Item 405 of Regulation S-K 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 |X| Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer [ ] Accelerated filer |X| Non-accelerated filer [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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. $81,927,306 As of August 15, 2007, Delta Natural Gas Company, Inc. had outstanding 3,277,729 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, 2007, is incorporated by reference in Part III of this Report. ================================================================================ TABLE OF CONTENTS Page Number PART I Item 1. Business 2 Item 1A. Risk Factors 8 Item 1B. Unresolved Staff Comments 9 Item 2. Properties 10 Item 3. Legal Proceedings 10 Item 4. Submission of Matters to a Vote of Security Holders 10 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 11 Item 6. Selected Financial Data 13 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation 14 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 22 Item 8. Financial Statements and Supplementary Data 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 23 Item 9A. Controls and Procedures 23 Item 9B. Other Information 26 PART III Item 10. Directors, Executive Officers and Corporate Governance of the Registrant 26 Item 11. Executive Compensation 26 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 26 Item 13. Certain Relationships and Related Transactions, and Director Independence 26 Item 14. Principal Accountant Fees and Services 26 PART IV Item 15. Exhibits and Financial Statement Schedules 27 Signatures 29 PART I Item 1. Business General We sell and distribute or transport natural gas to approximately 39,000 customers. Our distribution system is located in central and southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market and we also transport natural gas on behalf of local producers and customers not on our distribution system. We produce a relatively small amount of natural gas from our southeastern Kentucky wells and own and operate an underground storage field. We seek to provide dependable, high-quality service to our customers while steadily enhancing value for our shareholders. Our efforts have been focused on developing a balance of regulated and non-regulated businesses to contribute to our earnings by profitably producing, selling and transporting gas in our service territory. We strive to achieve operational excellence through economical, reliable service and our emphasis on responsiveness to customers. We continue to invest in facilities for the transmission, distribution and storage of natural gas. We believe that our responsiveness to customers and the dependability of the service we provide afford us additional opportunities for growth. While we seek those opportunities, our strategy will continue a conservative approach that seeks to minimize our exposure to market risk arising from fluctuations in the prices of gas. We operate through two segments, a regulated segment and a non-regulated segment. See Note 14 of the Notes to Consolidated Financial Statements for a discussion of these segments. Through our regulated segment, we sell and distribute natural gas to our retail customers in 23 predominantly rural counties. In addition, our regulated segment transports gas to industrial customers on our system who purchase gas in the open market. Our regulated segment also transports gas on behalf of local producers and other customers not on our distribution system. Our results of operations and financial condition have been strengthened by regulatory developments in recent years, including a $2,756,000 revenue increase from our 2004 rate case, a weather normalization provision, which has reduced fluctuations in our earnings due to variations in weather, and a gas cost recovery clause, which mitigates market risk arising from fluctuations in the price of gas. We operate our non-regulated segment through three wholly-owned subsidiaries. Two of these subsidiaries, Delta Resources, Inc. and Delgasco, Inc., purchase natural gas on the national market and from Kentucky producers. We resell this gas to industrial customers on our distribution system and to others not on our system. Our third subsidiary that is part of the non-regulated segment, Enpro, Inc., produces natural gas that is sold on the non-regulated market. 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. Distribution and Transmission of Natural Gas 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. During the past several years, we have experienced reduced margins in our regulated retail sales business due to customer conservation. During 2007, this continued due to customers switching to alternate energy sources. 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. Factors that affect our revenues include rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition. Although the rules of the Kentucky Public Service Commission permit us to pass through to our customers changes in the price we must pay for our gas supply, increases in our rates to customers may cause our customers to conserve or to use alternative energy sources. Our retail sales are seasonal and temperature-sensitive, since the majority of the gas we sell is used for heating. Variations in the average temperature during the winter impact our revenues year-to-year. Kentucky Public Service Commission regulations, however, permit 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 retail customers. These alternate sources include electricity, coal, oil, propane and wood. Our non-regulated subsidiaries, which sell gas to industrial customers and others, compete with natural gas producers and natural gas marketers for those customers. Our larger customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers may undertake such a by-pass of our distribution system in order to achieve lower prices for their gas service. Our larger customers who are in close proximity to alternative supplies would be most likely to consider taking this action. Additionally, some of our industrial customers are able to switch economically to alternative sources of energy. These are competitive concerns that we continue to address. Some natural gas producers in our service area can access pipeline delivery systems other than ours, which generates competition for our transportation function. We continue our efforts to purchase or transport natural gas that is produced in reasonable proximity to our transportation facilities. As an active participant in many areas of the natural gas industry, we plan to continue efforts to expand our gas distribution system and customer base. We continue to consider acquisitions of other gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas. We anticipate continuing activity in gas production and transportation and plan to pursue and increase these activities wherever practicable. We continue to consider the construction, expansion or acquisition of additional transmission, storage and gathering facilities to provide for increased transportation, enhanced supply and system flexibility. Gas Supply We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2007, we purchased approximately 99% of our natural gas from interstate sources. Interstate Gas Supply We acquire our interstate gas supply from gas marketers. We currently have commodity requirements agreements for our Columbia Gas Transmission Corporation, Columbia Gulf Transmission Corporation and Tennessee Gas Pipeline supplied areas with Atmos Energy Marketing. Under these commodity requirements agreements, the gas marketer is obligated to supply the volumes consumed by our regulated customers in defined sections of our service areas. The gas we purchase under these agreements is priced at index-based market prices or at mutually agreed-to fixed prices. 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 sold. Consequently, the price we pay for interstate gas is based on current market prices. Our agreement with Atmos Energy Marketing for the Tennessee Gas Pipeline supplied service areas is for a term that expires on April 30, 2008, and shall continue year to year thereafter unless cancelled by either party by written notice at least sixty (60) days prior to the annual anniversary date of the agreement. Our agreement with Atmos, under which we purchase the natural gas transported for us by Columbia Gas and Columbia Gulf, became effective May 1, 2003. The term for the Atmos supply for our Columbia Gas contract expires on April 30, 2008, and shall continue year to year thereafter unless cancelled by either party by written notice at least sixty (60) days prior to the annual anniversary date of the agreement. We also purchase additional interstate natural gas from Atmos, as needed, in addition to our commodity requirements agreements with Atmos. 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 (60) days written notice. Delta's purchases from Atmos under this spot purchase agreement are generally month-to-month. However, Delta does have the option of forward-pricing gas for one or more months for the upcoming winter season. The price of gas under this agreement is based on current market prices, determined in a similar manner as under the commodity requirements contract with Atmos, with an agreed-to fixed price adjustment per million British Thermal Units purchased. In our fiscal year ended June 30, 2007, approximately 43% of Delta's gas supply was purchased under our agreements with Atmos. Delta purchases gas from M & B Gas Services, Inc. for injection into our underground natural gas storage field and to supply a portion of our system. We are not obligated to purchase any minimum quantities from M & B nor to purchase gas from M & B for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices. 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, 2007, approximately 56% of Delta's 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 Gas Pipeline Company, Columbia Gas Transmission Corporation, Columbia Gulf Transmission Corporation and Texas Eastern Transmission Corporation. Our agreements with Tennessee Gas Pipeline extend through 2008 and thereafter automatically renew for subsequent five-year terms unless terminated by one of the parties. Tennessee is obligated under these agreements to transport up to 19,600 thousand cubic feet ("Mcf") per day for us. During fiscal 2007, Tennessee transported a total of 1,012,000 Mcf for us under these contracts. Annually, approximately 26% of Delta's supply requirements flow through Tennessee to our points of receipt under our transportation agreements with Tennessee. We have gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee's production area storage fields and its market area storage fields, and we reserve the right to withdraw up to fixed daily volumes. These gas storage agreements terminate 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 2007 Columbia Gas and Columbia Gulf transported for us a total of 659,000 Mcf, or approximately 17% of Delta's supply requirements, under all of our agreements with them. All of our transport agreements with Columbia Gas and Columbia Gulf extend through 2008 and thereafter continue on a year-to-year basis until terminated by one of the parties. Columbia Gulf also transported additional volumes under agreements it has with M & B to a point of interconnection between Columbia Gulf and us where we purchase the gas to inject into our storage field, as discussed below. The amounts transported and sold to us under the agreement between Columbia Gulf and this gas marketer for fiscal 2007 constituted approximately 56% of Delta's 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 Energy Marketing has an arrangement with Texas Eastern to transport the gas to us that we purchase from that marketer, to supply our customers' requirements in specific geographic areas. Consequently, Texas Eastern transports a small percentage of our interstate gas supply. In our fiscal year ended June 30, 2007, Texas Eastern transported approximately 16,000 Mcf of natural gas to our system, which constituted less than 1% of our gas supply. Kentucky Gas Supply We have an agreement with Chesapeake Appalachia LLC to purchase natural gas through October 31, 2007, and thereafter it will renew on a year-to-year basis unless terminated by one of the parties. We purchased 44,000 Mcf from Chesapeake during fiscal 2007. The price for the gas we purchase from Chesapeake is based on the index price of spot gas delivered to Columbia Gas in the relevant region as reported in Platt's Inside FERC's Gas Market Report, plus a fixed adjustment per million British Thermal units of gas purchased. Chesapeake delivers this gas to our customers directly from its own pipelines. We own and operate an underground natural gas storage field that we use to store a significant portion of our winter gas supply needs. The storage gas is delivered during the summer injection season by Columbia Gulf on behalf of M & B to an interconnection point between Columbia Gulf and us where we purchase and receive the gas and flow it to our storage field. M & B arranges transportation of the gas through the Columbia Gulf system to us. This storage capability permits us to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months. We continue to maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of gas for our customers. Regulatory Matters The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and our transportation services. The Kentucky Public Service Commission's regulation of our business includes setting the rates we are permitted to charge our retail customers and our transportation customers. We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our retail gas and transportation services. Through these general rate cases, we are able to adjust the sales prices of our retail gas we sell or transport for our customers. On April 20, 2007, we filed a request for increased rates with the Kentucky Public Service Commission. This general rate case, Case No. 2007-00089, requested an annual revenue increase of approximately $5,642,000, an increase of 9.3%. The test year for the case was the twelve months ended December 31, 2006. The increased rates were requested to become effective May 20, 2007. This rate case requests a return on common equity of 12.1%. The request allocates a component of the requested increase to the monthly customer charge, thus helping to de-couple our revenues from volumes of gas sold. It also seeks a new Conservation/Efficiency Program Cost Recovery tariff to help promote conservation and the efficient use of natural gas by our residential customers. Additionally, we proposed an Experimental Customer Rate Stabilization Mechanism to help provide in the future for stable and equitable rates to customers by adjusting rates annually without customers having to pay for frequent and costly rate cases. The Kentucky Public Service Commission suspended the implementation of the proposed new rates until October 20, 2007, during which time our filing will be reviewed and the reasonableness of the proposed rates will be considered. A public hearing has been set for October 3, 2007 for the purpose of cross-examination of witnesses. Although management is of the opinion that its request is reasonable, it is unable to predict the outcome of the proceeding. The Kentucky Public Service Commission has also approved a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs. Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission. Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred. Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which allows us to adjust our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles. These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts. In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise. We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, either our franchises have expired, 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. Capital Expenditures Capital expenditures during 2007 were $8.1 million and for 2008 are estimated to be $5.7 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 line of credit. The current available line of credit is $40 million, of which $4.2 million had been borrowed at June 30, 2007. Present plans are to utilize the short-term line of credit to help meet planned capital expenditures and operating cash requirements. The amounts and types of future long-term debt and equity financings will depend upon our capital needs and market conditions. Employees On June 30, 2007, we had 157 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 1-800-SEC-0330. <TABLE> Consolidated Statistics For the Years Ended June 30, 2007 2006 2005 2004 2003 <CAPTION> Average Retail Customers Served <S> <C> <C> <C> <C> <C> Residential 31,941 32,601 33,284 33,570 33,757 Commercial 5,128 5,154 5,241 5,298 5,290 Industrial 59 59 60 61 63 Total 37,128 37,814 38,585 38,929 39,110 Operating Revenues ($000) Residential sales 28,648 35,240 29,172 28,737 26,749 Commercial sales 19,339 24,081 18,029 18,719 16,916 Industrial sales 1,676 2,356 1,744 1,731 1,607 Total regulated sales (a) 49,663 61,677 48,945 49,187 45,272 On-system transportation 4,258 4,371 4,312 3,854 3,873 Off-system transportation 2,979 2,543 2,099 2,104 1,560 Non-regulated sales 44,669 51,904 31,971 27,091 20,611 Other 242 250 211 205 195 Eliminations for intersegment (3,643) (3,498) (3,357) (3,247) (3,131) Total 98,168 117,247 84,181 79,194 68,380 System Throughput (Million Cu. Ft.) Residential sales 1,801 1,764 2,018 2,202 2,416 Commercial sales 1,345 1,313 1,381 1,529 1,627 Industrial sales 136 146 158 164 181 Total regulated sales (a) 3,282 3,223 3,557 3,895 4,224 On-system transportation 5,161 5,322 5,273 5,166 5,299 Off-system transportation 9,774 8,789 7,194 7,190 5,396 Non-regulated sales 4,921 4,398 3,924 3,958 3,591 Eliminations for intersegment (4,822) (4,313) (3,831) (3,918) (3,523) Total 18,316 17,419 16,117 16,291 14,987 Average Annual Consumption Per Average Residential Customer (Thousand Cu. Ft.) 56 54 61 66 72 Lexington, Kentucky Degree Days Actual 4,419 4,309 4,293 4,493 4,914 Percent of 30 year average 95 92 92 96 106 (a) 2005 regulated sales includes a $1,246,000 non-recurring increase in revenues due to the recording of 58,000 Mcf of unbilled sales at June 30, 2005. </TABLE> Item 1A. Risk Factors The risk factors below should be carefully considered. WEATHER CONDITIONS MAY CAUSE OUR REVENUES TO VARY FROM YEAR TO YEAR. Our revenues vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, which would reduce our revenues and profits. Our weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, only partially mitigates this risk. We adjust our rates to residential and small non-residential customers to reflect variations from thirty-year average weather for our December through April billing cycles. CHANGES IN FEDERAL REGULATIONS COULD REDUCE THE AVAILABILITY OR INCREASE THE COST OF OUR INTERSTATE GAS SUPPLY. We purchase almost all of our gas supply from interstate sources. For example, in our fiscal year ended June 30, 2007, approximately 99% of our gas supply was purchased from interstate sources. The Federal Energy Regulatory Commission regulates the transmission of the natural gas we receive from interstate sources, and it could increase our transportation costs or decrease our available pipeline capacity by changing its regulatory policies in a manner that could increase transportation rates or reduce pipeline or storage capacity available to us. OUR GAS SUPPLY DEPENDS UPON THE AVAILABILITY OF ADEQUATE PIPELINE TRANSPORTATION CAPACITY. We purchase almost all of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of gas. OUR CUSTOMERS ARE ABLE TO ACQUIRE NATURAL GAS WITHOUT USING OUR DISTRIBUTION SYSTEM. Our larger customers can obtain their natural gas supply by purchasing their natural gas directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers may undertake such a by-pass of our distribution system in order to achieve lower prices for their gas service. Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. This potential to by-pass our distribution system creates a risk of the loss of large customers and thus could result in lower revenues and profits. WE FACE REGULATORY UNCERTAINTY AT THE STATE LEVEL. We are regulated by the Kentucky Public Service Commission. Our regulated segment generates a significant portion of our income from operations. We face the risk that the Kentucky Public Service Commission may fail to grant us adequate and timely rate increases or may take other actions that would cause a reduction in our income from operations, such as limiting our ability to pass on to our customers our increased costs of natural gas. Such regulatory actions would decrease our revenues and our profitability. VOLATILITY IN THE PRICE OF NATURAL GAS COULD REDUCE OUR PROFITS. Significant increases in the price of natural gas will likely cause our regulated retail customers to continue to conserve or switch to alternate sources of energy. Any decrease in the volume of gas we sell that is caused by such actions will reduce our revenues and profits. Higher prices also make it more difficult to add new customers. Significant decreases in the price of natural gas will likely cause our non-regulated segment margins to decrease. WE DO NOT GENERATE SUFFICIENT CASH FLOWS TO MEET ALL OUR CASH NEEDS. Historically, we have made large capital expenditures in order to maintain, expand and upgrade our distribution and transmission system. As a result, we have funded a portion of our cash needs through borrowing and by offering new securities into the market. For example, by a combination of increasing our borrowings under our short-term line of credit and sales of securities through our dividend reinvestment plan and other offerings, we generated cash in the amount of $1,764,000 in fiscal 2006 and $1,987,000 in fiscal 2005. In fiscal 2007 cash provided by operating was sufficient to meet our financing needs and were able to make a net repayment on our short-term line of credit in the amount of $2,856,000. Although cash needs vary from year to year, our dependence on external sources of financing creates the risks that our profits could decrease as a result of high capital costs and that lenders could impose onerous and unfavorable terms on us as a condition to granting us loans. We also have the risk that we may not be able to secure external sources of cash necessary to fund our operations. SUBSTANTIAL OPERATIONAL RISKS ARE INVOLVED IN OPERATING A NATURAL GAS DISTRIBUTION, PIPELINE AND STORAGE SYSTEM AND SUCH OPERATIONAL RISKS COULD REDUCE OUR REVENUES AND INCREASE EXPENSES. There are substantial risks associated with the operation of a natural gas distribution, pipeline and storage system, such as operational hazards and unforeseen interruptions caused by events beyond our control. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond our control. These risks could result in injury or loss of life, extensive property damage and environmental pollution, which in turn could lead to substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. Liabilities incurred that are not fully covered by insurance could adversely affect our results of operations and financial condition. Additionally, interruptions to the operation of our gas distribution, transmission or storage system caused by such an event could reduce our revenues and increase our expenses. HURRICANES OR OTHER EXTREME WEATHER COULD INTERRUPT OUR GAS SUPPLY AND INCREASE NATURAL GAS PRICES. Hurricanes or other extreme weather could damage production or transportation facilities, which could result in decreased supplies of natural gas and increased supply costs for us and higher prices for our customers. CROSS-DEFAULT PROVISIONS IN OUR BORROWING ARRANGEMENTS INCREASE THE CONSEQUENCES OF A DEFAULT ON OUR PART. Each indenture under which our outstanding debt has been issued, and the loan agreement for our bank line of credit, contains a cross-default provision which provides that we will be in default under such indenture or loan agreement in the event of certain defaults under any of the other indentures or loan agreement. Accordingly, should an event of default occur under one of our debt agreements, we face the prospect of being in default under all of our debt agreements and obliged in such instance to satisfy all of our then-outstanding indebtedness. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us. OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS NEGATIVE COVENANTS THAT RESTRICT OUR ACTIVITIES. Our bank line of credit restricts us from: o merging with another entity, o selling a material portion of our assets other than in the ordinary course of business, o issuing stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, and o having any person hold more than twenty percent (20%) of our outstanding shares of common stock, without bank approval or repaying the bank line of credit. Our 7.00% Debentures and 5.75% Insured Quarterly Notes restrict us from: o preventing us from assuming additional mortgage indebtedness in excess of $5,000,000, o paying dividends on our common stock unless our consolidated shareholders' equity minus the value of our intangible assets exceed $25,800,000. These negative covenants create the risk that we may be unable to take advantage of business and financing opportunities as they arise. Item 1B. Unresolved Staff Comments None. Item 2. Properties We own our corporate headquarters in Winchester, Kentucky. We own ten buildings used for field operations in the cities we serve. Also, we own a building in Laurel County, Kentucky used for training and equipment and materials storage. We own approximately 2,500 miles of natural gas gathering, transmission, distribution, storage and service lines. These lines range in size up to twelve inches in diameter. We hold leases for the storage of natural gas under 8,000 acres located in Bell County, Kentucky. We developed this property for the underground storage of natural gas. We use all the properties described in the three paragraphs immediately above principally in connection with our regulated natural gas distribution, transmission and storage segment. See Note 14 of the Notes to Consolidated Financial Statements for a description of Delta's two business segments. Through our wholly-owned subsidiary, Enpro, we produce natural gas as part of the non-regulated segment of our business. Enpro owns interests in oil and natural gas leases on 10,300 acres located in Bell, Knox and Whitley Counties. Thirty-five gas wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated at 3.1 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 and are currently being developed. We have performed no reserve studies on these properties. Enpro produced a total of 183,000 Mcf of natural gas during fiscal 2007 from all the properties described in this paragraph. A producer is conducting exploration activities on part of Enpro's developed holdings. Enpro reserved the option to participate in wells drilled by this producer and also retained certain working and royalty interests in any production from future wells. Our assets have no significant encumbrances. Item 3. Legal Proceedings We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial condition or results of operations. Item 4. Submission of Matters to a Vote of Security Holders No matter was submitted during the fourth quarter of 2007. PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities We have paid cash dividends on our common stock each year since 1964. The frequency and amount of future dividends will depend upon our earnings, financial requirements and other relevant factors, including limitations imposed by the indenture for our Insured Quarterly Notes and Debentures. Our common stock is traded on the NASDAQ Global Market and trades under the symbol "DGAS". There were 1,908 record holders of our common stock as of August 15, 2007. The accompanying table sets forth, for the periods indicated, the high and low sales prices for the common stock on the NASDAQ Global Market and the cash dividends declared per share. Range of Stock Prices ($) Dividends High Low Per Share ($) Quarter Fiscal 2007 First 25.50 24.11 .305 Second 25.60 24.50 .305 Third 25.48 24.30 .305 Fourth 26.08 23.89 .305 Fiscal 2006 First 30.00 25.56 .30 Second 28.42 23.60 .30 Third 26.75 24.80 .30 Fourth 26.82 24.22 .30 The closing sale prices shown above reflect prices between dealers and do not include markups or markdowns or commissions and may not necessarily represent actual transactions. In July, 2004, we distributed 4,826 shares of our common stock to our employees under our Employee Stock Purchase Plan (see Note 5(c) of the Notes to Consolidated Financial Statements). We received cash consideration for one half of those shares of $59,000, while one-half of the shares were provided to our employees without cash consideration as a part of our compensation and benefits for our employees. We discontinued our Employee Stock Purchase Plan after the July, 2004 distribution. We offered and sold our securities through our Employee Stock Purchase Plan pursuant to the exemption from registration provided by Rule 147 under the Securities Act of 1933. This exemption was available since we are incorporated and doing business in Kentucky, and all our eligible employees are residents of Kentucky. Our Employee Stock Purchase Plan was authorized by our Board of Directors but was not required to be submitted to our shareholders for approval. No underwriters were engaged in connection with any of the foregoing transactions, and thus no underwriter discounts or commissions were paid in connection with any of the foregoing. Comparison of Five-Year Cumulative Total Shareholder Return The following graph sets forth a comparison of five year cumulative total shareholder return (equal to dividends plus stock price appreciation) among our common shares, the Standard & Poor's 500 Stock Index, the Dow Jones Utilities Index and the Stifel, Nicolaus & Company, Incorporated Natural Gas Distribution Industry Index ("Industry Index") during the past five fiscal years. Information reflected on the graph assumes an investment of $100 on June 30, 2002 in each of our common shares, the Standard & Poor's Stock Index, the Dow Jones Utilities Index and the Industry Index. The Industry Index consists of six natural gas distribution companies chosen by Stifel, Nicolaus & Company, Incorporated. We are one of the companies included in the Industry Index. Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns. We presented the Industry Index in 2007 as we also presented this index in 2006. We also presented the Standard & Poor's 500 Stock Index and the Dow Jones Utilities Index for 2007, and we plan to present only these two indexes in subsequent years as they are published or line-of-business indexes. <TABLE> <CAPTION> 2002 2003 2004 2005 2006 2007 <S> <C> <C> <C> <C> <C> <C> Delta 100.0 114.3 126.5 138.2 137.1 152.3 Standard & Poor's 500 Stock Index 100.0 100.3 119.4 127.0 137.9 166.3 Dow Jones Utilities Index 100.0 96.1 110.5 159.2 176.5 219.1 Industry Index 100.0 114.0 128.2 149.4 164.1 192.7 </TABLE> <TABLE> Item 6. Selected Financial Data For the Years Ended June 30, 2007 2006 2005 2004 2003 Summary of Operations ($) <CAPTION> <S> <C> <C> <C> <C> <C> Operating revenues (a) 98,168,391 117,247,144 84,181,233 79,193,614 68,380,263 Operating income (a) 12,968,043 12,757,507 12,490,127 10,532,904 10,939,723 Net income (a) 5,298,347 5,024,635 4,998,619 3,838,059 3,850,607 Basic and diluted earnings per common share (a) 1.62 1.55 1.55 1.20 1.46 Dividends declared per common share 1.22 1.20 1.18 1.18 1.18 Weighted Average Number of Common Shares Outstanding (Basic and Diluted) 3,265,800 3,242,223 3,216,668 3,185,158 2,641,829 Total Assets ($) 160,400,950 155,554,125 144,762,217 138,372,129 133,287,316 Capitalization ($) Common shareholders' equity (b) 54,428,471 52,609,724 50,799,454 48,830,161 45,892,597 Long-term debt (b) 58,625,000 58,790,000 52,707,000 53,049,000 53,373,000 Total capitalization 113,053,471 111,399,724 103,506,454 101,879,161 99,265,597 Short-Term Debt ($)(b)(c) 5,389,918 8,246,434 7,609,122 6,388,180 2,681,099 Other Items ($) Capital expenditures 8,082,918 7,781,396 5,338,356 8,959,153 8,839,091 Total plant, before accumulated depreciation 187,148,032 182,155,110 174,711,253 170,337,427 163,745,044 (a) We recorded 58,000 Mcf of unbilled sales at June 30, 2005, resulting in non-recurring increases of $1,246,000 in operating revenues, $617,000 in operating income, $379,000 in net income and $.12 in basic and diluted earnings per common share for fiscal 2005. (b) During April, 2006, we issued $40,000,000 aggregate principal amount of 5.75% Insured Quarterly Notes due 2021. The net proceeds of the offering were $37,671,000. We used the net proceeds to redeem $23,700,000 and $10,200,000 aggregate principal amount of our 7.15% Debentures due 2018 and 6 5/8% Debentures due 2023, respectively. The remaining net proceeds of $3,830,000 were used to pay down our bank line of credit. (c) Includes current portion of long-term debt. </TABLE> Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Overview of 2007 and Future Outlook Overview The following is a discussion of the segments in which we compete, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during 2007. Our Company has two segments: (i) a regulated natural gas distribution, transmission and storage segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production. Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors. 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 unusual winter temperatures on our revenues is reduced given our ability to adjust our winter rates for residential and small non-residential customers in response to unusual winter temperatures. The Kentucky Public Service Commission sets the rates we are permitted to charge our customers in the regulated segment. We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our retail gas and transportation services. Through these general rate cases, we seek approval from the Kentucky Public Service Commission to adjust the rates we charge our customers. The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers. We control remaining expenses through budgeting, approval and review. Our non-regulated segment markets natural gas to large-use customers both on and off Delta's regulated system. We endeavor to enter sales agreements when we can match estimated demand with a supply that provides an acceptable margin. Earnings per share increased between 2007 and 2006 ($.07 per share) due to increased sales volumes in our non-regulated segment and increased retail sales and transportation volumes in our regulated segment, despite a decline in the number of regulated customers. Future Outlook In 2008 and beyond, our success will depend, in part, on our ability to maintain a reasonable rate of return in our regulated segment in light of higher gas prices and the resultant conservation by our customers and additional loss of customers switching to alternate energy sources. We filed for a general rate increase with the Kentucky Public Service Commission on April 20, 2007 to recover in rates our increased operating costs and a reasonable return on invested capital. This filing included the current usage patterns of our customers, and thus addressed the impacts of margin reductions experienced due to customer conservation as well as the loss of customers. We expect our non-regulated segment to continue to contribute to consolidated net income in 2008 as in recent years based on contracts currently in place. Future profitability of the non-regulated segment, though, is dependent on the business plans of a few large customers and the market prices of natural gas, which are both out of our control. If natural gas prices continue to decrease considerably, we expect to experience a corresponding decrease in our non-regulated segment margins. 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, deferred income taxes and changes in working capital. Our ability to maintain liquidity depends on our bank line of credit, shown as notes payable on the accompanying Consolidated Balance Sheets. Notes payable decreased to $4,190,000 at June 30, 2007, compared with $7,046,000 at June 30, 2006. The $2,856,000 decrease is attributable to increased internal cash flow. We generate internally only a portion of the cash necessary for our capital expenditure requirements. We made capital expenditures of $8,083,000, $7,781,000 and $5,338,000 during the fiscal years ended 2007, 2006 and 2005, respectively. We finance the balance of our capital expenditures on an interim basis through our bank line of credit. We periodically repay our short-term borrowings under our bank line of credit by using the net proceeds from the sale of long-term debt and equity securities, as was done in 2006 by a $3,830,000 repayment in connection with the issuance of the 5.75% Insured Quarterly Notes. Long-term debt decreased to $58,625,000 at June 30, 2007, compared with $58,790,000 at June 30, 2006. This $165,000 decrease resulted from provisions in the Debentures and Insured Quarterly Notes allowing limited redemptions to be made to certain holders or their beneficiaries. Cash and cash equivalents increased to $188,000 at June 30, 2007 compared with $150,000 at June 30, 2006. This $38,000 increase in cash and cash equivalents for the year ended June 30, 2007 is compared with the $22,000 increase and $41,000 decrease in cash and cash equivalents for the years ended June 30, 2006 and June 30, 2005, respectively, as shown in the following table: ($000) 2007 2006 2005 Provided by operating activities 14,486 6,423 7,372 Used in investing activities (7,936) (7,577) (5,263) Provided by (used in) financing activities (6,512) 1,177 (2,150) Increase (decrease) in cash and cash equivalents 38 23 (41) For the year ended June 30, 2007, cash provided by operating activities increased $8,063,000 as compared to 2006. The increase is attributable to a $24,909,000 decrease in cash paid for gas, partially offset by a decrease in cash received from customers in the amount of $16,052,000, both of which are a result of decreased sales volumes and cost of gas over the same time period (see related discussion in Results of Operations). For the year ended June 30, 2006, cash provided by operating activities decreased $949,000 as compared to 2005 due to increased income tax payments of $1,738,000 attributable to higher taxes payable as a result of the expiration of the bonus depreciation allowed under the Job Creation and Worker Assistance Act of 2002, which expired in 2005. The increase was partially offset by $793,000 of decreased gas costs relating to our deferred gas cost and gas payable accounts. Changes in cash used in investing activities result primarily from changes in the level of capital expenditures between years. For the year ended June 30, 2007, cash used in financing activities increased $7,689,000. The increase is attributable to increased net repayments on the bank line of credit in the amount of $3,944,000. An additional $3,480,000 was provided by financing activities in 2006 from the refinancing of the 7.15% and 6 5/8% Debentures. In 2007, there were no borrowings of long-term debt. For the year ended June 30, 2006, cash provided by financing activities increased by $3,327,000, as compared to 2005, primarily due to the issuance of the $40,000,000 5.75% Insured Quarterly Notes, offset partially by $2,300,000 in issuance costs and $33,900,000 in redemption of the 7.15% and 6 5/8% Debentures and limited redemptions made by certain holders or their beneficiaries of the outstanding Debentures. Cash Requirements Our capital expenditures result in a continued need for capital. These capital expenditures are being made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2008 to be $5.7 million. The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2007: <TABLE> Payments Due by Period <CAPTION> ($000) 2008 2009-2010 2011-2012 After 2012 Total <S> <C> <C> <C> <C> <C> Interest payments (a) $ 4,295 $ 7,588 $ 7,400 $ 36,100 $ 55,383 Long-term debt (b) 1,200 2,400 2,400 53,825 59,825 Pension contributions (c) 1,500 2,000 2,000 6,970 12,470 Total contractual $ 6,995 $ 11,988 $ 11,800 $ 96,895 $ 127,678 obligations </TABLE> (a) Our long-term debt, notes payable and customers' deposits all require interest payments. Interest payments are projected based on fiscal 2007 interest payments until the underlying debt matures. Interest on notes payable represents interest payments expected on the bank line of credit which extends through October 31, 2007. (b) See Note 9 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date. Our long-term debt does not have any sinking fund requirements. (c) Represents currently projected contributions to the defined benefit plan through 2017, as calculated by our actuary. All of our contracts to purchase gas are requirements based contracts and we do not have a minimum purchase obligation under these contracts. Additionally, all of our operating leases are year to year and cancelable at our option. See Note 12 of the Notes to Consolidated Financial Statements for other commitments and contingencies. Sufficiency of Future Cash Flows To the extent that internally generated cash is not sufficient to satisfy operating and capital expenditure requirements and to pay dividends, we will rely on our bank line of credit. Our current available bank line of credit is $40,000,000, of which $4,190,000 was borrowed at June 30, 2007 and classified as notes payable on the accompanying Consolidated Balance Sheets. The current bank line of credit is with Branch Banking and Trust Company and extends through October 31, 2007. We are in the process of extending this bank line of credit through October 31, 2009. We expect that internally generated cash, coupled with short-term and long-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future. Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices, and we continuously monitor our need to file rate requests with the Kentucky Public Service Commission for a general rate increase for our regulated services. On April 20, 2007, we filed a request for increased rates with the Kentucky Public Service Commission. This general rate case, Case No. 2007-00089, requested an annual revenue increase of approximately $5,642,000, an increase of 9.3%. The test year for the case was the twelve months ended December 31, 2006. The increased rates were requested to become effective May 20, 2007. This rate case requests a return on common equity of 12.1%. The request allocates a component of the requested increase to the monthly customer charge, thus helping to de-couple our revenues from volumes of gas sold. It also seeks a new Conservation/Efficiency Program Cost Recovery tariff to help promote conservation and the efficient use of natural gas by our residential customers. Additionally, we proposed an Experimental Customer Rate Stabilization Mechanism to help provide in the future for stable and equitable rates to customers by adjusting rates annually without customers having to pay for frequent and costly rate cases. The Kentucky Public Service Commission suspended the implementation of the proposed new rates until October 20, 2007, during which time our filing will be reviewed and the reasonableness of the proposed rates will be considered. A public hearing has been set for October 3, 2007 for the purpose of cross-examination of witnesses. Although management is of the opinion that its request is reasonable, it is unable to predict the outcome of the proceeding. Critical Accounting Policies and Estimates Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) 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: (1) the accounting estimate requires us to make assumptions about matters that were reasonably uncertain at the time the accounting estimate was made, and (2) 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 Financial Statements" in "Item 8. Financial Statements and Supplementary Data". We have other accounting policies that we consider to be significant; however, these policies do not meet the definition of critical accounting estimates, because they generally do not require us to make estimates or judgments that are particularly difficult or subjective. Regulatory Accounting Our accounting policies historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of Statement No. 71 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that the regulated segment no longer meets the criteria of regulatory accounting under Statement No. 71, that segment will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements. The application of Statement No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the Kentucky Public Service Commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or for probable future refunds to customers. We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that we will recover the regulatory assets that have been recorded. Pension Our reported costs of providing pension benefits (as described in Note 5(a) of the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs associated with our defined benefit pension plan, for example, are impacted by employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plan and earnings on plan assets. Changes made to the provisions of the plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs. Changes in pension obligations associated with the above factors may not be immediately recognized as pension costs on the income statement, but may be deferred and amortized in the future over the average remaining service period of active plan participants. For the years ended June 30, 2007, 2006 and 2005, we recorded pension costs for our defined benefit pension plan of $567,000, $717,000 and $556,000, respectively. Our pension plan assets are principally comprised of equity and fixed income investments. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs. 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 8 percent for 2007 and was based on our targeted asset allocation assumption of approximately 65 percent equity investments and approximately 35 percent fixed income investments. Our approximately 65 percent equity investment target includes allocations to domestic, international, and emerging markets. Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate. We calculate the expected return on assets in our determination of pension costs based on the market value of assets at the measurement date. Using the market value recognizes investment gains or losses in the year in which they occur. Based on an assumed long-term rate of return of 7 percent, discount rate of 5.8 percent, and various other assumptions, we estimate that our pension costs associated with our defined benefits pension plan will increase from $567,000 in 2007 to $670,000 in 2008. Modifying the expected long-term rate of return on our pension plan assets by .25 percent would change pension costs for 2008 by approximately $35,000. Increasing the discount rate assumption by .25 percent would decrease pension costs by approximately $24,000. Decreasing the discount rate assumption by .25 percent would increase pension costs by approximately $23,000. Accumulated Provisions for Doubtful Accounts We encounter risks associated with the collection of our accounts receivable. As such, we record a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, we primarily utilize our historical experience related to accounts written-off. Quarterly, at a minimum, we review the reserve for reasonableness based on the level of revenue and the aging of the receivable balance. The underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the Consolidated Income Statements and working capital. The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact operating income. Unbilled Revenues and Gas Costs At each month-end, we estimate the gas service that has been rendered from the latest date of each cycle meter reading to the 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 adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, during fiscal year 2003 and the primary impact was to change the method of accruing for gas well plugging and abandonment costs. We adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations as of June 30, 2006 and 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. These pronouncements require that the fair value of our retirement obligations be recorded at the time the obligations are incurred. These pronouncements do not require the recognition of asset retirement obligations with indeterminate useful lives. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time the liabilities are accreted for the change in their present value, through charges to depreciation, and the initial capitalized costs are depreciated over the useful lives of the related assets. For asset retirement obligations attributable to assets of our regulated operations, the depreciation and accretion are deferred as a regulatory asset. We must use judgment to identify all appropriate asset retirement obligations. The underlying assumptions used for the value of the retirement obligation and related capitalized costs can change from period to period. These assumptions include the estimated future retirement costs, the estimated retirement date and the assumed credit-adjusted risk-free interest rate. Our asset retirement obligations are discussed in Notes 2 and 3 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", "strives" ,"seeks", "will rely", "believes" and similar expressions. These forward-looking statements include, but are not limited to, statements about: o our operational plans, o the cost and availability of our natural gas supplies, o our capital expenditures, o sources and availability of funding for our operations and expansion, o our anticipated growth and growth opportunities through system expansion and acquisition, o competitive conditions that we face, o our production, storage, gathering and transportation activities, o acquisition of service franchises from local governments, o pension fund costs and management, o our contractual obligations and cash requirements, o management of our gas supply and risks due to potential fluctuation in the price of natural gas, o our revenues, income, margins and profitability, o our efforts to purchase and transport local produced natural gas, o recovery of regulatory assets, o regulatory and legislative matters, and o dividends. Our forward-looking statements are not guarantees of future performance and are based upon currently available competitive, financial and economic data along with our operating plans. Factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results include the impact or outcome of: o the ongoing restructuring of the natural gas industry and the outcome of the regulatory proceedings related to that restructuring, o the changing regulatory environment, generally, o a change in the rights under present regulatory rules to recover for costs of gas supply, other expenses and investments in capital assets, o uncertainty of our capital expenditure requirements, o changes in economic conditions, demographic patterns and weather conditions in our retail service areas, o changes affecting our costs of providing gas service, including changes in gas supply costs, interest rates, the availability of external sources of financing for our operations, tax laws, environmental laws and the general rate of inflation, o conservation by customers and loss of customers due to higher gas prices, o changes affecting the costs of competing energy alternatives and competing gas distributors, o changes in accounting principles and tax laws or the application of such principles and laws to us, and o other matters described in Item 1A. Risk Factors. Results of Operations Gross Margins Our regulated and non-regulated revenues, other than transportation, have offsetting gas expenses. Therefore, throughout the following Results of Operations, we refer to "gross margin". With respect to our regulated and non-regulated segments, gross margin refers to operating revenues less purchased gas, which can be derived directly from our Consolidated Statements of Income. Operating Income as presented on the Consolidated Statements of Income is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). "Gross margin" is a "non-GAAP financial measure", as defined in accordance with SEC rules. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. Natural gas prices are determined by an unregulated national market. Therefore, the price that we pay for natural gas fluctuates with national supply and demand. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for the impact of forward contracts. In the following table we set forth variations in our gross margins for the 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. 2007 compared 2006 compared ($000) to 2006 to 2005 Increase (decrease) in regulated Gross margins 333 (1,555) On-system transportation (112) 58 Off-system transportation 436 445 Other (155) (103) Total 502 (1,155) Increase in non-regulated Gross margins 615 1,384 Other 16 12 Total 631 1,396 Increase (decrease) in consolidated gross margins 1,133 241 Percentage increase (decrease) in regulated volumes Gas sales 1.8 (9.4) On-system transportation (3.0) 0.9 Off-system transportation 11.2 22.2 Percentage increase (decrease) in non-regulated gas sales volumes 11.9 12.1 Heating degree days were 95% of normal thirty year average temperatures for fiscal 2007, as compared with 92% of normal temperatures for 2006 and 92% of normal for 2005. 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. Gross margins increased $1,133,000 (4%) in 2007 due to an increase in non-regulated gross margins of $631,000 and a $502,000 increase in regulated gross margins. The $631,000 (7%) increase in non-regulated gross margins in 2007 is primarily attributable to a 523,000 Mcf (12%) increase in volumes sold. The $502,000 (2%) increase in regulated gross margins in 2007, is primarily attributable to a 985,000 Mcf increase in off-system transportation volumes (11%) and the 3% colder weather in 2007. These increases were offset by a 2% decrease in the number of regulated retail customers. Gross margins increased $241,000 (14%) in 2006 due to an increase in non-regulated gross margins of $1,396,000 offset by a $1,155,000 decrease in regulated gross margins. The $1,396,000 (19%) increase in non-regulated gross margins on sales in 2006 reflected a 12% increase in non-regulated gas sales volumes and higher natural gas prices during the period. Of the $1,155,000 (5%) decrease in regulated gross margins in 2006, $617,000 is non-recurring, relating to the initial recording in 2005 of unbilled regulated margins on 58,000 Mcf of unbilled regulated volumes as discussed in Note 1 of the Notes to Consolidated Financial Statements. Decreases of approximately $362,000 and $406,000 in regulated gross margins are attributable to a 2% decrease in the number of regulated retail customers and reduced usage due to customer conservation, respectively. These decreases in regulated retail sales were offset by a $503,000 increase in transportation revenues primarily due to increased volumes transported for gas producers. Depreciation The $494,000 (12%) increase in depreciation expenses for 2007 is primarily due to an increase in depreciable plant resulting from capital expenditures of $8,083,000 for the replacement and improvement of our transmission, distribution, gathering, storage and general facilities. Other Interest The decrease in other interest for 2007 of $169,000 (23%) was a result of decreased borrowings on our bank line of credit. The increase in other interest for 2006 of $315,000 (75%) was a result of increased borrowings and increased interest rates. Basic and Diluted Earnings Per Common Share For the fiscal years ended June 30, 2007, 2006 and 2005, our basic earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We have no potentially dilutive securities. As a result, our basic earnings per common share and our diluted earnings per common share are the same. Item 7A. Quantitative and Qualitative Disclosures About Market Risk We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. The price of spot market gas is based on the market price at the time of delivery. The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the gas. Additionally, we inject some of our gas purchases into gas storage facilities in the non-heating months and withdraw this gas from storage for delivery to customers during the heating season. For our regulated business, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism. Price risk for the non-regulated business is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand. In addition, we are exposed to price risk resulting from changes in the market price of gas on uncommitted gas volumes of our non-regulated companies. None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase contracts and gas sales contracts meet the definition of a derivative, we have designated these contracts as "normal purchases" and "normal sales" under Statement of Financial Accounting Standards No. 133, entitled Accounting for Derivative Instruments and Hedging Activities. We are exposed to risk resulting from changes in interest rates on our variable rate bank line of credit. The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate. The balance on our bank line of credit was $4,190,000 and $7,046,000 on June 30, 2007 and 2006, respectively. The weighted average interest rate on our bank line of credit was 6.32% and 6.13% as of June 30, 2007 and 2006, respectively. Based on the amount of our outstanding bank line of credit on June 30, 2007 and 2006, a one percent (one hundred basis points) increase in our average interest rate would result in a decrease in our annual pre-tax net income of $42,000 and $70,000, respectively. Item 8. Financial Statements and Supplementary Data INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE PAGE Report of Independent Registered Public Accounting Firm 30 Consolidated Statements of Income for the years ended June 30, 2007, 2006 and 2005 31 Consolidated Statements of Cash Flows for the years ended June 30, 2007, 2006 and 2005 32 Consolidated Balance Sheets as of June 30, 2007 and 2006 34 Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2007, 2006 and 2005 36 Consolidated Statements of Capitalization as of June 30, 2007 and 2006 37 Notes to Consolidated Financial Statements 38 Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2007, 2006 and 2005 52 Schedules other than those listed above are omitted because they are not required, are not applicable or the required information is shown in the financial statements or notes thereto. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's ("SEC") rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2007 and based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC's rules and forms. Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. 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, 2007 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, 2007. 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, 2007 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting. That report immediately follows: REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.: We have audited the internal control over financial reporting of Delta Natural Gas Company, Inc. (the "Company") as of June 30, 2007, 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. 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, 2007, 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 of the Company as of and for the year ended June 30, 2007 of the Company and our report dated August 28, 2007 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the Company's adoption of new accounting standards in 2006 and 2007. DELOITTE & TOUCHE LLP Cincinnati, Ohio August 28, 2007 Item 9B. Other Information None. PART III Item 10. Directors, Executive Officers and Corporate Governance of the Registrant We have a Business Code of Conduct and Ethics that applies to all Directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. You can find our Business Code of Conduct and Ethics on our website by going to the following address: http://www.deltagas.com. We will post any amendments to the Business Code of Conduct and Ethics, as well as any waivers that are required to be disclosed by the rules of either the Securities and Exchange Commission or the NASDAQ Global Market, on our website. Our Board of Directors has adopted charters for the Audit, Corporate Governance and Compensation and Executive Committees of the Board of Directors. You can find these documents on our website by going to the following address: http://www.deltagas.com and clicking on the appropriate link. You can also obtain a printed copy of any of the materials referred to above by contacting us at the following address: Delta Natural Gas Company, Inc. Attn: John B. Brown 3617 Lexington Road Winchester, KY 40391 (859) 744-6171 The Audit Committee of our Board of Directors is an "audit committee" for purposes of Section 3(a)(58) of the Securities Exchange Act of 1934. The other information required by this Item is incorporated herein by reference to the applicable information in the proxy statement for our 2007 annual meeting. Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services Registrant intends to file a definitive proxy statement with the Commission pursuant to Regulation 14A (17 CFR 240.14a) no later than 120 days after the close of the fiscal year. In accordance with General Instruction G(3) to Form 10-K, the information called for by Items 10 (except for the language above in Item 10 in this report), 11, 12, 13 and 14 is incorporated herein by reference to the definitive proxy statement. The Report on Executive Compensation included in the Company's definitive proxy statement shall not be deemed incorporated herein 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(i) Registrant's Amended and Restated Articles of Incorporation. 3(ii) Registrant's Amended and Restated By-Laws. 4(a) The Indenture dated March 1, 2006 in respect of 5.75% Insured Quarterly Notes due April 1, 2021, is incorporated herein by reference to Exhibit 4(d) to Delta's Form S-3 (Reg. No. 333-132322) dated March 31, 2006. 4(b) The Indenture dated January 1, 2003 in respect of 7% Debentures due February 1, 2023, is incorporated herein by reference to Exhibit 4(d) to Delta's Form S-2 (Reg. 333-100852) dated October 30, 2002. 10(a) Employment agreements between Registrant and four officers, those being John B. Brown, Johnny L. Caudill, Alan L. Heath and Glenn R. Jennings, are incorporated herein by reference to Exhibit 10(k) to Registrant's Form 10-Q (File No. 000-08788) for the period ended March 31, 2000. 10(b) Supplemental retirement benefit agreement and trust agreement between Registrant and Glenn R. Jennings is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated February 25, 2005. 10(c) Gas Sales Agreement, dated May 1, 2005, by and between the Registrant and Atmos Energy Marketing, L.L.C is filed herewith. 10(d) Gas Sales Agreement, dated May 1, 2003, by and between the Registrant and Atmos Energy Marketing, LLC is filed herewith. 10(e) Gas Transportation Agreement (Service Package 9069), dated December 19, 1994, by and between Tennessee Gas Pipeline Company and Registrant is incorporated herein by reference to Exhibit 10(e) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7, 2003. 10(f) GTS Service Agreement (Service Agreement No. 37815), dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Registrant is incorporated herein by reference to Exhibit 10(f) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7, 2003. 10(g) FTS1 Service Agreement (Service Agreement No. 4328), dated October 4, 1994, by and between Columbia Gulf Transmission Company and Registrant is incorporated herein by reference to Exhibit 10(g) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7, 2003. 10(h) Loan Agreement, dated October 31, 2002, by and between Branch Banking and Trust Company and Registrant is incorporated herein by reference to Exhibit 10(i) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7, 2003. 10(i) 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(j) 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(k) 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(l) 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(m) 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(n) 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(o) 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(p) Agreement to transport natural gas between Registrant and Nami Resources Company L.L.C. is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated March 23, 2005. 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. 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 29th day of August, 2007. 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 29, 2007 (Glenn R. Jennings) and Chief Executive Officer (ii) Principal Financial Officer and Principal Accounting Officer: /s/John B. Brown Chief Financial Officer, August 29, 2007 (John B. Brown) Treasurer and Secretary (iii) A Majority of the Board of Directors: /s/Donald R. Crowe Director August 29, 2007 (Donald R. Crowe) /s/Lanny D. Greer Director August 29, 2007 (Lanny D. Greer) /s/Billy Joe Hall Director August 29, 2007 (Billy Joe Hall) /s/Michael J. Kistner Director August 29, 2007 (Michael J. Kistner) /s/Lewis N. Melton Director August 29, 2007 (Lewis N. Melton) /s/Arthur E. Walker, Jr. Director August 29, 2007 (Arthur E. Walker, Jr.) /s/Michael R. Whitley Director August 29, 2007 (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 and statements of capitalization of Delta Natural Gas Company, Inc. and subsidiaries as of June 30, 2007 and 2006, 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, 2007. Our audits also included the consolidated financial statement schedule listed in the Index at Item 8. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic Consolidated Financial Statements taken as a whole, presents fairly, in all material respects, the information set forth therein. As discussed in Note 2 to the consolidated financial statements, effective June 30, 2006, the Company adopted Financial Accounting Standards Board Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." As discussed in Note 5 to the consolidated financial statements in 2007 the Company changed its method of accounting for its defined benefit pension plan as a result of adopting Statement of Financial Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans". We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of June 30, 2007, 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, 2007 expressed an unqualified opinion on the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP Cincinnati, Ohio August 28, 2007 <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Income <CAPTION> For the Years Ended June 30, 2007 2006 2005 <S> <C> <C> <C> Operating Revenues $ 98,168,391 $ 117,247,144 $ 84,181,233 Operating Expenses Purchased gas $ 66,060,368 $ 86,271,854 $ 53,446,986 Operation and maintenance 12,584,607 12,293,652 12,305,023 Depreciation 4,697,639 4,203,711 4,249,506 Taxes other than income taxes 1,857,734 1,720,420 1,689,591 Total operating expenses $ 85,200,348 $ 104,489,637 $ 71,691,106 Operating Income $ 12,968,043 $ 12,757,507 $ 12,490,127 Other Income and Deductions, Net $ 134,265 $ 227,636 $ 112,737 Interest Charges Interest on long-term debt $ 3,694,389 $ 3,968,993 $ 3,809,693 Other interest 565,790 735,082 419,568 Amortization of debt expense 387,082 273,533 236,184 Total interest charges $ 4,647,261 $ 4,977,608 $ 4,465,445 Income Before Income Taxes $ 8,455,047 $ 8,007,535 $ 8,137,419 Income Tax Expense $ 3,156,700 $ 2,982,900 $ 3,138,800 Net Income $ 5,298,347 $ 5,024,635 $ 4,998,619 Basic and Diluted Earnings Per Common Share $ 1.62 $ 1.55 $ 1.55 Weighted Average Number of Common Shares Outstanding (Basic and Diluted) 3,265,800 3,242,223 3,216,668 Dividends Declared Per Common Share $ 1.22 $ 1.20 $ 1.18 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended June 30, 2007 2006 2005 <CAPTION> Cash Flows From Operating Activities <S> <C> <C> <C> Net income $ 5,298,347 $ 5,024,635 $ 4,998,619 Adjustments to reconcile net income to net cash from operating activities Depreciation and amortization 5,157,922 4,550,444 4,534,490 Deferred income taxes and investment tax credits 2,345,300 1,814,475 2,570,789 Other - net (205,827) (73,869) (36,409) (Increase) decrease in assets Accounts receivable 1,746,732 (1,374,334) (1,778,187) Gas in storage (475,801) (2,172,326) (1,444,575) Deferred gas cost (1,116,773) 819,453 (1,123,236) Materials and supplies (87,859) 103,365 (176,329) Prepayments (897,682) (525,634) 197,311 Other assets (197,887) (772,733) (638,613) Increase (decrease) in liabilities Accounts payable 3,835,813 (668,039) 141,223 Accrued taxes (1,061,563) (226,523) 88,241 Other current liabilities 148,901 (66,759) (19,211) Other liabilities (3,717) (9,107) 58,323 Net cash provided by operating activities $ 14,485,906 $ 6,423,048 $ 7,372,436 Cash Flows From Investing Activities Capital expenditures $ (8,082,918) $ (7,781,396) $ (5,338,356) Proceeds from sale of property, plant and equipment 146,810 204,372 75,000 Net cash used in investing activities $ (7,936,108) $ (7,577,024) $ (5,263,356) The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Cash Flows (continued) For the Years Ended June 30, 2007 2006 2005 <CAPTION> Cash Flows From Financing Activities <S> <C> <C> <C> Dividends on common stock $ (3,983,909) $ (3,890,800) $ (3,795,823) Issuance of common stock, net 504,309 676,435 766,497 Long-term debt issuance expense (10,970) (2,329,393) -- Issuance of long-term debt -- 40,000,000 -- Repayment of long-term debt (165,000) (34,367,000) (342,000) Issuance of notes payable 51,518,605 92,710,796 62,907,306 Repayment of notes payable (54,375,121) (91,623,484) (61,686,364) Net cash (used in) provided by financing $ (6,512,086) $ 1,176,554 $ (2,150,384) activities Net Increase (Decrease) in Cash and Cash Equivalents $ 37,712 $ 22,578 $ (41,304) Cash and Cash Equivalents, Beginning of Year 150,108 127,530 168,834 Cash and Cash Equivalents, End of Year $ 187,820 $ 150,108 $ 127,530 Supplemental Disclosures of Cash Flow Information Cash paid during the year for Interest $ 4,232,155 $ 4,766,191 $ 4,230,667 Income taxes (net of refunds) 1,763,518 1,922,348 184,279 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Balance Sheets As of June 30, 2007 2006 Assets <CAPTION> Current Assets <S> <C> <C> Cash and cash equivalents $ 187,820 $ 150,108 Accounts receivable, less accumulated provision for doubtful accounts of $300,000 and $520,000 in 2007 and 2006, respectively 7,389,993 7,855,949 Gas in storage, at average cost 11,841,791 11,365,990 Deferred gas costs (Note 1 and 13) 2,941,826 1,827,078 Materials and supplies, at average cost 559,087 429,712 Prepayments 2,629,682 1,837,228 Total current assets $ 25,550,199 $ 23,466,065 Property, Plant and Equipment $ 187,148,032 $ 182,155,110 Less - Accumulated provision for depreciation (64,879,205) (61,765,836) Net property, plant and equipment $ 122,268,827 $ 120,389,274 Other Assets Cash surrender value of officers' life insurance (face amount of $1,134,087) $ 425,609 $ 401,032 Note receivable from officer (Note 7) -- 62,000 Prepaid pension cost (Note 5) 951,571 3,954,141 Regulatory assets (Note 1) 8,220,590 4,191,116 Unamortized debt expense and other (Notes 1 and 9) 2,984,154 3,090,497 Total other assets $ 12,581,924 $ 11,698,786 Total assets $ 160,400,950 $ 155,554,125 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Balance Sheets (continued) As of June 30, 2007 2006 <CAPTION> Liabilities and Shareholders' Equity Current Liabilities <S> <C> <C> Accounts payable $ 10,299,066 $ 6,375,882 Notes payable (Note 8) 4,189,918 7,046,434 Current portion of long-term debt (Notes 9 and 10) 1,200,000 1,200,000 Accrued taxes 973,651 1,207,742 Customers' deposits 482,446 444,955 Accrued interest on debt 865,871 837,847 Accrued vacation 702,521 693,123 Deferred income taxes 1,273,000 701,000 Other liabilities 459,651 387,630 Total current liabilities $ 20,446,124 $ 18,894,613 Long-term debt (Notes 9 and 10) $ 58,625,000 $ 58,790,000 Deferred Credits and Other Deferred income taxes $ 22,467,900 $ 20,679,500 Investment tax credits 213,600 250,600 Regulatory liabilities (Note 1) 2,503,256 2,576,203 Asset retirement obligations and other (Note 3) 1,716,599 1,753,485 Total deferred credits and other $ 26,901,355 $ 25,259,788 Commitments and Contingencies (Note 12) Total liabilities $ 105,972,479 $ 102,944,401 Common Shareholders' Equity Common shares ($1.00 par value) $ 3,277,106 $ 3,256,043 Premium on common shares 43,508,979 43,025,733 Retained earnings 7,642,386 6,327,948 Total common shareholders' equity $ 54,428,471 $ 52,609,724 Total liabilities and common shareholders' equity $ 160,400,950 $ 155,554,125 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> <TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Changes in Shareholders' Equity For the Years Ended June 30, 2007 2006 2005 <CAPTION> Common Shares <S> <C> <C> <C> Balance, beginning of year $ 3,256,043 $ 3,229,988 $ 3,200,715 Dividend reinvestment and stock purchase plan, $1.00 par value of 21,063, 26,055 and 24,447 shares issued in 2007, 2006 and 2005, respectively 21,063 26,055 24,447 Employee stock purchase plan and other, $1.00 par value of 4,826 shares issued in 2005 -- -- 4,826 Balance, end of year $ 3,277,106 $ 3,256,043 $ 3,229,988 Premium on Common Shares Balance, beginning of year $ 43,025,733 $ 42,375,353 $ 41,638,129 Dividend reinvestment and stock purchase plan 483,246 650,380 624,489 Employee stock purchase plan and other -- -- 112,735 Balance, end of year $ 43,508,979 $ 43,025,733 $ 42,375,353 Retained Earnings Balance, beginning of year $ 6,327,948 $ 5,194,113 $ 3,991,317 Net income 5,298,347 5,024,635 4,998,619 Cash dividends declared on common shares (See Consolidated Statements of Income for rates) (3,983,909) (3,890,800) (3,795,823) Balance, end of year $ 7,642,386 $ 6,327,948 $ 5,194,113 Common Shareholders' Equity Balance, beginning of year $ 52,609,724 $ 50,799,454 $ 48,830,161 Net income 5,298,347 5,024,635 4,998,619 Issuance of common stock 504,309 676,435 766,497 Dividends on common stock (3,983,909) (3,890,800) (3,795,823) Balance, end of year $ 54,428,471 $ 52,609,724 $ 50,799,454 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. </TABLE> Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Capitalization As of June 30, 2007 2006 Common Shareholders' Equity Common shares, par value $1.00 per share (Notes 5 and 6) Authorized 20,000,000 shares Issued and outstanding 3,277,106 and 3,256,043 shares in 2007 and 2006, respectively $ 3,277,106 $ 3,256,043 Premium on common shares 43,508,979 43,025,733 Retained earnings (Note 9) 7,642,386 6,327,948 Total common shareholders' equity $ 54,428,471 $ 52,609,724 Long-Term Debt (Notes 9 and 10) Insured Quarterly Notes, 5.75% due 2021 $ 39,845,000 $ 40,000,000 Debentures, 7.0%, due 2023 19,980,000 19,990,000 Total debt $ 59,825,000 $ 59,990,000 Less amounts due within one year, included in current liabilities (1,200,000) (1,200,000) Total long-term debt $ 58,625,000 $ 58,790,000 Total capitalization $ 113,053,471 $ 111,399,724 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies (a) Principles of Consolidation Delta Natural Gas Company, Inc. ("Delta" or "the Company") sells and distributes or transports natural gas to approximately 39,000 customers. Our distribution system is located in central and southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system and we own and operate an underground storage field. 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 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) Cash Equivalents For the purposes of the Consolidated Statements of Cash Flows, all temporary cash investments with a maturity of three months or less at the date of purchase are considered cash equivalents. (c) Property, Plant and Equipment Property, plant and equipment is stated at original cost, which includes materials, labor, labor related costs and an allocation of general and administrative costs. Construction work in progress has been included in the rate base for determining customer rates, and therefore an allowance for funds used during construction has not been recorded. The cost of regulated plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense, less salvage value, is charged to the accumulated provision for depreciation. (d) Depreciation We determine the provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant. The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of 2.7%, 2.5%, and 2.6% of average depreciable plant for 2007, 2006 and 2005, respectively. (e) Maintenance All expenditures for maintenance and repairs of units of property are charged to the