UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549

______________

FORM 10-K

______________

(Mark one)

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

For the fiscal year ended June 30, 2009

¨           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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock $1 Par Value	NASDAQ OMX Group

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act.  Yes  £  No x

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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   £

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 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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recent completed second fiscal quarter.  $80,205,566

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.  As of August 15, 2009, Delta Natural Gas Company, Inc. had outstanding 3,319,374 shares of common stock $1 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s definitive proxy statement, to be filed with the Commission not later than 120 days after June 30, 2009, is incorporated by reference in Part III of this Report.

TABLE OF CONTENTS

PART I			Page Number
	Item 1.	Business	2
	Item 1A.	Risk Factors	9
	Item 1B.	Unresolved Staff Comments	11
	Item 2.	Properties	12
	Item 3.	Legal Proceedings	12
	Item 4.	Submission of Matters to a Vote of  Security Holders	12
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of  Equity Securities	13
	Item 6.	Selected Financial Data	15
	Item 7.	Management’s Discussion and Analysis of  Financial Condition and Results of Operations	16
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	25
	Item 8.	Financial Statements and Supplementary Data	26
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	26
	Item 9A.	Controls and Procedures	26
	Item 9B.	Other Information	29
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance of the Registrant	29
	Item 11.	Executive Compensation	29
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	29
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	29
	Item 14.	Principal Accountant Fees and Services	29
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	30
Signatures			32

1

PART I

Item 1.     Business

General

We distribute or transport natural gas to approximately 37,000 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 produce a relatively small amount of natural gas from our southeastern Kentucky wells.

We seek to provide dependable, high-quality service to our customers while steadily enhancing value for our shareholders. Our efforts have been focused on developing a balance of regulated and non-regulated businesses to contribute to our earnings by profitably producing, selling and transporting natural gas in our service territory.

We strive to achieve operational excellence through economical, reliable service and our emphasis on responsiveness to customers. We continue to invest in facilities for the transmission, distribution and storage of natural gas. We believe that our responsiveness to customers and the dependability of the service we provide afford us additional opportunities for growth. While we seek those opportunities, our strategy will continue a conservative approach that seeks to minimize our exposure to market risk arising from fluctuations in the prices of gas.

We operate through two segments, a regulated segment and a non-regulated segment. See Note 14 of the Notes to Consolidated Financial Statements, in Item 8.  Financial Statements and Supplementary Data, for a discussion of these segments.

Our executive offices are located at 3617 Lexington Road, Winchester, Kentucky 40391. Our telephone number is (859) 744-6171. Our website is www.deltagas.com.

Regulated Operations

Distribution and Transportation

Through our regulated segment, we distribute natural gas to our retail customers in 23 predominantly rural counties. In addition, our regulated segment transports gas to industrial customers on our system who purchase gas in the open market. Our regulated segment also transports gas on behalf of local producers and other customers not on our distribution system.

The economy of our service area is based principally on coal mining, farming and light industry. The communities we serve typically contain populations of less than 20,000. Our three largest service areas are Nicholasville, Corbin and Berea, Kentucky. In Nicholasville we serve approximately 8,000 customers, in Corbin we serve approximately 6,000 customers, and in Berea we serve approximately 4,000 customers. Some of the communities we serve continue to expand, resulting in growth opportunities for us. Industrial parks have been developed in our service areas, which could result in additional growth in industrial customers as well.

The Kentucky Public Service Commission exercises regulatory authority over our regulated natural gas distribution and transportation services. The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers.

Factors that affect our regulated revenues include rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition.

Our results of operations and financial condition have been strengthened by regulatory developments in recent years, including a $3,920,000 annual revenue increase from our last rate case in 2007, a weather normalization provision in our tariff, which has reduced fluctuations in our earnings due to variations in weather, and a gas cost recovery clause, which mitigates market risk arising from fluctuations in the price of gas.

2

Although the Kentucky Public Service Commission permits us to pass through to our regulated customers changes in the price we must pay for our gas supply through our gas cost recovery clause, increases in our rates to customers may cause our customers to conserve or to use alternative energy sources.

Our regulated sales are seasonal and temperature-sensitive, since the majority of the gas we sell is used for heating.  During 2009, 73% of the regulated volumes were sold during the heating season (December through April).  Variations in the average temperature during the winter impact our revenues year-to-year. The Kentucky Public Service Commission, through a weather normalization provision in our tariff, permits us to adjust the rates we charge our customers in response to winter weather that is warmer or colder than normal temperatures.

We compete with alternate sources of energy for our regulated distribution customers. These alternate sources include electricity, coal, oil, propane and wood. Our non-regulated subsidiaries, which sell gas to industrial customers and others, compete with natural gas producers and natural gas marketers for those customers.

Our larger regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers may undertake such a by-pass of our distribution system in order to achieve lower prices for their gas service. Our larger customers who are in close proximity to alternative supplies would be most likely to consider taking this action. Additionally, some of our industrial customers are able to switch economically to alternative sources of energy. These are competitive concerns that we continue to address by utilizing our non-regulated segment to offer these customers gas supply at competitive market based rates.

Some natural gas producers in our service area can access pipeline delivery systems other than ours, which generates competition for our transportation services. We continue our efforts to purchase or transport natural gas that is produced in reasonable proximity to our transportation facilities through our regulated segment.

As an active participant in many areas of the natural gas industry, we plan to continue efforts to expand our gas distribution system and customer base. We continue to consider acquisitions of other gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas.

Gas Supply

We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2009, we purchased approximately 99% of our natural gas from interstate sources.

Interstate Gas Supply

Our regulated segment acquires its interstate gas supply from gas marketers. We currently have commodity requirements agreements with Atmos Energy Marketing (“Atmos”) for our Columbia Gas Transmission Corporation (“Columbia Gas”), Columbia Gulf Transmission Corporation (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”) and Texas Eastern Transmission Corporation (“Texas Eastern”) supplied areas. Under these commodity requirements agreements, Atmos is obligated to supply the volumes consumed by our regulated customers in defined sections of our service areas. The gas we purchase under these agreements is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  The index-based market prices are determined based on the prices published on the first of the month in Platts’ Inside FERC’s Gas Market Report in the indices that relate to the pipelines through which the gas will be transported, plus or minus an agreed-to fixed price adjustment per million British Thermal Units of gas purchased.  Consequently, the price we pay for interstate gas is based on current market prices.

Our agreements with Atmos for the Columbia Gas, Columbia Gulf, Tennessee and Texas Eastern supplied service areas continue year to year unless cancelled by either party by written notice at least sixty days prior to the annual anniversary date (April 30) of the agreement. In our fiscal year ended June 30, 2009, approximately 48% of our regulated gas supply was purchased under our agreements with Atmos.

Our regulated segment purchases gas from M & B Gas Services, Inc. (“M & B”) for injection into our underground natural gas storage field and to supply a portion of our system. We are not obligated to purchase any minimum quantities from M & B nor to purchase gas from M & B for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  Our agreement with M & B may be terminated upon 30 days prior written notice by either party.  In our fiscal year ended June 30, 2009, approximately 51% of our regulated gas supply was purchased under our agreement with M & B.

3

We also purchase interstate natural gas from other gas marketers as needed at either current market prices, determined by industry publications, or at forward market prices.

Transportation of Interstate Gas Supply

Our interstate natural gas supply is transported to us from market hubs, production fields and storage fields by Tennessee, Columbia Gas, Columbia Gulf and Texas Eastern.

Our agreements with Tennessee extend through 2013 and thereafter automatically renew for subsequent five-year terms unless terminated by one of the parties.  Tennessee is obligated under these agreements to transport up to 19,600 thousand cubic feet (“Mcf”) per day for us.  During fiscal 2009, Tennessee transported a total of 1,080,000 Mcf for us under these contracts.  Annually, approximately 31% of our regulated supply requirements flow through Tennessee to our points of receipt under our transportation agreements with Tennessee.  We have gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee’s storage fields and we reserve the right to withdraw daily gas volumes up to certain specified fixed quantities.  These gas storage agreements renew on the same schedule as our transportation agreements with Tennessee.

Under our agreements with Columbia Gas and Columbia Gulf, Columbia Gas is obligated to transport, including utilization of our defined storage space as required, up to 12,600 Mcf per day for us, and Columbia Gulf is obligated to transport up to a total of 4,300 Mcf per day for us.  During fiscal 2009 Columbia Gas and Columbia Gulf transported for us a total of 563,000 Mcf, or approximately 16% of our regulated supply requirements, under all of our agreements with them. All of our transportation agreements with Columbia Gas and Columbia Gulf continue on a year-to-year basis until terminated by one of the parties.

Columbia Gulf also transported additional volumes under agreements it has with M & B to a point of interconnection between Columbia Gulf and us where we purchase the gas to inject into our storage field.  The amounts transported and sold to us under the agreement between Columbia Gulf and M & B for fiscal 2009 constituted approximately 51% of our regulated gas supply.  We are not a party to any of these separate transportation agreements on Columbia Gulf.

We have no direct agreement with Texas Eastern. However, Atmos has an arrangement with Texas Eastern to transport the gas to us that we purchase from Texas Eastern to supply our customers’ requirements in specific geographic areas. Consequently, Texas Eastern transports a small percentage of our interstate gas supply.  In our fiscal year ended June 30, 2009, Texas Eastern transported approximately 17,000 Mcf of natural gas to our system, which constituted less than 1% of our gas supply.

Kentucky Gas Supply

We have an agreement with Chesapeake Appalachia LLC ("Chesapeake") to purchase natural gas on a year-to-year basis unless terminated by one of the parties.  We purchased 43,000 Mcf from Chesapeake during fiscal 2009. The price for the gas we purchase from Chesapeake is based on the index price of spot gas delivered to Columbia Gas in the relevant region as reported in Platt’s Inside FERC’s Gas Market Report, plus a fixed adjustment per million British Thermal units of gas purchased. Chesapeake delivers this gas to our customers directly from its own pipelines.

We own and operate an underground natural gas storage field that we use to store a significant portion of our winter gas supply needs.  This storage capability permits us to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months.

We continue to maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of gas for our customers.

4

Regulatory Matters

We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services.

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 shareholders’ equity.  The increase in rates was allocated primarily to the monthly customer charge, and therefore the increase in revenue occurred more evenly throughout the year and was not as dependent on customer usage.  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.

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.

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 customer's interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation.  Our rates are adjusted annually to recover the costs incurred under these programs, including the reimbursement of margins on lost sales and the incentives provided to us.

In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds.  No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise.  We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, the areas served do not have governmental organizations authorized to grant franchises or the city governments do not require a franchise.  We attempt to acquire or reacquire franchises whenever feasible.  Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city.  To date, the absence of a franchise has caused no adverse effect on our operations.

Non-Regulated Operations

Marketing and Production

We operate our non-regulated segment through three wholly-owned subsidiaries.  Two of these subsidiaries, Delta Resources, Inc. and Delgasco, Inc., purchase natural gas in the open market, including natural gas from Kentucky producers.  We resell this gas to industrial customers on our distribution system and to others not on our system.  Our third subsidiary, Enpro, Inc., produces natural gas that is sold to Delgasco for resale in the open market.

Factors that affect our non-regulated revenues include rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition.

5

Our larger non-regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Additionally, some of our industrial customers are able to switch economically to alternative sources of energy.  We continue to address these competitive concerns by offering these customers gas supply at competitive market based rates.

We anticipate continuing our non-regulated gas production and marketing activities and intend to pursue and increase these activities wherever practicable.

A single customer, Citizens Gas Utility District, provided $10,248,000, $17,087,000 and $9,843,000 of non-regulated revenues during 2009, 2008 and 2007, respectively.  Citizens has decreased their purchases from us, and thus revenues are not expected to continue at historical levels.

Gas Supply

           Our non-regulated segment purchases gas from M & B Gas Services, Inc. (“M & B”). We are not obligated to purchase any minimum quantities from M & B nor to purchase gas from M & B for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  Our agreement with M & B may be terminated upon 30 days prior written notice by either party. Any purchase agreements for unregulated sales activities may have longer terms or multiple month purchase commitments. In our fiscal year ended June 30, 2009, approximately 69% of our non-regulated gas supply was purchased under our agreement with M & B.

Additionally, our non-regulated segment purchases natural gas from Atmos as needed. This spot gas purchasing arrangement is pursuant to an agreement with Atmos containing an “evergreen” clause which permits either party to terminate the agreement by providing not less than sixty days written notice. Our purchases from Atmos under this spot purchase agreement are generally month-to-month. However, we have the option of forward-pricing gas for one or more months. The price of gas under this agreement is based on current market prices. In our fiscal year ended June 30, 2009, approximately 29% of our non-regulated gas supply was purchased under our agreement with Atmos.

We also purchase interstate natural gas from other gas marketers and Kentucky producers as needed at either current market prices, determined by industry publications, or at forward market prices.

Capital Expenditures

Capital expenditures during 2009 were $8.4 million and for 2010 are estimated to be $6.3 million.  Our expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities.

Financing

Our capital expenditures and operating cash requirements are met through the use of internally generated funds and a short-term bank line of credit.  The current available line of credit is $40 million, of which $3.7 million was borrowed at June 30, 2009.

Present plans are to continue to utilize the bank line of credit, which extends through June 30, 2011, to meet planned capital expenditures and operating cash requirements.  The amounts and types of future long-term debt and equity financings will depend upon our capital needs and market conditions.

6

Employees

On June 30, 2009, we had 155 full-time employees.  We consider our relationship with our employees to be satisfactory.  Our employees are not represented by unions nor are they subject to any collective bargaining agreements.

Available Information

We make available free of charge on our Internet website http://www.deltagas.com, our Business Code of Conduct and Ethics, annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains an internet site http://www.sec.gov that contains reports, proxy and information statements and other information regarding Delta. The public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC  20549.  The SEC's phone number is 1-800-732-0330.

7

Consolidated Statistics
For the Years Ended June 30,	2009			2008			2007			2006			2005
Average Retail Customers Served
Residential		30,881			31,520			31,941			32,601			33,284
Commercial		5,009			5,107			5,128			5,154			5,241
Industrial		49			54			59			59			60
Total		35,939			36,681			37,128			37,814			38,585
Operating Revenues ($000) (a)
Residential sales		33,774			30,742			28,648			35,240			29,172
Commercial sales		24,125			21,171			19,339			24,081			18,029
Industrial sales		1,769			1,707			1,676			2,356			1,744
Total regulated sales (b)(c)		59,668			53,620			49,663			61,677			48,945
On-system transportation (c)		4,118			4,461			4,258			4,371			4,312
Off-system transportation (c)		3,786			3,864			2,979			2,543			2,099
Non-regulated sales		41,147			54,438			44,669			51,904			31,971
Other		333			293			242			250			211
Eliminations for intersegment		(3,427	)		(4,019	)		(3,643	)		(3,498	)		(3,357	)
Total		105,625			112,657			98,168			117,247			84,181
System Throughput (Million Cu. Ft.) (a)
Residential sales		1,721			1,695			1,801			1,764			2,018
Commercial sales		1,346			1,286			1,345			1,313			1,381
Industrial sales		113			121			136			146			158
Total regulated sales (b)		3,180			3,102			3,282			3,223			3,557
On-system transportation		4,215			4,975			5,161			5,322			5,273
Off-system transportation		11,908			12,623			9,774			8,789			7,194
Non-regulated sales		4,219			5,394			4,921			4,398			3,924
Eliminations for intersegment		(4,135	)		(5,276	)		(4,822	)		(4,313	)		(3,831	)
Total		19,387			20,818			18,316			17,419			16,117
Average Annual Consumption Per
Average Residential Customer
(Thousand Cu. Ft.)		56			54			56			54			61
Lexington, Kentucky Degree Days
Actual		4,651			4,464			4,419			4,309			4,293
Percent of 30 year average		101			96			95			92			92

(a) Additional financial information related to our segments can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 14 of the Notes to Consolidated Financial Statements.

(b) 2005 regulated sales includes a $1,246,000 non-recurring increase in revenues due to the recording of 58,000 Mcf of unbilled sales at June 30, 2005.

(c) We implemented new regulated base rates, as approved by the Kentucky Public Service Commission in October, 2007, which were designed to generate additional annual revenue of $3,920,000.

8

Item 1A.  Risk Factors

The risk factors below should be carefully considered.

WEATHER CONDITIONS MAY CAUSE OUR REVENUES TO VARY FROM YEAR TO YEAR. Our revenues vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, which would reduce our revenues and profits.  The weather normalization clause in our rate tariff, approved by the Kentucky Public Service Commission, only partially mitigates this risk.  Under our weather normalization clause in our rate tariffs, we 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.

CHANGES IN FEDERAL REGULATIONS COULD REDUCE THE AVAILABILITY OR INCREASE THE COST OF OUR INTERSTATE GAS SUPPLY. We purchase almost all of our gas supply from interstate sources. For example, in our fiscal year ended June 30, 2009, approximately 99% of our gas supply was purchased from interstate sources. The Federal Energy Regulatory Commission regulates the transmission of the natural gas we receive from interstate sources, and it could increase our transportation costs or decrease our available pipeline capacity by changing its regulatory policies in a manner that could increase transportation rates or reduce pipeline or storage capacity available to us.

OUR GAS SUPPLY DEPENDS UPON THE AVAILABILITY OF ADEQUATE PIPELINE TRANSPORTATION CAPACITY. We purchase almost all of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of gas.

OUR CUSTOMERS ARE ABLE TO ACQUIRE NATURAL GAS WITHOUT USING OUR DISTRIBUTION SYSTEM. Our larger customers can obtain their natural gas supply by purchasing their natural gas directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers may undertake such a by-pass of our distribution system in order to achieve lower prices for their gas service. Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. This potential to by-pass our distribution system creates a risk of the loss of large customers and thus could result in lower revenues and profits.

WE FACE REGULATORY UNCERTAINTY AT THE STATE LEVEL. We are regulated by the Kentucky Public Service Commission. Our regulated segment generates a significant portion of our income from operations. We face the risk that the Kentucky Public Service Commission may fail to grant us adequate and timely rate increases or may take other actions that would cause a reduction in our income from operations, such as limiting our ability to pass on to our customers our increased costs of natural gas. Such regulatory actions would decrease our revenues and our profitability.

VOLATILITY IN THE PRICE OF NATURAL GAS COULD REDUCE OUR PROFITS. Significant increases in the price of natural gas will likely cause our regulated retail customers to continue to conserve or switch to alternate sources of energy. Any decrease in the volume of gas we sell that is caused by such actions will reduce our revenues and profits. Higher prices also make it more difficult to add new customers. Significant decreases in the price of natural gas will likely cause our non-regulated segment margins to decrease.

WE DO NOT ALWAYS GENERATE SUFFICIENT CASH FLOWS TO MEET ALL OUR CASH NEEDS. We make capital expenditures in order to maintain, expand and upgrade our distribution and transmission system.  As a result, we fund a portion of our cash needs through borrowing and by offering new securities into the market.  Although cash needs vary from year to year, our dependence on external sources of financing creates the risks that our profits could decrease as a result of high capital costs and that lenders could impose onerous and unfavorable terms on us as a condition to granting us loans.  We also have the risk that we may not be able to secure external sources of cash necessary to fund our operations.  In 2009 cash provided by operating activities was sufficient to meet our financing needs, and we were able to make a net repayment on our short-term bank line of credit in the amount of $3,176,000.

INTERSTATE AND OTHER PIPELINES DELTA INTERCONNECTS WITH CAN IMPOSE RESTRICTIONS ON THEIR PIPELINE.  The pipelines interconnected to Delta's system are owned and operated by third parties who can impose restrictions on the quantity and quality of natural gas they will accept into their pipelines.  To the extent natural gas on Delta's system does not conform to these restrictions, Delta could experience a decrease in volumes sold or transported to these pipelines.

9

FUTURE PROFITABILITY OF THE NON-REGULATED SEGMENT IS DEPENDENT ON A FEW INDUSTRIAL AND OTHER LARGE USE CUSTOMERS.  Our larger non-regulated customers are primarily industrial and other large use customers.  Fluctuations in the gas requirements of these customers can have a significant impact on the profitability of the non-regulated segment.  We attempt to mitigate this risk by seeking additional opportunities for our non-regulated segment to sell gas to customers on and off Delta's system.

CURRENT LEVELS OF CAPITAL AND CREDIT MARKET VOLATILITY ARE UNPRECEDENTED.  The capital and credit markets have been experiencing extreme volatility and disruption.  In recent months, the volatility and disruption have reached unprecedented levels.  In some cases, the markets have exerted downward pressure on stock prices and credit availability for certain companies.  To the extent that internally generated cash coupled with short-term borrowings under our bank line of credit is not sufficient for our operating cash requirements and normal capital expenditures we may need to obtain additional financing.  If current levels of market disruption and volatility continue or worsen, under such extreme market conditions, there can be no assurance other financing sources would be available or sufficient.  Additionally, our access to funds under our bank line of credit is dependent on the liquidity of the lender, Branch Banking & Trust Company.

POOR INVESTMENT PERFORMANCE OF PENSION PLAN HOLDINGS AND OTHER FACTORS IMPACTING PENSION PLAN COSTS COULD UNFAVORABLY IMPACT OUR LIQUIDITY AND RESULTS OF OPERATIONS.  Our cost of providing a non-contributory defined benefit pension plan is dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions made to the plan.  Due to the conditions in the debt and equity markets, we experienced a decline in the value of the assets held by our defined benefit pension plan and thus we contributed $2,677,000 to the plan in fiscal 2009.  Without sustained growth in the pension investments over time to increase the value of the plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plan with additional significant amounts of cash.  Such cash funding obligations could have a material impact on our financial position, results of operations or cash flows.

WE ARE EXPOSED TO CREDIT RISK OF CUSTOMERS AND OTHERS WITH WHOM WE DO BUSINESS.  Adverse economic conditions affecting, or financial difficulties of, customers and others with whom we do business could impair the ability of these customers and others to pay for our services or fulfill their contractual obligations or cause them to delay such payments or obligations.  We depend on these customers and others to remit payments on a timely basis.  Any delay or default in payment could adversely affect our cash flows, financial position or results of operations.

SUBSTANTIAL OPERATIONAL RISKS ARE INVOLVED IN OPERATING A NATURAL GAS DISTRIBUTION, PIPELINE AND STORAGE SYSTEM AND SUCH OPERATIONAL RISKS COULD REDUCE OUR REVENUES AND INCREASE EXPENSES.  There are substantial risks associated with the operation of a natural gas distribution, pipeline and storage system, such as operational hazards and unforeseen interruptions caused by events beyond our control.  These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline and storage facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond our control.  These risks could result in injury or loss of life, extensive property damage and environmental pollution, which in turn could lead to substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. Liabilities incurred that are not fully covered by insurance could adversely affect our results of operations and financial condition.  Additionally, interruptions to the operation of our gas distribution, transmission or storage system caused by such an event could reduce our revenues and increase our expenses.

HURRICANES OR OTHER EXTREME WEATHER COULD INTERRUPT OUR GAS SUPPLY AND INCREASE NATURAL GAS PRICES.  Hurricanes or other extreme weather could damage production or transportation facilities, which could result in decreased supplies of natural gas and increased supply costs for us and higher prices for our customers.

10

CROSS-DEFAULT PROVISIONS IN OUR BORROWING ARRANGEMENTS INCREASE THE CONSEQUENCES OF A DEFAULT ON OUR PART.  Each indenture under which our outstanding debt has been issued, and the loan agreements for our bank line of credit, contains a cross-default provision which provides that we will be in default under such indenture or loan agreement in the event of certain defaults under any of the other indentures or loan agreements.  Accordingly, should an event of default occur under one of our debt agreements, we face the prospect of being in default under all of our debt agreements and obliged in such instance to satisfy all of our then-outstanding indebtedness.  In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us.

OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS NEGATIVE COVENANTS THAT RESTRICT OUR ACTIVITIES.  Without bank approval or repaying the bank line of credit, our bank line of credit restricts us from:

· merging with another entity,

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

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

· having any person hold more than twenty percent (20%) of our outstanding shares of common stock.

Our 7.00% Debentures and 5.75% Insured Quarterly Notes restrict us from:

· assuming additional mortgage indebtedness in excess of $5,000,000, and

· paying dividends on our common stock unless our consolidated shareholders’ equity minus the value of our intangible assets exceed $25,800,000.

These negative covenants create the risk that we may be unable to take advantage of business and financing opportunities as they arise.

NEW LAWS OR REGULATIONS COULD HAVE A NEGATIVE IMPACT ON OUR FINANCIAL POSITION, RESULTS OF OPERATIONS OR CASH FLOWS.  Changes in laws and regulations, including new accounting standards and tax law, could change the way in which we are required to record revenues, expenses, assets and liabilities.  These types of regulations could have a negative impact on our financial position, cash flows, results of operations or access to capital.

Item 1B.  Unresolved Staff Comments

None.

11

Item 2.    Properties

We own our corporate headquarters in Winchester, Kentucky. We own ten buildings used for field operations in the cities we serve. Also, we own a building in Laurel County, Kentucky used for equipment and materials storage.

We own approximately 2,500 miles of natural gas gathering, transmission, distribution, storage and service lines. These lines range in size up to twelve inches in diameter.

We hold leases for the storage of natural gas under 8,000 acres located in Bell County, Kentucky. We developed this property for the underground storage of natural gas.

We use all the properties described in the three paragraphs immediately above principally in connection with our regulated natural gas distribution, transmission and storage segment.  See Note 14 of the Notes to Consolidated Financial Statements for a description of Delta’s two business segments.

Through our wholly-owned subsidiary, Enpro, we produce natural gas as part of the non-regulated segment of our business.

Enpro owns interests in oil and natural gas leases on 10,300 acres located in Bell, Knox and Whitley Counties. Thirty-five gas wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated at 2.9 million Mcf.  Also, Enpro owns the natural gas underlying 15,400 additional acres in Bell, Clay and Knox Counties. These properties have been leased to others for further drilling and development.  We have performed no reserve studies on these properties.  Enpro produced a total of 143,000 Mcf of natural gas during fiscal 2009 from all the properties described in this paragraph.

A producer plans to conduct further exploration activities on part of Enpro’s developed holdings. Enpro reserved the option to participate in wells drilled by this producer and also retained certain working and royalty interests in any production from future wells.

Our assets have no significant encumbrances.

Item 3.    Legal Proceedings

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

Item 4.   Submission of Matters to a Vote of Security Holders

No matter was submitted during the fourth quarter of 2009.

12

PART II

Item 5.             Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

We have paid cash dividends on our common stock each year since 1964. The frequency and amount of future dividends will depend upon our earnings, financial requirements and other relevant factors, including limitations imposed by the indenture for our Insured Quarterly Notes and Debentures (as described in Note 9 of the Notes to Consolidated Financial Statements).

Our common stock is traded on the NASDAQ OMX Group and trades under the symbol “DGAS”. There were 1,773 record holders of our common stock as of August 15, 2009. The accompanying table sets forth, for the periods indicated, the high and low sales prices for the common stock on the NASDAQ OMX Group and the cash dividends declared per share.

	Range of Stock Prices ($)		Dividends
	High	Low	Per Share ($)
Quarter
Fiscal 2009
First	28.60	11.70	.32
Second	26.00	18.01	.32
Third	26.86	18.68	.32
Fourth	24.21	18.46	.32
Fiscal 2008
First	25.83	23.50	.31
Second	25.84	24.10	.31
Third	26.73	24.11	.31
Fourth	32.19	24.25	.31

The closing sale prices shown above reflect prices between dealers and do not include markups or markdowns or commissions and may not necessarily represent actual transactions.

13

Comparison of Five-Year Cumulative Total Shareholder Return

The following graph sets forth a comparison of five year cumulative total shareholder return (equal to dividends plus stock price appreciation) among our common shares, the Standard & Poor’s 500 Stock Index and the Dow Jones Utilities Index during the past five fiscal years. Information reflected on the graph assumes an investment of $100 on June 30, 2004 in each of our common shares, the Standard & Poor’s Stock Index and the Dow Jones Utilities Index.  Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.

	2004		2005		2006		2007		2008		2009
Delta		100.0		109.2		108.5		120.0		127.3		133.9
Standard & Poor’s 500 Stock Index		100.0		106.3		115.5		139.3		121.0		89.3
Dow Jones Utilities Index		100.0		145.4		159.5		195.9		206.8		148.0

14

Item 6.    Selected Financial Data
For the Years Ended June 30,	2009		2008		2007		2006		2005
Summary of Operations ($)
Operating revenues (a)(b)		105,636,824		112,657,117		98,168,391		117,247,144		84,181,233
Operating income (a)(b)(c)		12,793,200		15,663,736		12,968,043		12,757,507		12,490,127
Net income (a)(b)(c)		5,210,729		6,829,868		5,298,347		5,024,635		4,998,619
Basic and diluted earnings per common share (a)(b)(c)		1.58		2.08		1.62		1.55		1.55
Cash dividends declared per common share		1.28		1.24		1.22		1.20		1.18
Weighted Average Number of Common Shares Outstanding (Basic and Diluted)		3,306,026		3,285,464		3,265,800		3,242,223		3,216,668
Total Assets ($)		162,505,295		170,814,856		160,400,950		155,554,125		144,762,217
Capitalization ($)
Common shareholders’ equity		58,999,182		57,593,585		54,428,471		52,609,724		50,799,454
Long-term debt  (d)		57,599,000		58,318,000		58,625,000		58,790,000		52,707,000
Total capitalization		116,598,182		115,911,585		113,053,471		111,399,724		103,506,454
Short-Term Debt ($)(d)(e)		4,853,103		8,028,791		5,389,918		8,246,434		7,609,122
Other Items ($)
Capital expenditures		8,422,433		5,563,667		8,082,918		7,781,396		5,338,356
Total property, plant and equipment		199,254,216		192,127,184		187,148,032		182,155,110		174,711,253

(a) We recorded 58,000 Mcf of unbilled sales at June 30, 2005, resulting in non-recurring increases of $1,246,000 in operating revenues, $617,000 in operating income, $379,000 in net income and $.12 in basic and diluted earnings per common share for fiscal 2005.

(b) We implemented new regulated base rates as approved by the Kentucky Public Service Commission in October, 2007 and the rates were designed to generate additional annual revenue of $3,920,000.

(c) We recorded a $1,350,000 non-recurring inventory adjustment at December 31, 2008 for our gas in storage, as discussed in Note 15 of the Notes to Consolidated Financial Statements.

(d) During April, 2006, we issued $40,000,000 aggregate principal amount of 5.75% Insured Quarterly Notes due 2021. The net proceeds of the offering were $37,671,000. We used the net proceeds to redeem $23,700,000 and $10,200,000 aggregate principal amount of our 7.15% Debentures due 2018 and 6 5/8% Debentures due 2023, respectively. The remaining net proceeds of $3,830,000 were used to pay down our bank line of credit.

(e) Includes current portion of long-term debt.

15

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview of 2009 and Future Outlook

Overview

The following is a discussion of the segments we operate, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during 2009. 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.

Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors.  Regulated sales volumes are temperature-sensitive. Our regulated sales volumes in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes.  The impact of winter temperatures on our revenues is partially reduced given our ability to adjust our winter rates for residential and small non-residential customers based on the degree to which actual winter temperatures deviate from normal.

Our non-regulated segment markets natural gas to large-use customers both on and off our regulated system. We endeavor to enter sales agreements when we can match estimated demand with a supply that provides an acceptable margin.

Earnings per share decreased between 2009 and 2008 by $.50 per share.  Our non-regulated segment's contribution to earnings decreased as a result of decreased non-regulated sales volumes and lower sales prices that resulted in a $2,800,000 reduction in gross margins.  Additionally, we incurred a non-recurring inventory adjustment for our gas in storage of $1,350,000 ($838,000 net of income tax benefit), as further discussed in Note 15 of the Notes to Consolidated Financial Statements.

Future Outlook

In 2010 and beyond, our success will depend, in part, on our regulated segment's ability to maintain a reasonable rate of return.  The Kentucky Public Service Commission sets the rates we are permitted to charge our customers in the regulated segment.  We monitor our need to file a general rate case with the Kentucky Public Service Commission to seek approval to adjust the rates we charge our regulated customers.  The regulated segment’s largest expense is gas supply, 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 a few industrial and other large use customers and the market prices of natural gas, all of which are out of our control.  Although in Fiscal 2009 we experienced a decline of gross margins in this segment due to decreased prices and decreases in the volumes sold to our non-regulated customers due to a decrease in our non-regulated customers' gas requirements, we anticipate our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2010 in a manner at least similar to fiscal 2009.  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.

16

Liquidity and Capital Resources

Sources and Uses of Cash

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, gains on the sale of assets 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 decreased to $3,653,000 at June 30, 2009, compared with $6,829,000 at June 30, 2008.  The $3,176,000 decrease reflects a decrease in the cost of gas purchased for our gas in storage.

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 $8,422,000, $5,564,000 and $8,803,000 during the fiscal years ended 2009, 2008 and 2007, respectively.

Long-term debt decreased to $57,599,000 at June 30, 2009, compared with $58,318,000 at June 30, 2008. The $719,000 decrease resulted from the redemption of the Debentures and Insured Quarterly Notes, which allow for limited redemptions to be made by certain holders or their beneficiaries.

Cash and cash equivalents were $123,000 at June 30, 2009 compared with $250,000 at June 30, 2008 and $188,000 at June 30, 2007.  These changes in cash and cash equivalents are summarized in the following table:

($000)	2009			2008			2007
Provided by operating activities		15,434			6,592			14,486
Used in investing activities		(7,956	)		(5,266	)		(7,936	)
Used in financing activities		(7,605	)		(1,264	)		(6,512	)
Increase (decrease) in cash and cash equivalents		(127	)		62			38

In 2009, cash provided by operating activities increased $8,842,000 as compared to 2008. In 2009, $8,626,000 less was paid for natural gas due to lower natural gas prices and $5,202,000 more cash was received from customers due to the timing of collections on customer accounts receivable. These increases were partially offset by a $1,932,000 increase in contributions we made to our pension plan and a $1,473,000 increase in cash paid for taxes.

In 2008, cash provided by operating activities decreased $7,894,000 as compared to 2007. In 2008, we paid $15,288,000 more for gas due to increased natural gas prices, increased volumes purchased and the timing of gas payables. This increase was partially offset due to $7,120,000 more cash received from customers due to increased prices and volumes sold.

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

In 2009, $6,341,000 more cash was used in financing activities due to increased net repayments on our bank line of credit.

In 2008, $5,248,000 less cash was used in financing activities due to increased net borrowings on our bank line of credit.

17

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 2010 to be approximately $6.3 million.

Due to the conditions in the debt and equity markets, we experienced a decline in the value of assets held by our defined benefit pension plan and thus we contributed $2,677,000 to the plan in fiscal 2009.

The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2009:

	Payments Due by Fiscal Year
($000)	2010			2011-2012		2013-2014	After 2014		Total
Interest payments (a)	$	4,192	$	7,859	$	7,400	$	28,700	$	48,151
Long-term debt (b)		1,200		2,400		2,400		52,799		58,799
Pension contributions (c)		500		1,000		1,000		9,182		11,682
Gas purchases (d)		3,764		143		—		—		3,907
Total contractual obligations (e)	$	9,656	$	11,402	$	10,800	$	90,681	$	122,539

(a) Our long-term debt, notes payable, customers’ deposits and unrecognized tax positions all require interest payments.  Interest payments are projected based on fiscal 2009 interest payments until the underlying obligation is satisfied. Interest on notes payable represents interest payments expected on the bank line of credit which extends through June 30, 2011.  As of June 30, 2009, we have accrued $60,000 of interest related to uncertain tax positions.  This amount has been excluded from the above table of contractual obligations as the timing of such payments is uncertain.

(b) See Note 9 of the Notes to Consolidated Financial Statements for a description of this debt.  The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.  Our long-term debt does not have any sinking fund requirements.

(c) This represents currently projected contributions to the defined benefit plan through 2019, as recommended by our actuary.

(d) As of June 30, 2009, we had ten contracts which have minimum purchase obligations.  These contracts have various terms with the last contract expiring November 1, 2010.  The remainder of our gas purchase contracts are requirement-based contracts or if a minimum purchase obligation exists the contract does not extend for a time period greater than one month.

(e) We have other long-term liabilities which include deferred income taxes ($27,538,000), regulatory liabilities ($1,711,000), asset retirement obligations ($1,670,000) and deferred compensation ($281,000).  Based on the nature of these items their expected settlement dates cannot be estimated.

All of our operating leases are year-to-year and cancelable at our option.

See Note 12 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

18

Sufficiency of Future Cash Flows

Current economic conditions have resulted in increased credit risk for us due to the potential for default from our customers.  For the twelve months ended June 30, 2009, we have experienced an increase in customer accounts written off, net of recoveries of $42,000 (10%).  Based on current outstanding receivables and expecting this trend to continue into fiscal 2010, our allowance for doubtful accounts has increased to $819,000 at June 30, 2009, as compared to $465,000 at June 30, 2008.  However, we are unable to estimate the impact this trend will have on future earnings and liquidity.

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

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 with Branch Banking and Trust Company, shown as notes payable on the accompanying Consolidated Balance Sheets,  is $40,000,000, of which $3,653,000 was borrowed at June 30, 2009.  The current bank line of credit extends through June 30, 2011.

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

· Dividend payments cannot be made unless consolidated shareholders' equity of other 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 fiscal 2009.  We are not aware of any events that would cause us to be in default in fiscal 2010.

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 monitor our need to file rate requests with the Kentucky Public Service Commission for a general rate increase 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%.  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, and therefore the increase in revenue occurred more evenly throughout the year and was not as dependent on customer usage.  An order from the Kentucky Public Service Commission was received on October 19, 2007 approving the terms of the settlement with rates effective October 20, 2007.

Critical Accounting Policies and Estimates

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the use of assumptions and estimates regarding future events, including the likelihood of success of particular investments or initiatives, estimates of future prices or rates, legal and regulatory challenges and anticipated recovery of costs.  Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions.  We consider an accounting estimate to be critical if (i) the accounting estimate requires us to make assumptions about matters that were reasonably uncertain at the time the accounting estimate was made, and (ii) changes in the estimate are reasonably likely to occur from period to period.

19

These critical accounting estimates should be read in conjunction with the Notes to Consolidated Financial Statements.  We have other accounting policies that we consider to be significant; however, these policies do not meet the definition of critical accounting estimates, because they generally do not require us to make estimates or judgments that are particularly difficult or subjective.

Regulatory Accounting

Our accounting policies historically reflect the effects of the rate-making process in accordance with Financial Accounting Standards Board Statement No. 71, entitled Accounting for the Effects of Certain Types of Regulation.  Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of Statement No. 71 to that segment continues to be appropriate.  We must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that the regulated segment no longer meets the criteria of regulatory accounting under Statement No. 71, that segment will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements.

The application of Statement No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the Kentucky Public Service Commission.  We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred, or they represent probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements.  We believe it is probable that we will recover the regulatory assets that have been recorded.

Pension

Our reported costs of providing pension benefits (as described in Note 5(a) of the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension costs associated with our defined benefit pension plan, for example, are impacted by employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plan and earnings on plan assets.  Additionally, changes made to the provisions of the plan may impact current and future pension costs.  Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

Changes in pension obligations associated with the above factors may not be immediately recognized as pension costs in the Consolidated Statements of Income, but may be deferred and amortized in the future over the average remaining service period of active plan participants.  For the years ended June 30, 2009, 2008 and 2007, we recorded pension costs for our defined benefit pension plan of $608,000, $670,000 and $567,000, respectively.

Our pension plan assets are principally comprised of equity and fixed income investments.  Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods.  Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.

20

In selecting our discount rate assumption we considered rates of return on high-quality fixed-income investments that are expected to be available through the maturity dates of the pension benefits.  Our expected long-term rate of return on pension plan assets was 7% for 2009 and was based on our targeted asset allocation assumption of approximately 65% equity investments and approximately 35% fixed income investments.  Our target investment allocation for equity investments includes allocations to domestic, international, and emerging markets.  Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective.  We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

We calculate the expected return on assets in our determination of pension costs based on the market value of assets at the measurement date. Using the market value recognizes investment gains or losses in the year in which they occur.

Based on an assumed long-term rate of return of 7%, discount rate of 6.25%, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plan will increase from $608,000 in 2009 to $1,040,000 in 2010. Modifying the expected long-term rate of return on our pension plan assets by .25% would change pension costs for 2010 by approximately $34,000.  Increasing the discount rate assumption by .25% would decrease pension costs by approximately $43,000.  Decreasing the discount rate assumption by .25% would increase pension costs by approximately $45,000.

Effective May 9, 2008, any employees hired on and after that date are not eligible to participate in our defined benefit pension plan.  Freezing the plan to new entrants did not impact the level of benefits for existing participants.

Effective July 1, 2008, we adopted the measurement date provision of Financial Accounting Standards Board Statement No. 158 entitled Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, 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 were $760,000.  Of this amount, $152,000 is attributable to the change in measurement dates and (net of tax effects of $58,000) was charged directly to retained earnings on July 1, 2008.

Provisions for Doubtful Accounts

We encounter risks associated with the collection of our accounts receivable.  As such, we record a monthly provision for accounts receivable that are considered to be uncollectible.  In order to calculate the appropriate monthly provision, we primarily utilize our historical experience related to accounts written-off.  Quarterly, at a minimum, we review the reserve for reasonableness based on the level of revenue and the aging of the receivable balance.  The underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the Consolidated Statements of Income and working capital.  The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact operating income.

Unbilled Revenues and Gas Costs

At each month-end, we estimate the gas service that has been rendered from the date the customer’s meter was last read to month-end.  This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather-sensitive usage for each degree day during the unbilled period.  Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month-end. Actual usage patterns may vary from these assumptions and may impact operating income.

Asset Retirement Obligations

We have accrued asset retirement obligations for gas well plugging and abandonment costs.  Additionally, we have recorded asset retirement obligations required pursuant to Federal regulations related to the retirement of our service lines and mains, although the timing of such retirements is uncertain.  The fair value of our retirement obligations are recorded at the time the obligations are incurred. We do not recognize asset retirement obligations relating to assets with indeterminate useful lives.  Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability.  Over time the liabilities are accreted for the change in their present value, through depreciation, and the initial capitalized costs are depreciated over the useful lives of the related assets.  For asset retirement obligations attributable to assets of our regulated operations, the depreciation and accretion are deferred as a regulatory asset.  We must use judgment to identify all appropriate asset retirement obligations.  The underlying assumptions used for the value of the retirement obligations and related capitalized costs can change from period to period.  These assumptions include the estimated future retirement costs, the estimated retirement date and the assumed credit-adjusted risk-free interest rate.  Our asset retirement obligations are discussed in Note 3 of the Notes to Consolidated Financial Statements.

21

New Accounting Pronouncements

Significant management judgment is generally required during the process of adopting new accounting pronouncements. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of these pronouncements.

Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations and the other sections of this report contain forward-looking statements that relate to future events or our future performance.  We have attempted to identify these statements by using words such as “estimates”, “attempts”, “expects”, “monitors”, “plans”, “anticipates”, “intends”, “continues”, “strives” ,”seeks”, “will rely”, “believes” and similar expressions.

These forward-looking statements include, but are not limited to, statements about:

· operational plans,

· the cost and availability of our natural gas supplies,

· capital expenditures,

· sources and availability of funding for our operations and expansion,

· anticipated growth and growth opportunities through system expansion and acquisition,

· competitive conditions that we face,

· production, storage, gathering and transportation activities,

· acquisition of service franchises from local governments,

· pension fund costs and management,

· contractual obligations and cash requirements,

· management of our gas supply and risks due to potential fluctuation in the price of natural gas,

· revenues, income, margins and profitability,

· efforts to purchase and transport locally produced natural gas,

· recovery of regulatory assets,

· regulatory and legislative matters, and

· dividends.

Our forward-looking statements are not guarantees of future performance and are based upon currently available competitive, financial and economic data along with our operating plans.

Item 1A.  Risk Factors lists factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results.

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 in 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.  This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments.  We believe that investors benefit from having access to the same financial measures that our management uses.

22

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 7A.  Quantitative and Qualitative Disclosures About Market Risk for discussion of our forward contracts.

In the following table we set forth variations in our gross margins for the last two fiscal years 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.

($000)	2009 compared  to 2008			2008 compared to 2007
Increase (decrease) in regulated gross margins
Gas sales		404			1,349
On-system transportation		(343	)		203
Off-system transportation		(78	)		884
Other		39			52
Intersegment elimination (a)		592			(376	)
Total		614			2,112
Increase (decrease) in non-regulated gross margins
Gas sales		(2,145	)		1,065
Other		(93	)		114
Intersegment elimination (a)		(592	)		376
Total		(2,830	)		1,555
Increase (decrease) in consolidated gross margins		(2,216	)		3,667
Percentage increase (decrease) in regulated volumes
Gas sales		3			(5	)
On-system transportation		(15	)		(4	)
Off-system transportation		(6	)		29
Percentage increase (decrease) in non-regulated gas sales volumes		(22	)		10

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

23

Heating degree days were 101% of normal thirty year average temperatures for fiscal 2009, as compared with 96% and 95% of normal temperatures for 2008 and 2007, respectively. 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.

In 2009, consolidated gross margins decreased $2,216,000 (6%) due to decreased non-regulated gross margins of $2,830,000 (26%) offset by increased regulated gross margins of $614,000 (2%). Our non-regulated gross margins decreased due to a 22% decrease in volumes sold and lower sales prices. The non-regulated volumes sold decreased due to a decrease in our non-regulated customers’ gas requirements.  Our regulated gross margin for gas sales increased $404,000 (2%) due to a 3% increase in volumes sold due to colder weather than in the previous year.

In 2008, consolidated gross margins increased $3,667,000 (11%) due to increased regulated and non-regulated gross margins of $2,112,000 (9%) and $1,555,000 (16%), respectively. Our regulated gross margins increased due to increased base rates which became effective October 20, 2007 and a 29% increase in off-system volumes transported. Our non-regulated gross margin for gas sales increased due to a 10% increase in volumes sold.

Operations and Maintenance

In 2009, operations and maintenance expense increased $901,000 (6%).  The increase was primarily due to an inventory adjustment for our gas in storage ($1,350,000, as further discussed in Note 15 of the Notes to Consolidated Financial Statements) and increased uncollectible expense ($231,000).  These increases were partially offset by decreased storage maintenance expense ($479,000) and decreased accrued bonuses ($355,000).

In 2008, operations and maintenance expense increased $1,544,000 (12%).  The increase was primarily due to increased uncollectible expense ($326,000), increased storage maintenance expense ($307,000), increased labor expense ($274,000), increased transportation expense ($165,000) and increase maintenance of transmission and distribution mains ($133,000).

Depreciation and Amortization

In 2008, depreciation and amortization decreased $527,000 (11%) due to lower depreciation rates approved by the Kentucky Public Service Commission that became effective October 20, 2007.  The decrease was 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

In 2009, other income and deductions, net decreased $130,000 (155%).  The decreases were due to decreases in bank interest earned, decreases in the cash surrender value of officers’ life insurance as well as decreases in the fair value of the supplemental retirement trust.  The decreases in the fair value of the supplemental retirement trust were offset by reductions in operating expense resulting from corresponding deceases in the liability of the plan.

Other Interest

In 2009, other interest decreased $213,000 (30%) due to a decrease in the average interest rate on our bank line of credit.

In 2008, other interest increased $139,000 (25%) due to increased net borrowings on our bank line of credit.

Income Tax Expense

In 2009, income tax expense decreased $1,139,000 (27%) due to a decrease in net income before income taxes.

In 2008, income tax expense increased $990,000 (31%) due to an increase in net income before income taxes.

24

Basic and Diluted Earnings Per Common Share

For the fiscal years ended June 30, 2009 and 2008, 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 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 7A. 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 and gas sales contracts meet the definition of a derivative, we have designated these contracts as “normal purchases” and “normal sales” under Financial Accounting Standards Board Statement No. 133, entitled Accounting for Derivative 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 balance on our bank line of credit was $3,653,000 and $6,829,000 on June 30, 2009 and 2008, respectively. The weighted average interest rate on our bank line of credit was 1.8% and 3.2% as of June 30, 2009 and 2008, respectively. Based on the amount of our outstanding bank line of credit on June 30, 2009 and 2008, a 1% (one hundred basis points) increase in our average interest rate would result in a decrease in our annual pre-tax net income of $37,000 and $68,000, respectively.  Effective June 30, 2009 the bank line of credit was extended through June 30, 2011.  The extension increased the interest rate on the used bank line of credit from the London Interbank Offered Rate plus .75% to the London Interbank Offered Rate plus 1.5%.

25

Item 8.    Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE	PAGE
Report of Independent Registered Public Accounting Firm	33
Consolidated Statements of Income for the years ended June 30, 2009, 2008 and 2007	34
Consolidated Statements of Cash Flows for the years ended June 30, 2009, 2008 and 2007	35
Consolidated Balance Sheets as of June 30, 2009 and 2008	37
Consolidated Statements of Changes in Shareholders’ Equity for the years ended June 30, 2009, 2008 and 2007	39
Notes to Consolidated Financial Statements	40
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2009, 2008 and 2007	58

Schedules other than those listed above are omitted because they are not required, are not applicable or the required information is shown in the financial statements or notes thereto.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 (“Exchange Act”) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) 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 Rule 13a – 15(e) and 15d – 15(e)  under the Exchange Act) as of June 30, 2009 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.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

26

Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of June 30, 2009 based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that evaluation, management concluded that our internal control over financial reporting was effective as of June 30, 2009.

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 June 30, 2009 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting. That report immediately follows:

27

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:

We have audited the internal control over financial reporting of Delta Natural Gas Company, Inc. (the "Company") as of June 30, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Certification of the Chief Executive Officer and Certification of the Chief Financial Officer.  Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended June 30, 2009 of the Company and our report dated August 31, 2009 expressed an unqualified opinion on those financial statements and financial statement schedule, and included explanatory paragraphs regarding the adoption of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109 and Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.

/S/  DELOITTE & TOUCHE LLP

Cincinnati, Ohio

August 31, 2009

28

Item 9B. Other Information

None.

PART III

Item 10.   Directors, Executive Officers and Corporate Governance of the Registrant

We have a Business Code of Conduct and Ethics that applies to all directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. You can find our Business Code of Conduct and Ethics on our website by going to the following address:  http://www.deltagas.com.   We will post any amendments to the Business Code of Conduct and Ethics, as well as any waivers that are required to be disclosed by the rules of either the Securities and Exchange Commission or the NASDAQ OMX Group, on our website.

Our Board of Directors has adopted charters for the Audit, Corporate Governance and Compensation and Executive Committees of the Board of Directors. You can find these documents on our website by going to the following address:  http://www.deltagas.com and clicking on the appropriate link.

You can also obtain a printed copy of any of the materials referred to above by contacting us at the following address:

Delta Natural Gas Company, Inc.

Attn:  John B. Brown

3617 Lexington Road

Winchester, KY  40391

(859) 744-6171

The Audit Committee of our Board of Directors is an “audit committee” for purposes of Section 3(a)(58) of the Securities Exchange Act of 1934.

The other information required by this Item is incorporated herein by reference to the applicable information in the proxy statement for our 2009 annual meeting.

Item 11.  Executive Compensation

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.  Certain Relationships and Related Transactions, and Director Independence

Item 14.  Principal Accountant Fees and Services

Registrant intends to file a definitive proxy statement with the Commission pursuant to Regulation 14A (17 CFR 240.14a) no later than 120 days after the close of the fiscal year. In accordance with General Instruction G(3) to Form 10-K, the information called for by Items 10 (except for the language above in Item 10 in this report), 11, 12, 13 and 14 is incorporated herein by reference to the definitive proxy statement.

29

PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a)		Financial Statements, Schedules and Exhibits
	(1)	Financial Statements See Index at Item 8
	(2)	Financial Statement Schedules See Index at Item 8
	(3)	Exhibits
	Exhibit No.

3(i)	Registrant’s Amended and Restated Articles of Incorporation (dated November 16, 2006) are incorporated herein by reference to Exhibit 3(i) to Registrant’s Form 10-K (File No. 000-08788) for the period ended June 30, 2007.
3(ii)	Registrant’s Amended and Restated By-Laws (dated November 16, 2006) are incorporated herein by reference to Exhibit 3(ii) to Registrant’s Form 10-K (File No. 000-08788) for the period ended June 30, 2007.
4(a)	The Indenture dated March 1, 2006 in respect of 5.75% Insured Quarterly Notes due April 1, 2021, is incorporated herein by reference to Exhibit 4(d) to Delta’s Form S-3 (Reg. No. 333-132322) dated March 31, 2006.
4(b)	The Indenture dated January 1, 2003 in respect of 7% Debentures due February 1, 2023, is incorporated herein by reference to Exhibit 4(d) to Delta’s Form S-2 (Reg. 333-100852) dated October 30, 2002.
10(a)	Gas Sales Agreement, dated May 1, 2005, by and between the Registrant and Atmos Energy Marketing, LLC is incorporated herein by reference to Exhibit 10(c) to the Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2005.
10(b)	Gas Sales Agreement, dated May 1, 2003, by and between the Registrant and Atmos Energy Marketing, LLC is incorporated herein by reference to Exhibit 10(d) to the Registrant's Form 10-K (File No. 000-08788) for the period ended June 30, 2003.
10(c)	Base Contract for Short-Term Sale and Purchase of Natural Gas, dated January 1, 2002, by and between M & B Gas Services, Inc. and Registrant, is incorporated herein by reference to Exhibit 10(n) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(d)	Gas Transportation Agreement (Service Package 9069), dated December 19, 1994, by and between Tennessee Gas Pipeline Company and Registrant is incorporated herein by reference to Exhibit 10(e) to Registrant’s Form S-2 (Reg. No. 333-100852) dated February 7, 2003.
10(e)	Agreement to transport natural gas between Registrant and Nami Resources Company L.L.C. is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 8-K (File No. 000-08788) dated March 23, 2005.
10(f)	GTS Service Agreement (Service Agreement No. 37815), dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Registrant is incorporated herein by reference to Exhibit 10(f) to Registrant’s Form S-2 (Reg. No. 333-100852) dated February 7, 2003.
10(g)	FTS1 Service Agreement (Service Agreement No. 4328), dated October 4, 1994, by and between Columbia Gulf Transmission Company and Registrant is incorporated herein by reference to Exhibit 10(g) to Registrant’s Form S-2 (Reg. No. 333-100852) dated February 7, 2003.
10(h)	Gas Storage Lease, dated October 4, 1995, by and between Judy L. Fuson, Guardian of Jamie Nicole Fuson, a minor, and Lonnie D. Ferrin and Assignment and Assumption Agreement, dated November 10, 1995, by and between Lonnie D. Ferrin and Registrant is incorporated herein by reference to Exhibit 10(j) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(i)	Gas Storage Lease, dated November 6, 1995, by and between Thomas J. Carnes, individually and as Attorney-in-fact and Trustee for the individuals named therein, and Registrant, is incorporated herein by reference to Exhibit 10(k) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(j)	Deed and Perpetual Gas Storage Easement, dated December 21, 1995, by and between Katherine M. Cornelius, William Cornelius, Frances Carolyn Fitzpatrick, Isabelle Fitzpatrick Smith and Kenneth W. Smith and Registrant is incorporated herein by reference to Exhibit 10(l) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.

30

10(k)	Underground Gas Storage Lease and Agreement, dated March 9, 1994, by and between Equitable Resources Exploration, a division of Equitable Resources Energy Company, and Lonnie D. Ferrin and Amendment No. 1 and Novation to Underground Gas Storage Lease and Agreement, dated March 22, 1995, by and between Equitable Resources Exploration, Lonnie D. Ferrin and Registrant, is incorporated herein by reference to Exhibit 10(m) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(l)	Oil and Gas Lease, dated July 19, 1995, by and between Meredith J. Evans and Helen Evans and Paddock Oil and Gas, Inc.; Assignment, dated June 15, 1995, by Paddock Oil and Gas, Inc., as assignor, to Lonnie D. Ferrin, as assignee; Assignment, dated August 31, 1995, by Paddock Oil and Gas, Inc., as assignor, to Lonnie D. Ferrin, as assignee; and Assignment and Assumption Agreement, dated November 10, 1995, by and between Lonnie D. Ferrin and Registrant, is incorporated herein by reference to Exhibit 10(o) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(m)	Loan Agreement, dated October 31, 2002, by and between Branch Banking and Trust Company and Registrant is incorporated herein by reference to Exhibit 10(i) to Registrant’s Form S-2 (Reg. No. 333-100852) dated February 7, 2003.
10(n)	Promissory Note, in the original principal amount of $40,000,000, made by Registrant to the order of Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended September 30, 2002.
10(o)	Modification Agreement extending to October 31, 2004 the Promissory Note and Loan Agreement dated October 31, 2002 between the Registrant and Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to the Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2003.
10(p)	Modification Agreement extending to October 31, 2005 the Promissory Note and Loan Agreement dated October 31, 2002 between the Registrant and Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to the Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2004.
10(q)	Modification Agreement extending to October 31, 2007 the Promissory Note and Loan Agreement dated October 31, 2002 between the Registrant and Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to the Registrant's Form 8-K (File No. 000-08788) dated August 19, 2005.
10(r)	Modification Agreement extending to October 31, 2009 the Promissory Note and Loan Agreement dated October 31, 2002 between the Registrant and Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended September 30, 2007.
10(s)	Modification Agreement extending to June 30, 2011 the Promissory Note and Loan Agreement dated October 31, 2002 between the Registrant and Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to the Registrant's Form 8-K (File No. 000-08788) dated June 30, 2009.
10(t)	Employment agreements between Registrant and three officers, those being John B. Brown, Johnny L. Caudill, and Glenn R. Jennings, are incorporated herein by reference to Exhibit 10(k) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended March 31, 2000.
10(u)	Employment agreement between Registrant and Brian S. Ramsey is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated November 21, 2008.
10(v)	Supplemental retirement benefit agreement and trust agreement between Registrant and Glenn R. Jennings is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 8-K (File No. 000-08788) dated February 25, 2005.
12	Computation of the Consolidated Ratio of Earnings to Fixed Charges.
21	Subsidiaries of the Registrant.
23	Consent of Independent Registered Public Accounting Firm.
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.

31

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on the 31st day of August, 2009.

DELTA NATURAL GAS COMPANY, INC.
By:	/s/Glenn R. Jennings
Glenn R. Jennings
Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

(i)	Principal Executive Officer:
/s/Glenn R. Jennings		Chairman of the Board, President	August 31, 2009
(Glenn R. Jennings)		and Chief Executive Officer
(ii)	Principal Financial Officer and Principal Accounting Officer:
/s/John B. Brown		Chief Financial Officer,	August 31, 2009
(John B. Brown)		Treasurer and Secretary
(iii)	A Majority of the Board of Directors:
/s/Linda K. Breathitt		Director	August 31, 2009
(Linda K. Breathitt)
/s/Lanny D. Greer		Director	August 31, 2009
(Lanny D. Greer)
/s/Billy Joe Hall		Director	August 31, 2009
(Billy Joe Hall)
/s/Michael J. Kistner		Director	August 31, 2009
(Michael J. Kistner)
/s/Lewis N. Melton		Director	August 31, 2009
(Lewis N. Melton)
/s/Arthur E. Walker, Jr.		Director	August 31, 2009
(Arthur E. Walker, Jr.)
/s/Michael R. Whitley		Director	August 31, 2009
(Michael R. Whitley)

32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:

We have audited the accompanying consolidated balance sheets of Delta Natural Gas Company, Inc. (the "Company") as of June 30, 2009 and 2008, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended June 30, 2009.  Our audits also included the financial statement schedule listed in the Index at Item 8.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at June 30, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2009, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, on July 1, 2007 the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.

As discussed in Note 2 to the consolidated financial statements, on July 1, 2008 the Company adopted the measurement date provision of Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of June 30, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated August 31, 2009 expressed an unqualified opinion on the Company's internal control over financial reporting.

/S/  DELOITTE & TOUCHE LLP

Cincinnati, Ohio

August 31, 2009

33

Delta Natural Gas Company, Inc.
Consolidated Statements of Income
For the Years Ended June 30,	2009			2008		2007
Operating Revenues	$	105,636,824		$	112,657,117	$	98,168,391
Operating Expenses
Purchased gas	$	72,077,631		$	76,882,387	$	66,060,368
Operation and maintenance		15,030,287			14,128,620		12,584,607
Depreciation and amortization		3,855,099			4,171,145		4,697,639
Taxes other than income taxes		1,880,607			1,811,229		1,857,734
Total operating expenses	$	92,843,624		$	96,993,381	$	85,200,348
Operating Income	$	12,793,200		$	15,663,736	$	12,968,043
Other Income and Deductions, Net	$	(46,418	)	$	83,521	$	134,265
Interest Charges
Interest on long-term debt	$	3,648,243		$	3,677,983	$	3,694,389
Other interest		492,151			705,240		565,790
Amortization of debt expense		387,263			387,266		387,082
Total interest charges	$	4,527,657		$	4,770,489	$	4,647,261
Income Before Income Taxes	$	8,219,125		$	10,976,768	$	8,455,047
Income Tax Expense	$	3,008,396		$	4,146,900	$	3,156,700
Net Income	$	5,210,729		$	6,829,868	$	5,298,347
Basic and Diluted Earnings Per Common Share	$	1.58		$	2.08	$	1.62
Weighted Average Number of Common Shares Outstanding (Basic and Diluted)		3,306,026			3,285,464		3,265,800
Dividends Declared Per Common Share	$	1.28		$	1.24	$	1.22

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

34

Delta Natural Gas Company, Inc.
Consolidated Statements of Cash Flows
For the Years Ended June 30,	2009			2008			2007
Cash Flows From Operating Activities
Net income	$	5,210,729		$	6,829,868		$	5,298,347
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		4,362,241			4,660,410			5,157,922
Provision for inventory adjustment		1,350,300			—			—
Deferred income taxes and investment tax credits		2,135,347			2,095,000			2,345,300
Gain on sale of property, plant and equipment		(156,023	)		(16,955	)		—
Change in cash surrender value of officer's life insurance		31,651			(18,704	)		(24,577	)
Other, net		(423,672	)		(219,041	)		(205,827	)
(Increase) decrease in assets
Accounts receivable		7,334,709			(5,016,055	)		1,746,732
Gas in storage		3,379,325			(2,634,602	)		(475,801	)
Deferred gas cost		2,255,751			(1,670,877	)		(1,116,773	)
Materials and supplies		(93,516	)		(38,568	)		(87,859	)
Prepayments		(2,173,506	)		(129,153	)		(897,682	)
Other assets		(77,411	)		(56,686	)		(173,310	)
Increase (decrease) in liabilities
Accounts payable		(7,418,187	)		1,920,832			3,835,813
Accrued taxes		(773,761	)		890,309			(1,061,563	)
Other current liabilities		486,664			(889	)		148,901
Other liabilities		3,279			(2,358	)		(3,717	)
Net cash provided by operating activities	$	15,433,920		$	6,592,531		$	14,485,906
Cash Flows From Investing Activities
Capital expenditures	$	(8,422,433	)	$	(5,563,667	)	$	(8,082,918	)
Proceeds from sale of property, plant and equipment		526,763			297,425			146,810
Other		(60,000	)		—			—
Net cash used in investing activities	$	(7,955,670	)	$	(5,266,242	)	$	(7,936,108	)

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

35

Delta Natural Gas Company, Inc.
Consolidated Statements of Cash Flows (continued)
For the Years Ended June 30,	2009			2008			2007
Cash Flows From Financing Activities
Dividends on common stock	$	(4,231,239	)	$	(4,073,278	)	$	(3,983,909	)
Issuance of common stock		520,407			477,155			504,309
Long-term debt issuance expense		—			—			(10,970	)
Repayment of long-term debt		(719,000	)		(307,000	)		(165,000	)
Borrowings on bank line of credit		74,107,057			64,602,956			51,518,605
Repayment of bank line of credit		(77,282,745	)		(61,964,083	)		(54,375,121	)
Net cash used in financing activities	$	(7,605,520	)	$	(1,264,250	)	$	(6,512,086	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(127,270	)	$	62,039		$	37,712
Cash and Cash Equivalents,  Beginning of Year		249,859			187,820			150,108
Cash and Cash Equivalents,  End of Year	$	122,589		$	249,859		$	187,820
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for
Interest	$	4,148,311		$	4,383,367		$	4,232,155
Income taxes (net of refunds)		1,630,937			1,376,093			1,763,518

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

36

Delta Natural Gas Company, Inc.
Consolidated Balance Sheets
As of June 30,	2009			2008
Assets
Current Assets
Cash and cash equivalents	$	122,589		$	249,859
Accounts receivable, less accumulated allowances for doubtful accounts of $819,000 and $465,000 in 2009 and 2008, respectively		4,085,867			11,437,219
Gas in storage, at average cost (Note 15)		9,746,768			14,476,393
Deferred gas costs (Notes 1 and 13)		2,356,943			4,612,752
Materials and supplies, at average cost		662,805			565,333
Prepayments		2,415,527			2,683,854
Total current assets	$	19,390,499		$	34,025,410
Property, Plant and Equipment	$	199,254,216		$	192,127,184
Less – Accumulated provision for depreciation		(70,616,271	)		(67,754,068	)
Net property, plant and equipment	$	128,637,945		$	124,373,116
Other Assets
Cash surrender value of officers' life insurance (face amount of $1,158,091)	$	412,661		$	444,312
Prepaid pension cost (Note 5)		—			1,423,932
Regulatory assets (Note 1)		11,394,844			7,713,358
Unamortized debt expense and other (Notes 1 and 9)		2,669,346			2,834,728
Total other assets	$	14,476,851		$	12,416,330
Total assets	$	162,505,295		$	170,814,856

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

37

Delta Natural Gas Company, Inc.
Consolidated Balance Sheets (continued)
As of June 30,	2009		2008
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable	$	4,691,152	$	12,154,432
Notes payable (Note 8)		3,653,103		6,828,791
Current portion of long-term debt (Notes 9 and 10)		1,200,000		1,200,000
Accrued taxes		983,376		1,656,391
Customers’ deposits		508,209		505,058
Accrued interest on debt		857,810		865,727
Accrued vacation		712,216		720,625
Deferred income taxes		814,549		1,483,700
Other liabilities		487,925		418,239
Total current liabilities	$	13,908,340	$	25,832,963
Long-term Debt (Notes 9 and 10)	$	57,599,000	$	58,318,000
Long-term Liabilities
Deferred income taxes	$	27,537,908	$	24,576,000
Investment tax credits		144,500		177,800
Regulatory liabilities (Note 1)		1,710,099		2,144,951
Accrued pension		430,095		—
Asset retirement obligations and other (Note 3)		2,176,171		2,171,557
Total long-term liabilities	$	31,998,773	$	29,070,308
Commitments and Contingencies (Note 12)
Total liabilities	$	103,506,113	$	113,221,271
Shareholders’ Equity
Common shares ($1.00 par value), 20,000,000 shares authorized; 3,318,046 and 3,295,759 shares outstanding at June 30, 2009 and June 30, 2008, respectively	$	3,318,046	$	3,295,759
Premium on common shares		44,465,601		43,967,481
Retained earnings		11,215,535		10,330,345
Total shareholders’ equity	$	58,999,182	$	57,593,585
Total liabilities and shareholders’ equity	$	162,505,295	$	170,814,856

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

38

Delta Natural Gas Company, Inc.
Consolidated Statements of Changes in Shareholders’ Equity
For the Years Ended June 30,	2009			2008			2007
Common Shares
Balance, beginning of year	$	3,295,759		$	3,277,106		$	3,256,043
Issuance of common stock $1.00 par value of 22,287, 18,653, and  21,063 shares issued in 2009, 2008 and 2007, respectively		22,287			18,653			21,063
Balance, end of year	$	3,318,046		$	3,295,759		$	3,277,106
Premium on Common Shares
Balance, beginning of year	$	43,967,481		$	43,508,979		$	43,025,733
Issuance of common stock		498,120			458,502			483,246
Balance, end of year	$	44,465,601		$	43,967,481		$	43,508,979
Retained Earnings
Balance, beginning of year	$	10,330,345		$	7,642,386		$	6,327,948
Adoption of FASB Interpretation No. 48		—			(68,631	)		—
Adoption of FASB Statement No. 158 (net of $57,699 of tax)		(94,300	)		—			—
Balance, beginning of year, as adjusted	$	10,236,045		$	7,573,755		$	6,327,948
Net income		5,210,729			6,829,868			5,298,347
Cash dividends declared on common shares (See Consolidated Statements of Income for rates)		(4,231,239	)		(4,073,278	)		(3,983,909	)
Balance, end of year	$	11,215,535		$	10,330,345		$	7,642,386
Common Shareholders’ Equity
Balance, beginning of year	$	57,593,585		$	54,428,471		$	52,609,724
Adoption of FASB Interpretation No. 48		—			(68,631	)		—
Adoption of FASB Statement No. 158 (net of $57,699 of tax)		(94,300	)		—			—
Balance, beginning of year, as adjusted	$	57,499,285		$	54,359,840		$	52,609,724
Net income		5,210,729			6,829,868			5,298,347
Issuance of common shares		520,407			477,155			504,309
Dividends on common shares		(4,231,239	)		(4,073,278	)		(3,983,909	)
Balance, end of year	$	58,999,182		$	57,593,585		$	54,428,471

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

39

DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  Summary of Significant Accounting Policies

(a) Principles of Consolidation  Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 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.  In the preparation of the Consolidated Financial Statements, we evaluated subsequent events after the balance sheet date of June 30, 2009 through August 31, 2009, the filing date of this Form 10-K.

(b) Cash Equivalents   For the purposes of the Consolidated Statements of Cash Flows, all temporary cash investments with a maturity of three months or less at the date of purchase are considered cash equivalents.

(c) Property, Plant and Equipment   Property, plant and equipment is stated at original cost, which includes materials, labor, labor related costs and an allocation of general and administrative costs.  Construction work in progress has been included in the rate base for determining customer rates, and therefore an allowance for funds used during construction has not been recorded.  The cost of regulated plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense, less salvage value, is charged to the accumulated provision for depreciation.

(d) Depreciation  We determine the provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant.  The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of 2.1%, 2.3%, and 2.7% of average depreciable plant for 2009, 2008 and 2007, respectively.  Effective October 20, 2007 we implemented new depreciation rates allowed by the Kentucky Public Service Commission in our 2007 rate case which increased the remaining depreciable lives of our depreciable assets.

(e) Maintenance   All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts in the month incurred.  A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant.  At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired.

(f) Gas Cost Recovery    We have a Gas Cost Recovery (“GCR”) clause which provides for a dollar-tracker that matches revenues and gas costs and provides eventual dollar-for-dollar recovery of all gas costs incurred by the regulated segment and approved by the Kentucky Public Service Commission.  We expense gas costs based on the amount of gas costs recovered through revenue.  Any differences between actual gas costs and those estimated costs billed are deferred and reflected in the computation of future billings to customers using the GCR mechanism.

40

(g) Revenue Recognition    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:

(000)	2009		2008
Unbilled revenues ($)		1,386		1,579
Unbilled gas costs ($)		519		736
Unbilled volumes (Mcf)		55		51

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

(h)  Excise Taxes    Certain excise taxes levied by state or local governments are collected by Delta from our customers.  These taxes are accounted for on a net basis and therefore are not included as revenues in the accompanying Consolidated Statements of Income.

(i) Revenues and Customer Receivables    We serve 37,000 customers in central and southeastern Kentucky. Revenues and customer receivables arise primarily from sales of natural gas to customers and from transportation services for others.  Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable. Customer accounts are charged off when deemed to be uncollectible or when turned over to a collection agency to pursue.

(j) Use of Estimates   The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(k) Rate Regulated Basis of Accounting     Our regulated operations follow the accounting and reporting requirements of Financial Accounting Standards Board Statement No. 71, entitled Accounting for the Effects of Certain Types of Regulation.  The economic effects of regulation can result in a regulated company recovering costs from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise.  When this results, costs are deferred as assets on the Consolidated Balance Sheets (regulatory assets) and recorded as expenses when such amounts are reflected in rates.  Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).  The amounts recorded as regulatory assets and regulatory liabilities are as follows:

41

($000)	2009		2008
Regulatory assets
Current assets
Deferred gas costs		2,357		4,613
Other assets
Conservation/efficiency program expenses		109		—
Loss on extinguishment of debt		2,348		2,539
Asset retirement obligations		1,464		1,352
Accrued pension		7,309		3,538
Regulatory case expenses		165		285
Total other assets		11,395		7,714
Total regulatory assets		13,752		12,327
Regulatory liabilities
Accrued cost of removal on long-lived assets		304		615
Regulatory liability for deferred income taxes		1,406		1,530
Total regulatory liabilities		1,710		2,145

Deferred gas costs are presented every three months to the Kentucky Public Service Commission for recovery in accordance with the gas cost recovery rate mechanism.  Amounts recoverable under our conservation and efficiency program are presented annually to the Kentucky Public Service Commission for recovery in accordance with the conservation/efficiency program cost recovery rate mechanism.  We are currently earning a return on loss on extinguishment of debt. Asset retirement costs are recovered through customer rates as they are included in our depreciation rates.  Pension expenses and regulatory case expenses are recovered through customer rates as allowed operating expenses.

(l) Impairment of Long-Lived Assets   We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets.  If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for an impairment loss if the carrying value is greater than the fair value.  In the opinion of management, our long-lived assets are appropriately valued in the accompanying consolidated financial statements.

(m)  Derivatives  We purchase and sell natural gas. Certain of our gas purchase and sale contracts qualify as a derivative under Financial Accounting Standards Board Statement No. 133, entitled Accounting for Derivative Instruments and Hedging Activities.  All such contracts have been designated as normal purchases and sales and as such are accounted for under the accrual basis and are not recorded at fair value in the accompanying consolidated financial statements.

(n)  Marketable Securities  We have a supplemental retirement benefit agreement with Glenn R. Jennings, our Chairman of the Board, President and Chief Executive Officer which is a non-qualified deferred compensation plan.  The agreement establishes an irrevocable rabbi trust, in which the assets of the trust are earmarked to pay benefits under the agreement.  We have recognized a liability related to the obligation to pay these benefits to Mr. Jennings.  We make discretionary contributions to the trust which increases both the trust assets and the deferred compensation liability.

42

The assets of the trust consist of exchange traded mutual funds and are classified as trading securities under Financial Accounting Standards Board Statement No. 115, entitled Accounting for Certain Investments in Debt and Equity Securities.  The assets are recorded at fair value on the Consolidated Balance Sheets based on observable market prices from active markets.  Net realized and unrealized gains and losses are included in earnings each period to effectively offset the corresponding earnings impact associated with the change in the fair value of the deferred compensation liability to which the assets relate.

(2)  New Accounting Pronouncements

Recently Adopted Pronouncements

In July, 2006, the FASB issued Interpretation No. 48, entitled Accounting for Uncertainty in Income Taxes, to clarify the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Financial Accounting Standards Board Statement No. 109, entitled Accounting for Income Taxes.  Interpretation No. 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements.  Under Interpretation No. 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.  We adopted the provisions of Interpretation No. 48 on July 1, 2007.  The adoption of Interpretation No. 48 resulted in an adjustment to beginning retained earnings of $69,000.  At adoption, the total amount of gross unrecognized tax benefits for uncertain tax positions, including positions impacting only the timing of tax benefits, was $668,000, of which $97,000 related to interest.  Note 4 of the Notes to Consolidated Financial Statements further discusses our income taxes.

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 were $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 expense 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.

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.

43

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.

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.

As of June 30, 2009, our financial assets and liabilities that are measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust.  As of June 30, 2009, the assets of the trust were $281,000 and are included in unamortized debt expense and other on the Consolidated Balance Sheets.  The offsetting liability is included in asset retirement obligations and other on the Consolidated Balance Sheets.  Contributions to the trust are presented in other investing activities on the 2009 Consolidated Statement of Cash Flows.  The liability is not considered a financial liability within the scope of Statement No. 157.  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 Statement No. 157 hierarchy.

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.  Effective March 31, 2009, we adopted the provisions of Statement No. 161.  To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk.  We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases.  We mitigate price risk by 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” under Statement No. 133.

In April, 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. FAS 157-4, entitled Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.  The staff position provides additional guidance for estimating fair value in accordance with Statement No. 157 when the volume and level of activity for the asset or liability have significantly decreased.  The staff position, which is effective for our fiscal year ending June 30, 2009, did not have an impact on our results of operations or financial position.

In April, 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. FAS 115-2 and FAS 124-2, entitled Recognition and Presentation of Other-Than-Temporary Impairments.  The staff position provides additional guidance for the presentation and disclosure of other-than-temporary impairments on debt and equity securities.  The staff position, which is effective for our fiscal year ending June 30, 2009, did not have an impact on our results of operations or financial position.

44

In May, 2009, the Financial Accounting Standards Board issued Statement No. 165, entitled Subsequent Events.  Statement No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued.  Statement No. 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for the date.  We adopted Statement No. 165 as of June 30, 2009, and as a result of adoption there was no impact on our results of operations or financial position.

Recently Issued Pronouncements

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.  This staff position, which shall be effective for our quarter ending September 30, 2009, will not have a material impact on our results of operations or financial position.

In December, 2008, The Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. FAS 132(R)-1, entitled Employer’s Disclosures about Postretirement Benefit Plan Assets, which amends Financial Accounting Standards Board Statement 132(R), entitled Employers’ Disclosures about Pensions and Other Postretirement Benefits, to increase transparency surrounding the types of assets and risks associated with 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.

In April, 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. FAS 107-1 and APB 28-1, entitled Interim Disclosures about Fair Value of Financial Instruments. The staff position amends Financial Accounting Standards Board Statement No. 107, Disclosures about Fair Value of Financial Instruments and Accounting Principles Board Opinion No. 28, entitled Interim Financial Reporting, to require disclosure about the fair value of financial instruments at interim reporting periods.  The staff position, which shall be effective for our quarter ending September 30, 2009, will not have an impact on our results of operations or financial position.

(3)   Asset Retirement Obligations

Legal obligations

As required by Financial Accounting Standards Board Statement No. 143, entitled Accounting for Asset Retirement Obligations, and Financial Accounting Standards Interpretation No. 47, entitled Accounting for Conditional Asset Retirement Obligations, as of June 30, 2009 and 2008 we have accrued liabilities and related assets, net of accumulated depreciation, relative to the legal obligation to retire certain gas wells, storage tanks, mains and services.  For asset retirement obligations related to regulated assets, accretion of the liability and depreciation of the asset retirement costs are recorded as regulatory assets, pursuant to Statement No. 71, as we recover the cost of removing our regulated assets through our depreciation rates.

45

The following is a summary of our asset retirement obligations and related assets (net of accumulated depreciation), reflected on the accompanying Consolidated Balance Sheets under the captions asset retirement obligations and other, and property, plant and equipment, respectively:

	Asset Retirement			Net
($000)	Obligations			Assets
As of June 30, 2007		1,466			32
Accretion		111			—
Depreciation		—			(2	)
Change in obligations		23			23
As of June 30, 2008		1,600			53
Accretion		120			—
Depreciation		—			(18	)
Change in obligations		(50	)		(29	)
As of June 30, 2009		1,670			6

We have an additional asset retirement obligation relative to the retirement of wells located at our underground natural gas storage facility.  Since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the underlying asset has an indeterminate life.  Therefore, we have not recorded a liability associated with the cost to retire the asset, pursuant to Interpretation No. 47.

Non-legal obligations

In accordance with established regulatory practices, we accrue costs of removal on long-lived assets through depreciation expense if we believe removal of the assets at the end of their useful life is likely even though such costs do not represent legal obligations under Statement No. 143. In accordance with the provisions of Statement No. 71, we have recorded approximately $304,000 and $615,000 of such accrued cost of removal as regulatory liabilities on the accompanying Consolidated Balance Sheets as of June 30, 2009 and 2008, respectively.

(4)   Income Taxes

We provide for income taxes on temporary differences resulting from the use of alternative methods of income and expense recognition for financial and tax reporting purposes.  The differences result primarily from the use of accelerated tax depreciation methods for certain properties versus the straight-line depreciation method for financial reporting purposes, differences in recognition of purchased gas costs and certain accruals which are not currently deductible for income tax purposes.  Investment tax credits were deferred for certain periods prior to fiscal 1987 and are being amortized to income over the estimated useful lives of the applicable properties.  We utilize the asset and liability method for accounting for income taxes, which requires that deferred income tax assets and liabilities be computed using tax rates that will be in effect when the book and tax temporary differences reverse. Changes in tax rates applied to accumulated deferred income taxes are not immediately recognized in operating results because of ratemaking treatment.  A regulatory liability has been established to recognize the regulatory obligation to refund these excess deferred taxes through customer rates.  The current portion of the net accumulated deferred income tax liability is shown as current liabilities and the long-term portion is included in deferred credits and other on the accompanying Consolidated Balance Sheets.  The temporary differences which gave rise to the net accumulated deferred income tax liability for the periods are as follows:

46

($000)	2009		2008
Deferred Tax Liabilities
Accelerated depreciation		25,650		23,251
Deferred gas costs		895		1,751
Pension		—		515
Regulatory assets – loss on extinguishment of debt		891		964
Regulatory assets – asset retirement obligations		556		513
Regulatory assets – unrecognized accrued  pension		2,775		1,343
Other		424		445
Total		31,191		28,782
Deferred Tax Assets
Alternative minimum tax credits		—		172
Regulatory liabilities		649		815
Investment tax credits		55		68
Reserve for bad debt		311		177
Asset retirement obligations		572		545
Accrued personal leave		221		227
Section 263(a) capitalized costs		64		113
Pension		543		—
Other		424		605
Total		2,839		2,722
Net accumulated deferred income tax liability		28,352		26,060

The components of the income tax provision are comprised of the following for the years ended June 30:

($000)	2009		2008		2007
Components of Income Tax Expense
Current
Federal		560		1,158		494
State		255		395		213
Total		815		1,553		707
Deferred		2,193		2,594		2,450
Income tax expense		3,008		4,147		3,157

47

Reconciliation of the statutory federal income tax rate to the effective income tax rate is shown in the table below: 

	2009			2008			2007
Statutory federal income tax rate		34.0	%		34.0	%		34.0	%
State income taxes, net of federal benefit		4.0			4.0			4.6
Amortization of investment tax credits		(0.4	)		(0.3	)		(0.5	)
Other differences, net		(1.0	)		—			(0.8	)
Effective income tax rate		36.6	%		37.7	%		37.3	%

In July, 2006, the Financial Accounting Standards Board issued Interpretation No. 48, to clarify the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement No. 109.  Interpretation No. 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements.  Under Interpretation No. 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.

The liability for unrecognized tax benefits expected to be recognized within the next twelve months has partially offset our prepaid income taxes and been presented in prepayments on the Consolidated Balance Sheets.  The liability for unrecognized tax benefits not expected to be recognized within the next twelve months has been presented in asset retirement obligations and other on the Consolidated Balance Sheets.  Interest and penalties on tax uncertainties are classified in income tax expense in the Consolidated Statements of Income.

The amount of unrecognized tax benefits, net of tax, which, if recognized, would impact the effective tax rate was $149,000.  We accrued interest of $60,000 on unrecognized tax positions, of which $14,000 and $18,000 was recognized in the 2009 and 2008 Consolidated Statements of Income, respectively.

In fiscal 2008, we filed a method change with the Internal Revenue Service related to the timing of deducting certain expenses.  During fiscal 2009 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.  It is reasonably possible that there will be additional changes to the unrecognized tax benefits within the next twelve months.  However, it is not expected that such change will have a significant impact on our results of operations or financial position.

The following is a tabular reconciliation of our unrecognized tax benefits:

($000)	2009			2008
Beginning Balance		653			668
Gross increases
Tax positions in prior period		—			1
Tax positions in current period		—			102
Gross decreases
Tax positions in prior period		(229	)		(102	)
Lapse of statute of limitations		(46	)		(16	)
Ending Balance		378			653

We file income tax returns in the federal and Kentucky jurisdictions.  Tax years previous to June 30, 2006 and June 30, 2005 are no longer subject to examination for federal and Kentucky income taxes, respectively.

48

(5)  Employee Benefit Plans

(a)   Defined Benefit Retirement Plan   We have a trusteed, noncontributory, defined benefit pension plan covering all eligible employees hired prior to May 9, 2008.  Retirement income is based on the number of years of service and annual rates of compensation.  The Company historically makes annual contributions equal to the amounts necessary to fund the plan adequately.  Due to the conditions in the debt and equity markets, we experienced a decline in the value of the assets held by our defined benefit pension plan and thus we contributed $2,677,000 to the plan in fiscal 2009.

Statement No. 158 requires employers who sponsor defined benefit plans to recognize the funded status of a defined benefit pension plan on the statement of financial position and to recognize through comprehensive income the changes in the funded status in the year in which the changes occur. Statement No. 71 provides that regulated entities can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current rate recovery in Kentucky is based on Financial Accounting Standards Board Statement No. 87, entitled Employers’ Accounting for Pensions, which was amended by Statement No. 158.  The Kentucky Public Service Commission has been clear and consistent with its historical treatment of such rate recovery; therefore, we have recorded a regulatory asset representing the probable recovery of the portion of the change in funded status of the defined benefit plan that is expected to be recovered through future rates. The regulatory asset is adjusted annually as prior service cost and actuarial losses are recognized in net periodic benefit cost.

Our obligations and the funded status of our plan, measured at June 30, 2009 and March 31, 2008, respectively, are as follows:

($000)	2009			2008
Change in Benefit Obligation
Benefit obligation at beginning of year		12,773			13,277
Service cost		677			749
Interest cost		810			746
Actuarial (gain) loss		328			(894	)
Amendments		—			(3	)
Benefits paid		(902	)		(1,102	)
Change in measurement date		373			—
Benefit obligation at end of year		14,059			12,773
Change in Plan Assets
Fair value of plan assets at beginning of year		14,197			14,229
Actual return on plan assets		(2,343	)		325
Employer contributions		2,677			745
Benefits paid		(902	)		(1,102	)
Fair value of plan assets at end of year		13,629			14,197
Recognized Amounts
Projected benefit obligation		(14,059	)		(12,773	)
Plan assets at fair value		13,629			14,197
Funded status		(430	)		1,424

49

	2009			2008
Net amount recognized as prepaid (accrued) benefit costs on the Consolidated Balance Sheets		(430	)		1,424
Items Not Yet Recognized as a Component of Net Periodic Benefit Costs
Prior service cost		(749	)		(857	)
Net loss		8,058			4,395
Amounts recognized as regulatory assets		7,309			3,538

The accumulated benefit obligation was $12,682,000 and $11,679,000 for 2009 and 2008, respectively.

($000)	2009			2008			2007
Components of Net Periodic Benefit Cost
Service cost		677			749			715
Interest cost		810			745			700
Expected return on plan assets		(1,010	)		(988	)		(995	)
Amortization of unrecognized net loss		217			250			233
Amortization of prior service cost		(86	)		(86	)		(86	)
Net periodic benefit cost		608			670			567
Weighted-Average % Assumptions Used to Determine Benefit Obligations
Discount rate		6.25			6.50			5.80
Rate of compensation increase		4.0			4.0			4.0
Weighted-Average % Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate		6.50			5.80			5.80
Expected long-term return on plan assets		7.0			7.0			8.0
Rate of compensation increase		4.0			4.0			4.0

Our expected long-term rate of return on pension plan assets is based on our targeted asset allocation assumption of approximately 65% equity investments and approximately 35% fixed income investments and the market-related value of plan assets.  The market-related value of plan assets is based upon the fair value of the plan assets.

Plan Assets

Our pension plan weighted-average asset allocations as of June 30, 2009 and March 31, 2008, the plan’s measurement date, by asset category are  as follows:

	2009			2008
Equity securities		73	%		63	%
Fixed income securities		22			30
Other		5			7
		100	%		100	%

50

Our equity investment target of approximately 65% includes allocations to domestic, international and emerging markets.  Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective.  We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

We expect to contribute $500,000 to the pension plan in 2010.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

($000)
2010	781
2011	510
2012	980
2013	1,578
2014	886
2015 – 2019	6,947

Effective May 9, 2008, any employees hired on and after that date were not eligible to participate in our defined benefit pension plan.  Freezing the defined benefit plan for new entrants did not impact the level of benefits for existing participants.

The Statement of Financial Accounting Standards No. 106, entitled Employers’ Accounting for Postretirement Benefits, and the Statement of Financial Accounting Standards No. 112, entitled Employers’ Accounting for Postemployment Benefits, do not affect us as we do not provide postretirement or postemployment benefits other than the pension plan for retired employees.

(b)  Employee Savings Plan   We have an Employee Savings Plan (“Savings Plan”) under which eligible employees may elect to contribute a portion of their annual compensation up to the maximum amount permitted by law. The Company matches 100% of the employee’s contribution up to a maximum company contribution of 4% of the employee’s annual compensation.  The maximum matching contribution was 3.5% prior to July 1, 2008.  Employees hired after May 9, 2008, who are not eligible to participate in the defined benefit pension plan,  annually receive a 4% non-elective contribution into their Savings Plan account beginning July 1, 2008.  This contribution is discretionary and subject to change with approval from our Board of Directors.  For 2009, 2008, and 2007, Delta’s Savings Plan expense was $308,000, $281,000 and $256,000, respectively.

(c)  Supplemental Retirement Agreement   We sponsor a nonqualified defined contribution supplemental retirement agreement for Glenn R. Jennings, Delta’s Chairman of the Board, President and Chief Executive Officer. Delta contributes $60,000 annually into an irrevocable trust until Mr. Jennings’ retirement. At retirement, the trustee will make annual payments of $100,000 to Mr. Jennings until the trust is depleted. As of June 30, 2009 and 2008, the irrevocable trust assets are $281,000 and $250,000, respectively. These amounts are included in unamortized debt expense and other on the accompanying Consolidated Balance Sheets. Liabilities, in corresponding amounts, are included in asset retirement obligations and other on the accompanying Consolidated Balance Sheets.

(6)  Dividend Reinvestment and Stock Purchase Plan

Our Dividend Reinvestment and Stock Purchase Plan (“Reinvestment Plan”) provides that shareholders of record can reinvest dividends and also make limited additional investments of up to $50,000 per year in shares of common stock of the Company.  Under the Reinvestment Plan we issued 22,287, 18,653, and 21,063 shares in 2009, 2008 and 2007, respectively.  We registered 200,000 shares for issuance under the Reinvestment Plan in 2006, and as of June 30, 2009 there were 133,811 shares available for issuance.

51

(7)  Note Receivable From Officer Related Party Transaction

Reflected in our 2007 Consolidated Statements of Income is $62,000 of compensation related to the forgiveness of principal on a $160,000 loan made to Glenn R. Jennings, our Chairman of the Board, President and Chief Executive Officer.  We forgave $2,000 of the principal amount for each month of service Mr. Jennings completed through June 30, 2007.  Mr. Jennings made monthly interest payments on the note based on an annual interest rate of 6%. We forgave the remaining balance of the note effective June 30, 2007.

(8)  Notes Payable

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 $3,653,000 and $6,829,000 were borrowed having a weighted average interest rate of 1.8% and 3.21% as of June 30, 2009 and 2008, respectively. The maximum amount borrowed during 2009 and 2008 was $31,325,000 and $26,858,000, respectively.  Effective June 30, 2009 the bank line of credit was extended through June 30, 2011.  The extension increased the interest rate on the used line of credit from the London Interbank Offered Rate plus .75% to the London Interbank Offered Rate plus 1.5%.  The annual cost of the unused bank line of credit is .125%.

(9)  Long-Term Debt

In April, 2006, we issued $40,000,000 of 5.75% Insured Quarterly Notes that mature in April, 2021, of which $39,140,000 and $39,642,000 was outstanding as of June 30, 2009 and 2008, respectively.  Redemption of up to $25,000 annually will be made on behalf of deceased holders, up to an aggregate of $800,000 annually for all deceased beneficial owners. The 5.75% Insured Quarterly Notes can be redeemed by us with no premium.  In the event of default on the Insured Quarterly Notes, the holders are insured for both principal and interest payments.  The insurer would continue to pay interest and principal through the maturity of the Insured Quarterly Notes.

In February, 2003 we issued $20,000,000 of 7.00% Debentures that mature in February, 2023, of which $19,659,000 and $19,876,000 was outstanding as of June 30, 2009 and 2008, respectively.  Redemption of up to $25,000 annually will be made on behalf of individual deceased holders, up to an aggregate of $400,000 annually for all deceased beneficial owners.  There is no premium to redeem the Debentures.

We amortize debt issuance expenses over the life of the related debt on a straight-line basis, which approximates the effective yield method.  At June 30, 2009 and 2008, the unamortized balance was $4,736,000 and $5,123,000, respectively. Loss on extinguishment of debt of $2,348,000 and $2,539,000 included in the above has been deferred and is being amortized over the term of the related debt consistent with regulatory treatment.

The current portion of long-term debt of $1,200,000 represents the maximum aggregate principal amounts which can be paid to deceased beneficial owners. Therefore, the maximum maturities over the next five years are $1,200,000 each year. The Insured Quarterly Notes and Debentures do not have any sinking fund requirements.

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.

52

(10)  Fair Values of Financial Instruments

The fair value of our long-term debt is estimated using discounted cash flow analysis, based on our current incremental borrowing rates for similar types of borrowing arrangements.  The fair value of our long-term debt at June 30, 2009 and 2008 was estimated to be $52,633,000 and $55,164,000, respectively.  The carrying amounts on the accompanying Consolidated Balance Sheets as of June 30, 2009 and 2008 are $58,799,000 and $59,518,000, respectively.

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

(11)  Operating Leases

We have no non-cancellable operating leases. Our operating leases relate primarily to well and compressor station site leases and are cancellable at our option. Rental expense under operating leases was $78,000 for each of the three years ending June 30, 2009, 2008 and 2007.

(12)  Commitments and Contingencies

We have entered into forward purchase agreements beginning in July, 2009 and expiring at various dates through October, 2011.  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 customer's gas requirements.  These agreements have aggregate minimum purchase obligations of $3,765,000 and $143,000 for our fiscal years ended June 30, 2010 and 2011, respectively.

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 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 $2.9 million would be paid in addition to continuation of specified benefits for up to five years.

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

(13)  Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services.  The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services.

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 shareholders’ equity.  The increase in rates was allocated primarily to the monthly customer charge, and therefore the increase in revenue occurred more evenly throughout the year and was not as dependent on customer usage.  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.

53

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 customer's interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation.  Our rates are adjusted annually 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.

In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise.  We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, the areas served do not have governmental organizations authorized to grant franchises or the city governments do not require a franchise.  We attempt to acquire or reacquire franchises whenever feasible.  Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city.  To date, the absence of a franchise has caused no adverse effect on our operations.

(14)  Operating Segments

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 single geographic area of central and southeastern Kentucky.  Virtually all of the revenues recorded under both segments come from the sale or transportation of natural gas. Price risk for the regulated business 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.

A single customer, Citizens Gas Utility District, provided $10,248,000, $17,087,000 and $9,843,000 of non-regulated revenues during 2009, 2008 and 2007, respectively.  Citizens has decreased their purchases from us, and thus revenues are not expected to continue at historical levels.

In 2009, 2008 and 2007, we purchased approximately 99% of our natural gas from Atmos Energy Marketing and M & B Gas Services.

The segments follow the accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements. Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services. Intersegment transportation revenues and expenses are recorded at our tariff rates. Revenues and expenses for the storage of natural gas are recorded based on quantities stored. Operating expenses, taxes and interest are allocated to the non-regulated segment.  Segment information is shown in the following table:

54

($000)	2009			2008			2007
Operating Revenues
Regulated
External customers		64,478			58,219			53,499
Intersegment		3,427			4,019			3,643
Total regulated		67,905			62,238			57,142
Non-regulated
External customers		41,158			54,438			44,669
Eliminations for intersegment		(3,427	)		(4,019	)		(3,643	)
Total operating revenues		105,636			112,657			98,168
Operating Expenses
Regulated
Purchased gas		39,138			33,493			30,887
Depreciation		3,737			4,053			4,579
Other		15,246			14,840			13,538
Total regulated		58,121			52,386			49,004
Non-regulated
Purchased gas		32,940			43,389			35,173
Depreciation		118			118			119
Other		5,092			5,119			4,547
Total non-regulated		38,150			48,626			39,839
Eliminations for intersegment		(3,427	)		(4,019	)		(3,643	)
Total operating expenses		92,844			96,993			85,200
Other Income and Deductions, Net
Regulated		(50	)		83			134
Non-regulated		4			—			—
Total other income and deductions		(46	)		83			134
Interest Charges
Regulated		4,305			4,556			4,501
Non-regulated		223			214			146
Total interest charges		4,528			4,770			4,647
Income Tax Expense
Regulated		1,949			2,022			1,349
Non-regulated		1,059			2,125			1,808
Total income tax expense		3,008			4,147			3,157
Net Income
Regulated		3,479			3,356			2,422
Non-regulated		1,732			3,474			2,876
Total net income		5,211			6,830			5,298
Assets
Regulated		154,297			163,952			154,029
Non-regulated		8,208			6,863			6,372
Total assets		162,505			170,815			160,401
Capital Expenditures
Regulated		8,422			5,564			8,083
Non-regulated		—			—			—
Total capital expenditures		8,422			5,564			8,083

55

(15)  Gas in Storage Inventory Adjustment

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 2009, after analyzing the storage field data at the end of the injection cycle, we determined that an inventory adjustment was required.  We estimated that the adjustment amount would 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 2009 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 2009, sufficient data had not been available to determine the amount of lost gas inventory resulting from the compromised storage well. Prior to 2009, we had no reason to believe this represented a material financial risk to the Company.  Our analysis in 2009 indicated a material shortfall of storage gas volumes in comparison with our perpetual inventory records.  The 2009 analysis also provided us enough information to estimate a range for adjusting inventory.

During 2009, we recorded a gas in storage inventory adjustment in the amount of $1,350,000.  The adjustment is included in operation and maintenance expense in the Consolidated Statements of Income for the year ended June 30, 2009.  Any future adjustment to inventory 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 have sought 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 through other recovery 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.

(16)  Sale of Property, Plant and Equipment

During 2009, 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 2009 Consolidated Statements of Income.

56

(17)  Quarterly Financial Data (Unaudited)

The quarterly data reflects, in the opinion of management, all normal recurring adjustments necessary to present fairly the results for the interim periods.

Quarter Ended	Operating Revenues		Operating Income (Loss)			Net Income (Loss)			Basic and Diluted Earnings (Loss) per Common Share
Fiscal 2009
September 30	$	18,108,090	$	1,570,336		$	273,215		$	.08
December 31		33,957,969		3,313,510	(a)		1,229,004	(a)		.37	(a)
March 31		43,160,716		7,919,488			4,259,874			1.29
June 30		10,410,049		(10,134	)		(551,364	)		(.16	)
Fiscal 2008
September 30	$	12,404,170	$	(102,919	)	$	(810,945	)	$	(.25	)
December 31		29,298,418		5,289,682			2,455,285			.75
March 31		48,396,125		9,884,436			5,421,108			1.65
June 30		22,558,404		592,537			(235,580	)		(.07	)

(a) We recorded a $1,350,000 non-recurring inventory adjustment at December 31, 2008 for our gas in storage, as discussed in Note 15 of the Notes to Consolidated Financial Statements.

57

SCHEDULE II

DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES

VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED JUNE 30, 2009, 2008, and 2007

Column A	Column B			Column C						Column D			Column E
				Additions						Deductions
							Charged to
	Balance at			Charged to			Other			Amounts
	Beginning of			Costs and			Accounts –			Charged Off			Balance at
Description	Period			Expenses			Recoveries			Or Paid			End of Period
Deducted From the Asset to Which it Applies – Allowance for doubtful accounts for the years ended:
June 30, 2009		$	465,000		$	830,588		$	67,803		$	544,391	$	819,000
June 30, 2008			300,000			599,345			64,139			498,484		465,000
June 30, 2007			520,000			272,893			9,824			502,717		300,000

58