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 December 31, 2008

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

For the transition period from _______ to ________

Commission File No. 0-8788

______________

DELTA NATURAL GAS COMPANY, INC.

(Exact name of registrant as specified in its charter)

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

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

859-744-6171

(Registrant’s telephone number, including area code)

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

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

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

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date:

3,307,446 Shares of Common Stock, Par Value $1.00 Per Share, Outstanding as of December 31, 2008.

DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

PART I -	FINANCIAL INFORMATION	3

ITEM 1.	Financial Statements	3

	Consolidated Statements of Income (Unaudited) for the three, six and twelve month periods ended December 31, 2008 and 2007	3

	Consolidated Balance Sheets (Unaudited) as of December 31, 2008, June 30, 2008 and December 31, 2007	4

	Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the six and twelve month periods ended December 31, 2008 and 2007	6

	Consolidated Statements of Cash Flows (Unaudited) for the six and twelve month periods ended December 31, 2008 and 2007	7

	Notes to Consolidated Financial Statements (Unaudited)	8

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	18

ITEM 4.	Controls and Procedures	18

PART II -	OTHER INFORMATION	19

ITEM 1.	Legal Proceedings	19

ITEM 1A.	Risk Factors	19

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19

ITEM 3.	Defaults Upon Senior Securities	19

ITEM 4.	Submission of Matters to a Vote of Security Holders	19

ITEM 5.	Other Information	19

ITEM 6.	Exhibits	20

	Signatures	21

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended					Six Months Ended					Twelve Months Ended
	December 31,					December 31,					December 31,
	2008			2007		2008			2007		2008			2007

OPERATING REVENUES	$	33,957,969		$	29,298,418	$	52,066,058		$	41,702,589	$	123,020,587		$	98,323,415

OPERATING EXPENSES
Purchased gas	$	24,081,852		$	19,335,440	$	36,404,948		$	27,244,641	$	86,042,694		$	66,008,819
Operation and maintenance		5,155,649			3,189,731		7,981,705			6,085,879		16,024,446			12,939,068
Depreciation and amortization		961,383			1,043,289		1,911,286			2,302,318		3,780,114			4,783,875
Taxes other than income taxes		445,575			440,276		884,275			882,989		1,812,515			1,846,286

Total operating expenses	$	30,644,459		$	24,008,736	$	47,182,214		$	36,515,827	$	107,659,769		$	85,578,048

OPERATING INCOME	$	3,313,510		$	5,289,682	$	4,883,844		$	5,186,762	$	15,360,818		$	12,745,367

OTHER INCOME AND DEDUCTIONS, NET		(78,620	)		5,197		(87,257	)		19,400		(23,136	)		113,401

INTEREST CHARGES		1,264,211			1,330,863		2,410,177			2,539,925		4,640,742			4,754,460

NET INCOME BEFORE INCOME TAXES	$	1,970,679		$	3,964,016	$	2,386,410		$	2,666,237	$	10,696,940		$	8,104,308

INCOME TAX EXPENSE		741,675			1,508,731		884,191			1,021,897		4,009,194			3,005,697

NET INCOME	$	1,229,004		$	2,455,285	$	1,502,219		$	1,644,340	$	6,687,746		$	5,098,611

BASIC AND DILUTED EARNINGS PER COMMON SHARE	$	.37		$	.75	$	.46		$	.50	$	2.03		$	1.56

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTAND-ING (BASIC AND DILUTED)		3,303,313			3,283,130		3,300,403			3,280,704		3,295,341			3,276,034

DIVIDENDS DECLARED PER COMMON SHARE	$	.32		$	.31	$	.64		$	.62	$	1.26		$	1.23

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

DELTA NATURAL GAS COMPANY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	December 31,			June 30,			December 31,
	2008			2008			2007
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	324,863		$	249,859		$	680,811
Accounts receivable, less allowances for doubtful accounts of $852,000, $465,000 and $252,000, respectively		18,602,820			11,437,219			19,648,063
Gas in storage, at average cost		21,183,038			14,476,393			16,391,139
Deferred gas costs		6,032,930			4,612,752			3,377,138
Materials and supplies, at average cost		588,409			565,333			503,029
Prepayments		4,178,350			2,683,854			3,862,022
Total current assets	$	50,910,410		$	34,025,410		$	44,462,202

PROPERTY, PLANT AND EQUIPMENT	$	195,391,491		$	192,127,184		$	189,900,707
Less-Accumulated provision for depreciation		(69,259,827	)		(67,754,068	)		(66,640,646	)
Net property, plant and equipment	$	126,131,664		$	124,373,116		$	123,260,061

OTHER ASSETS
Cash surrender value of officers’ life insurance	$	384,940		$	444,312		$	425,609
Prepaid pension cost		1,677,932			1,423,932			943,100
Regulatory assets		7,648,521			7,713,358			8,203,349
Unamortized debt expense and other		2,758,250			2,834,728			2,944,110
Total other assets	$	12,469,643		$	12,416,330		$	12,516,168

Total assets	$	189,511,717		$	170,814,856		$	180,238,431

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

DELTA NATURAL GAS COMPANY, INC.

CONSOLIDATED BALANCE SHEETS (continued)

(UNAUDITED)

		December 31,		June 30,			December 31,
		2008		2008			2007

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	8,868,368	$	12,154,432		$	9,015,838
Notes payable		28,652,755		6,828,791			23,798,147
Current portion of long-term debt		1,200,000		1,200,000			1,200,000
Accrued taxes		1,388,248		1,656,391			1,537,290
Customers’ deposits		621,511		505,058			611,016
Accrued interest on debt		859,592		865,727			869,543
Accrued vacation		605,410		720,625			593,515
Deferred income taxes		1,628,814		1,483,700			963,559
Other liabilities		470,066		418,239			472,954
Total current liabilities	$	44,294,764	$	25,832,963		$	39,061,862

LONG-TERM DEBT	$	58,063,000	$	58,318,000		$	58,402,000

DEFERRED CREDITS AND OTHER
Deferred income taxes	$	25,695,748	$		24,576,000	$		23,784,513
Investment tax credits		161,150			177,800			195,700
Regulatory liabilities		1,872,704			2,144,951			2,348,392
Asset retirement obligations and other		2,246,334			2,171,557			2,245,516
Total deferred credits and other	$	29,975,936	$		29,070,308	$		28,574,121

COMMITMENTS AND CONTINGENCIES (Notes 11, 12 and 13)
Total liabilities	$	132,333,700	$		113,221,271	$		126,037,983

SHAREHOLDERS’ EQUITY
Common shares ($1.00 par value), 20,000,000 shares
authorized; 3,307,446, 3,295,759, and
3,286,276 shares outstanding at December 31,
2008, June 30, 2008 and December 31, 2007,
respectively	$	3,307,446	$		3,295,759	$		3,286,276
Premium on common shares		44,244,428			43,967,481			43,729,714
Retained earnings		9,626,143			10,330,345			7,184,458
Total shareholders’ equity	$	57,178,017	$		57,593,585	$		54,200,448

Total liabilities and shareholders’ equity	$	189,511,717	$		170,814,856	$		180,238,431

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

DELTA NATURAL GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(UNAUDITED)

	Six Months Ended						Twelve Months Ended
	December 31,						December 31,
	2008			2007			2008			2007

COMMON SHARES
Balance, beginning of period	$	3,295,759		$	3,277,106		$	3,286,276		$	3,267,942
Dividend reinvestment and stock purchase plan		11,687			9,170			21,170			18,334

Balance, end of period	$	3,307,446		$	3,286,276		$	3,307,446		$	3,286,276

PREMIUM ON COMMON SHARES
Balance, beginning of period	$	43,967,481		$	43,508,979		$	43,729,714		$	43,285,686
Dividend reinvestment and stock purchase plan		276,947			220,735			514,714			444,028

Balance, end of period	$	44,244,428		$	43,729,714		$	44,244,428		$	43,729,714

RETAINED EARNINGS
Balance, beginning of period	$	10,330,345		$	7,642,386		$	7,184,458		$	6,183,319
Adoption of FASB Interpretation No. 48		—			(68,630	)		—			(68,630	)
Adoption of FASB Statement No. 158
(net of $57,699 of tax)		(94,300	)		—			(94,300	)		—
Beginning retained earnings, as adjusted	$	10,236,045		$	7,573,756		$	7,090,158		$	6,114,689
Net income		1,502,219			1,644,340			6,687,746			5,098,611
Dividends declared on common shares (See Consolidated Statements of Income for rates)		(2,112,121	)		(2,033,638	)		(4,151,761	)		(4,028,842	)

Balance, end of period	$	9,626,143		$	7,184,458		$	9,626,143		$	7,184,458

SHAREHOLDERS’ EQUITY
Balance, beginning of period	$	57,593,585		$	54,428,471		$	54,200,448		$	52,736,947
Adoption of FASB Interpretation No. 48		—			(68,630	)		—			(68,630	)
Adoption of FASB Statement No. 158
(net of $57,699 of tax)		(94,300	)		—			(94,300	)		—
Beginning retained earnings, as adjusted	$	57,499,285		$	54,359,841		$	54,106,148		$	52,668,317
Net income		1,502,219			1,644,340			6,687,746			5,098,611
Issuance of common stock		288,634			229,905			535,884			462,362
Dividends on common stock		(2,112,121	)		( 2,033,638	)		(4,151,761	)		(4,028,842	)

Balance, end of period	$	57,178,017		$	54,200,448		$	57,178,017		$	54,200,448

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

DELTA NATURAL GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended						Twelve Months Ended
	December 31						December 31
	2008			2007			2008			2007

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,502,219		$	1,644,340		$	6,687,746		$	5,098,611
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		2,164,858			2,539,549			4,285,720			5,251,341
Deferred income taxes and investment tax credits		1,216,112			895,072			2,416,040			1,798,684
Gain on sale of asset		(156,023	)		—			(172,978	)		—
Provision for inventory adjustment		1,350,300			—			1,350,300			—
Other, net		(317,632	)		(110,014	)		(440,646	)		(212,879	)
Increase in assets		(18,762,084	)		(18,830,135	)		(9,494,694	)		(9,059,542	)
Increase (decrease) in liabilities		(3,248,258	)		(587,550	)		145,312			1,401,008

Net cash provided by (used in) operating activities	$	(16,250,508	)	$	(14,448,738	)	$	4,776,800		$	4,277,223

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	$	(3,846,171	)	$	(2,824,475	)	$	(6,571,402	)	$	(7,072,264	)
Proceeds from sale of property, plant and equipment		426,206			184,708			538,923			272,887
Net cash used in investing activities	$	(3,419,965	)	$	(2,639,767	)	$	(6,032,479	)	$	(6,799,377	)

CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common stock	$	(2,112,121	)	$	(2,033,638	)	$	(4,151,761	)	$	(4,028,842	)
Issuance of common stock, net		288,634			229,905			535,884			462,362
Repayment of long-term debt		(255,000	)		(223,000	)		(339,000	)		(268,000	)
Borrowings on bank line of credit		53,515,222			41,846,544			76,271,635			59,672,448
Repayment of bank line of credit		(31,691,258	)		(22,238,315	)		(71,417,027	)		(53,020,647	)

Net cash provided by financing activities	$	19,745,477		$	17,581,496		$	899,731		$	2,817,321

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	$	75,004		$	492,991		$	(355,948	)	$	295,167

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		249,859			187,820			680,811			385,644

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	324,863		$	680,811		$	324,863		$	680,811

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

DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 38,000 customers. Our distribution and transportation systems are located in central and southeastern Kentucky and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system. We have three wholly-owned subsidiaries. Delta Resources, Inc. buys gas and resells it to industrial or other large use customers on Delta’s system. Delgasco, Inc. buys gas and resells it to Delta Resources, Inc. and to customers not on Delta’s system. Enpro, Inc. owns and operates production properties and undeveloped acreage. All subsidiaries of Delta are included in the consolidated financial statements. Intercompany balances and transactions have been eliminated.

(2)

All adjustments necessary for a fair presentation of the unaudited results of operations for the three, six and twelve months ended December 31, 2008 and 2007 are included. All such adjustments are accruals of a normal and recurring nature other than the inventory adjustment discussed in Note 12 to record a reserve against our gas in storage. The results of operations for the periods ended December 31, 2008 are not necessarily indicative of the results of operations to be expected for the full fiscal year. Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably. Most construction activity and gas storage injections take place during these warmer months. Twelve months ended financial information is provided for additional information only. The accompanying consolidated financial statements are unaudited and should be read in conjunction with the consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended June 30, 2008.

(3)

Pursuant to Financial Accounting Standards Board Interpretation No. 48, we recognize a liability for unrecognized tax positions for those tax positions taken on tax returns which are not deemed more likely than not to be sustained on examination by the taxing authorities. In fiscal 2008, we filed a method change with the Internal Revenue Service related to the timing of deducting certain expenses. During the quarter ended September 30, 2008, we received approval for the method change. As a result of the method change, our liability for unrecognized tax positions decreased $265,000 of which $45,000 represented interest previously accrued on the unrecognized tax position and $220,000 represented deferred taxes on the unrecognized tax position.

(4)

In September, 2006, the Financial Accounting Standards Board issued Statement No. 158, entitled Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. Statement No. 158 contains provisions relating to disclosure and recognition which we adopted effective June 30, 2007. Additionally, Statement No. 158 requires employers who sponsor defined benefit plans to measure assets and benefit obligations as of the end of the employer’s fiscal year in fiscal years beginning after December 15, 2007. Effective July 1, 2008, we adopted the measurement date provision of Statement No. 158, which required us to change the measurement date of our defined benefit plan from March 31 to June 30. Pension costs from April 1, 2008 to June 30, 2009 are $760,000. Of this amount, $152,000 was attributable to the change in measurement dates. Accordingly, we recognized a $119,000 decrease in our prepaid pension and a $33,000 decrease in our unrecovered pension expense regulatory asset. These decreases were accounted for as a reduction to beginning retained earnings as of July 1, 2008, net of $58,000 of tax.

(5)

In September, 2006, the Financial Accounting Standards Board issued Statement No. 157, entitled Fair Value Measures, and in February, 2007 it issued Statement No. 159, entitled The Fair Value Option for Financial Assets and Financial Liabilities. The Statements define fair value, establish a framework for measuring fair value in accordance with accounting principles generally accepted in the United States of America and expand disclosure requirements about fair value measurements.

Under Statement No. 157, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition under Statement No. 157 focuses on an exit price, which is the price that would be received by us to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability. Although Statement No. 157 does not require additional fair value

measurements, it applies to other accounting pronouncements that require or permit fair value measurements.

We determine the fair value of financial assets and liabilities based on the following fair value hierarchy, as prescribed by Statement No. 157, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

•

Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;

•

Level 2 – Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

•

Level 3 – Unobservable inputs which require the reporting entity to develop its own assumptions.

Effective July 1, 2008, we adopted Statement No. 157 for all financial instruments. There was no cumulative effect adjustment to retained earnings as a result of adopting Statement No. 157.

As of December 31, 2008, our financial assets and liabilities that are measured at fair value on a recurring basis consists of the assets of our supplemental retirement plan. The supplemental retirement plan is a non-qualified deferred compensation plan for Glenn R. Jennings, our Chairman of the Board, President and Chief Executive Officer. Assets earmarked to pay benefits under the Plan are held by a rabbi trust. As of December 31, 2008, the assets of the plan were $272,000 and are included in unamortized debt expense and other on the Consolidated Balance Sheets. The offsetting liability of the plan is included in asset retirement obligations and other on the Consolidated Balance Sheets. The liability of the plan is not considered a financial liability within the scope of Statement No. 157. The assets of the plan are recorded at fair value and consist of cash and cash equivalents and 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 Statement No. 157 hierarchy.

Our Debentures and Insured Quarterly Notes are stated at historical cost.

Statement No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Although Statement No. 159 was effective for our fiscal year beginning July 1, 2008, we do not currently have any financial assets or financial liabilities for which the provisions of Statement No. 159 has been elected. However, in the future, we may elect to measure certain financial instruments at fair value in accordance with this standard.

In February, 2008, the Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. 157-2, entitled Effective Date of Financial Accounting Standards Board Statement No. 157, which delays the effective date of Statement No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis.

(6)

In March, 2008, the Financial Accounting Standards Board issued Statement No. 161, entitled Disclosures about Derivative Instruments and Hedging Activities. Statement No. 161 enhances the disclosures as required by Statement No. 133, entitled Accounting for Derivative Instruments and Hedging Activities. Entities are required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged instruments are accounted for under Statement No. 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We do not expect this statement, which shall be effective for our quarter ending March 31, 2009, to have an impact on our results of operations or financial position.

(7)

In December, 2008, The Financial Accounting Standards Board issued FASB Staff Position No. FAS 132(R)-1, which amends Statement 132(R), entitled Employers’ Disclosures about Pensions and Other Postretirement Benefits, to increase transparency surrounding the types of assets and risks associated in a defined benefit pension or other postretirement plan. Statement 132(R), as amended, will require employers to provide additional disclosure surrounding investment strategies, major categories of plan assets, and valuation techniques used to measure the fair value of plan assets. The staff position, which shall be

effective for our fiscal year ending June 30, 2010, will not have an impact on our results of operations or financial position.

(8)	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:

	December 31,	June 30,	December 31,
(000)	2008	2008	2007

Unbilled revenues ($)	9,591	1,579	6,981
Unbilled gas costs ($)	6,788	736	4,224
Unbilled volumes (Mcf)	517	51	425

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

(9)	Net pension costs for our trusteed, noncontributory defined benefit pension plan for the periods ended December 31 include the following:

	Three Months Ended				Six Months Ended				Twelve Months Ended
	December 31,				December 31,				December 31,
($000)	2008		2007		2008		2007		2008		2007

Service cost	169		187		339		374		713		732
Interest cost	203		187		405		373		778		723
Expected return on plan assets	(253	)	(247	)	(505	)	(494	)	(999	)	(992	)
Amortization of unrecognized net loss	55		62		108		125		233		242
Amortization of prior service cost	(22	)	( 21	)	(43	)	(43	)	(86	)	(86	)
Net periodic benefit cost	152		168		304		335		639		619

(10)

The current available bank line of credit with Branch Banking and Trust Company, shown as notes payable on the accompanying Consolidated Balance Sheets, is $40,000,000, of which $28,653,000, $6,829,000 and $23,798,000 were borrowed having a weighted average interest rate of 2.66%, 3.21% and 5.99% as of December 31, 2008, June 30, 2008 and December 31, 2007, respectively. The interest on this line is determined monthly at the London Interbank Offered Rate plus .75% on the used bank line of credit. The annual cost of the unused bank line of credit is .125% and the bank line of credit extends through October 31, 2009.

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 unless consolidated shareholders’ equity of the Company exceeds $25,800,000 (thus no retained earnings were restricted); and

•

We may not assume any additional mortgage indebtedness in excess of $5,000,000 without effectively securing all Debentures and Insured Quarterly Notes equally to such additional indebtedness.

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.

(11)

We have entered into individual employment agreements with our 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 million would be paid in addition to continuation of specified benefits for up to five years.

(12)

We operate a natural gas underground storage field that we utilize to inject and store natural gas during the non-heating season, and we then withdraw natural gas during the heating season to meet our customers’ needs. We periodically analyze the volumes, pressure and other data relating to the storage field in order to substantiate the gas inventory carried in our perpetual inventory records. During January, 2009, after analyzing the storage field data at the end of the 2008 injection cycle, we determined that an inventory adjustment was required. We estimate that the adjustment amount will be in the range of $1,350,000 to $1,750,000. Based on the storage field data currently available, we cannot determine if any amount within the range is more likely than any other. The October, 2008 storage field data suggested that the inventory adjustment is related to a storage well that was identified in 2007 as allowing natural gas to escape. The storage well was remediated during fiscal 2008.

Prior to the current reporting period, sufficient data has not been available to determine the amount of lost gas inventory resulting from the compromised storage well. Prior to this current fiscal quarter, however, we had no reason to believe this represented a material financial risk to the Company. Our analysis in January, 2009 indicates a material shortfall of storage gas volumes in comparison with our perpetual inventory records. The January, 2009 analysis has also provided us enough information to estimate a range for adjusting inventory.

We have thus recorded a reserve in the amount of $1,350,000 against gas in storage on our December 31, 2008 Consolidated Balance Sheet. The reserved amount is included in operation and maintenance expense in the Consolidated Statements of Income for the three, six and twelve months ended December 31, 2008. Any future adjustment to the inventory reserve will be determined as additional storage field data is collected and evaluated during future storage injection and withdrawal cycles. The underground storage facility is insured against certain risks such as this, and although we intend to seek appropriate reimbursement from the insurer we cannot predict the amount of any insurance proceeds. Depending on the outcome of our pursuit of insurance recovery, we will also evaluate whether any unreimbursed gas losses are eligible for regulatory recovery under our gas cost recovery rate mechanism, or other appropriate methods. We have not recorded any insurance recovery asset or regulatory asset in the accompanying financial statements; however, to the extent recovery becomes probable, we will evaluate recognition of an asset at that time.

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

(14)	The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and our 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 distribution and transportation services.

On April 20, 2007, we filed a request for increased rates with the Kentucky Public Service Commission. This general rate case, Case No. 2007-00089, requested an annual revenue increase of approximately $5,642,000, an increase of 9.3%. The rate case requested a return on common equity of 12.1%. During October 2007, we negotiated a settlement with the Kentucky Attorney General regarding this rate case. The settlement agreement provided for $3,920,000 of additional annual revenues, and stipulated for settlement purposes a 10.5% return on common shareholders’ equity. The increase in rates was allocated primarily to the monthly customer charge to partially decouple revenues from volumes of gas sold. An order from the Kentucky Public Service Commission was received on October 19, 2007 approving the terms of the settlement with rates effective on or after October 20, 2007.

In July, 2008, the Kentucky Public Service Commission approved in Case No. 2008-00062 our request to implement a conservation and efficiency program for our residential customers. The program provides for

us to perform energy audits, promote conservation awareness, and provide rebates on the purchase of certain high-efficiency appliances. The program helps to align our interests with our residential customers by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation. Our rates will be adjusted annually, beginning in February, 2009, to recover the costs incurred under these programs, including the reimbursement of margins on lost sales and the incentives provided to us.

The Kentucky Public Service Commission has also approved a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs. Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission. Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred. Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which allows us to adjust our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles. These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts.

(15)

Our Company has two segments: (i) a regulated natural gas distribution, transmission and storage segment and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production. The regulated segment serves residential, commercial and industrial customers in the 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 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 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.

A single customer, Citizens Gas Utility District, provided $3,408,000, $8,035,000 and $17,747,000 of non-regulated revenues for the three, six and twelve months ended December 31, 2008, respectively. Citizens Gas Utility District provided $3,563,000, $5,724,000 and $10,934,000 of non-regulated revenues for the three, six and twelve months ended December 31, 2007, respectively. Citizens has notified us that they intend to cease purchasing gas from us on March 1, 2009, and we are in discussions with them relative to their future commitments to purchase gas from us. Although we intend to continue to pursue these commitments, there is no assurance that revenues from Citizens will continue at these levels. If Citizens ceases to purchase gas from us, we intend to pursue transporting and selling such gas to other markets.

For the three, six and twelve months ended December 31, 2008 and 2007, we purchased approximately 99% of our natural gas from interstate sources. We utilize Atmos Energy Marketing and M & B Gas Services to fulfill our interstate purchase requirements.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements which are included in our Annual Report on Form 10-K for the year ended June 30, 2008. Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services. Intersegment transportation revenue and expense 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				Six Months Ended				Twelve Months Ended
	December 31,				December 31,				December 31,
($000)	2008		2007		2008		2007		2008		2007
Operating Revenues
Regulated
External customers	22,177		16,423		28,826		21,691		65,354		52,699
Intersegment	971		1,086		1,733		1,782		3,970		3,702
Total regulated	23,148		17,509		30,559		23,473		69,324		56,401

Non-regulated
External customers	11,781		12,875		23,240		20,012		57,667		45,624

Eliminations for intersegment	(971	)	(1,086	)	(1,733	)	(1,782	)	(3,970	)	(3,702	)
Total operating revenues	33,958		29,298		52,066		41,703		123,021		98,323

Net Income
Regulated	870		1,606		411		406		3,360		2,527
Non-regulated	359		849		1,091		1,238		3,328		2,572
Total net income	1,229		2,455		1,502		1,644		6,688		5,099

(16)

During the quarter ended September 30, 2008, we sold two surplus office buildings for $335,000, which resulted in us recording $156,000 of gains on the sales. The gains are included in operation and maintenance expense in the six and twelve months ended December 31, 2008 Consolidated Statements of Income.

(17)

Due to the conditions in the worldwide debt and equity markets, we experienced a decline in the value of the assets held by our defined benefit pension plan. Although we are not required to make any minimum contributions during the current year, in January, 2009, we elected to contribute $2,000,000 to the plan.

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

YEAR TO DATE DECEMBER 31, 2008 OVERVIEW AND FUTURE OUTLOOK

For the six months ended December 31, 2008, consolidated net income per share of $0.46 decreased $0.04 per share as compared to the $0.50 net income per share for the six months ended December 31, 2007. The decrease is attributable to a non-recurring inventory adjustment to record a reserve against our gas in storage of $1,350,000 ($838,000 net of income tax benefit), as further discussed in Note 12 of the Notes to Consolidated Financial Statements. The decrease was substantially offset by increased gross margins for both our regulated and non-regulated segments.

Our 2009 results will be 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, a trend we have experienced for the last several fiscal years.

We expect our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2009, as in recent years, based on contracts currently in place. Future profitability of the non-regulated segment, though, is dependent on the business plans of a few large customers and the market prices of natural gas, which are both out of our control. 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 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.

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 ability to maintain liquidity depends on our bank line of credit, shown as notes payable on the accompanying Consolidated Balance Sheets. Notes payable increased to $28,653,000 at December 31, 2008, compared with $6,829,000 at June 30, 2008 and $23,798,000 at December 31, 2007. This increase reflects the seasonal nature of our sales and cash needs. Our cash requirements during the six months ended December 31, 2008 and 2007 exceeded cash provided by operations, primarily due to the purchase of natural gas which is injected into storage for use during the heating months. Additionally, our liquidity is impacted by the fact that we sometimes generate internally only a portion of the cash necessary for our capital expenditure requirements. We made capital expenditures of $3,846,000 and $6,571,000 during the six and twelve months ended December 31, 2008, respectively. We finance the balance of our capital expenditures on an interim basis through our bank line of credit.

Long-term debt decreased to $58,063,000 at December 31, 2008, compared with $58,318,000 at June 30, 2008 and $58,402,000 at December 31, 2007. These decreases resulted from provisions in the Debentures and Insured Quarterly Notes allowing limited redemptions to be made to certain holders or their beneficiaries.

Cash and cash equivalents were $325,000 at December 31, 2008, compared with $250,000 at June 30, 2008 and $681,000 at December 31, 2007. The changes in cash and cash equivalents for six and twelve months ended December 31, 2008 are summarized in the following table:

	Six Months Ended				Twelve Months Ended
	December 31,				December 31,
($000)	2008		2007		2008		2007

Provided by (used in) operating activities	(16,250	)	(14,449	)	4,777		4,277
Used in investing activities	(3,420	)	(2,639	)	(6,032	)	(6,799	)
Provided by financing activities	19,745		17,581		899		2,817
Increase (decrease) in cash and cash equivalents	75		493		(356	)	295

For the six months ended December 31, 2008, cash used in operating activities increased $1,801,000 (12%), as compared with the six months ended December 31, 2007. Cash paid for taxes increased $889,000 due to the timing of property tax payments between years. We also used an additional $796,000 in operating activities due to the timing of contributions to our pension plan, increased payroll, increased cost of removal and increases in other operating expenses.

For the twelve months ended December 31, 2008, cash provided by operating activities increased $500,000 (12%), as compared with the twelve months ended December 31, 2007, due to an increase in cash received from customers due to higher sales prices and increased volumes sold and transported. This increase was partially offset by an increase in cash paid for gas due to higher natural gas prices and increases in cash paid for other operating expenses.

Changes in cash used in investing activities result primarily from the changes in capital expenditures between periods.

For the six months ended December 31, 2008, cash provided by financing activities increased $2,164,000 (12%) due to increased net borrowings on our bank line of credit.

For the twelve months ended December 31, 2008, cash provided by financing activities decreased $1,918,000 (68%) due to increased net repayments on our bank line of credit.

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 2009 to be $7.9 million.

Due to volatile conditions in the debt and equity markets we experienced a decline in the value of the assets held by our defined benefit pension plan. Although we are not required to make any minimum contributions during the current year, in January, 2009, we elected to contribute $2,000,000 to the plan. Currently, we do not plan on making any additional contributions to the defined benefit pension plan during the remainder of fiscal 2009. We estimate that this contribution returned the plan to a fully funded status. The decrease in our plan assets could result in an increase in our fiscal 2010 net periodic benefit cost.

Sufficiency of Future Cash Flows

We expect that cash provided by operations, coupled with short and long-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.

Current economic conditions have resulted in increased credit risk for us due to the potential for default from our customers. For the six and twelve months ended December 31, 2008, we have experienced an increase in customer accounts written off, net of recoveries of $52,000 (23%) and $142,000 (41%), respectively. Based on current outstanding receivables and expecting this trend to continue for the remainder of fiscal 2009, our allowance for doubtful accounts has increased to $852,000 from $465,000 at June 30, 2008 and $252,000 at December 31, 2007. We do not anticipate that this trend will have a materially adverse impact on our liquidity.

To the extent that internally generated cash is not sufficient to satisfy 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 is $40,000,000, of which $28,653,000 was borrowed at December 31, 2008, and was classified as notes payable in the accompanying Consolidated Balance Sheets. The current bank line of credit is with Branch Banking and Trust Company and extends through October 31, 2009. We intend to extend our line of credit prior to October 31, 2009.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices and we continuously monitor our need to file rate requests with the Kentucky Public Service Commission for general rate increases for our regulated services.

On April 20, 2007, we filed a request for increased rates with the Kentucky Public Service commission. This general rate case, Case No. 2007-00089, requested an annual revenue increase of approximately $5,642,000, an increase of 9.3%. This rate case requested a return on common equity of 12.1%. During October, 2007, we negotiated a settlement agreement with the Kentucky Attorney General regarding this rate case. The settlement agreement provided for $3,920,000 of additional annual revenues, and stipulated for settlement purposes a 10.5% return on common shareholders’ equity. The increase in rates was allocated primarily to the monthly customer charge to partially decouple revenue from volumes of gas sold. An order from the Kentucky Public Service Commission was received on October 19, 2007 approving the terms of the settlement with rates effective on or after October 20, 2007.

RESULTS OF OPERATIONS

Gross Margins

Our regulated and non-regulated revenues, other than transportation, have offsetting gas expenses. Therefore, throughout the following Results of Operations, we refer to “gross margin”. With respect to our regulated and non-regulated segments, gross margin refers to operating revenues less purchased gas expense, which can be derived directly from our Consolidated Statements of Income. Operating Income as presented on the Consolidated Statements of Income, is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (“GAAP”). “Gross margin” is a “non-GAAP financial measure”, as defined in accordance with SEC rules. We view gross margin as an important performance

measure of the core profitability of our operations. The 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, Quantitative and Qualitative Disclosures About Market Risk, for the impact of forward contracts.

In the following table we set forth variations in our gross margins for the three, six and twelve months ended December 31, 2008 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 Consolidated Statements of Income.

	2008 compared to 2007
	Three Months		Six Months		Twelve Months
	Ended		Ended		Ended
($000)	December 31,		December 31,		December 31,

Increase (decrease) in regulated gross margins Gas sales	141		705		1,947
On-system transportation	(16	)	9		261
Off-system transportation	89		195		556
Other	140		102		(160	)
Total	354		1,011		2,604

Increase (decrease) in non-regulated gross margins Gas sales	(413	)	191		2,004
Other	(27	)	—		56
Total	(440	)	191		2,060

Increase in consolidated gross margins	(86	)	1,202		4,664
Percentage increase (decrease) in regulated volumes
Gas sales	20		16		4
On-system transportation	(7	)	(7	)	(3	)
Off-system transportation	8		9		15

Percentage increase (decrease) in non-regulated gas sales volumes	(15	)	(7	)	3

Heating degree days were 107%, 104% and 103% of normal thirty year average temperatures for the three, six and twelve months ended December 31, 2008, respectively, as compared with 87%, 85% and 92% of normal temperatures in the 2007 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 December 31, 2008, consolidated gross margins decreased $86,000 (1%) due to decreased non-regulated gross margins of $440,000 (16%) offset by increased regulated gross margins of $354,000 (5%). Our non-regulated gross margins decreased $440,000 (16%) due to a 15% decrease in volumes sold. Non-regulated customers are primarily industrial or other large use customers whose volumes are less sensitive to changes in the weather. The decrease in non-regulated volumes was attributable to an overall decrease in our non-regulated customer’s gas requirements. Our regulated gross margin for gas sales increased $141,000 (2%) primarily due to a 20% increase in volumes sold due to colder than normal weather which was partially offset by lower rates due to our weather normalization clause. Our regulated transportation and other gross margins increased $213,000 (19%) primarily due to an increase in regulated off-system transportation of 18%.

For the six months ended December 31, 2008, consolidated gross margins increased $1,202,000 (8%) due to increases in our regulated and non-regulated gross margins of $1,011,000 (10%) and $191,000 (5%), respectively. Our regulated gross margin for gas sales increased $705,000 (9%) primarily due to a 16% increase in volumes sold

due to colder than normal weather which was partially offset by lower rates due to our weather normalization clause. Our regulated off-system transportation margins increased $195,000 (11%) due to a 9% increase in volumes transported. Our non-regulated gross margin for gas sales increased $191,000 (5%) due to higher sales prices, partially offset by a 7% decrease in volumes sold.

For the twelve months ended December 31, 2008, consolidated gross margins increased $4,664,000 (14%) due to increases in our regulated and non-regulated gross margins of $2,604,000 (11%) and $2,060,000 (22%), respectively. Our regulated gross margin for gas sales increased $1,947,000 (10%) due to increased base rates which became effective October 20, 2007 as well as a 4% increase in volumes sold. Our regulated off-system transportation margins increased $556,000 (16%) due to a 15% increase in volumes transported. Our non-regulated gross margin for gas sales increased $2,004,000 (22%) due to higher sales prices.

Operations and Maintenance

For the three months ended December 31, 2008, operations and maintenance expense increased $1,966,000 (62%). The increase was due to an inventory adjustment to record a reserve against our gas in storage ($1,350,000, as further discussed in Note 12 of the Notes to Consolidated Financial Statements), increased uncollectible expense ($442,000) and increased employee benefit expense ($155,000).

For the six months ended December 31, 2008, operations and maintenance expense increased $1,896,000 (31%). The increase was due to an inventory adjustment to record a reserve against our gas in storage ($1,350,000, as further discussed in Note 12 of the Notes to Consolidated Financial Statements), increased uncollectible expense ($487,000), increased employee benefit expense ($121,000) and increased labor expense ($120,000), partially offset by $156,000 of gains on the sales of two surplus buildings.

For the twelve months ended December 31, 2008, operations and maintenance expense increased $3,085,000 (24%). The increase was due to an inventory adjustment to record a reserve against our gas in storage ($1,350,000, as further discussed in Note 12 of the Notes to Consolidated Financial Statements), increased uncollectible expense ($891,000), increased storage maintenance expense ($288,000), increased labor expense ($254,000) and increased transportation expense ($148,000).

Depreciation and Amortization

For the six and twelve months ended December 31, 2008, depreciation and amortization decreased $391,000 (17%) and $1,004,000 (21%), respectively. The decreases were due to lower depreciation rates approved by the Kentucky Public Service Commission that became effective October 20, 2007. The decreases were partially offset by increases in depreciable plant resulting from capital expenditures which relate to the replacement and improvement of our transmission, distribution, gathering, storage and general facilities.

Other Income and Deductions, Net

For the six and twelve months ended December 31, 2008, Other Income and Deductions, Net decreased $106,000 (558%) and $136,000 (120%), respectively. The decreases were due to decreases in the cash surrender value of officers’ life insurance as well as decreases in the fair value of the supplemental retirement plan. The decrease in the fair value of the supplemental retirement plan was offset by a reduction in operating expenses resulting from a corresponding decrease in the liability of the plan.

Income Tax Expense

For the three and six months ended December 31, 2008, income tax expense decreased $767,000 (51%) and $138,000 (14%), respectively. For the twelve months ended December 31, 2008, income tax expense increased $1,003,000 (33%). These changes are a result of changes in net income before income taxes.

Basic and Diluted Earnings Per Common Share

For the three, six and twelve months ended December 31, 2008 and 2007, our basic 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.

We have no potentially dilutive securities. As a result, our basic earnings per common share and our diluted earnings per common share are the same.

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 gas storage facilities 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 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 price risk resulting from 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 contracts meet the definition of a derivative, we have designated these contracts as “normal purchases” and “normal sales” under Statement of Financial Accounting Standards No. 133, entitled Accounting for Derivatives Instruments and Hedging Activities.

We are exposed to risk resulting from changes in interest rates on our variable rate bank line of credit. 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 balances on our bank line of credit were $28,653,000, $6,829,000 and $23,798,000 on December 31, 2008, June 30, 2008 and December 31, 2007, respectively. The weighted average interest rates on our bank line of credit were 2.66%, 3.21%, and 5.99% on December 31, 2008, June 30, 2008 and December 31, 2007, respectively. Based on the amounts of our outstanding bank line of credit on December 31, 2008, June 30, 2008 and December 31, 2007, a one percent (one hundred basis point) increase in our average interest rates would result in decreases in our annual pre-tax net income of $287,000, $68,000 and $238,000, respectively.

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 (“SEC’s”) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of the design and operations 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 December 31, 2008, 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 that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.

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 December 31, 2008 and found no changes that have materially affected, or are 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 condition or results of operations.

ITEM 1A.

RISK FACTORS

No material changes.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a)

The Registrant held its annual meeting of shareholders on November 20, 2008.

(b)

Glenn R. Jennings, Lewis N. Melton and Arthur E. Walker, Jr. were elected to Delta’s Board of Directors for three-year terms expiring in 2011. Michael J. Kistner and Michael R. Whitley will continue to serve on Delta’s Board of Directors until the election in 2009. Linda K. Breathitt, Lanny D. Greer and Billy Joe Hall will continue to serve on Delta’s Board of Directors until the election in 2010.

(c)

The total shares voted in the election of Directors were 2,941,796. There were no broker non-votes. The shares voted for each Nominee were:

Glenn R. Jennings

For

2,863,362

Withheld

78,434

Lewis N. Melton

For

2,865,956

Withheld

75,840

Arthur E. Walker, Jr.

For

2,850,468

Withheld

91,328

(d)

A shareholder recommended in a proposal to the Company’s Board of Directors that the Company amend its articles of incorporation to provide for all Directors to stand for election annually and to eliminate director classes with staggered terms. The vote tabulation for all Directors to stand for election annually and to eliminate director classes with staggered terms was:

For	666,737
Against	1,310,189
Abstain	69,627

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.

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: February 3, 2009		/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 and Principal Accounting Officer)