, thus, we contend, exempt from the utility tax. The position is based on case law and long-standing opinions issued by the State Attorney General and was further upheld in an opinion by the Commonwealth of Kentucky Fayette Circuit Court in May, 2010 in a case styled Commonwealth of Kentucky, Finance and Administration Cabinet, Department of Revenue v. Saint Joseph Health System, Inc.; Constellation New Energy-Gas Division, LLC; and Board of Education of Fayette County, Kentucky.

However, on October 7, 2011, the Kentucky Court of Appeals reversed the May, 2010 Fayette Circuit Court opinion, which had held that the Utility Gross Receipts License Tax did not apply to sales of gas by Constellation, a gas marketer, because it is not a utility. The opinion of the Kentucky Court of Appeals held that “because Constellation furnishes natural gas to Saint Joseph, Constellation is subject to imposition of the utility [gross receipts license] tax.” The opinion is not final as Saint Joseph Health System, Inc. filed a petition for rehearing on October 27, 2011 on the grounds that the court’s opinion is in direct conflict with the Kentucky Department of Revenue’s long-standing statutory interpretation. The Kentucky Court of Appeals could decide to rehear the case, reverse the opinion, remand the case to the Fayette Circuit Court, de-publish the opinion or deny the petition and allow the opinion to become final. We cannot predict what outcome the petition for rehearing will have on the opinion issued by the Kentucky Court of Appeals. Further, discretionary review of this opinion by the Kentucky Supreme Court is possible, and we can neither predict whether such review will be sought nor what the outcome of any such review may be. Therefore, we cannot predict the final judicial outcome of this case.

Similarly, we are unable to predict how the opinion by the Kentucky Court of Appeals will impact our ultimate liability for taxes, interest and penalties assessed by the Kentucky Department of Revenue.

As a result of the uncertainty created by the opinion issued by the Kentucky Court of Appeals, we have begun billing Delta Resources’ customers effective with our October billings, and have also accrued the total liability of $3,803,000. However, in the event we are unsuccessful in resolving our protest with the Kentucky Department of Revenue, of the $3,803,000 total liability, Delta Resources would have the right to seek reimbursement from its customers for the $3,055,000 of taxes, leaving Delta Resources liable for the $747,000 of interest and any uncollectible amounts. We estimate that Delta Resources’ potential liability for interest and taxes deemed uncollectible from Delta Resources’ customers to be in the range of $754,000 to $3,803,000. This estimate is based on the assumption that we will not be held liable for any penalties.

As of September 30, 2011, we have recorded the total liability of $3,803,000, a receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $754,000 of expense related to interest and uncollectibles. Included in the receivable is $196,000 due from a Resources customer which is wholly owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the September 30, 2011 Condensed Consolidated Balance Sheet, the liability for taxes is included in accrued taxes, the receivable from Delta Resources’ customers is included in accounts receivable, less accumulated allowances for doubtful accounts, and the liability for interest is included in other current liabilities. In the September 30, 2011 Condensed Consolidated Statement of Loss, interest accrued is included in interest charges and uncollectible amounts are included in operation and maintenance.

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

We have entered into forward purchase agreements beginning in October, 2011 and expiring at various dates through December, 2012. These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements. These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements. These agreements have aggregate minimum purchase obligations of $712,000 and $294,000 for our fiscal years ended June 30, 2012 and June 30, 2013, respectively.

(9)	Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers. We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services. The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.

In April, 2010, we filed a request for increased base rates with the Kentucky Public Service Commission. This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000. The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12.0%.

The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense. A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues is less dependent on customer usage and occurs more evenly throughout the year. The increased base rates were effective for service rendered on and after October 22, 2010.

In addition to the increased rates, our pipe replacement program and a change to our gas cost recovery clause were approved. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities. In February, 2011, the Kentucky Public Service Commission approved our initial pipe replacement filing, effective May, 2011, which will provide us $139,000 in additional annual revenues. The change to our gas cost recovery clause, which became effective with billings on and after January 24, 2011, provides recovery of the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.

(10)	Operating Segments

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

The segments follow the accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Condensed Consolidated Financial Statements which are included in our Annual Report on Form 10-K for the year ended June 30, 2011. Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services. Intersegment transportation revenues and expenses are recorded at our tariff rates. Revenues and expenses for the storage of natural gas are recorded based on quantities stored. Operating expenses, taxes and interest are allocated to the non-regulated segment.

Segment information is shown in the following table:

	Three Months Ended
	September 30,
($000)	2011		2010
Operating Revenues
Regulated
External customers	5,622		4,866
Intersegment	764		667
Total regulated	6,386		5,533
Non-regulated
External customers	7,274		5,150
Eliminations for intersegment	(764	)	(667	)
Total operating revenues	12,896		10,016

Net Income (Loss)
Regulated	(349	)	(559	)
Non-regulated	(448	)	143
Total net loss	(797	)	(416	)

(11) Loss per Common Share

Certain awards under our shareholder approved incentive compensation plan provide the recipient of the award all the rights of a shareholder of Delta Natural Gas Company, Inc. including a 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. There were 11,000 participating unvested shares outstanding as of September 30, 2011. There were no participating unvested shares outstanding as of September 30, 2010. The participating unvested shares are excluded from the computation of diluted weighted average common shares as of September 30, 2011, as the shares would have an antidilutive effect on the net loss.

As of September 30, 2011 and 2010, there were 18,000 and 16,000 non-participating unvested performance shares outstanding, respectively. As of September 30, 2011 and 2010, the performance shares are not dilutive as the underlying performance condition has not yet been satisfied.

(12) Share-Based Compensation

We have a shareholder approved incentive compensation plan (the “Plan”) which provides for incentive compensation payable in shares of our common stock. The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining 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 which may be issued pursuant to the Plan may not exceed in the aggregate 500,000 shares. As of September 30, 2011, 464,000 shares of common stock were available for issuance under the Plan. 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 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 September 30, 2011, a $22,000 tax benefit was recognized as a premium on common shares on our Condensed Consolidated Balance Sheet, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation. This excess tax benefit can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods. An immaterial tax deficiency was recognized in income tax expense for the three months ended September 30, 2010, which increased our taxes payable, as the compensation expense recognized for share-based compensation exceeded the deduction available for income tax purposes.

Stock Bonus

For the three months ended September 30, 2011 and 2010, common stock was awarded as a stock bonus to virtually all Delta employees and directors having grant date fair values of $337,000 (11,000 shares) and $264,000 (9,000 shares), respectively. The recipients vested in the award 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 bonus awards were immediately transferable.

Performance Shares

For the three months ended September 30, 2011 and 2010, performance shares were awarded to the Company’s executive officers having grant date fair values of $552,000 (18,000 shares) and $469,000 (16,000 shares), respectively. The performance share awards vest only if the performance objective of the award is met, which is 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 objective, unvested shares are issued to the recipient that vest equally over a three-year period beginning the August 31 subsequent to achieving the performance objective as long as the recipient is an employee throughout each such service period. The recipient of the award also becomes vested as a result of certain events such as death or disability of the holder. The unvested shares have both dividend participation rights and voting rights during the remaining term of the awards. Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

If the performance objective for the 2012 performance shares is met, up to 18,000 unvested shares could be issued to the recipients. The performance objective for the 2011 performance shares was met as of June 30, 2011 and 16,000 unvested shares were issued on August 31, 2011, of which 11,000 shares remain unvested as of September 30, 2011.

For the three months ended September 30, 2011 and 2010 compensation expense related to the performance shares was $78,000 and $24,000, respectively.

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 objective.

(13) Insurance Proceeds

During September, 2011, we received $300,000 of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company’s underground storage field. These proceeds are included in operation and maintenance in the Condensed Consolidated Statement of Loss for the three months ended September 30, 2011.

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

YEAR TO DATE SEPTEMBER 30, 2011 OVERVIEW AND FUTURE OUTLOOK

For the three months ended September 30, 2011, there was a consolidated net loss per common share of $.24 compared with a net loss of $.12 per share for the three months ended September 30, 2010. During the three months ended September 30, 2011, we accrued $754,000 ($468,000, net of income tax benefit) of expense relating to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 8 of the Notes to Condensed Consolidated Financial Statements). The assessment is currently under protest by us with the Kentucky Department of Revenue.

The results of operations for the period ended September 30, 2011 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 our operating revenues during the warmer months when our sales volumes decrease considerably. Our fiscal 2012 results are dependent on the winter weather and the extent to which our customers choose to conserve their natural gas usage or discontinue their natural gas service. The regulated segment’s largest expense purchased is gas, which we are permitted to pass through to our customers. We control 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 customers and the market prices of natural gas, all of which are out of our control. We anticipate our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2012. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production and marketing activities. However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities. Additionally, our non-regulated segment’s contribution to our consolidated net income for fiscal 2012 could be materially impacted by the ultimate resolution of the tax assessment issued by the Kentucky Department of Revenue.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of our net loss adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital. Our sales and cash requirements are seasonal. The largest portion of our sales occurs during the heating months, whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months. Therefore, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit. The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, of which $2,707,000 was borrowed as of September 30, 2011. There were no borrowings outstanding on the bank line of credit as of June 30, 2011. When we have no borrowings outstanding on our bank line of credit, excess cash is invested in overnight repurchase agreements. Through Branch Banking & Trust Company, we purchase U.S. Treasury or Federal Agency securities with a contractual agreement to sell back the securities the next day.

Long-term debt decreased to $56,665,000 at September 30, 2011, compared with $56,751,000 at June 30, 2011. The decreases resulted from the limited redemption made by certain holders or their beneficiaries as allowed by the Debentures and Insured Quarterly Notes.

Cash and cash equivalents were $136,000 at September 30, 2011, as compared with $7,340,000 at June 30, 2011. The changes in cash and cash equivalents are summarized in the following table:

	Three Months Ended
	September 30,
($000)	2011		2010

Used in operating activities	(6,699	)	(4,429	)
Used in investing activities	(2,071	)	(1,815	)
Provided by financing activities	1,566		1,731
Decrease in cash and cash equivalents	(7,204	)	(4,513	)

For the three months ended September 30, 2011, cash used in operating activities increased $2,270,000 (51%). Cash paid for natural gas increased $3,708,000 due to an increase in the quantities purchased. The increase was partially offset by a $1,450,000 decrease in cash paid for income taxes due to an income tax refund resulting from a method change that reduced our capitalization of expenses for income tax purposes.

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

For the three months ended September 30, 2011, cash provided by financing activities decreased $165,000 due to increased repayments on the bank line of credit.

Cash Requirements

Our capital expenditures result in a continued need for capital. These capital expenditures are made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2012 to be approximately $6.5 million.

Sufficiency of Future Cash Flows

We expect that cash provided by operations, coupled with short-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future.

To the extent that internally generated cash is not sufficient to satisfy seasonal operating and capital expenditure requirements and to pay dividends, we will rely on our bank line of credit. Our current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, of which $2,707,000 was borrowed as of September 30, 2011.

Our ability to borrow on our bank line of credit is dependent on our compliance with covenants. Our bank line of credit agreement and the Indentures relating to all of our publicly held Debentures and Insured Quarterly Notes contain defined "events of default" which, among other things, can make the obligations immediately due and payable. Of these, we consider the following covenants to be most restrictive:

·	Dividend payments cannot be made or our capital stock repurchased unless after giving effect to such dividend payments or repurchases consolidated shareholders' equity minus the value of the Company’s intangible assets exceeds $25,800,000 (thus no retained earnings were restricted); and

·	we may not assume any secured indebtedness in excess of $5,000,000, unless we secure our 7% Debentures and 5.75% Insured Quarterly Notes equally with the additional indebtedness; and

·	without the consent of the bank that has extended to us our bank line of credit (or paying off and terminating our bank line of credit), we may not:

·	merge with another entity,

·	sell a material portion of our assets other than in the ordinary course of business,

·	issue stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, or

·	permit any person or group of related persons to hold more than twenty percent (20%) of the Company’s outstanding shares of common stock.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated base rates and transportation rates we charge our customers. The Kentucky Public Service Commission sets these prices and we monitor our need to file rate requests with the Kentucky Public Service Commission for a general rate increase for our regulated services. Our regulated base rates and transportation rates were adjusted in our 2010 rate case and were implemented in October, 2010.

RESULTS OF OPERATIONS

Gross Margins

Our operating revenues are derived primarily from the sale of natural gas and the provision of natural gas transportation services. We define “gross margin” as gas sales less the corresponding purchased gas expenses, plus transportation and other revenues. We view gross margins as an important performance measure of the core profitability of our operations. Gross margin can be derived directly from our Condensed Consolidated Statements of Loss as follows:

	Three Months Ended
($000)	2011		2010

Operating revenues (a)	12,896		10,016
Less – Purchased gas (a)	(7,207	)	(5,054	)

Gross margin	5,689		4,962

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

Operating Income, as presented in the Condensed Consolidated Statements of Loss, is the most directly comparable financial measure to gross margin calculated and presented in accordance with accounting principles generally accepted in the United States ("GAAP"). Gross margin is a “non-GAAP financial measure”, as defined in accordance with SEC rules. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses.

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

In the following table we set forth variations in our gross margins for the three months ended September 30, 2011 compared with the same period in the preceding year. The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Loss.

($000)	Three Months Ended September 30, 2011 Compared to 2010

Increase (decrease) in regulated gross margins
Regulated segment
Gas sales	681
On-system transportation	72
Off-system transportation	80
Other	20
Intersegment elimination (a)	(97	)
Total	756
Non-regulated segment
Gas sales	(178	)
Other	52
Intersegment elimination (a)	97
Total	(29	)

Increase in consolidated gross margins	727

Percentage increase in volumes
Regulated segment
Gas sales	5
On-system transportation	1
Off-system transportation	8
Non-regulated segment
Gas sales	63

(a)	Intersegment eliminations represent the transportation fee charged by the regulated segment to the non-regulated segment.

For the three months ended September 30, 2011, consolidated gross margins increased $727,000 (15%) due to increased regulated gross margins of $756,000, which were partially offset by a $29,000 decrease in non-regulated gross margins. Regulated gross margins increased due to increased base rates which became effective October 22, 2010 and an increase in volumes transported for our non-regulated segment. Our non-regulated gross margins decreased $29,000 (2%) due to a decline in sales prices, which was partially offset by an increase in volumes sold due to an increase in our non-regulated customers’ gas requirements.

Operation and Maintenance

For the three months ended September 30, 2011, operation and maintenance decreased $226,000 (7%) due to the receipt of $300,000 of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company’s underground storage field.

Depreciation and Amortization

For the three months ended September 30, 2011, depreciation and amortization increased $470,000 (47%) due to increased depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case.

Taxes Other Than Income Taxes

For the three months ended September 30, 2011, taxes other than income taxes increased $152,000 (40%) due to increased property tax expense.

Other Income and Deductions, Net

For the three months ended September 30, 2011, other income and deductions, net decreased $126,000 (247%) due to a decrease in the cash surrender value of life insurance as well as a decrease in the fair value of the supplemental retirement trust. The decrease in the fair value of the supplemental retirement trust was offset by a reduction in operating expense resulting from a corresponding decrease in the liability of the plan.

Interest Charges

For the three months ended September 30, 2011, interest charges increased $741,000 (73%) primarily due to $747,000 of interest accrued for a tax assessment issued by the Kentucky Department of Revenue (as further discussed in Note 8 of the Notes to Condensed Consolidated Financial Statements). The assessment is currently under protest by us with the Kentucky Department of Revenue.

Income Tax Benefit

For the three months ended September 30, 2011, income tax benefit increased $155,000 (49%) due to an increase in our net loss before income taxes. There were no significant changes to our effective tax rate for the three months ended September 30, 2011 as compared to the three months ended September 30, 2010.

Basic and Diluted Earnings Per Common Share

For the three months ended September 30, 2011, our basic loss per common share changed as a result of a change in our net loss 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.

Certain awards under our shareholder approved incentive compensation plan provide the recipient of the award all the rights of a shareholder of Delta Natural Gas Company, Inc. including a 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 September 30, 2011, there were 11,000 participating unvested shares outstanding. As of September 30, 2010, there were no participating unvested shares outstanding. The participating unvested shares are excluded from the computation of diluted weighted average common shares as of September 30, 2011, as the shares would have an antidilutive effect on the net loss.

As of September 30, 2011 and 2010, there were 18,000 and 16,000 non-participating unvested performance shares outstanding, respectively. As of September 30, 2011 and 2010, the unvested performance shares are not dilutive as the underlying performance condition has not yet been satisfied.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

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. The balance on our bank line of credit was $2,707,000 at September 30, 2011. There were no borrowings outstanding on our bank line of credit as of June 30, 2011. The weighted average interest rate on our bank line of credit was 1.4% on September 30, 2011. Based on average borrowings on our bank line of credit, 1% (one hundred basis point) increase in our average interest rate would decrease our annual pre-tax net income by $27,000.

ITEM 4. 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 September 30, 2011, 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.

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 September 30, 2011 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. See Note 8 of the Notes to Condensed Consolidated Financial Statements for a discussion of a tax assessment issued to Delta Resources by the Kentucky Department of Revenue. The assessment is currently being protested by us with the Kentucky Department of Revenue.

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.	REMOVED AND RESERVED

	None.

ITEM 5.	OTHER INFORMATION

	None.

ITEM 6.	EXHIBITS

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


	Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL):
	(i)		Document and Entity Information
	(ii)		Condensed Consolidated Statements of Loss (Unaudited) for the three months ended September 30, 2011 and 2010;
	(iii)		Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended September 30, 2011 and 2010; and
	(iv)		Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2011 and June 30, 2011
	(v)		Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the three months ended September 30, 2011 and 2010;
	(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 prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

SIGNATURES

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

DATE: November 7, 2011		/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)

Three Months Ended

September 30,

Share-based compensation expense