Delta Natural Gas 10K 2012 Annual report

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, 2012

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

For the transition period from _______ to ________

Commission File No. 0-8788

______________

DELTA NATURAL GAS COMPANY, INC.

(Exact name of registrant as specified in its charter)

______________

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

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

859-744-6171
(Registrant's telephone number, including area code)

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

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. T

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. $116,530,074.

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, 2012, Delta Natural Gas Company, Inc. had outstanding 6,805,418 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, 2012, 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	10

	Item 1B.	Unresolved Staff Comments	13

	Item 2.	Properties	13

	Item 3.	Legal Proceedings	14

	Item 4.	(Not Applicable)	14

PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14

	Item 6.	Selected Financial Data	17

	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18

	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28

	Item 8.	Financial Statements and Supplementary Data	29

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	30

	Item 9A.	Controls and Procedures	30

	Item 9B.	Other Information	32

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	32

	Item 11.	Executive Compensation	32

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	33

	Item 13.	Certain Relationships and Related Transactions, and Director Independence	33

	Item 14.	Principal Accountant Fees and Services	33

PART IV
	Item 15.	Exhibits and Financial Statement Schedules	34

Signatures			37

PART I

Item 1. Business

General

Delta Natural Gas Company, Inc. (Nasdaq: DGAS) distributes or transports natural gas to approximately 36,000 customers. Our distribution and transmission systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market and we transport natural gas on behalf of local producers and customers not on our distribution system. We have three wholly-owned subsidiaries. Delta Resources, Inc. ("Delta Resources") buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. ("Delgasco") buys natural gas and resells it to Delta Resources and to customers not on Delta's system. Enpro, Inc. ("Enpro") owns and operates production properties and undeveloped acreage. We also sell liquids extracted from natural gas in our system.

References to "Delta", "the Company", "we", "us" and "our" refer to Delta Natural Gas Company, Inc. and its consolidated subsidiaries, except as otherwise stated. We were incorporated under the laws of the Commonwealth of Kentucky on October 7, 1949.

Unless otherwise stated, "2012", "2011" and "2010" refers to the respective twelve month period ending June 30.

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 selling, transporting and producing natural gas in our service territory.

We strive to achieve operational excellence through economical, reliable service with an emphasis on responsiveness to customers. We continue to invest in facilities for the distribution, transmission 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, we will continue a conservative strategy of minimizing our exposure to market risk arising from fluctuations in the prices of natural gas.

We operate through two segments, a regulated segment and a non-regulated segment.

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 natural gas to industrial customers on our system who purchase their natural gas in the open market. Our regulated segment also transports natural 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. The impact of this regulation is further discussed in Note 14 of the Notes to Consolidated Financial Statements, in Item 8. Financial Statements and Supplementary Data and under "Regulatory Matters" in Item 1. Business.

Factors that affect our regulated revenues include the rates we charge our customers, economic conditions in our service areas, competition, our supply cost for the natural gas we purchase for resale and weather. Our current rate design lessens the impact natural gas prices and weather have on our regulated revenues as our rates include a weather normalization provision in our tariff, which reduces 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.

Through our gas cost recovery clause, 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. However, increases in our rates 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 natural gas we sell is used for heating. During 2012, 71% of the regulated volumes were sold during the heating season (December through April). Variations in the average temperature during the winter impact our volumes sold. 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 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 natural gas to their plants or facilities. Customers for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers. Customers may undertake such a by-pass in order to seek lower prices for their gas and/or transportation services. 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 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 natural gas transmission and distribution system and customer base. We continue to consider acquisitions of other natural gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas.

Gas Supply

We maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of natural gas for our customers. We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2012, 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 natural 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 natural 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, 2012, approximately 54% of our regulated gas supply was purchased under our agreements with Atmos.

Our regulated segment purchases natural 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 natural gas from M & B for any periods longer than one month at a time. The natural 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, 2012, approximately 45% of our regulated gas supply was purchased under our agreement with M & B.

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 Delta notifies Tennessee of its intent not to renew the agreements at least one year prior to the expiration of any renewal terms. Subject to the terms of Tennessee's Federal Energy Regulatory Commission gas tariff, Tennessee is obligated under these agreements to transport up to 19,600 thousand cubic feet ("Mcf") per day for us. During fiscal 2012, Tennessee transported for us a total of 927,000 Mcf, or approximately 23% of our regulated supply requirements, under these agreements. 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 2012, Columbia Gas and Columbia Gulf transported for us a total of 1,229,000 Mcf, or approximately 31% of our regulated supply requirements, under all of our agreements with them. Our transportation agreements with Columbia Gas and Columbia Gulf extend through 2015. After 2015, our agreement with Columbia Gas continues on a year-to-year basis unless terminated by one of the parties. After 2015, our agreement with Columbia Gulf may be extended by mutual agreement.

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 2012 constituted approximately 45% 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 Atmos to supply our customers' requirements in specific geographic areas. In our fiscal year ended June 30, 2012, Texas Eastern transported approximately 7,000 Mcf of natural gas to our system, which constituted less than 1% of our gas supply.

Kentucky Gas Supply

We have an agreement with Vinland Energy Operations LLC ("Vinland") to purchase natural gas on a year-to-year basis unless terminated by one of the parties. We purchased 33,000 Mcf from Vinland during fiscal 2012. The price for the gas we purchase from Vinland 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. Vinland delivers this gas to our customer meters directly from its own pipelines. In fiscal 2012, the natural gas we purchased from Vinland constituted approximately 1% of our regulated gas supply.

Gas in Storage

We own and operate an underground natural gas storage field that we use to store a significant portion of our 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 have a legal obligation to retire wells located at our underground natural gas storage facility. However, since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the wells have an indeterminate life and have therefore not recorded a liability associated with the cost to retire the wells.

Regulatory Matters

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

In April, 2010, we filed a request for increased base rates with the Kentucky Public Service Commission. This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000, as further discussed in Note 14 of the Notes to Consolidated Financial Statements. The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12%.

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

In addition to the increased rates, our pipe replacement program was approved in our 2010 rate case. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year that are associated with the replacement of pipe and related facilities. In February, 2011, the Kentucky Public Service Commission approved our initial pipe replacement filing, effective May, 2011, which provided us $139,000 in additional annual revenues.

The Kentucky Public Service Commission allows us 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. In our 2010 general rate case, the Kentucky Public Service Commission approved a change to our gas cost recovery clause, effective January, 2011, that provides recovery of the portion of bad debt expense related to gas cost as a component of the gas cost recovery adjustment.

Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which provides for the adjustment of 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.

The Kentucky Public Service Commission also allows us a conservation and efficiency program for our residential customers. The program provides the ability for us to perform energy audits, promote conservation awareness and provide rebates on the purchase of certain high-efficiency appliances. The program helps to align our interests with our residential customers' 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, 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, there are no 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

Natural Gas Marketing

Our non-regulated segment includes three wholly-owned subsidiaries. Two of these subsidiaries, Delta Resources and Delgasco, 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.

Factors that affect our non-regulated revenues include the 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 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.

In our fiscal year ended June 30, 2012, approximately 95% of our non-regulated revenue was derived from our natural gas marketing activities. In our non-regulated segment two customers each provided more than 5% of our operating revenues. Seminole Energy provided approximately $12,450,000, $11,461,000 and $6,722,000 of non-regulated revenues during 2012, 2011 and 2010, respectively. Atmos provided approximately $6,815,000, $8,067,000 and $5,097,000 of non-regulated revenues during 2012, 2011 and 2010, respectively. There is no assurance that revenues from these customers will continue at these levels.

Natural Gas Production

Our subsidiary, Enpro, produces natural gas that is sold to Delgasco for resale in the open market. Item 2. Properties further describes Enpro's oil and natural gas leases and production properties. Enpro produced a total of 144,000 Mcf of natural gas during 2012 which contributed less than 1% of our non-regulated revenue.

Natural Gas Liquids

In order to improve the operations of our distribution, transmission and storage system, we operate a facility that is designed to extract liquids from the natural gas in our system. We sell these natural gas liquids at a price determined by a national unregulated market. In our fiscal year ended June 30, 2012, approximately 4% of our non-regulated revenue was derived from the sale of natural gas liquids.

Gas Supply

Our non-regulated segment purchases gas from M & B. Our underlying agreement with M & B does not obligate us 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, 2012, approximately 85% 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, 2012, approximately 15% 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.

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

Capital Expenditures

Capital expenditures during 2012 were $7.3 million and for 2013 are estimated to be $7.5 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, all of which was available at June 30, 2012.

Our current bank line of credit extends through June 30, 2013 and will be utilized to meet capital expenditure 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.

We currently have long-term debt of $58,000,000 in the form of our Series A Notes. The Series A Notes are unsecured, bear interest at 4.26% per annum and mature on December 20, 2031. Accrued interest on the Series A Notes is payable quarterly. Beginning in December 2012, we are required to make a $1,500,000 principal reduction payment on the Series A Notes each December.

Employees

On June 30, 2012, we had 151 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.

Consolidated Statistics

For the Years Ended June 30,	2012		2011		2010		2009		2008

Average Regulated Customers Served

Residential	29,929		30,420		30,575		30,881		31,520
Commercial	4,890		4,949		4,957		5,009		5,107
Industrial	41		44		46		49		54

Total	34,860		35,413		35,578		35,939		36,681

Operating Revenues ($000) (a)
Regulated (b)(c)
Residential sales	22,720		25,800		23,783		33,774		30,742
Commercial sales	14,026		16,672		15,894		24,125		21,171
Industrial sales	914		1,199		1,075		1,769		1,707
On-system transportation	4,780		4,830		4,421		4,118		4,461
Off-system transportation	3,595		3,670		3,650		3,786		3,864
Other	324		303		294		333		293
Total regulated revenues	46,359		52,474		49,117		67,905		62,238

Non-regulated sales	31,423		34,343		30,746		41,159		54,438
Intersegment eliminations (d)	(3,704	)	(3,777	)	(3,441	)	(3,427	)	(4,019	)

Total	74,078		83,040		76,422		105,637		112,657

System Throughput (Million Cu. Ft.) (a)
Regulated
Residential sales	1,331		1,737		1,756		1,721		1,695
Commercial sales	1,027		1,310		1,331		1,346		1,286
Industrial sales	90		120		111		113		121
On-system transportation	4,724		4,830		4,533		4,215		4,975
Off-system transportation	11,225		11,531		11,039		11,908		12,623
Total regulated throughput	18,397		19,528		18,770		19,303		20,700

Non-regulated sales	6,455		6,010		4,787		4,219		5,394
Intersegment eliminations (d)	(6,326	)	(5,890	)	(4,692	)	(4,135	)	(5,276	)

Total	18,526		19,648		18,865		19,387		20,818

Average Annual Consumption Per
Average Residential Customer
(Thousand Cu. Ft.)	44		57		57		56		54

Lexington, Kentucky Degree Days
Actual	3,797		4,725		4,782		4,651		4,464
Percent of 30 year average	83		103		104		101		96

(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 15 of the Notes to Consolidated Financial Satements.

(b) 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.

(c) We implemented new regulated base rates, as approved by the Kentucky Public Service Commission in October, 2010, which were designed to generate additional annual revenue of $3,513,000.

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

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 71% 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 provision in our tariff, approved by the Kentucky Public Service Commission, only partially mitigates this risk. Under our weather normalization provision in our tariff, we adjust our rates for our 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, 2012, 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. Additionally, federal legislation could restrict or limit drilling which could decrease the supply of available natural gas. A decrease in available pipeline capacity or decrease in natural gas available to us could result in a loss of customers and decrease in profits.

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. A decrease in our normal interstate supply of gas could result in a loss of customers and decrease in profits.

OUR CUSTOMERS ARE ABLE TO BY-PASS OUR DISTRIBUTION AND TRANSMISSION SYSTEMS.

Our larger 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 for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers. Customers may undertake such by-passes in order to achieve lower prices for their gas and/or transportation services. 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 and transportation systems creates a risk of the loss of large customers and thus could result in lower revenues and profits.

ACTIONS BY OUR REGULATORS COULD DECREASE FUTURE PROFITABILITY.

We are regulated by the Kentucky Public Service Commission. Our regulated segment generates a significant portion of our operating revenues. 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. Additionally, our consolidated financial statements reflect the application of regulatory accounting standards by our regulated segment. Our regulated segment has recognized regulatory assets representing costs incurred in prior periods that are probable of recovery from customers in future rates. Disallowance of such costs in future proceedings before the Kentucky Public Service Commission could require us to write-off regulatory assets, which could have a material impact on our income and consolidated financial statements.

VOLATILITY IN PRICES COULD REDUCE OUR PROFITS.

Significant increases in the price of natural gas will likely cause our regulated retail customers to increase conservation 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. The price of natural gas liquids is determined by a national unregulated market, and decreases in the price would cause a decrease in our non-regulated gross margins.

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.

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 RELY ON ACCESS TO CAPITAL TO MAINTAIN LIQUIDITY.

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. Additionally, market disruptions may increase our cost of borrowing or adversely affect our access to capital markets. Such disruptions could include: economic downturns, the bankruptcy of an unrelated energy company, general capital market conditions, market price for natural gas, terrorist attacks or the overall health of the energy industry. There is no guarantee we could obtain needed capital in the future.

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 level of the plan, future government regulation and our required or voluntary contributions made to the plan. 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 RISKS 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, TRANSPORTATION, LIQUIDS EXTRACTION 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, transportation, liquids extraction 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 or 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, EXTREME WEATHER OR WELL-HEAD DISASTERS COULD DISRUPT OUR GAS SUPPLY AND INCREASE NATURAL GAS PRICES.

Hurricanes, extreme weather or well-head disasters could damage production or transportation facilities, which could result in decreased supplies of natural gas, increased supply costs for us and higher prices for our customers. Such events could also result in new governmental regulations or rules that limit production or raise production costs.

OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS FINANCIAL AND NEGATIVE COVENANTS AND A PREPAYMENT PENALTY THAT COULD RESTRICT OUR ACTIVITIES.

Our bank line of credit and Series A Notes contain financial covenants. Noncompliance with these covenants can make the obligations immediately due and payable. If we breach any of the financial covenants under these agreements, our debt repayment obligations under the bank line of credit and Series A Notes could be accelerated. In such event, we may not be able to refinance, repay all our indebtedness, pay dividends or have sufficient liquidity to meet our operating and capital expenditure requirements, all of which could result in a material adverse effect on our business, results of operations and financial condition. Furthermore, a default on the performance of any single obligation incurred in connection with our borrowings, or a default on other indebtedness that exceeds $2,500,000, simultaneously creates an event of default with the bank line of credit and the Series A Notes. Additionally, our bank line of credit and Series A Notes contain various negative covenants and a prepayment penalty which create a risk that we may be unable to take advantage of business and financing opportunities as they arise.

OUR LONG-TERM DEBT ARRANGEMENTS LIMIT THE AMOUNT OF DIVIDENDS WE MAY PAY AND OUR REPURCHASE OF STOCK.

Under the terms of our 4.26% Series A Notes, the aggregate amount we may pay in dividends on our common stock and in repurchase of our common stock may not exceed the sum of $15,000,000 and our cumulative net income after September 30, 2011. Between September 30, 2011 and June 30, 2012, we paid $3,575,000 in dividends, repurchased no stock and have had cumulative net income of $6,662,000. Consequently, as of June 30, 2012 we had the ability to pay up to $18,087,000 in dividends and for the repurchase of our common stock. However, if we fail to generate sufficient net income in the future, our ability to continue to pay our regular quarterly dividend may be impaired and the value of our common stock would likely decline.

A SECURITY BREACH COULD DISRUPT OUR IT SYSTEMS, INTERRUPT THE NATURAL GAS SERVICE WE PROVIDE TO OUR CUSTOMERS, COMPROMISE THE SAFETY OF OUR NATURAL GAS DISTRIBUTION, TRANSMISSION AND STORAGE SYSTEMS OR EXPOSE CONFIDENTIAL PERSONAL INFORMATION.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to IT system disruptions or shutdowns, result in the interruption of our ability to provide natural gas to our customers or compromise the safety of our distribution, transmission and storage systems. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

Additionally, the protection of customer, employee, vendor, investor and company data is critical to us. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. There is no guarantee that the procedures that we have implemented to protect against unauthorized access to secured data are adequate to safeguard against all data security breaches.

FAILURE TO ATTRACT AND RETAIN AN APPROPRIATELY QUALIFIED WORKFORCE COULD UNFAVORABLY IMPACT OUR RESULTS OF OPERATIONS.

Certain events, such as an aging workforce, mismatch of skill sets to complement future needs, or unavailability of future resources, may lead to increased operational risks and costs. As a result of these events, we could face lack of resources knowledgeable about the natural gas industry and a lengthy time period associated with skill development and knowledge transfer. Failure to address this risk may result in increased operational and safety risks as well as increased costs. Even if we have reasonable plans in place to address succession planning and workforce training, we cannot control the future availability of qualified labor. If we are unable to successfully attract and retain an appropriately qualified workforce, our financial position or results of operations could be negatively affected.

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, adoption of International Financial Reporting Standards and tax law, could change the way in which we are required to record revenues, expenses, assets and liabilities. Additionally, governing bodies may choose to re-interpret laws and regulations. These changes could have a negative impact on our financial position, cash flows, results of operations or access to capital.

CLIMATE CHANGE LEGISLATION MAY POSE NEW FINANCIAL OR REGULATORY RISKS.

A number of proposals to limit greenhouse gas emissions are pending at the regional, federal, and international levels. These proposals, if enacted and made applicable to us, may require us to measure and potentially limit greenhouse gas emissions from our utility operations and our customers or purchase allowances for such emissions. While we cannot predict the extent of these limitations or when or if they will become effective, the adoption of such proposals could:

·	increase utility costs related to operations, energy efficiency activities and compliance,
·	affect the demand for natural gas, and
·	increase the prices we charge our utility customers.

Unless we are able to timely recover the costs of such impacts from customers through the regulatory process, costs associated with any such regulatory or legislative changes could adversely affect Delta's results of operations, financial condition and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

We own our corporate headquarters in Winchester, Kentucky. We own eleven buildings used for field operations in the cities we serve.

We own approximately 2,500 miles of natural gas gathering, transmission, distribution and storage 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 segment, as further discussed in Item 1. Business.

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 2.6 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 144,000 Mcf of natural gas during fiscal 2012 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

The Kentucky Department of Revenue has assessed Delta Resources for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011. We are currently protesting the assessment with the Kentucky Department of Revenue and the outcome is uncertain; therefore we are unable to predict whether the issue will ultimately have a materially adverse impact on our liquidity, financial position or results of operations. A discussion of the assessment and protest is provided in Note 13 of the Notes to Consolidated Financial Statements.

Other than the protest of the assessment for the 3% Utility Gross Receipts License Tax, we are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.

Item 4. (Not Applicable)

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 our Series A Notes as described in Note 10 of the Notes to Consolidated Financial Statements.

Our common stock is listed on NASDAQ and trades under the symbol "DGAS". There were 1,592 record holders of our common stock as of August 15, 2012. The accompanying table sets forth, for the periods indicated, the high and low sales prices for the common stock on the NASDAQ stock market and the cash dividends declared per share.

	Range of Stock Prices ($)		Dividends
	High	Low	Per Share ($)

Quarter

Fiscal 2012
First	16.98	14.51	.175
Second	17.24	14.12	.175
Third	19.61	16.72	.175
Fourth	23.15	18.83	.175

Fiscal 2011
First	15.81	13.17	.17
Second	16.49	14.76	.17
Third	17.00	15.10	.17
Fourth	16.49	15.00	.17

The sales prices shown above reflect prices between dealers and do not include markups or markdowns or commissions and may not necessarily represent actual transactions. Additionally, as a result of the two-for-one stock split distributed on May 1, 2012, as further discussed in Note 17 of the Notes to Consolidated Financial Statements, the stock prices and dividends per share above have been restated.

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 Dow Jones Utilities Index and the Standard & Poor's 500 Stock Index during the past five fiscal years. Information reflected on the graph assumes an investment of $100 on June 30, 2007 in each of our common shares, the Dow Jones Utilities Index and the Standard & Poor's Stock Index. Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.


	2007	2008	2009	2010	2011	2012

Delta	100	106	96	128	148	210

Dow Jones Utilities Index	100	108	77	81	102	119

Standard & Poor's 500 Stock Index	100	87	64	73	96	101

Item 6. Selected Financial Data

The following selected financial data is derived from the Company's audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto.

For the Years Ended June 30,		2012	2011	2010	2009	2008

Summary of Operations ($)

Operating revenues (a)(b)		74,078,322	83,040,251	76,422,068	105,636,824	112,657,117

Operating income (a)(b)(c)		13,265,228	14,061,794	12,904,494	12,793,200	15,663,736

Net income (a)(b)(c)		5,783,998	6,364,895	5,651,817	5,210,729	6,829,868

Earnings per common share (a)(b)(c)(d)
Basic and diluted		.85	.95	.85	.79	1.04

Cash dividends declared per common share (d)		.70	.68	.65	.64	.62

Weighted Average Number of Common Shares (d) Basic		6,777,186	6,707,224	6,652,320	6,612,052	6,570,928
Diluted		6,777,186	6,712,804	6,652,320	6,612,052	6,570,928

Total Assets ($)		182,895,363	174,896,239	168,632,420	162,505,295	170,814,856

Capitalization ($)

Common shareholders' equity		66,220,407	63,767,184	60,760,170	58,999,182	57,593,585

Long-term debt		56,500,000	56,751,006	57,112,000	57,599,000	58,318,000

Total capitalization		122,720,407	120,518,190	117,872,170	116,598,182	115,911,585

Short-Term Debt ($) (e)		1,500,000	1,200,000	1,200,000	4,853,103	8,028,791

Other Items ($)

Capital expenditures		7,337,115	8,123,479	5,275,194	8,422,433	5,563,667

Total property, plant and equipment		217,172,542	211,409,336	204,248,520	199,254,216	192,127,184
	(a)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. (b)We implemented new regulated base rates as approved by the Kentucky Public Service Commission in October, 2010 and the rates were designed to generate additional annual revenue of $3,513,000, with a $1,770,000 increase in annual depreciation expense. (c)We recorded a non-recurring $1,350,000 gas in storage inventory adjustment at December 31, 2008. (d)As a result of a two-for-one stock split distributed on May 1, 2012, all amounts related to shares, share prices, earnings per share and dividends per share have been retroactively restated. (e)Includes current portion of long-term debt.

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

Overview of 2012 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 2012. Our Company has two segments: (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing, natural gas production and the sale of liquids extracted from natural gas.

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 to match estimated demand with supply and provide an acceptable margin. The non-regulated segment also produces natural gas and sells liquids extracted from natural gas.

Consolidated earnings per common share for 2012 decreased $.10 per common share. In 2012, we accrued interest expense relating to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 13 of the Notes to Consolidated Financial Statements). Additionally, we experienced both a winter that was significantly warmer than the preceding year and historically low prices for natural gas that also adversely impacted earnings but were offset by other factors which improved earnings. The warmer than normal weather resulted in decreased volumes of natural gas sold by our regulated segment, which was partially offset by our ability, under our weather normalization tariff, to adjust regulated rates during the winter months. Although the decline in the market price of natural gas reduced the gross margin earned from the non-regulated segment's sale of natural gas, this reduction was more than offset by the revenue derived from the sale of natural gas liquids extracted at our liquids extraction facility which was completed in 2012.

Future Outlook

Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers. The Kentucky Public Service Commission sets these rates, and we monitor our need to file rate cases with the Kentucky Public Service Commission for a general rate increase for our regulated services. The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers. We manage remaining expenses through budgeting, approval and review.

Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large use customers and the market prices of natural gas and natural gas liquids, all of which are out of our control. We anticipate our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2013. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production and marketing activities. However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities. We anticipate selling additional natural gas liquids in 2013. The profitability of such sales is dependent on the amount of liquids extracted and the pricing for any such liquids is determined by a national unregulated market.

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 and changes in working capital. Our sales and cash requirements are seasonal. The largest portion of our sales occurs during the heating months, whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months. Therefore, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit. The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of June 30, 2012 or June 30, 2011.

Long-term debt decreased to $56,500,000 at June 30, 2012, compared with $56,751,000 at June 30, 2011. The decrease resulted from an increase in the current portion of our long-term debt as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures, as further discussed in Note 10 of the Notes to Consolidated Financial Statements.

Cash and cash equivalents were $9,741,000 at June 30, 2012 compared with $7,340,000 at June 30, 2011 and $4,639,000 at June 30, 2010. These changes in cash and cash equivalents are summarized in the following table:

($000)	2012		2011		2010

Provided by operating activities	13,514		14,467		17,600
Used in investing activities	(7,012	)	(7,520	)	(5,052	)
Used in financing activities	(4,102	)	(4,246	)	(8,031	)

Increase in cash and cash equivalents	2,400		2,701		4,517

In 2012, there was not a significant change in cash provided by operating activities.

In 2011, $3,133,000 less cash was provided by operating activities as compared to 2010. Cash contributed to our defined benefit pension plan increased $1,500,000 as we made an elective contribution in 2011 to increase the funded status of the plan. Cash paid for natural gas increased $6,164,000 due to increased volumes purchased during 2011 to meet our customers' gas requirements as well as increased volumes purchased for injection into our storage field. Cash paid for other operation and maintenance expenses increased $434,000. These increases were partially offset by a $5,464,000 increase in cash received from our customers due to increased rates in our regulated segment and increased volumes sold.

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

In 2012, there was not a significant change in cash used in financing activities.

In 2011, cash used in financing activities decreased $3,785,000 due to decreased repayments on our bank line of credit.

Cash Requirements

Our capital expenditures result in a continued need for cash. These capital expenditures are being made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2013 to be approximately $7.5 million.

The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2012:

	Payments Due by Fiscal Year
$(000)		2013		2014-2015		2016-2017	After 2017		Total
Interest payments (a)	$	2,537	$	4,682	$	4,427	$	24,419	$	36,065
Long-term debt (b)		1,500		3,000		3,000		50,500		58,000
Pension contributions (c)		2,300		1,000		1,000		4,500		8,800
Gas purchases (d)		391		-		-		-		391
Total contractual obligations (e)	$	6,728	$	8,682	$	8,427	$	79,419	$	103,256

(a)

Our long-term debt, notes payable, customers' deposits and unrecognized tax positions all require interest payments. Interest payments are projected based on fiscal 2012 interest payments until the underlying obligation is satisfied. As of June 30, 2012, we have accrued $877,000 of interest related to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue, as further discussed in Note 13 of the Notes to Consolidated Financial Statements. As of June 30, 2012, we have also accrued $10,000 of interest related to uncertain tax positions. These amounts have been excluded from the above table of contractual obligations as the timing of such payments is uncertain.

(b)	See Note 10 of the Notes to Consolidated Financial Statements for a description of this debt.

(c)	This represents currently projected contributions to the defined benefit plan through 2025, as recommended by our actuary and a $2,300,000 discretionary contribution made to the defined benefit plan in August, 2012.

(d)

As of June 30, 2012, we had three contracts which had minimum purchase obligations. These contracts have various terms with the last contract expiring December, 2012. The remainder of our gas purchase contracts are either requirements-based contracts, or contracts with a minimum purchase obligation extending for a time period not exceeding one month.

(e)	We have other long-term liabilities which include deferred income taxes ($37,732,000), regulatory liabilities ($1,381,000), asset retirement obligations ($3,824,000) and deferred compensation ($590,000). 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 13 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

Sufficiency of Future Cash Flows

Our ability to maintain liquidity, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated rates we charge our customers. We expect that cash provided by operations, coupled with short-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future.

To the extent that internally generated cash is not sufficient to satisfy seasonal operating and capital expenditure requirements and to pay dividends, we rely on our bank line of credit. Our current available bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of June 30, 2012.

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

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031. Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. Any refinance of the Series A Notes, or any additional prepayments of principal, may be subject to a prepayment penalty.

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

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

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

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

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

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

The following table shows the required and actual financial covenants under our Series A Notes as of June 30, 2012:

Requirement		Actual

Tangible net worth	no less than $25,800,000	$	64,306,718
Debt to capitalization ratio	no more than 70%		47	%
Fixed charge coverage ratio	no less than 1.20x		6.02x
Dividends paid	no more than $21,662,000	$	3,575,000

Our 4.26% Series A Notes restrict us from:

·	with limited exceptions, granting or permitting liens on or security interests in our properties,

·	selling a subsidiary, except in limited circumstances,

·	incurring secured debt, or permitting a subsidiary to incur debt or issue preferred stock to any third party, in an aggregate amount that exceeds 10% of our tangible net worth,

·	changing the general nature of our business,

merging with another company, unless (i) we are the survivor of the merger or the survivor of the merger is another domestic company that assumes the 4.26% Series A Notes, (ii) there is no event of default under the 4.26% Series A Notes and (iii) the continuing company has a tangible net worth at least as high as our tangible net worth immediately prior to such merger, or

selling or transferring assets, other than (i) the sale of inventory in the ordinary course of business, (ii) the transfer of obsolete equipment and (iii) the transfer of other assets in any 12 month period where such assets constitute no more than 5% of the value of our tangible assets and, over any period of time, the cumulative value of all assets transferred may not exceed 15% of our tangible assets.

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

·	merge with another entity;

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

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

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

Furthermore, the agreement governing our 4.26% Series A Notes contains a cross-default provision which provides that we will be in default under the 4.26% Series A Notes if we are in default on any other outstanding indebtedness that exceeds $2,500,000. Similarly, the loan agreement governing the bank line of credit contains a cross-default provision which provides that we will be in default under the bank line of credit if we are in default under our 4.26% Series A Notes and fail to cure the default within ten days of notice from the bank. We were not in default on our bank line of credit, 4.26% Series A Notes or the long-term debt we redeemed in 2012 for any period presented in the Consolidated Financial Statements.

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.

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 reflect the effects of the rate-making process in accordance with regulatory accounting standards. Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of regulatory accounting standards 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, 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 regulatory accounting standards 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 the Kentucky Public Service Commission 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

We have a trusteed, non-contributory, defined benefit pension plan covering all eligible employees hired prior to May 9, 2008. The net periodic benefit costs ("pension costs") for our defined benefit plan as described in Note 6 of the Notes to Consolidated Financial Statements are dependent upon numerous factors resulting from actual plan experience and assumptions concerning future experience. These costs, 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. For the years ended June 30, 2012, 2011 and 2010, we recorded pension costs for our defined benefit pension plan of $481,000, $1,129,000 and $1,040,000, respectively.

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. As of June 30, 2012, $9,537,000 of net losses have been deferred for amortization as pension costs into future periods.

Our pension plan assets are principally comprised of equity and fixed income investments. Differences between actual portfolio returns and expected returns will 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 pension costs in future periods.

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 2012 and was based on our targeted asset allocation assumption of approximately 70% equity investments and approximately 30% fixed income investments. Our target investment allocation for equity investments includes allocations to domestic, global and real estate 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.

The funded status of our plan reflects investment gains or losses in the year in which they occur based on the market value of assets at the measurement date.

Based on an assumed long-term rate of return of 7%, discount rate of 4%, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plan will increase from $481,000 in 2012 to $980,000 in 2013. Modifying the expected long-term rate of return on our pension plan assets by .25% would change pension costs for 2013 by approximately $56,000. Increasing the discount rate assumption by .25% would decrease pension costs by approximately $82,000. Decreasing the discount rate assumption by .25% would increase pension costs by approximately $87,000.

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 our regulated segment, the risk of non-collection on accounts receivable is partially mitigated by our ability to recover the portion of bad debt expense that relates to the customers' gas cost through our gas cost recovery mechanism. We began recovery of our uncollectible gas cost by this method in January, 2011.

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. 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 is 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, 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 further discussed in Note 4 of the Notes to Consolidated Financial Statements.

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", "could", "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, transportation, marketing and natural gas liquids activities,
·	acquisition of service franchises from local governments,
·	pension plan 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,
·	litigation and other contingencies,
·	regulatory and legislative matters, and
·	dividends.

Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. 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, among others, 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 operating revenues are derived primarily from the sale of natural gas and the provision of natural gas transportation services. We define "gross margins" as gas sales less the corresponding purchased gas expenses, plus transportation and other revenues. We view gross margins as an important performance measure of the core profitability of our operations and believe investors benefit from having access to the same financial measures that our management uses. Gross margin can be derived directly from our Consolidated Statements of Income as follows:

($000)	2012		2011		2010

Operating revenues (a)	74,078		83,040		76,422
Regulated purchased gas (a)	(15,703	)	(21,077	)	(20,518	)
Non-regulated purchased gas (a)	(23,380	)	(26,762	)	(23,582	)

Consolidated gross margin	34,995		35,201		32,322

(a)	amounts from the Consolidated Statements of Income included in Item 8. Financial Statements and Supplemental Data

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.

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)			2012 compared to 2011		2011 compared to 2010

Increase (decrease) in gross margins
	Regulated segment
		Natural gas sales	(641	)	2,360
		On-system transportation	(50	)	409
		Off-system transportation	(75	)	20
		Other	25		9
		Intersegment elimination (a)	73		(336	)

		Total	(668	)	2,462

	Non-regulated segment
		Natural gas sales	(784	)	61
		Natural gas liquids	1,360		-
		Other	(41	)	20
		Intersegment elimination (a)	(73	)	336

		Total	462		417

Increase (decrease) in consolidated gross margins			(206	)	2,879

Percentage increase (decrease) in volumes
	Regulated segment
		Natural gas sales	(23	)	(1	)
		On-system transportation	(2	)	7
		Off-system transportation	(3	)	4

	Non-regulated segment
		Natural gas sales	7		26

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

Heating degree days were 83% of normal thirty year average temperatures for fiscal 2012, as compared with 103% and 104% of normal temperatures for 2011 and 2010, 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 2012, consolidated gross margins decreased $206,000 (1%) due to decreased regulated gross margins of $668,000 (2%) partially offset by increased non-regulated gross margins of $462,000 (6%). Regulated gross margins decreased due to a 23% decline in volumes sold as a result of warmer weather as compared to 2011. Partially offsetting this decrease are increased rates billed through our weather normalization tariff. Non-regulated gross margins increased due to the sale of liquids extracted from natural gas, as we completed the installation of a facility to extract liquids from the natural gas in our system in order to improve the operations of our distribution, transmission and storage systems. The increase was partially offset by decreases in gross margins from non-regulated natural gas sales due to a decline in sales prices.

In 2011, consolidated gross margins increased $2,879,000 (9%) due to increased regulated and non-regulated gross margins of $2,462,000 (10%) and $417,000 (6%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010 and an increase in volumes transported. Non-regulated margins increased due to an increase in volumes sold due to an increase in our non-regulated customers' gas requirements, which was partially offset by a decline in sales prices.

Depreciation and Amortization

In 2012 and 2011, depreciation and amortization increased $767,000 (15%) and $1,216,000 (31%), respectively, due to increased depreciation rates approved by the Kentucky Public Service Commission in October 2010 as part of our 2010 rate case.

Taxes Other Than Income Taxes

In 2012, taxes other than income taxes increased $238,000 (12%) due to increased property tax expense resulting from both higher assessed values and rates assessed by taxing jurisdictions.

In 2011, there were no significant changes in taxes other than income taxes as compared to 2010.

Interest on Long-Term Debt

In 2012, interest on long-term debt decreased $601,000 (17%) as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures (as further discussed in the Note 10 of the Notes to Consolidated Financial Statements).

In 2011, there were no significant changes in interest on long-term debt as compared to 2010.

Other Interest

In 2012, other interest increased $868,000 (742%) due to the accrual of interest expense relating to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 13 of the Notes to Consolidated Financial Statements).

In 2011, there were no significant changes in other interest as compared to 2010.

Income Tax Expense

In 2012, income tax expense decreased $502,000 (13%) due to a decrease in net income before income taxes. There were no significant changes in our effective tax rate for 2012 as compared to 2011.

In 2011, income tax expense increased $568,000 (18%) due to an increase in net income before income taxes. There were no significant changes in our effective tax rate for 2011 as compared to 2010.

Basic and Diluted Earnings Per Common Share

For 2012 and 2011, our basic and diluted earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our dividend reinvestment and stock purchase plan as well as those awarded through our incentive compensation plan. Our computation of basic and diluted earnings per share is set forth in Note 11 of the Notes to Consolidated Financial Statements.

Under our Incentive Compensation Plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 18 of the Notes to Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end. The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.

Certain unvested awards under our shareholder approved incentive compensation plan, as further discussed in Note 18 of the Notes to Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta Natural Gas Company, Inc. including a right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. There were 48,000 and 32,000 unvested participating shares outstanding as of June 30, 2012 and 2011, respectively. There were no unvested participating shares outstanding as of June 30, 2010.

In accordance with the provisions of our incentive compensation plan, all unvested shares have been adjusted for the two-for-one stock split distributed in May, 2012, as further discussed in Note 17 of the Notes to Consolidated Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We purchase our natural 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 natural gas purchase contracts, however, is fixed prior to the delivery of the gas. Additionally, we inject some of our natural gas purchases into gas storage facilities in the non-heating months and withdraw this natural gas from storage for delivery to customers during the heating months. For our regulated segment, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for the non-regulated business is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand. In addition, we are exposed to changes in the market price of natural gas on uncommitted natural gas inventory 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. As of June 30, 2012, we had forward purchase contracts totaling $391,000 that have various terms with the last contract expiring in December, 2012. These forward purchase contracts are at a fixed price and not impacted by changes in the market price of natural gas.

When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates. The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate. There were no borrowings outstanding on our bank line of credit as of June 30, 2012 or June 30, 2011. The weighted average interest rate on our bank line of credit was 1.4% and 1.8% as of June 30, 2012 and June 30, 2011, respectively. Based on the average borrowings on our bank line of credit during 2012, a 1% (one hundred basis points) increase in our average interest rate would have resulted in a $21,000 decrease in our annual pre-tax net income.

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE	PAGE

Report of Independent Registered Public Accounting Firm	38

Consolidated Statements of Income for the years ended June 30, 2012, 2011 and 2010	39

Consolidated Statements of Cash Flows for the years ended June 30, 2012, 2011 and 2010	40

Consolidated Balance Sheets as of June 30, 2012 and 2011	42

Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2012, 2011 and 2010	44

Notes to Consolidated Financial Statements	45

Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2012, 2011 and 2010	69

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

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, 2012 and based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended June 30, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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

Management's Annual Report on Internal Control over Financial Reporting

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, 2012 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, 2012.

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.

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:

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. and subsidiaries (the "Company") as of June 30, 2012, 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 Management's Annual Report on Internal Control over Financial Reporting. 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, 2012, 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, 2012 of the Company and our report dated August 28, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

August 28, 2012

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

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. Our Business Code of Conduct and Ethics can be found 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. These documents can be found on our website by going to the following address: http://www.deltagas.com and clicking on the appropriate link.

A printed copy of any of the materials referred to above can be obtained 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 contained under the captions "Election of Directors", "Board Leadership, Committees and Meetings", "Executive Officers", "Certain Relationships and Related Transactions" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive Proxy Statement for the 2012 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2012. We incorporate that information in this document by reference.

Item 11. Executive Compensation

Information in response to this item is contained under the captions "Director Compensation", "Compensation Committee Interlocks and Insider Participation", "Compensation Discussion and Analysis", "Compensation Risks", "Corporate Governance and Compensation Committee Report", "Summary Compensation Table", "Grants of Plan Based Awards", "Outstanding Equity Awards at Fiscal Year-End", "Retirement Benefits", "Potential Payments Upon Termination Or Change in Control" and "Termination Table" in our definitive Proxy Statement for the 2012 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2012. We incorporate that information in this document by reference.

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

Equity Compensation Plans

Pursuant to our shareholder approved incentive compensation plan, we have the ability to grant stock bonuses, performance shares and restricted stock to employees, officers and directors. The plan does not provide for the awarding of options, warrants or rights. We do not have any equity compensation plans which have not been approved by our shareholders.

The following table sets forth certain information with respect to our equity compensation plan at June 30, 2012:

Column A	Column B	Column C

Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column A)

-	-	901,000 *

* In accordance with the provisions of our incentive compensation plan, all remaining shares available for future issuance have been adjusted for the two-for-one stock split distributed in May, 2012, as further discussed in Note 17 of the Notes to Consolidated Financial Statements.

The other information required by this Item is contained under the caption "Security Ownership of Certain Beneficial Owners and Management" in our definitive Proxy Statement for the 2012 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2012. We incorporate that information in this document by reference.

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

The information required by this item is contained under the captions "Election of Directors", "Board Leadership, Committees and Meetings" and "Certain Relationships and Related Transactions" in our definitive Proxy Statement for the 2012 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2012. We incorporate that information in this document by reference.

Item 14. Principal Accountant Fees and Services

The information required by this item is contained under the caption "Audit Committee Report" in our definitive Proxy Statement for the 2012 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2012. We incorporate that information in this document by reference.

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.

	3.1	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/A (File No. 000-08788) for the period ended June 30, 2007.
	3.2	Registrant's Amended and Restated By-Laws (dated September 24, 2010) are incorporated herein by reference to Exhibit 3.1 to Registrant's Form 8-K (File No. 000-8788) dated September 27, 2010.
	4	Note Purchase and Private Shelf Agreement dated December 8, 2011 in respect of 4.26% Senior Notes, Series A, due December 20, 2031, is incorporated herein by reference to Exhibit 10.01 to Registrant's Form 8-K (File No. 000-08788) dated December 13, 2011.
	10.01	Gas Sales Agreement, dated May 1, 2000 by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10(c) to Registrant's Form S-2/A (Reg. No. 333-100852) dated December 13, 2002.
	10.02	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.
	10.03	Gas Sales Agreement, dated May 1, 2003, by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10(d) to Registrant's Form 10-K (File No. 000-08788) for the period ended June 30, 2003.
	10.04	Gas Sales Agreement, dated May 1, 2010, by and between Atmos Energy Marketing, LLC and Registrant is filed herein.
	10.05	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/A (Reg. No. 333-100852) dated December 13, 2002.
	10.06	Agreement to transport natural gas between Nami Resources Company L.L.C. and Registrant, dated March 10, 2005, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated March 23, 2005.
	10.07	Amendment, dated July 22, 2010, of agreement to transport natural gas between Nami Resources Company, L.L.C. and Registrant incorporated herein by reference to Exhibit 10(f) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
	10.08	GTS Service Agreements, dated November 1, 1993 (Service Agreement Nos. 37,813, 37,814 and 37,815), and Appendix A to respective Service Agreements, effective November 1, 2010, by and between Columbia Gas Transmission Corporation and Registrant incorporated herein by reference to Exhibit 10(g) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
	10.09	FTS1 Service Agreements, dated October 4, 1994, (Service Agreement Nos. 43,827, 43,828 and 43,829), and Appendix A to respective Service Agreements, effective November 1, 2010, by and between Columbia Gulf Transmission Corporation and Registrant incorporated herein by reference to Exhibit 10(h) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
	10.10	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.

	10.11	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.
	10.12	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.
	10.13	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.
	10.14	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.
	10.15	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/A (Reg. No. 333-100852) dated December 13, 2002.
	10.16	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.
	10.17	Modification Agreement extending to October 31, 2004 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, 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, 2003.
	10.18	Modification Agreement extending to October 31, 2005 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, 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, 2004.
	10.19	Modification Agreement extending to October 31, 2007 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated August 19, 2005.
	10.20	Modification Agreement extending to October 31, 2009 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, 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.
	10.21	Modification Agreement extending to June 30, 2011 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated June 30, 2009.
	10.22	Modification Agreement extending to June 30, 2013 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated June 30, 2011.
	10.23	Employment agreement dated March 1, 2000, between Glenn R. Jennings, Registrant's Chairman of the Board, President and Chief Executive Officer, and Registrant, is incorporated herein by reference to Exhibit (k) to Registrant's Form 10-Q (File No. 000-08788) dated March 31, 2000.
	10.24	Officer agreements dated March 1, 2000, between two officers, those being John B. Brown and Johnny L. Caudill, and Registrant, 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.
	10.25	Officer agreement dated November 20, 2008, between Brian S. Ramsey and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated November 21, 2008.
	10.26	Officer agreement dated November 19, 2010, between Matthew D. Wesolosky and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated November 24, 2010.

10.27	Supplemental retirement benefit agreement and trust agreement between Glenn R. Jennings and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated February 25, 2005.
10.28	Registrant's Amended and Restated Dividend Reinvestment and Stock Purchase Plan, dated November 17, 2005, is incorporated herein by reference to Exhibit 99(b) to Registrant's S-3D (Reg. No. 333-130301) dated December 14, 2005.
10.29	Registrant's Incentive Compensation Plan, dated January 1, 2008, is incorporated herein by reference to Exhibit 4.1 to Registrant's S-8 (Reg. No. 333-165210) dated March 4, 2010.
10.30	Notices of Performance Shares Award between four officers, those being John B. Brown, Johnny L. Caudill, Glenn R. Jennings, and Brian S. Ramsey, and Registrant, are incorporated herein by reference to Exhibits 10.3, 10.4, 10.5 and 10.6 of Registrant's Form 8-K (File No. 000-08788) dated August 20, 2010.
10.31	Notices of Performance Shares Award between five officers, those being John B. Brown, Johnny L. Caudill, Glenn R. Jennings, Brian S. Ramsey and Matthew D. Wesolosky and Registrant, are incorporated herein by reference to Exhibits 10.1, 10.2, 10.3, 10.4 and 10.5 of Registrant's Form 8-K (File No. 000-08788) dated August 16, 2011.
10.32	Notices of Performance Shares Award between five officers, those being John B. Brown, Johnny L. Caudill, Glenn R. Jennings, Brian S. Ramsey and Matthew D. Wesolosky and Registrant, are incorporated herein by reference to Exhibit 10.1, 10.2, 10.3, 10.4 and 10.5 of Registrant's Form 8-K (File No. 000-08788) dated August 21, 2012.
10.33	Settlement and Release Agreement, dated September 12, 2011, between the "Chartis Parties" and Registrant, incorporated herein by reference to Exhibit 10(a) of Registrant's Form 8-K (File No. 000-08788) dated September 14, 2011.
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.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Database
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
	Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL):
	(i)	Document and Entity Information;
	(ii)	Consolidated Statements of Income for the years ended June 30, 2012, 2011 and 2010;
	(iii)	Consolidated Statements of Cash Flows for the years ended June 30, 2012, 2011 and 2010;
	(iv)	Consolidated Balance Sheets as of June 30, 2012 and 2011;
	(v)	Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2012, 2011 and 2010;
	(vi)	Notes to Consolidated Financial Statements;
	(vii)	Schedule II – Valuation and Qualifying Accounts for the years ended June 30, 2012, 2011 and 2010.
	Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospects for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

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 28th day of August, 2012.

	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 28, 2012
(Glenn R. Jennings)	and Chief Executive Officer

(ii) Principal Financial Officer

/s/John B. Brown	Chief Financial Officer,	August 28, 2012
(John B. Brown)	Treasurer and Secretary

(iii) Principal Accounting Officer:

/s/ Matthew D. Wesolosky	Vice President - Controller	August 28, 2012
(Matthew D. Wesolosky)

(iv) A Majority of the Board of Directors:

/s/Glenn R. Jennings	Chairman of the Board, President	August 28, 2012
(Glenn R. Jennings)	and Chief Executive Officer

/s/Lanny D. Greer	Director	August 28, 2012
(Lanny D. Greer)

/s/Edward J. Holmes	Director	August 28, 2012
(Edward J. Holmes)

/s/Michael J. Kistner	Director	August 28, 2012
(Michael J. Kistner)

/s/Lewis N. Melton	Director	August 28, 2012
(Lewis N. Melton)

/s/Arthur E. Walker, Jr.	Director	August 28, 2012
(Arthur E. Walker, Jr.)

/s/Michael R. Whitley	Director	August 28, 2012
(Michael R. Whitley)

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. and subsidiaries (the "Company") as of June 30, 2012 and 2011, and the related consolidated statements of income, changes in shareholders' equity, and cash flows for each of the three years in the period ended June 30, 2012. 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 Delta Natural Gas Company, Inc. and subsidiaries as of June 30, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2012, 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.

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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated August 28, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

August 28, 2012

Delta Natural Gas Company, Inc.

Consolidated Statements of Income

For the Years Ended June 30,			2012		2011		2010

Operating Revenues
Regulated revenues		$	42,655,378	$	48,697,530	$	45,675,860
Non-regulated revenues			31,422,944		34,342,721		30,746,208
Total operating revenues		$	74,078,322	$	83,040,251	$	76,422,068

Operating Expenses
Regulated purchased gas		$	15,703,114	$	21,077,548	$	20,518,120
Non-regulated purchased gas			23,380,426		26,761,726		23,582,209
Operation and maintenance			13,651,689		14,065,725		13,456,449
Depreciation and amortization			5,923,775		5,156,973		3,941,353
Taxes other than income taxes			2,154,090		1,916,485		2,019,443
Total operating expenses		$	60,813,094	$	68,978,457	$	63,517,574

Operating Income		$	13,265,228	$	14,061,794	$	12,904,494

Other Income and Deductions, Net		$	75,170	$	151,506	$	108,800

Interest Charges
Interest on long-term debt		$	2,984,413	$	3,584,772	$	3,606,086
Other interest			984,612		116,763		175,843
Amortization of debt expense			329,231		387,263		387,263
Total interest charges		$	4,298,256	$	4,088,798	$	4,169,192


Net Income Before Income Taxes		$	9,042,142	$	10,124,502	$	8,844,102

Income Tax Expense		$	3,258,144	$	3,759,607	$	3,192,285

Net Income		$	5,783,998	$	6,364,895	$	5,651,817

Earnings Per Common Share (Note 11)	��
Basic		$	.85	$	.95	$	.85
Diluted		$	.85	$	.95	$	.85

Dividends Declared Per Common Share		$	.70	$	.68	$	.65

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

Delta Natural Gas Company, Inc.

Consolidated Statements of Cash Flows

For the Years Ended June 30,		2012			2011			2010

Cash Flows From Operating Activities
Net income	$	5,783,998		$	6,364,895		$	5,651,817

Adjustments to reconcile net income to net
cash from operating activities
Depreciation and amortization		6,334,647			5,640,916			4,448,496
Deferred income taxes and investment
tax credits		2,513,400			2,536,234			5,015,750
Change in cash surrender value of officer's
life insurance		153			(58,744	)		(28,829	)
Share-based compensation		712,144			526,859			-

(Increase) decrease in assets
Accounts receivable		(1,407,711	)		(1,833,298	)		(845,479	)
Gas in storage		(121,547	)		(605,529	)		3,541,037
Deferred gas cost		(7,581	)		(81,799	)		(939,969	)
Materials and supplies		(51,724	)		20,629			143,764
Prepayments		(2,606,809	)		1,874,828			(1,473,433	)
Other assets		(548,470	)		(34,260	)		(285,347	)

Increase (decrease) in liabilities
Accounts payable		(3,518,540	)		1,936,487			1,706,121
Accrued taxes		2,695,526			122,358			256,066
Asset retirement obligations		1,085,920			(1,351,841	)		761,374
Other liabilities		2,650,640			(591,014	)		(351,057	)

Net cash provided by operating activities	$	13,514,046		$	14,466,721		$	17,600,311

Cash Flows From Investing Activities
Capital expenditures	$	(7,337,115	)	$	(8,123,479	)	$	(5,275,194	)
Proceeds from sale of property, plant and equipment		183,678			171,641			161,949
Other		141,530			431,897			60,422
Net cash used in investing activities	$	(7,011,907	)	$	(7,519,941	)	$	(5,052,823	)

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

Delta Natural Gas Company, Inc.

Consolidated Statements of Cash Flows (continued)

For the Years Ended June 30,		2012			2011			2010

Cash Flows From Financing Activities
Dividends on common shares	$	(4,762,257	)	$	(4,562,284	)	$	(4,323,439	)
Issuance of common shares		697,775			677,544			432,610
Debt issuance costs		(107,904	)		-			-
Issuance of long-term debt		58,000,000			-			-
Excess tax benefit from share-based compensation		21,563			-			-
Repayment of long-term debt		(57,951,006	)		(360,993	)		(487,000	)
Borrowings on bank line of credit		17,697,829			17,824,196			25,205,557
Repayment of bank line of credit		(17,697,829	)		(17,824,196	)		(28,858,660	)

Net cash used in financing activities	$	(4,101,829	)	$	(4,245,733	)	$	(8,030,932	)


Net Increase in Cash and Cash Equivalents	$	2,400,310		$	2,701,047		$	4,516,556


Cash and Cash Equivalents, Beginning of Year		7,340,192			4,639,145			122,589


Cash and Cash Equivalents, End of Year	$	9,740,502		$	7,340,192		$	4,639,145

Supplemental Disclosures of Cash Flow Information

Cash paid during the year for
Interest	$	3,795,590		$	3,702,692		$	3,785,630
Income taxes (net of refunds)	$	1,011,138		$	(124,861	)	$	(676,439	)

Significant non-cash transactions
Accrued capital expenditures	$	336,543		$	340,670		$	460,357
Loss on extinguishment of debt recognized as a regulatory asset (Note 10)	$	1,896,000		$	-		$	-

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

Delta Natural Gas Company, Inc.

Consolidated Balance Sheets

As of June 30,		2012			2011

Assets

Current Assets
Cash and cash equivalents	$	9,740,502		$	7,340,192
Accounts receivable, less accumulated allowances for doubtful		8,028,937			6,540,702
accounts of $157,000 and $190,000 in 2012 and 2011,
respectively
Gas in storage, at average cost (Notes 1 and 16)		6,932,807			6,811,260
Deferred gas costs (Notes 1 and 14)		3,386,292			3,378,711
Materials and supplies, at average cost		557,118			555,883
Prepayments		2,393,674			2,113,224

Total current assets	$	31,039,330		$	26,739,972

Property, Plant and Equipment	$	217,172,542		$	211,409,336
Less - Accumulated provision for depreciation		(82,835,542	)		(78,232,077	)

Net property, plant and equipment	$	134,337,000		$	133,177,259

Other Assets
Cash surrender value of life insurance
(face amount of $941,000 and $1,178,000 in 2012 and 2011, respectively)	$	307,125		$	508,808
Prepaid Pension (Note 6)		-			3,141,116
Regulatory assets (Note 1)		16,517,812			8,823,310
Unamortized debt expense (Notes 1 and 10)		104,104			1,994,788
Other non-current assets		589,992			510,986

Total other assets	$	17,519,033		$	14,979,008

Total assets	$	182,895,363		$	174,896,239

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

Delta Natural Gas Company, Inc.

Consolidated Balance Sheets (continued)

As of June 30,		2012		2011

Liabilities and Shareholders' Equity

Current Liabilities
Accounts payable	$	4,325,653	$	8,201,249
Current portion of long-term debt (Note 10)		1,500,000		1,200,000
Accrued taxes		4,154,064		1,447,094
Customers' deposits		853,061		643,692
Accrued interest on debt		1,026,387		852,952
Accrued vacation		736,856		707,544
Deferred income taxes		1,130,581		1,092,255
Other liabilities		436,281		317,867

Total current liabilities	$	14,162,883	$	14,462,653

Long-Term Debt (Note 10)	$	56,500,000	$	56,751,006

Long-Term Liabilities
Deferred income taxes	$	37,732,457	$	35,114,249
Investment tax credits		62,700		86,700
Regulatory liabilities (Note 1)		1,380,838		1,507,928
Accrued pension		2,307,260		-
Asset retirement obligations (Note 4)		3,823,724		2,560,796
Other long-term liabilities		705,094		645,723

Total long-term liabilities	$	46,012,073	$	39,915,396

Commitments and Contingencies (Note 13)

Total liabilities	$	116,674,956	$	111,129,055

Shareholders' Equity
Common shares ($1.00 par value), 20,000,000 shares authorized; 6,803,941 and 6,732,344 shares outstanding at June 30, 2012 and June 30, 2011, respectively	$	6,803,941	$	6,732,344
Premium on common shares		44,048,201		42,688,316
Retained earnings		15,368,265		14,346,524

Total shareholders' equity	$	66,220,407	$	63,767,184

Total liabilities and shareholders' equity	$	182,895,363	$	174,896,239

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

Delta Natural Gas Company, Inc.

Consolidated Statements of Changes in Shareholders' Equity

	Year Ended June 30, 2012
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity

Balance, beginning of period (Note 14)	$	6,732,344	$	42,688,316	$	14,346,524		$	63,767,184
Net income		-		-		5,783,998			5,783,998
Issuance of common shares		38,929		658,846		-			697,775
Issuance of common shares under the
incentive compensation plan		32,668		304,373		-			337,041
Share-based compensation expense		-		375,103		-			375,103
Tax benefit from share-based compensation		-		21,563		-			21,563
Dividends on common shares		-		-		(4,762,257	)		(4,762,257	)

Balance, end of period	$	6,803,941	$	44,048,201	$	15,368,265		$	66,220,407

	Year Ended June 30, 2011
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity

Balance, beginning of period (Note 14)	$	6,669,712	$	41,546,545	$	12,543,913		$	60,760,170
Net income		-		-		6,364,895			6,364,895
Issuance of common shares		44,632		632,912		-			677,544
Issuance of common shares under the
incentive compensation plan		18,000		245,970		-			263,970
Share-based compensation expense		-		262,889		-			262,889
Dividends on common shares		-		-		(4,562,284	)		(4,562,284	)

Balance, end of period	$	6,732,344	$	42,688,316	$	14,346,524		$	63,767,184

	Year Ended June 30, 2010
	Common Shares		Premium on Common Shares		Retained Earnings			Shareholders' Equity

Balance, beginning of period (Note 14)	$	6,636,092	$	41,147,555	$	11,215,535		$	58,999,182
Net income		-		-		5,651,817			5,651,817
Issuance of common shares		33,620		398,990		-			432,610
Issuance of common shares under the
incentive compensation plan		-		-		-			-
Share-based compensation expense		-		-		-			-
Dividends on common shares		-		-		(4,323,439	)		(4,323,439	)

Balance, end of period	$	6,669,712	$	41,546,545	$	12,543,913		$	60,760,170

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

DELTA NATURAL GAS COMPANY, INC.

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 36,000 customers. Our distribution and transportation systems are located in central and southeastern Kentucky and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market and we transport natural gas on behalf of local producers and customers not on our distribution system. We also sell liquids extracted from natural gas in our storage field and our distribution system. We have three wholly-owned subsidiaries. Delta Resources, Inc. ("Delta Resources") 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.

(b) 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.

(c) 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.

(d) 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. A betterment or replacement of a unit of property is accounted for as an addition of utility plant. 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, less salvage value, is charged to the accumulated provision for depreciation.

Property, plant and equipment is comprised of the following major classes of assets:

($000)	2012	2011

Regulated segment
Distribution, transmission and storage	192,107	182,041
General, miscellaneous and intangibles	21,963	21,847
Construction work in progress	724	5,142
Total regulated segment	214,794	209,030

Non-regulated segment	2,379	2,379
Total property, plant and equipment	217,173	211,409

We have a pipe replacement program approved by the Kentucky Public Service Commission, which allows us to adjust rates annually to earn a return on capital expenditures for the replacement of pipe and related facilities incurred subsequent to the test year in our most recent rate case. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.

(e) 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 2.9%, 2.6% and 2.1% of average depreciable plant for 2012, 2011 and 2010, respectively. Effective October, 2010 we implemented new depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case which decreased the remaining depreciable lives of our depreciable assets.

As approved by the Kentucky Public Service Commission, we accrue asset removal costs for certain types of property through depreciation expense with a corresponding increase to regulatory liabilities on the Consolidated Balance Sheet. When depreciable utility plant and equipment is retired any related removal costs incurred are charged against the regulatory liability.

(f) Maintenance All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts in the month incurred.

(g) Gas Cost Recovery Our regulated gas rates include a gas cost recovery clause approved by the Kentucky Public Service Commission 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. We expense gas costs based on the amount of gas costs recovered through revenue. Any differences between actual gas costs and those gas costs billed are deferred and reflected in the computation of future billings to customers using the gas cost recovery mechanism. Effective January, 2011, the uncollectible gas cost portion of bad debt expense is included as a component of the gas cost recovery clause.

(h) 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)	2012	2011

Unbilled revenues ($)	1,358	1,437
Unbilled gas costs ($)	392	410
Unbilled volumes (Mcf)	46	58

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

(i) 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.

(j) Revenues and Accounts Receivable Revenues and accounts receivable 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. Accounts receivable are charged off when deemed to be uncollectible or when turned over to a collection agency to pursue.

(k) Rate Regulated Basis of Accounting We account for our regulated segment in accordance with applicable regulatory guidance. 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:

($000)	2012	2011

Regulatory assets
Current assets
Deferred gas costs	3,386	3,379

Other assets
Conservation/efficiency program expenses	236	206
Loss on extinguishment of debt	3,636	1,967
Asset retirement obligations	3,001	2,391
Accrued pension	9,537	4,069
Regulatory case expenses	108	190
Total other assets	16,518	8,823

Total regulatory assets	19,904	12,202

Regulatory liabilities
Long-term liabilities
Accrued cost of removal on long-lived assets	338	346
Regulatory liability for deferred income taxes	1,043	1,162
Total regulatory liabilities	1,381	1,508

All of our regulatory assets and liabilities have been approved for recovery by the Kentucky Public Service Commission and are currently being recovered or refunded through our regulated gas rates. In addition, the unrecovered balance of the loss on extinguishment of debt is included in rate base and, therefore, earns a return. The weighted average recovery period of regulatory assets not earning a return is 19 years.

(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. There were no impairments of long-lived assets during 2012, 2011 and 2010.

(m) Derivatives Certain of our natural gas purchase and sale contracts qualify as derivatives. 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, that 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 in order to fully fund the related deferred compensation liability.

The assets of the trust consist of exchange traded mutual funds and are classified as trading 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.

(o) Fair Value Fair value is defined as the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. Fair value 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.

We determine fair value based on the following fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

•

Level 1 -

Observable inputs consisting of 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.

Although accounting standards permit entities to elect to measure many financial instruments and certain other items at fair value, we do not currently have any financial assets or financial liabilities for which this provision has been elected. However, in the future, we may elect to measure certain financial instruments at fair value in accordance with these standards.

(p) Gas In Storage 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. The potential exists for differences between actual volumes stored versus our perpetual records primarily due to differences in measurement of injections and withdrawals or the risks of gas escaping from the field. 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. The periodic analysis of the storage field data utilizes trends in the underlying data and can require multiple periods of observation to determine if differences exist. The analysis can result in adjustments to our perpetual inventory records. The gas in storage inventory is recorded at average cost.

(2) New Accounting Pronouncements

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

(3) Fair Value Measurements

Our financial assets and liabilities measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in other non-current assets on the Consolidated Balance Sheets. Contributions to the trust are presented in other investing activities on the Consolidated Statements of Cash Flows. The assets of the trust are recorded at fair value and consist of exchange traded mutual funds. The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy. The fair value of the trust assets are as follows:


($000)	2012	2011

Trust assets
Money market	6	5
U.S. equity securities	364	320
U.S. fixed income securities	220	186
	590	511

The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value. The fair value of the assets in our defined benefit retirement plan are disclosed in Note 6 of the Notes to Consolidated Financial Statements.

Our Series A Notes, Debentures and Insured Quarterly Notes, presented as current portion of long-term debt and long-term debt on the Consolidated Balance Sheets, are stated at historical cost. All of the Debentures and Insured Quarterly Notes were refinanced and redeemed in 2012. Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate. The credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date. The credit adjusted risk-free rate for our 7% Debentures and 5.75% Insured Quarterly Notes was based on trades of our 7% Debentures at the measurement date. The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy. The Insured Quarterly Notes contained insurance that provided for the continuing payment of principal and interest to the holders in the event we defaulted on the Insured Quarterly Notes. Upon default, the insurer would have paid interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation would have transferred to the insurer. Therefore, the insurance was not considered in the determination of the fair value of the Insured Quarterly Notes.


	2012		2011
	Carrying	Fair	Carrying	Fair
($000)	Amount	Value	Amount	Value

4.26% Series A Notes	58,000	59,027	-	-
7% Debentures	-	-	19,410	18,988
5.75% Insured Quarterly Notes	-	-	38,541	34,400

(4) Asset Retirement Obligations

Legal obligations

As of June 30, 2012 and 2011, 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. During the fiscal year ended 2012, we recognized asset retirement obligations for mains and services placed into service in the amount of $16,000. In 2012, our asset retirement obligations increased to reflect revisions to the estimated cost to retire certain services. In 2011, our asset retirement obligations increased to reflect revisions to the estimated cost to retire certain mains and wells. 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 regulatory accounting standards, as we recover the cost of removing our regulated assets through our depreciation rates.

The following is a summary of our asset retirement obligations as shown as asset retirement obligations on the accompanying Consolidated Balance Sheets:


($000)	2012		2011

Asset Retirement Obligations
Balance, Beginning of Period	2,561		2,201
Liabilities incurred	16		1
Liabilities settled	(552	)	(434	)
Accretion	207		167
Revisions in estimated cash flows	1,592		626
Balance, End of Period	3,824		2,561

We have an additional asset retirement obligation related 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 wells.

Non-legal obligations

In accordance with established regulatory practices, we accrue costs of removal on long-lived assets through depreciation expense to the extent recovery of such costs is granted by our regulator even though such costs do not represent legal obligations. In accordance with regulatory accounting standards, $338,000 and $346,000 of such accrued cost of removal was recorded as a regulatory liability on the accompanying Consolidated Balance Sheets as of June 30, 2012 and 2011, respectively.

(5) 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:

($000)	2012		2011

Deferred Tax Liabilities
Current
Deferred gas cost	(1,170	)	(1,282	)
Prepaid expenses	(319	)	(346	)
	(1,489	)	(1,628	)

Non-Current
Accelerated depreciation	(34,955	)	(32,827	)
Other	(1,077	)	(506	)
Pension	-		(1,035	)
Regulatory assets - asset retirement obligations	(640	)	(589	)
Regulatory assets - loss on extinguishment of debt	(1,380	)	(747	)
Regulatory assets - unrecognized accrued pension	(3,620	)	(1,545	)
Regulatory liabilities	(1,268	)	(1,269	)
	(42,940	)	(38,518	)

Total deferred tax liabilities	(44,429	)	(40,146	)

Deferred Tax Assets
Current
Accrued employee benefits	238		248
Bad debt reserve	57		81
Other	63		91
State net operating loss carryforward	-		116
	358		536

Non-Current
Accrued employee benefits	653		517
Alternative minimum tax credits	-		36
Asset retirement obligations	1,389		910
Investment tax credits	38		53
Other	505		122
Pension	886		-
Regulatory liabilities	1,650		1,689
Section 263 (a) capitalized costs	87		77
	5,208		3,404

Total deferred tax assets	5,566		3,940

Net accumulated deferred income tax liability	(38,863	)	(36,206	)

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

($000)	2012	2011	2010

Components of Income Tax Expense
Current
Federal	525	956	(1,709	)
State	220	276	(115	)
Total	745	1,232	(1,824	)
Deferred	2,513	2,528	5,016
Income tax expense	3,258	3,760	3,192

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

(%)	2012		2011		2010

Statutory federal income tax rate	34.0		34.0		34.0
State income taxes, net of federal benefit	4.0		4.0		4.0
Amortization of investment tax credits	(0.3	)	(0.3	)	(0.3	)
Other differences, net	(1.7	)	(0.6	)	(1.6	)
Effective income tax rate	36.0		37.1		36.1

We recognize the income 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 $38,000 and $80,000 as of June 30, 2012 and 2011, respectively. As of June 30, 2012, we have accrued interest of $10,000 on unrecognized tax positions, of which $3,000 and $26,000 was recognized in the 2012 and 2011 Consolidated Statements of Income, respectively. We recognized interest income of $49,000 on unrecognized tax positions in 2012.

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

($000)	2012		2011

Balance, Beginning of Period	266		194
Gross increases
Tax positions in prior period	131		102
Gross decreases
Tax positions in prior period	(197	)	(30	)
Balance, End of Period	200		266

We file income tax returns in the federal and Kentucky jurisdictions. Tax years previous to June 30, 2010 and June 30, 2008 are no longer subject to examination for federal and Kentucky income taxes, respectively.

(6) Employee Benefit Plans

(a) Defined Benefit Retirement Plan We have a trusteed, noncontributory, defined benefit retirement 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 has historically made annual contributions equal to the amounts necessary to fund the plan adequately.

Generally accepted accounting principles ("GAAP") require employers who sponsor defined benefit plans to recognize the funded status of a defined benefit pension plan on the balance sheet and to recognize through comprehensive income the changes in the funded status in the year in which the changes occur. However, regulatory accounting standards provide that regulated entities can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current cost-of-service ratemaking in Kentucky allows recovery of net periodic benefit cost as determined under GAAP. 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 recognized in future net periodic benefit cost. 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, 2012 and June 30, 2011, respectively, are as follows:

($000)	2012		2011

Change in Benefit Obligation
Benefit obligation at beginning of year	17,915		16,506
Service cost	921		939
Interest cost	921		854
Actuarial loss	3,994		64
Benefits paid	(473	)	(448)
Benefit obligation at end of year	23,278		17,915

Change in Plan Assets
Fair value of plan assets at beginning of year	21,056		15,288
Actual return on plan assets	(112	)	4,216
Employer contributions	500		2,000
Benefits paid	(473	)	(448)
Fair value of plan assets at end of year	20,971		21,056

Recognized Amounts
Projected benefit obligation	(23,278	)	(17,915)
Plan assets at fair value	20,971		21,056
Funded status	(2,307	)	3,141


Net amount recognized as prepaid (accrued) benefit costs on the Consolidated Balance Sheets		(2,307	)	3,141

	2012		2011

Items Not Yet Recognized as a Component of Net Periodic Benefit Costs
Prior service cost	(489	)	(576	)
Net loss	10,026		4,645
Amounts recognized as regulatory assets	9,537		4,069

The accumulated benefit obligation was $20,125,000 and $15,721,000 for 2012 and 2011, respectively.

($000)	2012		2011		2010

Components of Net Periodic Benefit Cost
Service cost	921		939		727
Interest cost	921		854		855
Expected return on plan assets	(1,474	)	(1,079	)	(953	)
Amortization of unrecognized net loss	200		501		497
Amortization of prior service cost	(87	)	(86	)	(86	)
Net periodic benefit cost	481		1,129		1,040

Weighted-Average % Assumptions Used to Determine Benefit Obligations
Discount rate	4.0		5.25		5.25
Rate of compensation increase	4.0		4.0		4.0

Weighted-Average % Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	5.25		5.25		6.25
Expected long-term return on plan assets	7.0		7.0		7.0
Rate of compensation increase	4.0		4.0		4.0

Plan Assets

Our target investment allocations have been developed using an asset allocation model which weighs risk versus return of various investment indices to create a target asset allocation to maximize return subject to a moderate amount of portfolio risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolios contain a diversified blend of equity and fixed income investments. Our target investment allocations are approximately 70% equity investments and 30% fixed income investments. Our equity investment target allocations are heavily weighted toward domestic equity securities, with allocations to real estate equity securities and foreign equity securities for the purposes of diversification. Fixed income securities primarily include U.S. government obligations and corporate debt securities. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

The assets of the plan are comprised of investments in mutual funds and common collective trusts. Each individual mutual fund or common collective trust has been selected based on its investment strategy, which approximates a specific asset class within our target allocation.

		Actual Allocation
	Target
(%)	Allocation	2012	2011
Asset Class (a)
Cash	2	-	-

Equity Securities
U.S. Equity Securities	48	48	47
Foreign Equity Securities	14	13	16
Domestic Real Estate	6	13	12
	68	74	75

Fixed Income Securities	30	26	25
	100	100	100

(a) Each mutual fund and common collective trust has been categorized based on its primary investment strategy.

The mutual funds are categorized as Level 1 in the fair value hierarchy as the fair value of the mutual funds is determined based on the quoted market price of each fund. The common/collective trusts are categorized as Level 2 in the fair value hierarchy. The fair value of the common/collective trusts are determined based on the net asset value as published by the respective fund manager multiplied by the number of units held in the trust. For our investments in the common/collective trusts, there are no restrictions on our ability to sell these investments. The respective level within the fair value hierarchy is determined as described in Note 1 of the Notes to Consolidated Financial Statements. The following represents the fair value of plan assets:


($000)	2012	Level 1	Level 2	Level 3
Asset Class (a)
Cash	31	31	-	-

Exchange Traded Mutual Funds
U.S. Equity Securities	696	696	-	-
Fixed Income Securities	1,115	1,115	-	-
Foreign Equity Securities	1,062	1,062	-	-
Domestic Real Estate Securities	2,737	2,737	-	-
	5,610	5,610

Common Collective Trusts
Short-Term Income Fund	148	-	148	-
U.S. Fixed Income Fund	2,202	-	2,202	-
Global Equity Growth Fund	2,472	-	2,472	-
Global Equity Value Fund	1,136	-	1,136	-
U.S. Equity Index Fund	2,098	-	2,098	-
Foreign Equity Index Fund	1,694	-	1,694	-
Blended Fund (b)	5,580	-	5,580	-
	15,330	-	15,330	-

Total	20,971	5,641	15,330	-


($000)	2011	Level 1	Level 2	Level 3
Asset Class (a)
Cash	21	21	-	-

Exchange Traded Mutual Funds
U.S. Equity Securities	717	717	-	-
Fixed Income Securities	1,098	1,098	-	-
Foreign Equity Securities	1,263	1,263	-	-
Domestic Real Estate Securities	2,442	2,442	-	-
	5,520	5,520	-	-

Common Collective Trusts
Short-Term Income Fund	68	-	68	-
U.S. Fixed Income Fund	2,179	-	2,179	-
Global Equity Growth Fund	2,559	-	2,559	-
Global Equity Value Fund	1,150	-	1,150	-
U.S. Equity Index Fund	2,000	-	2,000	-
Foreign Equity Index Fund	2,039	-	2,039	-
Blended Fund (b)	5,520	-	5,520	-
	15,515	-	15,515	-

Total	21,056	5,541	15,515	-

(a) Each mutual fund and common collective trust has been categorized based on its primary investment

strategy.

(b) The blended fund is a combination of the U.S. equity securities (65%) and U.S. fixed income securities (35%).

We determined the expected long-term rate of return for plan assets with input from plan actuaries and investment consultants based upon many factors including asset allocations, historical asset returns and expected future market conditions. The discount rates used by the Company for valuing pension liabilities are based on a review of high quality corporate bond yields with maturities approximating the remaining life of the projected benefit obligations.

We made $500,000 of discretionary contributions to the defined benefit plan in fiscal 2012. We made an additional $2,300,000 discretionary contribution to the defined benefit plan in August, 2012.

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

($000)

2013			911
2014			650
2015			2,520
2016			854
2017			1,278
2018 - 2022			6,669

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

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. Employees hired after May 9, 2008, who are not eligible to participate in the defined benefit retirement plan, annually receive an additional 4% non-elective contribution into their Savings Plan account. Company contributions are discretionary and subject to change with approval from our Board of Directors. For 2012, 2011 and 2010, Delta's Savings Plan expense was $325,000, $301,000 and $293,000, 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, 2012 and 2011, the irrevocable trust assets are $590,000 and $511,000, respectively. These amounts are included in other non-current assets on the accompanying Consolidated Balance Sheets. Liabilities, in corresponding amounts, are included in other long-term liabilities on the accompanying Consolidated Balance Sheets.

(7) 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 38,929, 44,632 and 33,620 shares in 2012, 2011 and 2010, respectively. We registered 200,000 shares for issuance under the Reinvestment Plan in 2006, and as of June 30, 2012 there were 71,000 shares available for issuance. The number of shares registered and available for issuance as of June 30, 2012 does not reflect the stock split distributed on May 1, 2012. We intend, simultaneous with filing our report on Form 10-K for the year ended June 30, 2012, to amend the registration statement for our Reinvestment Plan to include additional shares reflective of the stock split. Upon amending the registration statement, we then would have 150,000 shares registered and available for issuance under the Reinvestment Plan.

(8) Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk. We purchase our gas supply through a combination of spot market natural gas purchases and forward natural gas purchases. We mitigate price risk by efforts to balance supply and demand. None of our natural gas contracts are accounted for using the fair value method of accounting. While some of our natural gas purchase contracts and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

(9) Notes Payable

The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available as of June 30, 2012 and June 30, 2011. The maximum amount borrowed during 2012 and 2011 was $6,491,000 and $7,709,000, respectively. The bank line of credit extends through June 30, 2013. The interest rate on the used line of credit is the London Interbank Offered Rate plus 1.15%. The annual cost of the unused bank line of credit is .125%. We were not in default on our bank line of credit during any period presented in the Consolidated Financial Statements.

(10) Long-Term Debt

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

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

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031. Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. The following table summarizes the contractual maturities of our Series A Notes by fiscal year:

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

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

In April, 2006, we issued $40,000,000 of 5.75% Insured Quarterly Notes that were scheduled to mature in April, 2021 and were redeemed in December, 2012. Redemption of up to $25,000 annually was made on behalf of individual deceased holders, up to an aggregate of $800,000 annually for all deceased beneficial owners. In the event of default on the Insured Quarterly Notes, the holders were insured for both principal and interest payments. The insurer would have continued 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 were scheduled to mature in February, 2023 and were redeemed in December, 2012. Redemption of up to $25,000 annually was made on behalf of individual deceased holders, up to an aggregate of $400,000 annually for all deceased beneficial owners.

We amortize debt issuance expenses over the life of the related debt using the effective interest method. At June 30, 2012 and 2011, the unamortized balance was $3,740,000 and $3,961,000, respectively. Loss on extinguishment of debt of $3,636,000 and $1,967,000 included in the above has been deferred as a regulatory asset and is being amortized over the term of the related debt consistent with regulatory accounting as further discussed in Note 1 of the Notes to Consolidated Financial Statements.

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

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

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

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

As of June 30, 2012, we were in compliance with all financial covenants.

The following table shows the required and actual financial covenants under our Series A Notes as of June 30, 2012:

Requirement		Actual

Tangible net worth	no less than $25,800,000	$	64,306,718
Debt to capitalization ratio	no more than 70%		47	%
Fixed charge coverage ratio	no less than 1.20x		6.02x
Dividends paid	no more than $21,662,000	$	3,575,000

Our 4.26% Series A Notes restrict us from:

·	with limited exceptions, granting or permitting liens on or security interests in our properties,

·	selling a subsidiary, except in limited circumstances,

·	incurring secured debt, or permitting a Subsidiary to incur debt or issue preferred stock to any third party, in an aggregate amount that exceeds 10% of our tangible net worth,

·	changing the general nature of our business,

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

·	merge with another entity,

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

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

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

(11)	Earnings per Share

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



	2012		2011		2010
Numerator - Basic and Diluted
Net Income ($000)	5,784		6,365		5,652
Dividends paid ($000)	(4,762	)	(4,562	)	(4,323	)

Undistributed earnings ($000)	1,022		1,803		1,329
Percentage allocated to common shares (a)	99.6	%	99.9	%	100.00	%

Undistributed earnings allocated to common shares ($000)	1,018		1,801		1,329
Dividends declared allocated to common shares ($000)	4,747		4,557		4,323

Net income available to common shares ($000)	5,765		6,358		5,652

Denominator - Basic
Weighted-average
Common shares (b)	6,777,186		6,707,224		6,652,320
Incremental unvested non-participating shares (b)(c)	-		5,580		-

Denominator - Diluted	6,777,186		6,712,804		6,652,320

Per common share net income ($)(b)
Basic	.85		.95		.85
Diluted	.85		.95		.85


(a) Percentage allocated to common shares - weighted average
Common shares outstanding (b)	6,777,186		6,707,224		6,652,320
Unvested participating shares (b)(d)	28,082		8,000		-
Total	6,805,268		6,715,224		6,652,320
Percentage allocated to common shares	99.6	%	99.9	%	100.0	%

(b)	In accordance with the provisions of our incentive compensation plan, all unvested shares have been adjusted for the two-for-one stock split distributed in May, 2012, as further discussed in Note 17 of the Notes to Consolidated Financial Statements.

(c)

Under our Incentive Compensation Plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 18 of the Notes to Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end, as further discussed in (d). The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.

(d)

Certain awards under our shareholder approved incentive compensation plan, as further discussed in Note 18 of the Notes to Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. There were 48,000 and 32,000 unvested participating shares outstanding as of June 30, 2012 and 2011, respectively. There were no unvested participating shares as of June 30, 2010.

(12) 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 $70,000, $72,000 and $74,000 for the years ended June 30, 2012, 2011 and 2010, respectively.

(13) Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in control agreements with our other four officers. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company. In the event all of these agreements were exercised in the form of lump sum payments, approximately $3.6 million would be paid in addition to continuation of specified benefits for up to five years. Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 18 of the Notes to Consolidated Financial Statements, would immediately vest.

The Kentucky Department of Revenue has assessed Delta Resources $5,565,000, which includes $3,013,000 in taxes, $1,963,000 in penalties and $589,000 in interest, for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011. The tax is a 3% license tax levied on the gross receipts derived from furnishing utility services and is passed through to customers. The Kentucky Department of Revenue has not asserted a claim for the tax periods after June, 2011 or for interest accrued subsequent to the initial assessments. Regarding the penalties, Kentucky law provides for the assessment of penalties for failure to pay a tax, unless it is shown to the satisfaction of the Kentucky Department of Revenue that the failure to pay is due to reasonable cause. Applicable regulatory authority provides that reasonable cause exists when the tax position is based on advice by a tax advisor on whom the taxpayer had a reasonable right to rely or substantial legal authority, as we have done in this matter. Therefore, as of June 30, 2012, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,932,000, which includes $3,055,000 in taxes and $877,000 in interest.

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

However, on October 7, 2011, the Kentucky Court of Appeals reversed the May, 2010 Fayette Circuit Court opinion, which had held that the Utility Gross Receipts License Tax did not apply to sales of gas by Constellation, a gas marketer, because it is not a utility. The opinion of the Kentucky Court of Appeals held that "because Constellation furnishes natural gas to Saint Joseph, Constellation is subject to imposition of the utility [gross receipts license] tax". Saint Joseph Health System, Inc. filed a petition for rehearing on October 27, 2011 on the grounds that the court's opinion was in direct conflict with the Kentucky Department of Revenue's long-standing statutory interpretation. The Kentucky Court of Appeals decided on January 30, 2012 to deny the petition. Saint Joseph Health System, Inc. filed a motion for discretionary review of this opinion by the Kentucky Supreme Court. We can neither predict whether such review will be granted nor, if review is granted, what the outcome of any such review may be. Therefore, we cannot predict the final judicial outcome of this case.

As a result of the uncertainty created by the October 7, 2011 opinion issued by the Kentucky Court of Appeals, we have accrued the total liability of $3,932,000 and began billing the Utility Gross Receipts License Tax to Delta Resources' customers prospectively with our October, 2011 billings. Since October, 2011, Delta Resources has billed its customers $154,000 for Utility Gross Receipts License Tax, substantially all of which has been collected. In the event we are unsuccessful in resolving our protest with the Kentucky Department of Revenue, of the $3,932,000 total liability, Delta Resources would have the right to seek reimbursement from its customers for the $3,055,000 of taxes, leaving Delta Resources liable for $877,000 of interest in addition to any uncollectible amounts. We estimate that Delta Resources' potential liability for interest and taxes deemed uncollectible from Delta Resources' customers to be in the range of $884,000 to $3,932,000. This estimate is based on the assumption that we will not be held liable for any penalties.

As of June 30, 2012, we recorded the total liability of $3,932,000, an unbilled receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $884,000 of expense related to interest and uncollectibles. Included in the receivable is $196,000 due from a Delta Resources customer that is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the June 30, 2012 Consolidated Balance Sheet, the liability for taxes is included in accrued taxes, the receivable from Delta Resources' customers is included in accounts receivable, less accumulated allowances for doubtful accounts, and the liability for interest is included in accrued interest on debt. In the June 30, 2012 Consolidated Statement of Income, interest accrued is included in interest charges and uncollectible amounts are included in operation and maintenance.

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

We have entered into forward purchase agreements beginning in November, 2011 and expiring at various dates through January, 2013. These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements. These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements. These agreements have aggregate remaining minimum purchase obligations of $391,000 for our fiscal year ending June 30, 2013.

(14) Regulatory Matters

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

In April, 2010, we filed a request for increased rates with the Kentucky Public Service Commission. This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000. The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12%. The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense. A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues is less dependent on customer usage and occurs more evenly throughout the year. The increased base rates were effective for service rendered on and after October 22, 2010.

In addition to the increased rates, our pipe replacement program was approved in our 2010 general rate case. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.

Additionally, we have a weather normalization provision in our 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.

The Kentucky Public Service Commission allows us 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, 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.

(15) Segment Information

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

In our non-regulated segment, two customers each provided more than 5% of our operating revenues. Our largest customer provided approximately $12,450,000, $11,461,000 and $6,722,000 of non-regulated revenues during 2012, 2011 and 2010, respectively. Our second largest customer provided approximately $6,815,000, $8,067,000 and $5,097,000 of non-regulated revenues during 2012, 2011 and 2010, respectively. There is no assurance that revenues from these customers will continue at these levels.

In 2012, 2011 and 2010, we purchased approximately 99% of our natural gas from Atmos Energy Marketing and M & B Gas Services.

The reportable 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 represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates. Operating expenses, taxes and interest are allocated to the non-regulated segment.

Segment information is shown in the following table:

($000)	2012		2011		2010
Operating Revenues
Regulated
External customers	42,655		48,697		45,676
Intersegment	3,704		3,777		3,441
Total regulated	46,359		52,474		49,117
Non-regulated
External customers	31,423		34,343		30,746
Eliminations for intersegment	(3,704	)	(3,777	)	(3,441	)
Total operating revenues	74,078		83,040		76,422

Operating Expenses
Regulated
Purchased gas	15,703		21,078		20,518
Depreciation	5,871		5,037		3,823
Other	13,909		14,318		15,105
Total regulated	35,483		40,433		39,446
Non-regulated
Purchased gas	23,380		26,762		23,582
Depreciation	53		120		118
Other	5,601		5,440		3,813
Total non-regulated	29,034		32,322		27,513
Eliminations for intersegment	(3,704	)	(3,777	)	(3,441	)
Total operating expenses	60,813		68,978		63,518

Other Income and Deductions, Net
Regulated	77		153		108
Non-regulated	(2	)	(1	)	-
Total other income and deductions	75		152		108

Interest Charges
Regulated	3,366		4,029		4,055
Non-regulated	932		60		114
Total interest charges	4,298		4,089		4,169

Income Tax Expense
Regulated	2,772	3,012	2,008
Non-regulated	486	748	1,184
Total income tax expense	3,258	3,760	3,192

Net Income
Regulated	4,990	5,153	3,717
Non-regulated	794	1,212	1,935
Total net income	5,784	6,365	5,652

Assets
Regulated	174,454	168,997	164,871
Non-regulated	8,441	5,899	3,761
Total assets	182,895	174,896	168,632

Capital Expenditures
Regulated	7,163	8,120	5,275
Non-regulated	174	3	-
Total capital expenditures	7,337	8,123	5,275

(16) Insurance Proceeds

In September, 2011, we received $300,000 of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company's underground storage field. These proceeds are included in operation and maintenance in the 2012 Consolidated Statement of Income.

(17) Two-for-One Stock Split

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

(18)	Share-Based Compensation

We have a shareholder approved incentive compensation plan (the "Plan") that provides for incentive compensation payable in shares of our common stock. The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining our employees, officers and outside directors who shall be eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan. In accordance with the provisions of the Plan, the number of shares that may be issued under the Plan and all unvested shares have been adjusted for the two-for-one stock split distributed May 1, 2012, as further discussed in Note 17 of the Notes to Consolidated Financial Statements.

The number of shares of our common stock which may be issued pursuant to the Plan may not exceed in the aggregate 1,000,000 shares. As of June 30, 2012, 901,000 shares of common stock were available for issuance under the Plan. Shares of common stock may be issued from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market.

Compensation expense for share-based compensation is recorded in operation and maintenance expense in the Consolidated Statement of Income based on the fair value of the awards at the grant date and is amortized over the requisite service period. Fair value is the closing price of our common shares at the grant date. The grant date is the date at which our commitment to issue the share-based awards arises, which is generally when the award is approved and the terms of the awards are communicated to the employee or director. We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met.



($000)	2012	2011	2010

Share-based compensation expense	712	527	-

In 2012, a $22,000 tax benefit was recognized as a premium on common shares on our Consolidated Balance Sheet, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation. This excess tax benefit can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods. In 2011, an immaterial tax deficiency was recognized in income tax expense.

Stock Awards

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

Performance Shares

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

As of June 30, 2012 the performance objectives for the 2012 performance shares have been satisfied and subject to further limitations of the plan, up to 27,000 unvested shares will be issued to the recipients, which contain a service condition whereby a recipient of the award shall vest in one-third increments each year beginning August 31, 2012 and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period. The performance objectives for the 2011 performance shares were met and 32,000 unvested shares were issued on August 31, 2011, of which 21,000 shares remain unvested as of June 30, 2012.

For 2012 and 2011, compensation expense related to the performance shares was $375,000 and $263,000, respectively. Compensation expense of $245,000 is expected to be recognized between 2013 and 2015 for the unvested shares.

Our performance shares have graded vesting schedules, and each separate annual vesting tranche is treated as a separate award for expense recognition. Compensation expense is amortized over the vesting period of the individual awards based on the probable outcome of meeting the performance objectives.

Since the performance condition has been satisfied, the holder of performance shares will have both dividend participation rights and voting rights during the remaining term of the awards. The holder becomes vested as a result of certain events such as death or disability of the holder. Subject to the satisfaction of the performance condition, the weighted average expected remaining vesting period at June 30, 2012 is 1.7 years. Holders of performance shares may not sell, transfer, or pledge their shares until the shares vest.

The following summarizes the activity for performance shares:

	Performance shares
	Number of shares		Weighted-average grant date fair value

Unvested shares at June 30, 2010		-	$	-
Granted (1)		32,000	$	14.67
Vested		-		-
Forfeited		-		-

Unvested shares at June 30, 2011	32,000		$	14.67
Granted (1)	36,000		$	15.32
Vested	(11,000	)		(14.67	)
Forfeited (2)	(9,000	)		(15.32	)
Unvested shares at June 30, 2012	48,000		$	15.03

(1)	Represents the maximum number of shares which could be issued based on achieving the performance criteria.

(2)	Adjusts the maximum number of shares which could have been issued in (1) to the actual number of shares which will be issued based on the actual performance criteria achieved.

(19) 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		Net Income (Loss)			Basic Earnings (Loss) per Common Share			Diluted Earnings (Loss) per Common Share

Fiscal 2012

September 30	$	12,896,327	$	566,101	$	(797,126	)	$	(.12	)	$	(.12	)
December 31		22,526,345		4,984,294		2,512,238			.37			.37
March 31		26,716,070		6,971,971		3,925,295			.58			.58
June 30		11,939,580		742,862		143,591			.02			.02


Fiscal 2011

September 30	$	10,016,478	$	234,448	$	(416,177	)	$	(.06	)	$	(.06	)
December 31		23,756,304		5,282,172		2,694,024			.40			.40
March 31		35,355,010		7,945,879		4,331,090			.64			.64
June 30		13,912,459		599,295		(244,042	)		(.03	)		(.03	)

(20) Subsequent Events

In August, 2012, 12,000 shares were awarded as a stock bonus for employees and officers and as equity compensation for members of the Board of Directors, which had a grant date fair value of $264,000. Additionally, in August, 2012, performance shares were awarded to the Company's executive officers. The performance share awards will vest only if the performance objective of the awards is met, which is based on the Company's fiscal 2013 audited earnings per share, before any cash bonuses or share-based compensation. Subject to further limitations described in the Incentive Compensation Plan and the Notice of Performance Share Awards, all performance shares paid shall be in the form of unvested shares, which contain a service condition whereby recipients of the awards shall vest in one-third increments each year beginning on August 31, 2013, and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period. The maximum number of shares which could be issued under the performance awards is 39,000, having a grant date fair value of $844,000.

SCHEDULE II

DELTA NATURAL GAS COMPANY, INC.

VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED JUNE 30, 2012, 2011 and 2010

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, 2012		$	190,000		$	127,891			$	168,204		$	329,095	$	157,000
June 30, 2011			273,000			67,359				170,810			321,169		190,000
June 30, 2010			819,000			(163,088	)			71,866			454,778		273,000

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Delta Natural Gas (DGAS) Inactive 10-K2012 FY Annual report

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