DELTA NATURAL GAS CO INC - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - DELTA NATURAL GAS CO INC	Financial_Report.xls
EX-31.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INC	exhibit311.htm
EX-32.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INC	exhibit321.htm
EX-32.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INC	exhibit322.htm
EX-31.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INC	exhibit312.htm

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, 2012

¨	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 March 31, 2012, Delta Natural Gas Company, Inc. had 6,793,768 shares of Common Stock outstanding.

DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

PART I -	FINANCIAL INFORMATION	3

ITEM 1.	Financial Statements	3

	Condensed Consolidated Statements of Income (Unaudited) for the three and nine month periods ended March 31, 2012 and 2011	3

	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and June 30, 2011	4

	Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the nine month periods ended March 31, 2012 and 2011	6

	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2012 and 2011	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	24

ITEM 4.	Controls and Procedures	24

PART II -	OTHER INFORMATION	25

ITEM 1.	Legal Proceedings	25

ITEM 1A.	Risk Factors	25

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25

ITEM 3.	Defaults Upon Senior Securities	25

ITEM 4.	Removed and Reserved	25

ITEM 5.	Other Information	25

ITEM 6.	Exhibits	25

	Signatures	27

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,
	2012		2011		2012		2011

OPERATING REVENUES
Regulated revenues	$	16,927,971	$	21,102,579	$	35,529,294	$	41,216,486
Non-regulated revenues		9,788,099		14,252,431		26,609,449		27,911,306
Total operating revenues	$	26,716,070	$	35,355,010	$	62,138,743	$	69,127,792

OPERATING EXPENSES
Regulated purchased gas	$	7,205,406	$	10,673,944	$	13,491,470	$	18,858,802
Non-regulated purchased gas		7,065,624		11,347,074		20,252,696		21,533,300
Operation and maintenance		3,426,405		3,527,287		9,806,549		10,276,297
Depreciation and amortization		1,488,472		1,436,872		4,430,190		3,713,091
Taxes other than income taxes		558,192		423,954		1,635,471		1,283,802

Total operating expenses	$	19,744,099	$	27,409,131	$	49,616,376	$	55,665,292

OPERATING INCOME	$	6,971,971	$	7,945,879	$	12,522,367	$	13,462,500

OTHER INCOME (DEDUCTIONS), NET		69,694		31,583		47,514		137,995

INTEREST CHARGES		760,206		1,023,743		3,540,988		3,075,738

NET INCOME BEFORE INCOME TAXES	$	6,281,459	$	6,953,719	$	9,028,893	$	10,524,757

INCOME TAX EXPENSE		2,356,164		2,622,629		3,388,485		3,915,819

NET INCOME	$	3,925,295	$	4,331,090	$	5,640,408	$	6,608,938

EARNINGS PER COMMON SHARE (Note 11)
Basic and diluted	$	.58	$	.65	$	.83	$	.99

DIVIDENDS DECLARED PER COMMON SHARE	$	.175	$	.17	$	.525	$	.51

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

		March 31,			June 30,
		2012			2011
ASSETS

	CURRENT ASSETS
	Cash and cash equivalents	$	7,800,045		$	7,340,192
	Accounts receivable, less accumulated allowances for doubtful accounts of $209,000 and $190,000, respectively		11,793,545			6,540,702
	Gas in storage, at average cost		5,186,312			6,811,260
	Deferred gas costs		3,641,372			3,378,711
	Materials and supplies, at average cost		544,736			555,883
	Prepayments		1,171,905			2,113,224
	Total current assets	$	30,137,915		$	26,739,972

	PROPERTY, PLANT AND EQUIPMENT	$	214,721,608		$	211,409,336
	Less-Accumulated provision for depreciation		(81,465,627	)		(78,232,077	)
	Net property, plant and equipment	$	133,255,981		$	133,177,259

	OTHER ASSETS
	Cash surrender value of life insurance	$	516,271		$	508,808
	Prepaid pension		3,280,440			3,141,116
	Regulatory assets		10,950,195			8,823,310
	Unamortized debt expense		105,904			1,994,788
	Other non-current assets		601,256			510,986
	Total other assets	$	15,454,066		$	14,979,008

	Total assets	$	178,847,962		$	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

(UNAUDITED)

			March 31,		June 30,
			2012		2011

LIABILITIES AND SHAREHOLDERS’ EQUITY

	CURRENT LIABILITIES
	Accounts payable	$	3,537,024	$	8,201,249
	Current portion of long-term debt		1,500,000		1,200,000
	Accrued taxes		5,522,270		1,447,094
	Customers’ deposits		946,087		643,692
	Accrued interest on debt		981,696		852,952
	Accrued vacation		693,573		707,544
	Deferred income taxes		1,187,675		1,092,255
	Other current liabilities		413,717		317,867
	Total current liabilities	$	14,782,042	$	14,462,653

	LONG-TERM DEBT	$	56,500,000	$	56,751,006

	LONG-TERM LIABILITIES
	Deferred income taxes	$	35,515,629	$	35,114,249
	Investment tax credits		68,700		86,700
	Regulatory liabilities		1,442,831		1,507,928
	Asset retirement obligations		2,715,646		2,560,796
	Other long-term liabilities		862,220		645,723
	Total long-term liabilities	$	40,605,026	$	39,915,396

	COMMITMENTS AND CONTINGENCIES (Note 8)
	Total liabilities	$	111,887,068	$	111,129,055

	SHAREHOLDERS’ EQUITY (Note 14)
	Common shares ($1.00 par value, 20,000,000
	shares authorized; 6,793,768 and 6,732,344
	shares outstanding at March 31, 2012 and June 30,
	2011, respectively)	$	6,793,768	$	6,732,344
	Premium on common shares		43,748,886		42,688,316
	Retained earnings		16,418,240		14,346,524
	Total shareholders’ equity	$	66,960,894	$	63,767,184

	Total liabilities and shareholders’ equity	$	178,847,962	$	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)


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

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

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


		Nine Months Ended March 31, 2011
		Common Shares		Premium on Common Shares		Retained Earnings			Shareholders’ Equity

Balance, beginning of period (Note 14)	$	6,669,712	$	41,546,545	$	12,543,913		$	60,760,170
Net income		—		—		6,608,938			6,608,938
Issuance of common shares		35,986		504,476		—			540,462
Issuance of common shares under the
incentive compensation plan		18,000		245,970		—			263,970
Share-based compensation expense		—		191,192		—			191,192
Dividends on common shares		—		—		(3,418,895	)		(3,418,895	)

Balance, end of period	$	6,723,698	$	42,488,183	$	15,733,956		$	64,945,837

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

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended
	March 31,
	2012			2011

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	5,640,408		$	6,608,938
Adjustments to reconcile net income to net cash flows from operating activities
Depreciation and amortization		4,756,462			4,078,948
Deferred income taxes and investment tax credits		389,450			1,637,686
Change in cash surrender value of officer’s life insurance		(7,463	)		(39,991	)
Share-based compensation		613,102			455,162
Decrease (increase) in assets		(3,292,076	)		1,305,837
Increase in liabilities		300,130			884,036

Net cash provided by operating activities	$	8,400,013		$	14,930,616

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(4,913,175	)	$	(6,085,663	)
Proceeds from sale of property, plant and equipment		151,725			140,540
Other		(60,000	)		431,897
Net cash used in investing activities	$	(4,821,450	)	$	(5,513,226	)

CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common shares	$	(3,568,692	)	$	(3,418,895	)
Issuance of common shares		487,330			540,462
Debt issuance costs		(107,904	)		—
Issuance of long-term debt		58,000,000			—
Excess tax benefit from share-based compensation		21,562			—
Repayment of long-term debt		(57,951,006	)		(240,994	)
Borrowings on bank line of credit		17,697,829			17,824,196
Repayment of bank line of credit		(17,697,829	)		(17,824,196	)

Net cash used in financing activities	$	(3,118,710	)	$	(3,119,427	)

NET INCREASE IN CASH AND CASH EQUIVALENTS	$	459,853		$	6,297,963

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

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	7,800,045		$	10,937,108

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

DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1)	Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 36,000 customers. Our distribution and transmission systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system. 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, 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 and nine months ended March 31, 2012 and 2011 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 results of operations for the periods ended March 31, 2012 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 cash from operations during the heating months (November – April), when sales volumes increase considerably. Most construction activity and gas storage injections take place during non-winter 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, 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 was adopted as of March 31, 2012, did not have a material impact on our results of operations, financial position or cash flows.

(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:

	March 31,	June 30,
($000)	2012	2011

Trust assets
Money market	5	5
U.S. equity securities	377	320
U.S. fixed income securities	219	186
	601	511

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, 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 credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date. The credit adjusted risk-free rate for our 7% Debentures and 5.75% Insured Quarterly Notes was based on trades of our 7% Debentures at the measurement date. The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy. The Insured Quarterly Notes contained insurance that provided for the continuing payment of principal and interest to the holders in the event we defaulted on the Insured Quarterly Notes. Upon default, the insurer would have paid interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation would have transferred to the insurer. Therefore, the insurance was not considered in the determination of the fair value of the Insured Quarterly Notes.

March 31, 2012

June 30, 2011

($000)

Carrying

Amount

Fair

Value

Carrying

Amount

Fair

Value

4.26% Series A Notes

58,000

58,118

–

7% Debentures

–

19,410

18,988

5.75% Insured Quarterly Notes

–

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 commodity 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:

	March 31,	June 30,
(000)	2012	2011

Unbilled revenues ($)	2,569	1,437
Unbilled gas costs ($)	826	410
Unbilled volumes (Mcf)	133	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 and regulated revenues and regulated purchased gas on the accompanying Condensed Consolidated Statements of Income.

(6)	Defined Benefit Retirement Plan

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

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2012		2011		2012		2011

Service cost	228		235		690		704
Interest cost	231		213		691		640
Expected return on plan assets	(367	)	(269	)	(1,105	)	(809	)
Amortization of unrecognized net loss	50		125		150		376
Amortization of prior service cost	(21	)	(22	)	(65	)	(65	)
Net periodic benefit cost	121		282		361		846

(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 at March 31, 2012 and June 30, 2011. 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%.

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

Long-Term Debt

In December, 2011, we refinanced our 5.75% Insured Quarterly Notes ($38,450,000) and 7% Debentures ($19,410,000) from the proceeds of a private debt financing. Under the Note Purchase and Private Shelf Agreement we issued $58,000,000 of Series A Notes, for which the purchasers paid 100% of the face principal amount.

Unamortized debt expense of $1,896,000 related to the 5.75% Insured Quarterly Notes and 7% Debentures was reclassified from unamortized debt expense to regulatory assets on the accompanying Condensed Consolidated Balance Sheet. The $1,896,000 regulatory asset representing the loss on extinguishment of the 5.75% Insured Quarterly Notes and 7% Debentures, combined with $1,872,000 of unamortized loss on extinguishment of debt recognized from prior refinancings, will be amortized over the life of the 4.26% Series A Notes consistent with treatment approved by the Kentucky Public Service Commission.

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. Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. The following table summarizes the contractual maturities of our Series A Notes by fiscal year:

($000)
2012		—
2013		1,500
2014		1,500
2015		1,500
2016		1,500
Thereafter		52,000
Total long-term debt		58,000

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

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

(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 $3.6 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 for 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 whom the taxpayer had a reasonable right to rely or substantial legal authority, as we have done in this matter. Therefore, as of March 31, 2012, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,887,000, which includes $3,055,000 in taxes and $832,000 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, it is 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”. Saint Joseph Health System, Inc. filed a petition for rehearing on October 27, 2011 on the grounds that the court’s opinion was in direct conflict with the Kentucky Department of Revenue’s long-standing statutory interpretation. The Kentucky Court of Appeals decided on January 30, 2012 to deny the petition. Saint Joseph Health System, Inc. filed a motion for discretionary review of this opinion by the Kentucky Supreme Court. We can neither predict whether such review will be granted nor, if review is granted, what the outcome of any such review may be. Therefore, we cannot predict the final judicial outcome of this case.

As a result of the uncertainty created by the October 7, 2011 opinion issued by the Kentucky Court of Appeals, we have accrued the total liability of $3,887,000 and began billing the Utility Gross Receipts License Tax to Delta Resources’ customers prospectively with our October, 2011 billings. Since October, 2011, Delta Resources has billed its customers $120,000 for Utility Gross Receipts License Tax, substantially all of which has been collected. In the event we are unsuccessful in resolving our protest with the Kentucky Department of Revenue, of the $3,887,000 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 $832,000 of interest in addition to 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 $839,000 to $3,887,000. This estimate is based on the assumption that we will not be held liable for any penalties.

As of March 31, 2012, we recorded the total liability of $3,887,000, a receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $839,000 of expense related to interest and uncollectibles. Included in the receivable is $196,000 due from a Delta Resources customer that is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the March 31, 2012 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 March 31, 2012 Condensed Consolidated Statement of Income, interest accrued is included in interest charges and uncollectible amounts are included in operation and maintenance.

We are not a party to any other 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 remaining minimum purchase obligations of $205,000 and $391,000 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. Their regulation of our business includes approving the rates we are permitted to charge our regulated customers. We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services. They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.

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 base rates, a change to our gas cost recovery clause and our pipe replacement program were approved. 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. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year that are associated with the replacement of pipe and related facilities. Currently, the pipe replacement program, which became effective on May 1, 2011, is designed to additionally recover $139,000 annually. On February 29, 2012, we submitted our annual pipe replacement program filing to adjust rates to recover an additional $181,000 annually through rates beginning May 1, 2012. On April 17, 2012, the Kentucky Public Service Commission suspended the increased rates for a period of five months to determine the reasonableness of the rate increase. We cannot predict the outcome of such review.

(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, production and sales of natural gas liquids. The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky. Virtually all of the revenue recorded under both segments comes 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 price risk resulting from changes in the market price of gas and uncommitted gas volumes of our non-regulated companies.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Condensed Consolidated Financial Statements that 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 below for the periods:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2012		2011		2012		2011
Operating Revenues
Regulated
External customers	16,928		21,103		35,530		41,217
Intersegment	1,090		1,360		2,918		3,054
Total regulated	18,018		22,463		38,448		44,271

Non-regulated
External customers	9,788		14,252		26,609		27,911
Eliminations for intersegment	(1,090	)	(1,360	)	(2,918	)	(3,054	)
Total operating revenues	26,716		35,355		62,139		69,128

Net Income
Regulated	3,125		3,588		4,768		5,160
Non-regulated	800		743		872		1,449
Total net income	3,925		4,331		5,640		6,609

(11)	Earnings per Common Share

Certain unvested awards under our incentive compensation plan, as further discussed in Note 12 of Notes to Condensed Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta 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. In accordance with the provisions of our incentive compensation plan, all unvested shares have been adjusted for the two-for-one stock split having a May 1, 2012 distribution date, as further discussed in Note 14 of Notes to Condensed Consolidated Financial Statements. There were 21,000 unvested participating shares outstanding as of March 31, 2012. There were no unvested participating shares outstanding as of March 31, 2011.

As of March 31, 2012 and 2011, there were 36,000 and 32,000 unvested non-participating performance shares outstanding, respectively. As of March 31, 2012, the unvested performance shares were not dilutive as the underlying performance conditions have not yet been satisfied. Upon satisfaction of the performance conditions, unvested non-participating performance shares are included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. For the three and nine months ended March 31, 2012 and 2011 there were no antidilutive shares.

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

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2012		2011			2012		2011
Numerator – Basic and Diluted
Net Income ($000)	3,925		4,331			5,640		6,609
Less: dividends paid ($000)	(1,192	)	(1,142	)		(3,569	)	(3,419	)

Undistributed earnings ($000)	2,733		3,189			2,071		3,190
Percentage allocated to common shares (a)	99.7		100.0			99.7		100.0

Undistributed earnings allocated to common shares ($000)	2,725		3,189			2,065		3,190
Add: dividends declared allocated to common shares ($000)	1,188		1,142			3,558		3,419

Earnings available to common shares ($000)	3,913		4,331			5,623		6,609

Denominator – Basic (Note 14)
Weighted-average common shares	6,788,307		6,717,828			6,770,438		6,701,019
Add: Incremental unvested non-participating shares	—		22,324			—		7,442
Denominator - Diluted	6,788,307		6,740,152			6,770,438		6,708,461

Earnings per common share ($) (Note 14)
Basic	.58		.65			.83		.99
Diluted	.58		.65			.83		.99


(a) Percentage allocated to common shares – weighted average
Common shares outstanding	6,788,307		6,717,828			6,770,438		6,701,019
Unvested participating shares	21,332		—			21,332		—
Total	6,809,639		6,717,828			6,791,770		6,701,019
Percentage allocated to common shares	99.7	%	100.0	%		99.7	%	100.0	%

(12)	Share-Based Compensation

We have a shareholder approved incentive compensation plan (the “Plan”) that 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. In accordance with the provisions of the Plan, the number of shares that may be issued under the Plan and all unvested shares have been adjusted for the two-for-one stock split having a May 1, 2012 distribution date, as further discussed in Note 14 of Notes to Condensed Consolidated Financial Statements.

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, 2012, 928,000 shares of common stock were available for issuance under the Plan. Shares of common stock may be issued 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.

	Three Months Ended		Nine Months Ended
	March 31,		March 31,
($000)	2012	2011	2012	2011

Share-based compensation expense	99	131	613	455

For the nine months ended March 31, 2012, 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 and nine months ended March 31, 2011.

Stock Awards

For the nine months ended March 31, 2012 and 2011, common stock was awarded to virtually all Delta employees and directors having grant date fair values of $337,000 (22,000 shares) and $264,000 (18,000 shares), respectively. The recipients vested in the awards shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.

Performance Shares

For the nine months ended March 31, 2012 and 2011, performance shares were awarded to the Company’s executive officers having grant date fair values of $552,000 (36,000 shares) and $469,000 (32,000 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, before any cash bonuses or share-based compensation, for the fiscal year in which the performance shares are awarded. Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest equally over a three-year period beginning the August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period. The recipients of the awards also become vested as a result of certain events such as death or disability of the holders. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards. Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

If the performance objectives for the 2012 performance shares are met, up to 36,000 unvested shares could be issued to the recipients. The performance objectives for the 2011 performance shares were met and 32,000 unvested shares were issued on August 31, 2011, of which 21,000 shares remain unvested as of March 31, 2012.

For the three and nine months ended March 31, 2012, compensation expense related to the performance shares was $99,000 and $276,000, respectively. For the three and nine months ended March 31, 2011, compensation expense related to the performance shares was $131,000 and $191,000, 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 objectives.

(13) Insurance Proceeds

In 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 Income for the nine months ended March 31, 2012.

(14) Subsequent Events

On February 17, 2012, the Company’s Board of Directors declared a two-for-one stock split of the Company’s issued and outstanding common stock, par value $1.00 per share. The stock split was distributed May 1, 2012 to all shareholders of record on April 17, 2012. As a result of the stock split, all amounts related to shares, share prices and earnings per share have been retroactively restated, where appropriate, throughout this Form 10-Q.

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

YEAR TO DATE MARCH 31, 2012 OVERVIEW AND FUTURE OUTLOOK

For the nine months ended March 31, 2012, basic and diluted earnings per common share of $.83 decreased $.16 per common share as compared to the $.99 basic and diluted earnings per common share for the nine months ended March 31, 2011. During the nine months ended March 31, 2012, we experienced warmer weather as compared to the prior year, which resulted in decreased volumes of natural gas sold in both our regulated and non-regulated segments. Also during the nine months ended March 31, 2012, we accrued $839,000 ($520,000, 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 impact of the tax assessment was partially offset by the sale of natural gas liquids as we completed installation during fiscal 2012 of a facility that is designed to extract liquids from the natural gas in our system in order to improve the operations of our distribution, transmission and storage systems.

The results of operations for the period ended March 31, 2012 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 (November – April) when our sales volumes increase considerably. We expect the remainder of 2012 to be impacted by a reduction in interest charges resulting from the refinancing of our 7% Debentures and 5.75% Insured Quarterly Notes (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements). The regulated segment’s largest expense is purchased 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 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. We anticipate selling additional natural gas liquids during the remainder of 2012; however, the profitability of such sales is dependent on the amount of liquids extracted and the pricing 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 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. There were no borrowings outstanding on the bank line of credit as of March 31, 2012 or June 30, 2011.

Long-term debt decreased to $56,500,000 at March 31, 2012, compared with $56,751,000 at June 30, 2011. The decrease resulted from an increase in the current portion of our long-term debt as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures, as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements.

Cash and cash equivalents were $7,800,000 at March 31, 2012, as compared with $7,340,000 at June 30, 2011. Changes in cash and cash equivalents are summarized in the following table:

	Nine Months Ended
	March 31,
($000)	2012		2011

Provided by operating activities	8,400		14,930
Used in investing activities	(4,821	)	(5,513	)
Used in financing activities	(3,119	)	(3,119	)
Increase in cash and cash equivalents	460		6,298

For the nine months ended March 31, 2012, cash provided by operating activities decreased $6,530,000 (44%) due to a $4,148,000 decrease in cash received from customers resulting from a decline in sales volumes due to warmer weather and a $2,995,000 increase in cash paid for natural gas due to the timing of natural gas purchases. These changes were partially offset by a $1,500,000 decrease in contributions to our defined benefit plan as we made additional elective contributions in the prior year to maintain the funded status of the plan.

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

Cash Requirements

Our capital expenditures result in a continued need for capital. 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 2012 to be approximately $6.5 million.

The following table summarizes our contractual cash obligations for the remainder of fiscal 2012, and fiscal years thereafter:

		Payments Due by Fiscal Year
($000)	2012			2013-2014		2015-2016		After 2016		Total

Interest payments			643		4,947		4,555		26,606		36,751
Long-term debt (a)			—		3,000		3,000		52,000		58,000
Pension contributions			—		1,000		1,000		4,500		6,500
Gas purchases			205		391		—		—		596
Total contractual obligations			848		9,338		8,555		83,106		101,847

(a)	See Note 7 of Notes to Condensed Consolidated Financial Statements for a description of this debt.

See Note 8 of Notes to Condensed Consolidated Financial Statements for other commitments and contingencies. See Item 7. Management’s Discussion and Analysis included in our Annual Report on Form 10-K for the year ended June 30, 2011 for additional information related to our contractual cash obligations.

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 available bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of March 31, 2012.

In December, 2011, we refinanced our 5.75% Insured Quarterly Notes and 7% Debentures from the proceeds of a private debt financing. Under the Note Purchase and Private Shelf Agreement, we issued $58,000,000 of Series A Notes, for which the purchasers paid 100% of the face principal amount. The proceeds from the sale of the Series A Notes were used to fund the redemption of our 5.75% Insured Quarterly Notes Due April 1, 2021, which had an outstanding principal balance of $38,450,000, and our 7% Debentures Due February 1, 2023, which had an outstanding principal balance of $19,410,000.

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

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

With our bank line of credit and Series A Notes, we have agreed to certain financial covenants. Noncompliance with these covenants can make the obligation immediately due and payable. We have agreed to the following financial covenants:

·	The Company must at all times maintain a tangible net worth of at least $25,800,000.

·	The Company must at the end of each fiscal quarter maintain a total debt to capitalization ratio of no more than 70%. The total debt to capitalization ratio is calculated as the ratio of (i) the Company’s total debt to (ii) the sum of the Company’s shareholders’ equity plus total debt.

The Company must maintain a fixed charge coverage ratio for the twelve months ending each quarter of not less than 1.20x. The fixed charge coverage ratio is calculated as the ratio of (i) the Company’s earnings adjusted for certain unusual or non-recurring items, before interest, taxes, depreciation and amortization plus rental expense to (ii) the Company’s interest and rental expense.

·	The Company may not pay aggregate dividends on its capital stock (plus amounts paid in redemption of its capital stock) in excess of the sum of $15,000,000 plus the Company’s cumulative earnings after September 30, 2011 adjusted for certain unusual or non-recurring items.

The following table shows the required and actual financial covenants under our Series A Notes as of March 31, 2012:

	Requirement	Actual

Tangible net worth	no less than $25,800,000	$ 66,221,461
Debt to capitalization ratio	no more than 70%	46%
Fixed charge coverage ratio	no less than 1.20x	5.49x
Dividends paid	no more than $21,490,000	$ 2,381,000

Additionally, the bank line of credit and the Series A Notes contain affirmative and negative covenants. The most restrictive, subject to certain exclusions, limit our ability to:

·	permit or grant liens or security interests; and

·	sell subsidiaries or transfer assets outside of the normal course of business; and

·	incur secured debt in an amount that exceeds 10% of tangible net worth; and

·	merge with another company; and

·	change the general nature of our business; and

·	issue any stock to the public or in an exempt transaction whereby such issuances in the aggregate exceed thirty-five percent (35%) of the currently authorized and outstanding shares of common stock; and

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

The Series A Notes are subject to customary events of default, including failure to make payments of principal or interest when due, breaches of other material obligations of the Company and breaches of the Agreement, including breaches of the financial and other covenants set forth above. Upon an event of default, the holders of the Series A Notes may exercise customary remedies, including accelerating the indebtedness due under the Series A Notes, and the Company would be prohibited from paying any dividends. 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 the Series A Notes. We were not in default on our bank line of credit or Series A Notes during any period presented in the Condensed Consolidated Financial Statements.

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 and believe that investors benefit from having access to the same financial measures that our management uses. Gross margin can be derived directly from our Condensed Consolidated Statements of Income as follows:

	Three Months Ended				Nine Months Ended
	March 31,				March 31,
($000)	2012		2011		2012		2011

Operating revenues (a)	26,716		35,355		62,139		69,128
Less – Regulated purchased gas (a)	(7,205	)	(10,674	)	(13,491	)	(18,859	)
Less – Non-regulated purchased gas (a)	(7,066	)	(11,347	)	(20,253	)	(21,533	)
Consolidated gross margin	12,445		13,334		28,395		28,736

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

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

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

In the following table we set forth variations in our gross margins for the three and nine months ended March 31, 2012 compared with the same periods in the preceding year. The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Income.

	2012 compared to 2011
	Three Months		Nine Months
	Ended		Ended
($000)	March 31,		March 31,

Increase (decrease) in gross margins Regulated segment Natural gas sales	(650	)	(322	)
On-system transportation	(108	)	(71	)
Off-system transportation	(217	)	(99	)
Other	(2	)	37
Intersegment elimination (a)	270		136
Total	(707	)	(319	)

Non-regulated segment Natural gas sales	(202	)	(623	)
Natural gas liquids	302		753
Other	(13	)	(16	)
Intersegment elimination (a)	(270	)	(136	)
Total	(183	)	(22	)

Decrease in consolidated gross margins	(890	)	(341	)
Percentage increase (decrease) in volumes Regulated segment
Natural gas sales	(26	)	(23	)
On-system transportation	(5	)	(4	)
Off-system transportation	(20	)	(4	)

Non-regulated segment
Natural gas sales	(26	)	6

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

Heating degree days were 78% and 84% of normal thirty year average temperatures for the three and nine months ended March 31, 2012, respectively, as compared with 102% and 105% of normal temperatures in the 2011 periods. A “heating degree day” results from a day during which the average of the high and low temperature is at least one degree less than 65 degrees Fahrenheit.

For the three months ended March 31, 2012, consolidated gross margins decreased $890,000 (7%) due to decreased regulated and non-regulated gross margins of $707,000 (7%) and $183,000 (6%), respectively. Regulated gross margins decreased due to a 26% decline in volumes sold as a result of warmer weather, as compared to the same period in the prior year. Partially offsetting this decrease are increased rates billed through our weather normalization tariff. Non-regulated gross margins decreased due to a 26% decline in volumes sold due to a decline in our non-regulated customers’ gas requirement, partially offset by a decline in the cost of gas and the sale of natural gas liquids.

For the nine months ended March 31, 2012, consolidated gross margins decreased $341,000 (1%) due to decreased regulated gross margins of $319,000 (1%). Regulated gross margins decreased due to a 23% decline in volumes sold as a result of warmer weather, as compared to the same period in the prior year. Partially offsetting this decrease are increased rates billed through our weather normalization tariff and increased base rates which became effective October 22, 2010. The increased base rates allocated a majority of the rate increase to the monthly customer charge, partially decoupling revenues from volumes sold and thus reducing the impact of the warmer weather this year.

Depreciation and Amortization

For the three months ended March 31, 2012, there were no significant changes in depreciation and amortization as compared to the three months ended March 31, 2011.

For the nine months ended March 31, 2012, depreciation and amortization increased $717,000 (19%) due to increased depreciation rates allowed in our 2010 rate case.

Taxes Other Than Income Taxes

For the three and nine months ended March 31, 2012, taxes other than income taxes increased $134,000 (32%) and $351,000 (27%) due to increased property tax expense resulting from both higher assessed values and rates assessed by taxing jurisdictions.

Interest Charges

For the three months ended March 31, 2012, interest charges decreased $264,000 (26%) as a result of refinancing our 5.75% Insured Quarter Notes and 7% Debentures (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements).

For the nine months ended March 31, 2012, interest charges increased $465,000 (15%) primarily due to $832,000 of interest accrued for a tax assessment issued by the Kentucky Department of Revenue (as further discussed in Note 8 of Notes to Condensed Consolidated Financial Statements). The assessment is currently under protest by us with the Kentucky Department of Revenue. The increase was partially offset by decreased interest charges as a result of refinancing our 5.75% Insured Quarter Notes and 7% Debentures (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements).

Income Tax Expense

For the three and nine months ended March 31, 2012, income tax expense decreased $267,000 (10%) and $528,000 (13%), respectively, due to a decrease in our net income before income taxes. There were no significant changes to our effective tax rate for the three and nine months ended March 31, 2012.

Basic and Diluted Earnings Per Common Share

For the three and nine months ended March 31, 2012, our basic and diluted earnings per common share changed as a result of changes in 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 awarded through our incentive compensation plan.

Certain unvested awards under our shareholder approved incentive compensation plan provide the recipients of the awards 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 March 31, 2012, there were 21,000 participating unvested shares outstanding. As of March 31, 2011, there were no participating unvested shares outstanding.

There were 36,000 and 32,000 unvested non-participating performance shares outstanding as of March 31, 2012 and 2011, respectively. As of March 31, 2012, the unvested performance shares are not dilutive as the underlying performance conditions have not yet been satisfied. Upon satisfaction of the performance conditions unvested non-participating performance shares are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. For the three and nine months ended March 31, 2012 and 2011 there were no antidilutive shares.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We purchase our gas supply through a combination of spot market natural gas purchases and forward natural gas purchases. The price of spot market natural gas is based on the market price at the time of delivery. The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the natural gas. Additionally, we inject some of our natural gas purchases into gas storage facilities in the non-heating months and withdraw this natural 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 business 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 monthly to the London Interbank Offered Rate. There were no borrowings outstanding on the bank line of credit as of March 31, 2012 and June 30, 2011.

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 March 31, 2012, 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 change 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, 2012 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 Income (Unaudited) for the three and nine month periods ended March 31, 2012 and 2011;
	(iii)		Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2012 and 2011; and
	(iv)		Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and June 30, 2011
	(v)		Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the nine month periods ended March 31, 2012 and 2011;
	(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.

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 8, 2012		/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)

DELTA NATURAL GAS CO INC - FORM 10-Q - May 8, 2012

Attached files

DELTA NATURAL GAS CO INC Reports