Item 1. Business
General
Delta Natural Gas Company, Inc. provides natural gas distribution to retail customers and also provides gas transportation service to industrial customers and interconnected pipelines.
Delta operates under two segments, a regulated segment and an unregulated segment. See Note 11 of the Notes to Consolidated Financial Statements.
Delta's regulated segment sells natural gas to 40,000 retail customers in 23 predominately rural communities in central and southeastern Kentucky. In addition, Delta transports gas to industrial customers on Delta's system who purchase gas in the open market. Delta also transports gas on behalf of local producers and customers not on Delta's distribution system.
Delta's unregulated segment operates through two wholly-owned subsidiaries, Delta Resources, Inc. and Delgasco, Inc. These subsidiaries purchase gas from gas marketers and Kentucky producers and resell the gas to industrial customers on Delta's system and to others not on Delta's distribution system. Enpro, Inc., another wholly-owned subsidiary that is part of the unregulated segment, produces natural gas and oil that is sold in the unregulated market.
Gas Operations and Supply
Currently, over 99% of Delta's customers are residential and commercial. Delta's remaining light industrial customers purchased 4% of the total volume of gas sold by Delta at retail during 2002.
The communities in Delta's service area typically contain populations of less than 20,000. The three largest service areas are Nicholasville, Corbin and Berea, where Delta serves 7,000, 6,000 and 4,000 retail customers, respectively. The communities served by Delta continue to expand, resulting in some growth opportunities for the Company. Industrial parks have been developed in several areas and have resulted in additional industrial customers, some of whom purchase gas through Delta's regulated segment.
The economy of Delta's service area is based principally on light industry, farming and coal mining. Delta's revenues are affected by various factors, including rates billed to customers, the cost of natural gas, economic conditions in the areas that Delta serves, weather conditions and competition.
Delta competes for retail customers and sales with alternative sources of energy, including electricity, coal, oil, propane and wood. Delta Resources and Delgasco, who purchase gas and resell it to various industrial customers and others, also compete for their customers with producers and marketers of natural gas. Higher gas costs, which the Company is generally able to pass through to customers, may influence customers to conserve, or, in the case of industrial customers, to use alternative energy sources. Also, the potential bypass of Delta's system by industrial customers and others is a competitive concern that Delta has addressed and will continue to address through rate design and marketing strategies.
Delta's retail sales are seasonal and temperature-sensitive, as the majority of the gas sold by Delta is used for heating. This seasonality impacts Delta's liquidity position and its management of its working capital requirements. Variations in the average temperature during the winter impacts its revenues year-to-year. The impact of average temperature variations is ameliorated, however, by regulatory rules that allow Delta to vary rates charged customers in response to weather conditions that vary from thirty-year average ("normal") weather in the five traditional winter months billed in December through April. (See Management's Discussion and Analysis of Financial Condition and Results of Operations).
Retail gas sales in 2002 were 3,664,000 Mcf, generating $38,175,000 in revenues, as compared to 4,529,000 Mcf and $47,174,000 in revenues for 2001. Heating degree days billed during 2002 were 89.0% of normal as compared with 106.8% in 2001. Sales volumes decreased by 865,000 Mcf, or 19%, in 2002 as compared to 2001.
Delta's transportation of natural gas during 2002 generated revenues of $5,046,000 as compared with $4,709,000 during 2001. Of the total transportation revenues in 2002, $3,826,000 (4,866,000 Mcf) was earned for transportation of gas to customers on Delta's distribution system ("on-system"), while $1,220,000 (3,590,000 Mcf) was earned for transportation of gas to customers outside Delta's distribution system ("off-system"). Of the total transportation revenues for 2001, $3,895,000 (4,768,000 Mcf) and $814,000 (2,677,000 Mcf) were earned for transportation for on-system and off-system customers, respectively.
As an active participant in many areas of the natural gas industry, Delta plans to continue its efforts to expand its gas distribution system and customer base. Delta continues to consider acquisitions of other gas systems, some of which are contiguous to its existing service areas, as well as expansion within its existing service areas.
Delta also anticipates continuing activity in gas production and transportation and plans to pursue and increase these activities wherever practicable. Delta will 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.
Some producers in Delta's service area can access certain pipeline delivery systems other than Delta, which provides competition from others for transportation of gas. Delta will continue its efforts to purchase or transport any natural gas available that is produced in reasonable proximity to its facilities.
Delta receives its gas supply from a combination of interstate and Kentucky sources. Delta acquires its interstate gas supply from gas marketers. Delta's interstate gas supply is transported to Delta from production and storage fields by Tennessee Gas Pipeline Company ("Tennessee"), Columbia Gas Transmission Corporation ("Columbia"), Columbia Gulf and Texas Eastern Transmission Corporation.
Delta's agreements with Tennessee extend until 2003 and unless terminated by Tennessee or Delta, shall automatically renew thereafter on subsequent five-year terms. Tennessee is obligated under the agreements to transport up to 19,600 Mcf per day for Delta. During 2002, Tennessee transported a total of 1,109,000 Mcf for Delta under these agreements.
All but two of Delta's agreements with Columbia and Columbia Gulf extend through 2008 and thereafter continue on a year-to-year basis until terminated by one of the parties to the particular agreement. The two other agreements currently continue on a year-to-year basis. Under these agreements, Columbia is obligated to transport up to 12,500 Mcf per day for Delta, and Columbia Gulf is obligated to transport up to 4,300 Mcf per day for Delta. During 2002, Columbia and Columbia Gulf transported a total of 555,000 Mcf for Delta under these agreements.
Delta currently has agreements with two gas marketers. Under these commodity requirements contracts, the marketers are obligated to supply the volumes consumed by Delta's regulated customers in the respective Tennessee or Columbia serviced areas. Gas prices are based on index prices. One of the agreements began May 1, 2000 and extends through April 30, 2003 with an option to extend the agreement for one additional year. The other agreement currently continues on a year-to-year basis. Delta purchases gas from other gas marketers as needed at either current market prices or forward market prices.
Delta has an agreement with Columbia Natural Resources ("CNR") to purchase natural gas through October 31, 2004. Delta purchased 55,000 Mcf from CNR during 2002. CNR delivers this gas to Delta's customers on CNR's pipelines.
Delta also purchased 25,000 Mcf of natural gas from its wholly-owned subsidiary, Enpro, Inc., during 2002.
Delta owns and operates an underground natural gas storage field which is used to provide storage for a significant portion of Delta's winter gas supply needs. This storage capability permits Delta to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months. During 2002, 1,900,000 Mcf was withdrawn from this storage field.
Delta continues to seek additional new gas supplies from available sources. Delta will continue to maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost effective sources of gas for its customers. Regulatory Matters
Delta's retail natural gas distribution and its transportation services are subject to the regulatory authority of the Public Service Commission of Kentucky ("PSC") with respect to various aspects of Delta's business, including rates and service to retail and transportation customers. Delta monitors the need to file a general rate case as a way to adjust its sales prices.
On December 27, 1999, Delta received approval from the PSC for an annual revenue increase of $420,000. This resulted from Delta's last rate case that was filed by Delta in July, 1999. The approval included a weather normalization provision that permits Delta to adjust base rates for the billing months of December through April to reflect variations from normal winter weather.
Delta's rates include a Gas Cost Recovery ("GCR") clause, which permits changes in Delta's gas supply costs to be reflected in the rates charged to customers. The GCR requires Delta to make quarterly filings with the PSC, but such procedure does not require a general rate case.
During July, 2001, the PSC required an independent audit of the gas procurement activities of Delta and four other gas distribution companies as part of its investigation of increases in wholesale natural gas prices and their impacts on customers. The PSC indicated that Kentucky distributors had generally developed sound planning and procurement procedures for meeting their customers' natural gas requirements and that these procedures had provided customers with a reliable supply of natural gas at reasonable costs. The PSC noted the events of the prior year, including changes in natural gas wholesale markets, and required the audits to evaluate distributors' gas planning and procurement strategies in light of the recent more volatile wholesale markets, with a primary focus on a balanced portfolio of gas supply that balances cost issues, price risk and reliability. The consultants that were selected by the PSC are currently completing this audit. Delta has received a draft of the consultant's report and is in the process of reviewing and commenting on it. The draft report contains procedural and reporting-related recommendations in the areas of gas supply planning, organization, staffing, controls, gas supply management, gas transportation, gas balancing, response to regulatory change and affiliate relations. The report also addresses several general areas for the five gas distribution companies involved in the audit, including Kentucky natural gas price issues, hedging, GCR mechanisms, budget billing, uncollectible accounts and forecasting. Delta cannot predict how the PSC will interpret or act on any audit recommendations. As a result, Delta cannot predict the impact of this regulatory proceeding on the Company's financial position or results of operations.
In addition to PSC regulation, Delta may obtain non-exclusive franchises from the cities and communities in which it operates authorizing it to place its facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the PSC to bid on a local franchise. Delta holds franchises in four of the cities and seven other communities it serves. In the other cities and communities served by Delta, either Delta's franchises have expired, the communities do not have governmental organizations authorized to grant franchises, or the local governments have not required or do not want to offer a franchise. Delta attempts to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government could require Delta to cease its occupation of the streets and public grounds or prohibit Delta from extending its facilities into any new area of that city or community. To date, the absence of a franchise has had no adverse effect on Delta's operations.
Capital Expenditures
Capital expenditures during 2002 were $9.4 million and for 2003 are estimated to be $9.8 million. The Company's planned expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering and general facilities.
Financing
The Company's 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 $19.4 million had been borrowed at June 30, 2002.
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 the Company's capital needs and market conditions.
During 2002 the requirements of the Employee Stock Purchase Plan (see Note 4(c) of the Notes to Consolidated Financial Statements) were met through the issuance of 4,916 shares of common stock resulting in an increase of $96,000 in Delta's common shareholders' equity. The Dividend Reinvestment and Stock Purchase Plan (see Note 5 of the Notes to Consolidated Financial Statements) resulted in the issuance of 28,506 shares of common stock providing an increase of $590,000 in Delta's common shareholders' equity.
Employees
Delta employed a total of 156 full-time employees on June 30, 2002. Delta considers its relationship with its employees to be satisfactory. Delta's employees are not represented by unions or subject to any collective bargaining agreements.
Item 2.
Item 2. Properties
Delta owns its corporate headquarters in Winchester, Kentucky. Delta owns ten buildings used for field operations in the cities it serves. Also, Delta owns a building in Laurel County used for training and equipment and materials storage.
The Company owns 2,403 miles of natural gas gathering, transmission, distribution, storage and service lines. These lines range in size up to twelve inches in diameter.
Delta holds leases for the storage of natural gas under 8,000 acres located in Bell County, Kentucky. This property was developed for the underground storage of natural gas.
All the foregoing properties described in this Item 2 are used principally in connection with Delta's regulated natural gas distribution, transmission and storage segment. See Note 11 of the Notes to Consolidated Financial Statements for a description of Delta's two business segments.
In addition, through its three wholly-owned subsidiaries, Enpro, Delgasco and Delta Resources, the Company operates its unregulated segment, which involves related ventures consisting of natural gas marketing as well as oil and gas production. The properties owned by Enpro that are described in the following two paragraphs are used in connection with Delta's unregulated segment.
Enpro owns interests in certain oil and gas leases relating to 11,000 acres located in Bell, Knox and Whitley Counties. There presently are 40 gas wells and 5 oil wells producing from these properties. Enpro's remaining proved, developed natural gas reserves are estimated at 3 million Mcf. Oil production from the property has not been significant. Also, Enpro owns the oil and gas underlying 15,400 additional acres in Bell, Clay and Knox Counties. These properties are currently non-producing, and no reserve studies have been performed on the properties. Enpro had production of 187,000 Mcf during 2002.
Under the terms of an agreement with a producer relating to 14,000 acres of Enpro's undeveloped holdings, the producer is conducting exploration activities on the acreage. Enpro reserved the option to participate in wells drilled and also retained certain working and royalty interests in any production from future wells.
There are no significant encumbrances on the Company's assets.
Item 3.
Item 3. Legal Proceedings
Delta and its subsidiaries are not parties to any legal proceedings that are expected to have a materially adverse impact on the liquidity, financial condition or results of operations of the Company.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of 2002.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Delta has paid cash dividends on its common stock each year since 1964. While it is the intention of the Board of Directors to continue to declare dividends on a quarterly basis, the frequency and amount of future dividends will depend upon the Company's earnings, financial requirements and other relevant factors, including limitations imposed by the indenture for the Debentures. There were 2,298 record holders of Delta's common stock as of August 1, 2002.
Delta's common stock is traded in the National Association of Securities Dealers Automated Quotation ("NASDAQ") National Market System under the symbol DGAS. The accompanying table reflects the high and low sales prices during each quarter as reported by NASDAQ and the quarterly dividends declared per share.
Range of Stock Prices($) Dividends Quarter High Low Per Share($) - ------- ---- --- ------------
Fiscal 2002
First 20.43 18.90 .29 Second 20.99 18.67 .29 Third 23.08 19.75 .29 Fourth 22.50 21.47 .29
Fiscal 2001
First 18.00 15.25 .285 Second 19.62 16.25 .285 Third 20.31 17.69 .285 Fourth 20.75 18.00 .285
During July, 2001, Delta distributed 4,916 shares of its common stock to its employees under its Employee Stock Purchase Plan (see Note 4(c) of the Notes to Consolidated Financial Statements). Delta received cash consideration of $19.58 per share for one-half of those shares (2,458 shares), for a total cash consideration of $48,000, while one-half of the shares (2,458 shares) were provided to the employees without cash consideration as a part of Delta's compensation and benefits for its employees. The securities were sold pursuant to the exemption from registration provided by Rule 147 under the Securities Act of 1933. This exemption was relied upon in light of the facts that Delta is incorporated and doing business in Kentucky, and all eligible employees are residents of Kentucky. Subsequent to year end, in July, 2002 Delta distributed 4,728 shares of its common stock to its employees at $21.83 per share under the same program, and this was recorded in July, 2002. Delta's Employee Stock Purchase Plan was authorized by Delta's Board of Directors, but was not required to be submitted for shareholder approval.
Also, during June, 2002, Delta provided a total of 800 shares of its common stock to its directors (100 shares per director). Delta received no cash consideration for the shares, which were provided to its directors as a part of their compensation. This transaction may not involve a "sale" of securities under the Securities Act of 1933, and in any event, the securities were qualified for an exemption from registration provided by Rule 147 under the Securities Act of 1933. This exemption was relied upon in light of the facts that Delta is incorporated and doing business in Kentucky, and all participating directors are residents of Kentucky.
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.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
The Company's utility operations are subject to regulation by the PSC, which has a significant role in determining the Company's return on equity. The PSC approves rates that are intended to permit a specified rate of return on investment. The Company's rate tariffs allow the cost of gas to be passed through to customers (see Business - Regulatory Matters).
The Company's business is temperature-sensitive. Accordingly, the Company's sales volumes in any given period reflect, in addition to other factors, the impact of weather, with colder temperatures generally resulting in increased sales volumes by the Company. The Company anticipates that this sensitivity to seasonal and other weather conditions will continue to be reflected in the Company's sales volumes in future periods. However, Delta's current tariffs, approved by the PSC effective January 1, 2000, provide for some adjustment of gas rates through a weather normalization tariff (see Business - Regulatory Matters). Under the weather normalization tariff, Delta's rates for residential and small non-residential customers are generally increased when winter weather is warmer than normal and decreased when winter weather is colder than normal. Delta is permitted to adjust rates for these classes of customers for the billing months of December through April under this tariff.
Liquidity and Capital Resources
Because of the seasonal nature of Delta's sales, the smallest proportion of cash generated from operations is received during the warmer months when sales volumes decrease considerably. Additionally, most construction activity takes place during the non-heating season because of more favorable weather conditions. During the warmer, non-heating months, therefore, cash needs for operations and construction are partially met through short-term borrowings.
Capital expenditures for Delta for fiscal 2003 are expected to be $9.8 million. The capital expenditures will be made for system extensions as well as the replacement and improvement of existing transmission, distribution, gathering and general facilities.
Delta has been generating internally only a portion of the cash necessary for its capital expenditure requirements and thus finances the balance of its capital expenditures on an interim basis through the use of its borrowing capability under its short-term line of credit. The current available line of credit is $40,000,000, of which $19,355,000 was borrowed at June 30, 2002. The line of credit, which is with Bank One, Kentucky, NA, requires renewal during October, 2002. The Company intends to pursue renewal or to enter into a new agreement and seek substantially the same terms as the existing agreement.
These short-term borrowings are periodically repaid with the net proceeds from the sale of long-term debt and equity securities, as was done in March, 1998 when the net proceeds of $24,100,000 from the sale of $25,000,000 of debentures were used to repay short-term debt and to redeem the Company's 9% debentures, that would have matured in 2011, in the amount of $10,000,000.
The primary cash flows during the last three years are summarized below: 2002 2001 2000 ---- ---- ----
Provided by operating activities $10,511,896 $ 2,652,572 $ 8,827,505 Used in investing activities (9,421,765) (7,069,713) (8,795,653) Provided by used in)financing activities (1,028,996) 4,185,248 115,554 ------------ ----------- -----------
Net increase (decrease) in cash and cash equivalents $ 61,135 $ (231,893) $ 147,406 =========== =========== ===========
Cash provided by operating activities consists of net income and noncash items including depreciation, depletion, amortization and deferred income taxes. Additionally, changes in working capital are also included in cash provided by operating activities. The Company expects that internally generated cash, coupled with short-term borrowings, will be sufficient to satisfy its operating, normal capital expenditure and dividend requirements. Results of Operations
Operating Revenues
The decrease in operating revenues for 2002 of $14,840,000 was primarily attributable to decreased sales volumes and decreased gas rates. Sales volumes decreased due to the warmer winter weather in 2002. Gas rates decreased due to lower gas prices, net of increases from the impact of the weather normalization tariff.
The increase in operating revenues for 2001 of $24,843,000 was primarily attributable to increased gas rates and increased sales volumes. Gas rates increased due to higher gas prices, net of decreases from the impact of the weather normalization tariff. Sales volumes increased due to the colder winter weather in 2001.
Heating degree days billed for 2002 were 89.0% of normal as compared with 106.8 % of normal for 2001 and 89.6% of normal for 2000.
The following table sets forth certain variations in revenues for the last two fiscal years:
2002 compared 2001 compared Increase (Decrease) to 2001 to 2000 Variations in regulated revenues Gas rates $ (1,930,000) $ 11,364,800 Weather normalization adjustment 1,935,000 (1,634,000) Sales volumes (9,002,000) 5,715,700 Transportation 529,000 69,100 Other (49,000) 57,400 --------------- --------------- Total $ (8,517,000) $ 15,573,000 ------------- ------------
Variations in non-regulated revenues Gas rates $ (6,354,000) $ 8,669,000 Sales volumes 32,000 601,000 Other (1,000) ----------------- -------------- Total (6,323,000) 9,270,000 --------------- --------------
Total variations in revenues $(14,840,000) $ 24,843,000 ============= ============
Percentage variations in regulated volumes Gas sales (19.1) 18.0 Transportation 13.6 16.8
Percentage variations in non-regulated gas .4 7.7 sales volumes
Operating Expenses
The decrease in purchased gas expense for 2002 of $14,551,000 was due primarily to the 21.3% decrease in the cost of gas purchased for retail sales and the 10.7% decrease in volumes sold.
The increase in purchased gas expense for 2001 of $23,493,000 was due primarily to the 73% increase in the cost of gas purchased for retail sales and the 13% increase in volumes sold, both related to the above detailed revenue variations.
The following table sets forth certain variations in purchased gas expense for the last two fiscal years:
2002 compared 2001 compared to 2001 to 2000 ------------------- ------------
Variations in regulated gas expense Gas rates $ (2,887,000) $ 11,505,000 Purchase volumes (4,877,000) 2,967,000 -------------- --------------- Total $ (7,764,000) $ 14,472,000 -------------- --------------
Variations in non-regulated gas expense Gas rates $ (6,651,000) $ 8,308,000 Purchase volumes (136,000) 713,000 ---------------- --------------- Total $ (6,787,000) $ 9,021,000 --------------- ---------------
Total variations in gas expense $ (14,551,000) $ 23,493,000 =============== ==============
Basic and Diluted Earnings Per Common Share
For the years ended June 30, 2002, 2001 and 2000, basic earnings per common share changed as a result of changes in net income and the increased average common shares outstanding that resulted from the common shares issued under Delta's dividend reinvestment plan and shares issued to employees during the periods. There are no potentially dilutive securities, therefore basic and diluted earnings per common share are the same.
Factors That May Affect Future Results
Management's Discussion and Analysis of Financial Condition and Results of Operations and the other sections of this report contain forward-looking statements that are not statements of historical facts. These forward-looking statements are identified by their language, which may in some cases include words such as "estimates", "attempts", "expects", "monitors", "plans", "anticipates", "intends", "continues" or "will continue", "believes", and similar expressions. Such forward-looking statements may concern future matters (among other matters) such as: Delta's cost and the availability of natural gas supplies; Delta's capital expenditures; its sources and availability of funding for operation and expansion; Delta's anticipated growth and growth opportunities through system expansion and acquisition; competitive conditions; Delta's production, storage, gathering and transportation activities; regulatory and legislative matters; dividends; and external and internal funding sources.
Such forward-looking statements are accordingly subject to important risks and uncertainties that could cause the Company's actual results to differ materially from those expressed in any such forward-looking statements.
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 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 in Delta's capital expenditure requirements. o Changes in economic conditions, demographic patterns and weather conditions in Delta's retail service areas. o Changes affecting Delta's cost of providing gas service, including changes in gas supply costs, interest rates, the availability of external sources of financing for Delta's operations, tax laws, environmental laws, and the general rate of inflation. o Changes affecting the cost 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 Delta.
New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 eliminates the pooling-of-interests method and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. It also requires intangible assets acquired in a business combination to be recognized separately from goodwill. SFAS No. 141 had no impact on the Company's financial position or results of operations with respect to business combination transactions that occurred prior to June 30, 2001. SFAS No. 142 addresses how goodwill and other intangible assets should be accounted for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is that future goodwill and intangible assets with indefinite lives will no longer be amortized beginning in 2002. Instead of amortization, goodwill will be subject to an assessment for impairment by applying a fair-value-based test annually and more frequently if circumstances indicate a possible impairment. If the carrying amount of goodwill exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. The Company does not have recorded goodwill or intangible assets. Accordingly, these new accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No. 143 addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations as a liability when the liability is incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which is required to be adopted July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" and combines the two accounting models into a single model based on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment". This proposed SOP applies to all nongovernmental entities that acquire, construct or replace tangible property, plant and equipment ("PP&E") including lessors and lessees. A significant element of the SOP requires that entities use component accounting for PP&E to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The proposed effective date of the SOP is January 1, 2003. The Company is currently analyzing the impact of this proposed SOP.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Delta serves its regulated customers using 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, while the price of a forward purchase is fixed months prior to the delivery of the gas. Some of Delta's gas purchases are injected into gas storage facilities in the non-heating months and withdrawn from storage for delivery to customers during the heating season. The Company has minimal price risk resulting from these gas purchase and storage arrangements because these gas costs are passed on to Delta's regulated customers through the gas cost recovery rate mechanism.
Delta's non-regulated subsidiaries actively pursue gas sales opportunities for customers within and outside the Company's service area. At the time the Company makes a sales commitment to one of these customers, the Company attempts to cover this position immediately with gas purchase commitments matched to the terms of the related sales contract. The non-regulated subsidiaries attempt to minimize their exposure to price volatility by predetermining the gross profit on their sales at the time of each sales commitment.
None of the Company's gas contracts is accounted for using the fair value method of accounting. While some of the Company's gas purchase contracts meet the definition of a derivative, the Company has designated these contracts as "normal purchases" under SFAS No. 133, "Accounting for Derivatives".
Delta is exposed to risk resulting from changes in interest rates on its variable rate notes payable. The interest rate on the notes payable is benchmarked to the monthly London Interbank Offered Rate. Delta's outstanding notes payable amounted to $19,355,000 and $16,800,000, as of June 30, 2002 and 2001, respectively. Based on the amount of the outstanding notes payable on June 30, 2002, a one percent increase (decrease) in average interest rates would result in a decrease (increase) in annual pre-tax net income of $194,000. See (6) of the Notes to Consolidated Financial Statements.
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE PAGE
Management's Statement of Responsibility for Financial Reporting and Accounting 24
Report of Independent Public Accountants 25
Consolidated Statements of Income for the years ended June 30, 2002, 2001, and 2000 27
Consolidated Statements of Cash Flows for the years ended June 30, 2002, 2001 and 2000 28
Consolidated Balance Sheets as of June 30, 2002 and 2001 30
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2002, 2001, and 2000 32
Consolidated Statements of Capitalization as of June 30, 2002 and 2001 33
Notes to Consolidated Financial Statements 34
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2002, 2001, and 2000 46
Schedules other than those listed above are omitted because they are not required, 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.
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
Registrant intends to file a definitive proxy statement with the Commission pursuant to Regulation 14A (17 CFR 240.14a) not 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, 11, 12 and 13 is incorporated herein by reference to the definitive proxy statement. Neither the report on Executive Compensation nor the performance graph included in the Company's definitive proxy statement shall be deemed incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(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(a) - Delta's Amended and Restated Articles of Incorporation are incorporated herein by reference to Exhibit 3(a) to Delta's Form 10-Q for the period ended March 31, 1990.
3(b) - Delta's By-Laws as amended August 21, 1996 are incorporated herein by reference to Exhibit 3(b) to Delta's Form 10-K for the period ended June 30, 1996.
4(a) - The Indenture dated September 1, 1993 in respect of 6 5/8% Debentures due October 1, 2023, is incorporated herein by reference to Exhibit 4(e) to Delta's Form S-2 dated September 2, 1993.
4(b) - The Indenture dated July 1, 1996 in respect of 8.3% Debentures due August 1, 2026, is incorporated herein by reference to Exhibit 4(c) to Delta's Form S-2 dated June 21, 1996.
4(c) - The Indenture dated March 1, 1998 in respect of 7.15% Debentures due April 1, 2018, is incorporated herein by reference to Exhibit 4(d) to Delta's Form S-2 dated March 11, 1998.
10(a) - Certain of Delta's material natural gas supply contracts are incorporated herein by reference to Exhibit 10 to Delta's Form 10 for the year ended June 30, 1978 and by reference to Exhibits C and D to Delta's Form 10-K for the year ended June 30, 1980.
10(b) - Assignment to Delta by Wiser of its Columbia Service Agreement, including a copy of said Service Agreement, is incorporated here- in by reference to Exhibit 2(D) to Delta's Form 8-K dated February 9, 1981.
10(c) - Contract between Tennessee and Delta (amends earlier contract for Nicholasville and Wilmore Service Areas) is incorporated herein by reference to Exhibit 10(d) to Delta's Form 10-Q for the period ended September 30, 1990.
10(d) - Contract between Tennessee and Delta (amends earlier contract for Jeffersonville Service Area) is incorporated herein by reference to Exhibit 10(e) to Delta's Form 10-Q for the period ended September 30, 1990.
10(e) - Contract between Tennessee and Delta (amends earlier contract for Salt Lick Service Area) is incorporated herein by reference to Exhibit 10(f) to Delta's Form 10-Q for the period ended September 30, 1990.
10(f) - Contract between Tennessee and Delta (amends earlier contract for Berea Service Area) is incorporated herein by reference to Exhibit 10(g) to Delta's Form 10-Q for the period ended September 30, 1990.
10(g) - Service Agreements between Columbia and Delta (amends earlier service agreements for Cumberland, Stanton and Owingsville service areas) are incorporated herein by reference to Exhibit 10(h) to Delta's Form 10-Q for the period ended September 30, 1990.
10(h) - Employment agreements between Delta and five officers, those being John B. Brown, Johnny L. Caudill, John F. Hall, Alan L. Heath and Glenn R. Jennings, are incorporated herein by reference to Exhibit 10(k) to Delta's Form 10-Q for the period ended March 31, 2000.
10(i) - Agreement between Delta and Harrison D. Peet, Chairman of the Board, is incorporated herein by reference to Exhibit 10(l) to Delta's Form 10-Q for the period ended March 31, 2000.
12 - Computation of the Consolidated Ratio of Earnings to Fixed Charges.
16 - Letter dated May 22, 2002 to the Securities and Exchange Commission is incorporated herein by reference as Exhibit 16 to Delta's Form 8-K dated May 22, 2002.
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Public Accountants.
(b) Reports on 8-K.
On May 22, 2002, the Company filed a Form 8-K reporting the change in the Company's Auditor.
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 9th day of September, 2002.
DELTA NATURAL GAS COMPANY, INC.
By: /s/Glenn R. Jennings
Glenn R. Jennings, 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 President, Chief Executive September 9, 2002 (Glenn R. Jennings) Officer and Vice Chairman of the Board
(ii) Principal Financial Officer:
/s/John F. Hall Vice-President - Finance, September 9, 2002 (John F. Hall) Secretary and Treasurer
(iii) Principal Accounting Officer:
/s/John B. Brown Controller September 9, 2002 (John B. Brown)
(iv) A Majority of the Board of Directors:
/s/H. D. Peet Chairman of the Board September 9, 2002 (H. D. Peet)
/s/Donald R. Crowe Director September 9, 2002 (Donald R. Crowe)
/s/Jane Hylton Green Director September 9, 2002 (Jane Hylton Green)
/s/Lanny D. Greer Director September 9, 2002 (Lanny D. Greer)
/s/Billy Joe Hall Director September 9, 2002 (Billy Joe Hall)
/s/Lewis N. Melton Director September 9, 2002 (Lewis N. Melton)
/s/Arthur E. Walker, Jr. Director September 9, 2002 (Arthur E. Walker, Jr.)
/s/Michael R. Whitley Director September 9, 2002 (Michael R. Whitley)
Management's Statement of Responsibility for Financial Reporting and Accounting
Management is responsible for the preparation, presentation and integrity of the financial statements and other financial information in this report. In preparing financial statements in conformity with accounting principles generally accepted in the United States, management is required to make estimates and assumptions that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company maintains a system of accounting and internal controls which management believes provides reasonable assurance that the accounting records are reliable for purposes of preparing financial statements and that the assets are properly accounted for and protected.
The Board of Directors pursues its oversight role for these financial statements through its Audit Committee, which consists of four outside directors. The Audit Committee meets periodically with management to review the work and monitor the discharge of their responsibilities. The Audit Committee also meets periodically with the Company's internal auditor as well as Deloitte & Touche LLP, the independent auditors, who have full and free access to the Audit Committee, with or without management present, to discuss internal accounting control, auditing and financial reporting matters.
Glenn R. Jennings John F. Hall John B. Brown President & Chief Vice President - Finance, Controller Executive Officer Secretary & Treasurer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:
We have audited the accompanying consolidated balance sheet of Delta Natural Gas Company, Inc. and subsidiary companies (the "Company") as of June 30, 2002, and the related consolidated statements of capitalization, income, cash flows and changes in shareholders' equity for the year ended June 30, 2002. Our audit also included the 2002 financial statement schedule listed on the index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides 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 subsidiary companies as of June 30, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 2002 financial statement schedule, when considered in relation to the basic 2002 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio August 19, 2002
Report of Previous Independent Public Accountants
THE FOLLOWING REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
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. (a Kentucky corporation) and subsidiary companies as of June 30, 2001 and 2000, and the related consolidated statements of income, cash flows and changes in shareholders' equity for each of the three years in the period ended June 30, 2001. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Delta Natural Gas Company, Inc. and subsidiary companies as of June 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2001, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the Index to Consolidated Financial Statements and Schedule is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Louisville, Kentucky August 10, 2001
Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Income
For the Years Ended June 30, 2002 2001 2000
Operating Revenues $ 55,929,780 $ 70,770,156 $45,926,775 ------------ ------------ -----------
Operating Expenses
Purchased gas $ 30,157,225 $ 44,707,739 $21,214,834
Operation and maintenance 9,685,746 9,844,728 9,139,143
Depreciation and depletion 4,080,944 3,840,450 3,989,090
Taxes other than income taxes 1,354,913 1,423,020 1,338,486
Income taxes (Note 3) 2,249,500 2,232,500 2,068,500 ------------ ------------ ---------
Total operating expenses $ 47,528,328 $ 62,048,437 $37,750,053 ------------ ------------ -----------
Operating Income $8,401,452 $8,721,719 $ 8,176,722
Other Income and Deductions, Net 17,018 31,141 42,866 ------------ ------------ ------------
Income Before Interest Charges $8,418,470 $8,752,860 $ 8,219,588 ---------- ---------- -----------
Interest Charges
Interest on long-term debt $3,728,847 $3,775,856 $ 3,845,565
Other interest 891,750 1,179,949 748,006
Amortization of debt expense 161,160 161,160 161,160 ------------ ----------- -----------
Total interest charges $4,781,757 $5,116,965 $ 4,754,731 ---------- ---------- -----------
Net Income $3,636,713 $3,635,895 $ 3,464,857 ========== ========== ===========
Weighted Average Number of Common Shares Outstanding (Basic and Diluted) 2,513,804 2,477,983 2,433,397
Basic and Diluted Earnings Per Common Share $ 1.45 $ 1.47 $ 1.42
Dividends Declared Per Common Share $ 1.16 $ 1.14 $ 1.14
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended June 30, 2002 2001 2000
Cash Flows From Operating Activities Net income $ 3,636,713 $ 3,635,895 $ 3,464,857
Adjustments to reconcile net income to net cash from Operating activities Depreciation, depletion and Amortization 4,354,396 4,047,715 4,240,595 Deferred income taxes and Investment tax credits 1,110,916 2,332,458 1,446,444 Other - net 595,894 700,091 841,877
(Increase) decrease in assets Accounts receivable 1,767,741 (1,860,926) (1,160,957) Gas in storage (556,871) (1,665,124) 48,005 Deferred (advance recovery of) gas cost 368,648 (4,518,953) (1,124,219) Materials and supplies 69,663 (129,278) 200,689 Prepayments 681,195 (690,662) (51,964) Other assets (1,551,055) (333,402) (561,893)
Increase (decrease) in liabilities Accounts payable (1,524,216) 1,647,056 1,630,760 Refunds due customers 35,653 (5,708) 2,679 Accrued taxes (44,503) (521,190) 284,891 Other current liabilities 128,283 11,340 (302,553) Other liabilities 1,439,439 3,260 (131,706) ----------- ------------ ------------
Net cash provided by operating activities $10,511,896 $ 2,652,572 $ 8,827,505 ----------- ----------- ------------
Cash Flows From Investing Activities Capital expenditures $(9,421,765) $(7,069,713) $ (8,795,653) ------------ ------------ ------------
Net cash used in investing activities $(9,421,765) $(7,069,713) $ (8,795,653) ------------ ----------- ------------
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows (continued)
For the Years Ended June 30, 2002 2001 2000
Cash Flows From Financing Activities Dividends on common stock $(2,916,418) $ (2,825,267) $ (2,777,372) Issuance of common stock, net 707,422 646,514 697,926 Repayment of long-term debt (1,375,000) (810,999) (1,735,000) Issuance of notes payable 36,860,000 52,415,000 27,810,000 Repayment of notes payable (34,305,000) (45,240,000) (23,880,000) ----------- ------------ ------------
Net cash provided by financing activities $(1,028,996) $ 4,185,248 $ 115,554 ----------- ------------ ------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 61,135 $ (231,893) $ 147,406
Cash and Cash Equivalents, Beginning of Year 164,101 395,994 248,588 ----------- ------------ ------------
Cash and Cash Equivalents, End of Year $ 225,236 $ 164,101 $ 395,994 =========== ============ ============
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for Interest $ 4,636,051 $ 4,970,327 $ 4,626,542 Income taxes (net of refunds) $ 1,130,566 $ 395,737 $ 533,908
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets
As of June 30, 2002 2001
Assets Gas Utility Plant, at cost $156,305,063 $147,792,390 Less - Accumulated provision for depreciation (49,142,976) (45,375,230) ------------ ------------
Net gas plant $107,162,087 $102,417,160 ------------ ------------
Current Assets Cash and cash equivalents $ 225,236 $ 164,101 Accounts receivable, less accumulated provisions for doubtful accounts of $165,000 and $575,000 in 2002 and 2001, respectively 2,884,025 4,651,766 Gas in storage, at average cost 5,216,772 4,659,901 Deferred gas costs 4,076,059 4,444,707 Materials and supplies, at first-in, first-out cost 523,756 593,419 Prepayments 388,794 1,090,515 ------------ ------------
Total current assets 13,314,642 $ 15,604,409 ------------ ------------
Other Assets Cash surrender value of officers' life insurance (face amount of $1,236,009) $ 344,687 $ 354,891 Note receivable from officer 158,000 128,000 Prepaid pension, unamortized debt expense and other (Notes 4 and 7) 6,969,109 5,674,678 ------------ ------------
Total other assets $ 7,471,796 $ 6,157,569 ------------ ------------
Total assets $127,948,525 $124,179,138 ============ ============
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets (continued)
As of June 30, 2002 2001
Liabilities and Shareholders' Equity
Capitalization (See Consolidated Statements of Capitalization) Common shareholders' equity $ 34,182,277 $ 32,754,560 Long-term debt (Notes 7 and 8) 48,600,000 49,258,902 ---------- ----------
Total capitalization $ 82,782,277 $ 82,013,462 ------------ ------------
Current Liabilities Notes payable (Note 6) $ 19,355,000 $ 16,800,000 Current portion of long-term debt (Notes 7 and 8) 1,750,000 2,450,000 Accounts payable 4,077,983 5,602,199 Accrued taxes 673,873 718,376 Refunds due customers 73,973 38,320 Customers' deposits 440,568 418,582 Accrued interest on debt 1,162,956 1,178,410 Accrued vacation 558,066 538,595 Other accrued liabilities 503,178 400,898 ------- ----------
Total current liabilities $ 28,595,597 $ 28,145,380 ------------ ------------
Deferred Credits and Other Deferred income taxes $ 14,078,273 $ 12,851,457 Investment tax credits 404,600 449,800 Regulatory liability (Note 3) 562,025 632,725 Additional minimum pension liability (Note 4) 1,461,440 -- Advances for construction and other 64,313 86,314 ----------- ----------
Total deferred credits and other $ 16,570,651 $ 14,020,296 ------------ ------------
Commitments and Contingencies (Note 9) ____________ ____________
Total liabilities and shareholders' equity $127,948,525 $124,179,138 ============ ============
The accompanying notes to consolidated financial statements are an integral part of these statements.
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Capitalization
As of June 30, 2002 2001
Common Shareholders' Equity Common shares, par value $1.00 per share (Notes 4 and 5) Authorized 6,000,000 shares Issued and outstanding 2,530,079 and 2,495,679 shares in 2002 and 2001, respectively $ 2,530,079 $ 2,495,679 Premium on common shares 30,330,330 29,657,308 Capital stock expense (1,925,431) (1,925,431) Retained earnings (Note 7) 3,247,299 2,527,004 ----------- -----------
Total common shareholders' equity $34,182,277 $32,754,560 ----------- -----------
Long-Term Debt (Notes 7 and 8) Debentures, 8.3%, due 2026 $14,816,000 $14,821,000 Debentures, 6 5/8%, due 2023 11,445,000 11,933,000 Debentures, 7.15%, due 2018 24,089,000 24,271,000 Promissory note from acquisition of under- ground storage, non-interest bearing, due through 2001 (less unamortized discount of $16,098 in 2001) - 683,902 ------------ -----------
Total long-term debt $50,350,000 $51,708,902
Less amounts due within one year, included in current liabilities (1,750,000) (2,450,000) ----------- -----------
Net long-term debt $48,600,000 $49,258,902 ----------- -----------
Total capitalization $82,782,277 $82,013,462 =========== ===========
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") has 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) Depreciation The Company determines its provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant. The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of 2.9%, 2.8% and 3.1% of average depreciable plant for 2002, 2001 and 2000, respectively.
(d) Maintenance All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal.
(e) Gas Cost Recovery Delta has a Gas Cost Recovery ("GCR") clause which provides for a dollar-tracker that matches revenues and gas costs and provides eventual dollar-for-dollar recovery of all gas costs incurred. The Company expenses gas costs based on the amount of gas costs recovered through revenue. Any differences between actual gas costs and those estimated costs billed are deferred and reflected in the computation of future billings to customers using the GCR mechanism.
(f) Revenue Recognition The Company records revenues as billed to its customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the latest date of each cycle meter reading to the month-end is unbilled.
(g) Revenues and Customer Receivables The Company serves 40,000 customers in central and southeastern Kentucky. Revenues and customer receivables arise primarily from sales of natural gas to customers and from transportation services for others. Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable.
(h) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(i) Rate Regulated Basis of Accounting The Company's regulated operations follow the accounting and reporting requirements of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". The economic effects of regulation can result in a regulated company recovering costs from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). The amounts recorded by the Company as regulatory assets and regulatory liabilities are as follows:
Regulatory assets ($000) 2002 2001 ---- ----
Deferred gas cost 4,076 4,445 Loss on extinguishment of debt 1,337 1,395 Rate case and gas audit expense 116 142 ------ ------ Total regulatory assets 5,529 5,982 ===== =====
Regulatory liabilities ($000)
Refunds from suppliers that are due customers 74 38 Regulatory liability for deferred income taxes 562 633 ------ ------- Total regulatory liabilities 636 671 ====== =======
The Company is currently earning a return on loss on extinguishment of debt and rate case expenses. Deferred gas costs are presented every three months to the PSC for recovery in accordance with the gas cost recovery rate mechanism.
(2) New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 eliminates the pooling-of-interests method and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. It also requires intangible assets acquired in a business combination to be recognized separately from goodwill. SFAS No. 141 had no impact on the Company's financial position or results of operations with respect to business combination transactions that occurred prior to June 30, 2001. SFAS No. 142 addresses how goodwill and other intangible assets should be accounted for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is that future goodwill and intangible assets with indefinite lives will no longer be amortized beginning in 2002. Instead of amortization, goodwill will be subject to an assessment for impairment by applying a fair-value-based test annually and more frequently if circumstances indicate a possible impairment. If the carrying amount of goodwill exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. The Company does not have recorded goodwill or intangible assets. Accordingly, these new accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No. 143 addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations as a liability when the liability is incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which is required to be adopted July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" and combines the two accounting models into a single model based on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment". This proposed SOP applies to all nongovernmental entities that acquire, construct or replace tangible property, plant and equipment ("PP&E") including lessors and lessees. A significant element of the SOP requires that entities use component accounting for PP&E to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The proposed effective date of the SOP is January 1, 2003. The Company is currently analyzing the impact of this proposed SOP.
(3) Income Taxes
The Company provides for income taxes on temporary differences resulting from the use of alternative methods of income and expense recognition for financial and tax reporting purposes. The differences result primarily from the use of accelerated tax depreciation methods for certain properties versus the straight-line depreciation method for financial purposes, differences in recognition of purchased gas cost recoveries and certain other accruals which are not currently deductible for income tax purposes. Investment tax credits were deferred for certain periods prior to fiscal 1987 and are being amortized to income over the estimated useful lives of the applicable properties. The Company utilizes the asset and liability method for accounting for income taxes, which requires that deferred income tax assets and liabilities are computed using tax rates that will be in effect when the book and tax temporary differences reverse. The change in tax rates applied to accumulated deferred income taxes may not be immediately recognized in operating results because of ratemaking treatment. A regulatory liability has been established to recognize the future revenue requirement impact from these deferred taxes. The temporary differences which gave rise to the net accumulated deferred income tax liability for the periods are as follows:
2002 2001 ---- ---- Deferred Tax Liabilities Accelerated depreciation $ 13,436,373 $12,440,957 Deferred gas cost 1,364,800 1,444,200 Accrued pension 1,104,200 1,157,200 Debt expense 406,300 426,900 ------------ -----------
Total $ 16,311,673 $15,469,257 ------------ -----------
Deferred Tax Assets Alternative minimum tax credits $ 1,365,200 $ 1,701,100 Regulatory liabilities 221,700 249,600 Investment tax credits 159,600 177,400 Other 486,900 489,700 ----------- -----------
Total $2,233,400 $ 2,617,800 ---------- -----------
Net accumulated deferred income tax liability $ 14,078,273 $12,851,457 ============ ===========
The components of the income tax provision are comprised of the following for the years ended June 30:
2002 2001 2000 ---- ---- ---- Components of Income Tax Expense Current Federal $ 776,200 $ (77,000) $ 568,100 State 296,100 (71,700) 137,500 ----------- ----------- ----------- Total $ 1,072,300 $ (148,700) $ 705,600
Deferred 1,177,200 2,381,200 1,362,900 ----------- ----------- -----------
Income tax expense $ 2,249,500 $ 2,232,500 $ 2,068,500 =========== =========== ===========
Reconciliation of the statutory federal income tax rate to the effective income tax rate is shown in the table below: 2002 2001 2000 ---- ---- ----
Statutory federal income tax rate 34.0 % 34.0 % 34.0 % State income taxes net of federal benefit 5.3 5.4 5.2 Amortization of investment tax credits (0.8) (0.9) (1.1) Other differences - net (0.2) (0.3) (0.4) ------ ------ -----
Effective income tax rate 38.3 % 38.2 % 37.7 % ======= ====== ======
(4) Employee Benefit Plans
(a) Defined Benefit Retirement Plan Delta has a trusteed, noncontributory, defined benefit pension plan covering all eligible employees. Retirement income is based on the number of years of service and annual rates of compensation. The Company makes annual contributions equal to the amounts necessary to fund the plan adequately. The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ended March 31, 2002, and a statement of the funded status as of March 31 of both years, as recognized in the Company's consolidated balance sheets at June 30:
2002 2001 ---- ---- Change in Benefit Obligation Benefit obligation at beginning of year $ 8,486,103 $ 8,188,361 Service cost 518,496 487,392 Interest cost 657,126 592,537 Amendments 1,514,620 -- Actuarial loss (84,009) 332,610 Benefits paid (411,217) (1,114,797) ------------ ------------ Benefit obligation at end of year $ 10,681,119 $ 8,486,103 ------------ ------------
Change in Plan Assets Fair value of plan assets at beginning of year $ 9,073,398 $ 10,176,049 Actual return (loss) on plan assets 14,243 (636,591) Employer contribution 543,255 648,737 Benefits paid (411,217) (1,114,797) ------------ ------------ Fair value of plan assets at end of year $ 9,219,679 $ 9,073,398 ------------ ------------
Funded status $ (1,461,440) $ 587,295 Unrecognized net actuarial loss 2,272,764 1,652,236 Unrecognized prior service cost 1,514,620 -- Net transition asset -- (29,262) ------------- ------------
Net pension asset $ 2,325,944 $ 2,210,269 ============ ============
In addition, the Company has recognized an additional minimum pension liability of $1,461,440 and a corresponding intangible pension asset in the accompanying balance sheet as of June 30, 2002. Effective April 1, 2002, the Company adopted a plan amendment which enhanced the formula for benefits paid under the plan.
The assets of the plan consist primarily of common stocks, bonds and certificates of deposit. Net pension costs for the years ended June 30 include the following: 2002 2001 2000 ---- ---- ---- Components of Net Periodic Benefit Cost Service cost $ 518,496 $ 487,392 $ 535,681 Interest cost 657,125 592,537 538,400 Expected return on plan assets (755,307) (800,303) (764,449) Amortization of unrecognized net loss 36,528 -- -- Amortization of net transition asset (29,262) (42,394) (42,394) --------- --------- --------- Net periodic benefit cost $ 427,580 $ 237,232 $ 267,238 ========= ========= =========
Weighted-Average Assumptions Discount rate 7.50% 7.75% 7.75% Expected return on plan assets 8.00% 8.00% 8.00% Rate of compensation increase 4.00% 4.00% 4.00%
During the plan year ended March 31, 2000, Delta eliminated 16 positions in conjunction with a workforce reduction plan. Subsequently, 7 additional positions were eliminated as a result of reorganization of Delta's branch offices, which was completed by June 30, 2000. These events constituted a curtailment under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". The combined impact of the curtailment gain, the savings in salary expense, and the cost of one time payments made to severed employees was not material to results of operations in 2000.
SFAS No. 106, "Employers' Accounting for Post-Retirement Benefits", and SFAS No. 112, "Employers' Accounting for Post-Employment Benefits", do not affect the Company, as Delta does not provide benefits for post-retirement or post-employment other than the pension plan for retired employees.
(b) Employee Savings Plan The Company has an Employee Savings Plan ("Savings Plan") under which eligible employees may elect to contribute any whole percentage between 2% and 15% of their annual compensation. The Company will match 50% of the employee's contribution up to a maximum Company contribution of 2.5% of the employee's annual compensation. For 2002, 2001, and 2000, Delta's Savings Plan expense was $165,500, $154,600, and $170,800, respectively.
(c) Employee Stock Purchase Plan The Company has an Employee Stock Purchase Plan ("Stock Plan") under which qualified permanent employees are eligible to participate. Under the terms of the Stock Plan, such employees can contribute on a monthly basis 1% of their annual salary level (as of July 1 of each year) to be used to purchase Delta's common stock. The Company issues Delta common stock, based upon the fiscal year contributions, using an average of the high and low sale prices of Delta's stock as quoted in NASDAQ's National Market System on the last business day in June and matches those shares so purchased. Therefore, stock with an equivalent market value of $96,300 was issued in July, 2002. The continuation and terms of the Stock Plan are subject to approval by Delta's Board of Directors on an annual basis. Delta's Board has continued the Stock Plan through June 30, 2003.
(5) Dividend Reinvestment and Stock Purchase Plan
The Company's Dividend Reinvestment and Stock Purchase Plan ("Reinvestment Plan") provides that shareholders of record can reinvest dividends and also make limited additional investments of up to $50,000 per year in shares of common stock of the Company. Under the Reinvestment Plan the Company issued 28,506, 28,958, and 37,499 shares in 2002, 2001, and 2000, respectively. Delta reserved 150,000 shares for issuance under the Reinvestment Plan in December, 2000, and as of June 30, 2002 there were 106,266 shares still available for issuance.
(6) Notes Payable and Line of Credit
The current available line of credit is $40,000,000, of which $19,355,000 and $16,800,000 was borrowed having a weighted average interest rate of 3.67% and 6.97% as of June 30, 2002 and 2001, respectively. The maximum amount borrowed during 2002 and 2001 was $29,005,000 and $21,445,000, respectively. The interest on this line is determined monthly at the London Interbank Offered Rate plus 1% on the used line of credit. The cost of the unused line of credit is 0.30%. The current line of credit must be renewed during October, 2002.
(7) Long-Term Debt
In March, 1998 Delta issued $25,000,000 of 7.15% Debentures that mature in March, 2018. Redemption of up to $25,000 annually will be made on behalf of deceased holders within 60 days of notice, subject to an annual aggregate $750,000 limitation. The 7.15% Debentures can be redeemed by the Company after April 1, 2003. Restrictions under the indenture agreement covering the 7.15% Debentures include, among other things, a restriction whereby dividend payments cannot be made unless consolidated shareholders' equity of the Company exceeds $21,500,000. No retained earnings are restricted under the provisions of the indenture.
In July, 1996 Delta issued $15,000,000 of 8.3% Debentures that mature in July, 2026. Redemption on behalf of deceased holders within 60 days of notice of up to $25,000 per holder will be made annually, subject to an annual aggregate limitation of $500,000. The 8.3% Debentures can be redeemed by the Company beginning in August, 2001 at a 5% premium, such premium declining ratably until it ceases in August, 2006.
In October, 1993 Delta issued $15,000,000 of 6 5/8% Debentures that mature in October, 2023. Each holder may require redemption of up to $25,000 annually, subject to an annual aggregate limitation of $500,000. Such redemption will also be made on behalf of deceased holders within 60 days of notice, subject to the annual aggregate $500,000 limitation. The 6 5/8% Debentures can be redeemed by the Company beginning in October, 1998 at a 5% premium, such premium declining ratably until it ceases in October, 2003. The Company may not assume any additional mortgage indebtedness in excess of $2 million without effectively securing the 6 5/8% Debentures equally to such additional indebtedness.
The Company amortizes debt issuance expenses over the life of the related debt on a straight-line basis, which approximates the effective yield method.
(8) Fair Values of Financial Instruments
The fair value of the Company's debentures is estimated using discounted cash flow analysis, based on the Company's current incremental borrowing rates for similar types of borrowing arrangements. The fair value of the Company's debentures at June 30, 2002 and 2001 was estimated to be $47,479,000 and $48,429,000, respectively. The carrying amount in the accompanying consolidated financial statements as of June 30, 2002 and 2001 is $50,350,000 and $51,025,000, respectively.
The carrying amount of the Company's other financial instruments including cash equivalents, accounts receivable, notes receivable, accounts payable and the non-interest bearing promissory note approximate their fair value.
(9) Commitments and Contingencies
The Company has entered into individual employment agreements with its five officers and an agreement with the Chairman of the Board. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company.
(10) Rates
Delta's retail natural gas distribution and its transportation services are subject to the regulatory authority of the Public Service Commission of Kentucky ("PSC") with respect to various aspects of Delta's business, including rates and service to retail and transportation customers. Delta monitors the need to file a general rate case as a way to adjust its sales prices.
On December 27, 1999, Delta received approval from the PSC for an annual revenue increase of $420,000. This resulted from Delta's last rate case that was filed by Delta in July, 1999. The approval included a weather normalization provision that permits Delta to adjust base rates for the billing months of December through April to reflect variations from normal winter weather.
Delta's rates include a Gas Cost Recovery ("GCR") clause, which permits changes in Delta's gas supply costs to be reflected in the rates charged to customers. The GCR requires Delta to make quarterly filings with the PSC, but such procedure does not require a general rate case.
During July, 2001, the PSC required an independent audit of the gas procurement activities of Delta and four other gas distribution companies as part of its investigation of increases in wholesale natural gas prices and their impacts on customers. The PSC indicated that Kentucky distributors had generally developed sound planning and procurement procedures for meeting their customers' natural gas requirements and that these procedures had provided customers with a reliable supply of natural gas at reasonable costs. The PSC noted the events of the prior year, including changes in natural gas wholesale markets, and required the audits to evaluate distributors' gas planning and procurement strategies in light of the recent more volatile wholesale markets, with a primary focus on a balanced portfolio of gas supply that balances cost issues, price risk and reliability. The consultants that were selected by the PSC are currently completing this audit. Delta has received a draft of the consultant's report and is in the process of reviewing and commenting on it. The draft report contains procedural and reporting-related recommendations in the areas of gas supply planning, organization, staffing, controls, gas supply management, gas transportation, gas balancing, response to regulatory change and affiliate relations. The report also addresses several general areas for the five gas distribution companies involved in the audit, including Kentucky natural gas price issues, hedging, GCR mechanisms, budget billing, uncollectible accounts and forecasting. Delta cannot predict how the PSC will interpret or act on any audit recommendations. As a result, Delta cannot predict the impact of this regulatory proceeding on the Company's financial position or results of operations.
In addition to PSC regulation, Delta may obtain non-exclusive franchises from the cities and communities in which it operates authorizing it to place its facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the PSC to bid on a local franchise. Delta holds franchises in four of the cities and seven other communities it serves. In the other cities and communities served by Delta, either Delta's franchises have expired, the communities do not have governmental organizations authorized to grant franchises, or the local governments have not required or do not want to offer a franchise. Delta attempts to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government could require Delta to cease its occupation of the streets and public grounds or prohibit Delta from extending its facilities into any new area of that city or community. To date, the absence of a franchise has had no adverse effect on Delta's operations.
(11) Operating Segments
The Company has two segments: (i) a regulated natural gas distribution, transmission and storage segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production. The regulated segment represents Delta and the non-regulated segment consists of Resources, Delgasco and Enpro. The Company operates in a single geographic area of central and southeastern Kentucky.
The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements. Intersegment revenues and expenses consist of intercompany revenues and expenses from the sale and purchase of gas as well as intercompany gas transportation services. Effective January 1, 2002, the non-regulated segment discontinued the practice of selling gas to the regulated segment. This led to a decline in intersegment revenues and expenses for 2002. Intersegment transportation revenue and expense is recorded at Delta's tariff rates. Transfer pricing for sales of gas between segments is at cost. Operating expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown below for the periods:
($000) 2002 2001 2000 ---- ---- ---- Revenues Regulated External customers 40,370 48,887 33,314 Intersegment 3,050 3,244 4,606 ------- --------- -------- Total regulated 43,420 52,131 37,920 Non-regulated External customers 15,560 21,883 12,613 Intersegment 1,688 27,609 16,249 ------- --------- -------- Total non-regulated 17,248 49,492 28,862 Eliminations for intersegment (4,738) (30,853) (20,855) -------- -------- -------- Total operating revenues 55,930 70,770 45,927 ======= ========= ========
Operating Expenses Regulated Depreciation 3,964 3,797 3,940 Income taxes 1,599 1,696 1,657 Other 30,485 38,662 24,792 ------- --------- -------- Total regulated 36,048 44,155 30,389 ------- --------- -------- Non-regulated Depreciation 117 43 49 Income taxes 651 536 412 Other 15,450 48,167 27,755 ------- --------- -------- Total non-regulated 16,218 48,746 28,216 Eliminations for intersegment (4,738) (30,853) (20,855) -------- -------- -------- Total operating expenses 47,528 62,048 37,750 ======= ========= ========
($000) 2002 2001 2000 ---- ---- ----
Other Income and Deductions Regulated 17 31 43 Non-regulated - - - --------- --------- ------ Total other income 17 31 43 and deductions ======== ========= ========
Interest Charges Regulated 4,768 5,191 4,766 Non-regulated 25 42 41 Eliminations for intersegment (11) (116) (52) -------- -------- -------- Total interest charges 4,782 5,117 4,755 ======== ========= ========
Net Income Regulated 2,621 2,817 2,808 Non-regulated 1,016 819 657 -------- --------- -------- Total net income 3,637 3,636 3,465 ======== ========= ========
Assets Regulated 124,764 120,710 108,876 Non-regulated 1,723 3,469 4,043 -------- --------- -------- Total assets 126,487 124,179 112,919 ======== ========= ========
Capital Expenditures Regulated 9,415 7,070 8,796 Non-regulated 7 - - --------- --------- ------ Total capital expenditures 9,422 7,070 8,796 ======== ========= ========
(12) Quarterly Financial Data (Unaudited)
The quarterly data reflects, in the opinion of management, all normal recurring adjustments necessary to present fairly the results for the interim periods. Basic and Diluted Earnings(Loss) Operating Operating Net Income per Common Revenues Income (Loss) Share(a) Quarter Ended
Fiscal 2002
September 30 $ 7,258,892 $ 479,305 $ (778,325) $ (.31) December 31 12,580,389 1,880,382 591,751 .24 March 31 25,158,025 4,843,984 3,745,226 1.49 June 30 10,932,474 1,197,781 78,061 .03
Fiscal 2001
September 30 $ 6,722,188 $ 152,070 $ (1,055,810) $ (.43) December 31 16,941,117 2,081,843 765,633 .31 March 31 32,330,755 5,315,853 3,983,175 1.60 June 30 14,776,096 1,171,953 (57,103) (.02)
(a) Quarterly earnings per share may not equal annual earnings per share due to changes in shares outstanding.
EXHIBIT 21
Subsidiaries of the Registrant
Delgasco, Inc., Enpro, Inc. and Delta Resources, Inc. are wholly-owned subsidiaries of the Registrant, are incorporated in the state of Kentucky and do business under their corporate names.
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in Registration Statement No. 333-52542 of Delta Natural Gas Company, Inc. on Form S-3 of our report dated August 19, 2002, appearing in this Form 10-K of Delta Natural Gas Company, Inc. for the year ended June 30, 2002.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio September 6, 2002
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
The Company's utility operations are subject to regulation by the PSC, which has a significant role in determining the Company's return on equity. The PSC approves rates that are intended to permit a specified rate of return on investment. The Company's rate tariffs allow the cost of gas to be passed through to customers (see Business - Regulatory Matters).
The Company's business is temperature-sensitive. Accordingly, the Company's sales volumes in any given period reflect, in addition to other factors, the impact of weather, with colder temperatures generally resulting in increased sales volumes by the Company. The Company anticipates that this sensitivity to seasonal and other weather conditions will continue to be reflected in the Company's sales volumes in future periods. However, Delta's current tariffs, approved by the PSC effective January 1, 2000, provide for some adjustment of gas rates through a weather normalization tariff (see Business - Regulatory Matters). Under the weather normalization tariff, Delta's rates for residential and small non-residential customers are generally increased when winter weather is warmer than normal and decreased when winter weather is colder than normal. Delta is permitted to adjust rates for these classes of customers for the billing months of December through April under this tariff.
Liquidity and Capital Resources
Because of the seasonal nature of Delta's sales, the smallest proportion of cash generated from operations is received during the warmer months when sales volumes decrease considerably. Additionally, most construction activity takes place during the non-heating season because of more favorable weather conditions. During the warmer, non-heating months, therefore, cash needs for operations and construction are partially met through short-term borrowings.
Capital expenditures for Delta for fiscal 2003 are expected to be $9.8 million. The capital expenditures will be made for system extensions as well as the replacement and improvement of existing transmission, distribution, gathering and general facilities.
Delta has been generating internally only a portion of the cash necessary for its capital expenditure requirements and thus finances the balance of its capital expenditures on an interim basis through the use of its borrowing capability under its short-term line of credit. The current available line of credit is $40,000,000, of which $19,355,000 was borrowed at June 30, 2002. The line of credit, which is with Bank One, Kentucky, NA, requires renewal during October, 2002. The Company intends to pursue renewal or to enter into a new agreement and seek substantially the same terms as the existing agreement.
These short-term borrowings are periodically repaid with the net proceeds from the sale of long-term debt and equity securities, as was done in March, 1998 when the net proceeds of $24,100,000 from the sale of $25,000,000 of debentures were used to repay short-term debt and to redeem the Company's 9% debentures, that would have matured in 2011, in the amount of $10,000,000.
The primary cash flows during the last three years are summarized below: 2002 2001 2000 ---- ---- ----
Provided by operating activities $10,511,896 $ 2,652,572 $ 8,827,505 Used in investing activities (9,421,765) (7,069,713) (8,795,653) Provided by used in)financing activities (1,028,996) 4,185,248 115,554 ------------ ----------- -----------
Net increase (decrease) in cash and cash equivalents $ 61,135 $ (231,893) $ 147,406 =========== =========== ===========
Cash provided by operating activities consists of net income and noncash items including depreciation, depletion, amortization and deferred income taxes. Additionally, changes in working capital are also included in cash provided by operating activities. The Company expects that internally generated cash, coupled with short-term borrowings, will be sufficient to satisfy its operating, normal capital expenditure and dividend requirements. Results of Operations
Operating Revenues
The decrease in operating revenues for 2002 of $14,840,000 was primarily attributable to decreased sales volumes and decreased gas rates. Sales volumes decreased due to the warmer winter weather in 2002. Gas rates decreased due to lower gas prices, net of increases from the impact of the weather normalization tariff.
The increase in operating revenues for 2001 of $24,843,000 was primarily attributable to increased gas rates and increased sales volumes. Gas rates increased due to higher gas prices, net of decreases from the impact of the weather normalization tariff. Sales volumes increased due to the colder winter weather in 2001.
Heating degree days billed for 2002 were 89.0% of normal as compared with 106.8 % of normal for 2001 and 89.6% of normal for 2000.
The following table sets forth certain variations in revenues for the last two fiscal years:
2002 compared 2001 compared Increase (Decrease) to 2001 to 2000 Variations in regulated revenues Gas rates $ (1,930,000) $ 11,364,800 Weather normalization adjustment 1,935,000 (1,634,000) Sales volumes (9,002,000) 5,715,700 Transportation 529,000 69,100 Other (49,000) 57,400 --------------- --------------- Total $ (8,517,000) $ 15,573,000 ------------- ------------
Variations in non-regulated revenues Gas rates $ (6,354,000) $ 8,669,000 Sales volumes 32,000 601,000 Other (1,000) ----------------- -------------- Total (6,323,000) 9,270,000 --------------- --------------
Total variations in revenues $(14,840,000) $ 24,843,000 ============= ============
Percentage variations in regulated volumes Gas sales (19.1) 18.0 Transportation 13.6 16.8
Percentage variations in non-regulated gas .4 7.7 sales volumes
Operating Expenses
The decrease in purchased gas expense for 2002 of $14,551,000 was due primarily to the 21.3% decrease in the cost of gas purchased for retail sales and the 10.7% decrease in volumes sold.
The increase in purchased gas expense for 2001 of $23,493,000 was due primarily to the 73% increase in the cost of gas purchased for retail sales and the 13% increase in volumes sold, both related to the above detailed revenue variations.
The following table sets forth certain variations in purchased gas expense for the last two fiscal years:
2002 compared 2001 compared to 2001 to 2000 ------------------- ------------
Variations in regulated gas expense Gas rates $ (2,887,000) $ 11,505,000 Purchase volumes (4,877,000) 2,967,000 -------------- --------------- Total $ (7,764,000) $ 14,472,000 -------------- --------------
Variations in non-regulated gas expense Gas rates $ (6,651,000) $ 8,308,000 Purchase volumes (136,000) 713,000 ---------------- --------------- Total $ (6,787,000) $ 9,021,000 --------------- ---------------
Total variations in gas expense $ (14,551,000) $ 23,493,000 =============== ==============
Basic and Diluted Earnings Per Common Share
For the years ended June 30, 2002, 2001 and 2000, basic earnings per common share changed as a result of changes in net income and the increased average common shares outstanding that resulted from the common shares issued under Delta's dividend reinvestment plan and shares issued to employees during the periods. There are no potentially dilutive securities, therefore basic and diluted earnings per common share are the same.
Factors That May Affect Future Results
Management's Discussion and Analysis of Financial Condition and Results of Operations and the other sections of this report contain forward-looking statements that are not statements of historical facts. These forward-looking statements are identified by their language, which may in some cases include words such as "estimates", "attempts", "expects", "monitors", "plans", "anticipates", "intends", "continues" or "will continue", "believes", and similar expressions. Such forward-looking statements may concern future matters (among other matters) such as: Delta's cost and the availability of natural gas supplies; Delta's capital expenditures; its sources and availability of funding for operation and expansion; Delta's anticipated growth and growth opportunities through system expansion and acquisition; competitive conditions; Delta's production, storage, gathering and transportation activities; regulatory and legislative matters; dividends; and external and internal funding sources.
Such forward-looking statements are accordingly subject to important risks and uncertainties that could cause the Company's actual results to differ materially from those expressed in any such forward-looking statements.
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 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 in Delta's capital expenditure requirements. o Changes in economic conditions, demographic patterns and weather conditions in Delta's retail service areas. o Changes affecting Delta's cost of providing gas service, including changes in gas supply costs, interest rates, the availability of external sources of financing for Delta's operations, tax laws, environmental laws, and the general rate of inflation. o Changes affecting the cost 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 Delta.
New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 eliminates the pooling-of-interests method and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. It also requires intangible assets acquired in a business combination to be recognized separately from goodwill. SFAS No. 141 had no impact on the Company's financial position or results of operations with respect to business combination transactions that occurred prior to June 30, 2001. SFAS No. 142 addresses how goodwill and other intangible assets should be accounted for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is that future goodwill and intangible assets with indefinite lives will no longer be amortized beginning in 2002. Instead of amortization, goodwill will be subject to an assessment for impairment by applying a fair-value-based test annually and more frequently if circumstances indicate a possible impairment. If the carrying amount of goodwill exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. The Company does not have recorded goodwill or intangible assets. Accordingly, these new accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No. 143 addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations as a liability when the liability is incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which is required to be adopted July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" and combines the two accounting models into a single model based on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment". This proposed SOP applies to all nongovernmental entities that acquire, construct or replace tangible property, plant and equipment ("PP&E") including lessors and lessees. A significant element of the SOP requires that entities use component accounting for PP&E to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The proposed effective date of the SOP is January 1, 2003. The Company is currently analyzing the impact of this proposed SOP.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Delta serves its regulated customers using 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, while the price of a forward purchase is fixed months prior to the delivery of the gas. Some of Delta's gas purchases are injected into gas storage facilities in the non-heating months and withdrawn from storage for delivery to customers during the heating season. The Company has minimal price risk resulting from these gas purchase and storage arrangements because these gas costs are passed on to Delta's regulated customers through the gas cost recovery rate mechanism.
Delta's non-regulated subsidiaries actively pursue gas sales opportunities for customers within and outside the Company's service area. At the time the Company makes a sales commitment to one of these customers, the Company attempts to cover this position immediately with gas purchase commitments matched to the terms of the related sales contract. The non-regulated subsidiaries attempt to minimize their exposure to price volatility by predetermining the gross profit on their sales at the time of each sales commitment.
None of the Company's gas contracts is accounted for using the fair value method of accounting. While some of the Company's gas purchase contracts meet the definition of a derivative, the Company has designated these contracts as "normal purchases" under SFAS No. 133, "Accounting for Derivatives".
Delta is exposed to risk resulting from changes in interest rates on its variable rate notes payable. The interest rate on the notes payable is benchmarked to the monthly London Interbank Offered Rate. Delta's outstanding notes payable amounted to $19,355,000 and $16,800,000, as of June 30, 2002 and 2001, respectively. Based on the amount of the outstanding notes payable on June 30, 2002, a one percent increase (decrease) in average interest rates would result in a decrease (increase) in annual pre-tax net income of $194,000. See (6) of the Notes to Consolidated Financial Statements.
Item 8.
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE PAGE
Management's Statement of Responsibility for Financial Reporting and Accounting 24
Report of Independent Public Accountants 25
Consolidated Statements of Income for the years ended June 30, 2002, 2001, and 2000 27
Consolidated Statements of Cash Flows for the years ended June 30, 2002, 2001 and 2000 28
Consolidated Balance Sheets as of June 30, 2002 and 2001 30
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2002, 2001, and 2000 32
Consolidated Statements of Capitalization as of June 30, 2002 and 2001 33
Notes to Consolidated Financial Statements 34
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2002, 2001, and 2000 46
Schedules other than those listed above are omitted because they are not required, not applicable or the required information is shown in the financial statements or notes thereto.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Item 11.
Item 11. Executive Compensation
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13.
Item 13. Certain Relationships and Related Transactions
Registrant intends to file a definitive proxy statement with the Commission pursuant to Regulation 14A (17 CFR 240.14a) not 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, 11, 12 and 13 is incorporated herein by reference to the definitive proxy statement. Neither the report on Executive Compensation nor the performance graph included in the Company's definitive proxy statement shall be deemed incorporated herein by reference.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(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(a) - Delta's Amended and Restated Articles of Incorporation are incorporated herein by reference to Exhibit 3(a) to Delta's Form 10-Q for the period ended March 31, 1990.
3(b) - Delta's By-Laws as amended August 21, 1996 are incorporated herein by reference to Exhibit 3(b) to Delta's Form 10-K for the period ended June 30, 1996.
4(a) - The Indenture dated September 1, 1993 in respect of 6 5/8% Debentures due October 1, 2023, is incorporated herein by reference to Exhibit 4(e) to Delta's Form S-2 dated September 2, 1993.
4(b) - The Indenture dated July 1, 1996 in respect of 8.3% Debentures due August 1, 2026, is incorporated herein by reference to Exhibit 4(c) to Delta's Form S-2 dated June 21, 1996.
4(c) - The Indenture dated March 1, 1998 in respect of 7.15% Debentures due April 1, 2018, is incorporated herein by reference to Exhibit 4(d) to Delta's Form S-2 dated March 11, 1998.
10(a) - Certain of Delta's material natural gas supply contracts are incorporated herein by reference to Exhibit 10 to Delta's Form 10 for the year ended June 30, 1978 and by reference to Exhibits C and D to Delta's Form 10-K for the year ended June 30, 1980.
10(b) - Assignment to Delta by Wiser of its Columbia Service Agreement, including a copy of said Service Agreement, is incorporated here- in by reference to Exhibit 2(D) to Delta's Form 8-K dated February 9, 1981.
10(c) - Contract between Tennessee and Delta (amends earlier contract for Nicholasville and Wilmore Service Areas) is incorporated herein by reference to Exhibit 10(d) to Delta's Form 10-Q for the period ended September 30, 1990.
10(d) - Contract between Tennessee and Delta (amends earlier contract for Jeffersonville Service Area) is incorporated herein by reference to Exhibit 10(e) to Delta's Form 10-Q for the period ended September 30, 1990.
10(e) - Contract between Tennessee and Delta (amends earlier contract for Salt Lick Service Area) is incorporated herein by reference to Exhibit 10(f) to Delta's Form 10-Q for the period ended September 30, 1990.
10(f) - Contract between Tennessee and Delta (amends earlier contract for Berea Service Area) is incorporated herein by reference to Exhibit 10(g) to Delta's Form 10-Q for the period ended September 30, 1990.
10(g) - Service Agreements between Columbia and Delta (amends earlier service agreements for Cumberland, Stanton and Owingsville service areas) are incorporated herein by reference to Exhibit 10(h) to Delta's Form 10-Q for the period ended September 30, 1990.
10(h) - Employment agreements between Delta and five officers, those being John B. Brown, Johnny L. Caudill, John F. Hall, Alan L. Heath and Glenn R. Jennings, are incorporated herein by reference to Exhibit 10(k) to Delta's Form 10-Q for the period ended March 31, 2000.
10(i) - Agreement between Delta and Harrison D. Peet, Chairman of the Board, is incorporated herein by reference to Exhibit 10(l) to Delta's Form 10-Q for the period ended March 31, 2000.
12 - Computation of the Consolidated Ratio of Earnings to Fixed Charges.
16 - Letter dated May 22, 2002 to the Securities and Exchange Commission is incorporated herein by reference as Exhibit 16 to Delta's Form 8-K dated May 22, 2002.
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Public Accountants.
(b) Reports on 8-K.
On May 22, 2002, the Company filed a Form 8-K reporting the change in the Company's Auditor.
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 9th day of September, 2002.
DELTA NATURAL GAS COMPANY, INC.
By: /s/Glenn R. Jennings
Glenn R. Jennings, 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 President, Chief Executive September 9, 2002 (Glenn R. Jennings) Officer and Vice Chairman of the Board
(ii) Principal Financial Officer:
/s/John F. Hall Vice-President - Finance, September 9, 2002 (John F. Hall) Secretary and Treasurer
(iii) Principal Accounting Officer:
/s/John B. Brown Controller September 9, 2002 (John B. Brown)
(iv) A Majority of the Board of Directors:
/s/H. D. Peet Chairman of the Board September 9, 2002 (H. D. Peet)
/s/Donald R. Crowe Director September 9, 2002 (Donald R. Crowe)
/s/Jane Hylton Green Director September 9, 2002 (Jane Hylton Green)
/s/Lanny D. Greer Director September 9, 2002 (Lanny D. Greer)
/s/Billy Joe Hall Director September 9, 2002 (Billy Joe Hall)
/s/Lewis N. Melton Director September 9, 2002 (Lewis N. Melton)
/s/Arthur E. Walker, Jr. Director September 9, 2002 (Arthur E. Walker, Jr.)
/s/Michael R. Whitley Director September 9, 2002 (Michael R. Whitley)
Management's Statement of Responsibility for Financial Reporting and Accounting
Management is responsible for the preparation, presentation and integrity of the financial statements and other financial information in this report. In preparing financial statements in conformity with accounting principles generally accepted in the United States, management is required to make estimates and assumptions that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company maintains a system of accounting and internal controls which management believes provides reasonable assurance that the accounting records are reliable for purposes of preparing financial statements and that the assets are properly accounted for and protected.
The Board of Directors pursues its oversight role for these financial statements through its Audit Committee, which consists of four outside directors. The Audit Committee meets periodically with management to review the work and monitor the discharge of their responsibilities. The Audit Committee also meets periodically with the Company's internal auditor as well as Deloitte & Touche LLP, the independent auditors, who have full and free access to the Audit Committee, with or without management present, to discuss internal accounting control, auditing and financial reporting matters.
Glenn R. Jennings John F. Hall John B. Brown President & Chief Vice President - Finance, Controller Executive Officer Secretary & Treasurer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:
We have audited the accompanying consolidated balance sheet of Delta Natural Gas Company, Inc. and subsidiary companies (the "Company") as of June 30, 2002, and the related consolidated statements of capitalization, income, cash flows and changes in shareholders' equity for the year ended June 30, 2002. Our audit also included the 2002 financial statement schedule listed on the index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides 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 subsidiary companies as of June 30, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 2002 financial statement schedule, when considered in relation to the basic 2002 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio August 19, 2002
Report of Previous Independent Public Accountants
THE FOLLOWING REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
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. (a Kentucky corporation) and subsidiary companies as of June 30, 2001 and 2000, and the related consolidated statements of income, cash flows and changes in shareholders' equity for each of the three years in the period ended June 30, 2001. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Delta Natural Gas Company, Inc. and subsidiary companies as of June 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2001, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the Index to Consolidated Financial Statements and Schedule is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Louisville, Kentucky August 10, 2001
Delta Natural Gas Company, Inc. and Subsidiary Companies Consolidated Statements of Income
For the Years Ended June 30, 2002 2001 2000
Operating Revenues $ 55,929,780 $ 70,770,156 $45,926,775 ------------ ------------ -----------
Operating Expenses
Purchased gas $ 30,157,225 $ 44,707,739 $21,214,834
Operation and maintenance 9,685,746 9,844,728 9,139,143
Depreciation and depletion 4,080,944 3,840,450 3,989,090
Taxes other than income taxes 1,354,913 1,423,020 1,338,486
Income taxes (Note 3) 2,249,500 2,232,500 2,068,500 ------------ ------------ ---------
Total operating expenses $ 47,528,328 $ 62,048,437 $37,750,053 ------------ ------------ -----------
Operating Income $8,401,452 $8,721,719 $ 8,176,722
Other Income and Deductions, Net 17,018 31,141 42,866 ------------ ------------ ------------
Income Before Interest Charges $8,418,470 $8,752,860 $ 8,219,588 ---------- ---------- -----------
Interest Charges
Interest on long-term debt $3,728,847 $3,775,856 $ 3,845,565
Other interest 891,750 1,179,949 748,006
Amortization of debt expense 161,160 161,160 161,160 ------------ ----------- -----------
Total interest charges $4,781,757 $5,116,965 $ 4,754,731 ---------- ---------- -----------
Net Income $3,636,713 $3,635,895 $ 3,464,857 ========== ========== ===========
Weighted Average Number of Common Shares Outstanding (Basic and Diluted) 2,513,804 2,477,983 2,433,397
Basic and Diluted Earnings Per Common Share $ 1.45 $ 1.47 $ 1.42
Dividends Declared Per Common Share $ 1.16 $ 1.14 $ 1.14
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended June 30, 2002 2001 2000
Cash Flows From Operating Activities Net income $ 3,636,713 $ 3,635,895 $ 3,464,857
Adjustments to reconcile net income to net cash from Operating activities Depreciation, depletion and Amortization 4,354,396 4,047,715 4,240,595 Deferred income taxes and Investment tax credits 1,110,916 2,332,458 1,446,444 Other - net 595,894 700,091 841,877
(Increase) decrease in assets Accounts receivable 1,767,741 (1,860,926) (1,160,957) Gas in storage (556,871) (1,665,124) 48,005 Deferred (advance recovery of) gas cost 368,648 (4,518,953) (1,124,219) Materials and supplies 69,663 (129,278) 200,689 Prepayments 681,195 (690,662) (51,964) Other assets (1,551,055) (333,402) (561,893)
Increase (decrease) in liabilities Accounts payable (1,524,216) 1,647,056 1,630,760 Refunds due customers 35,653 (5,708) 2,679 Accrued taxes (44,503) (521,190) 284,891 Other current liabilities 128,283 11,340 (302,553) Other liabilities 1,439,439 3,260 (131,706) ----------- ------------ ------------
Net cash provided by operating activities $10,511,896 $ 2,652,572 $ 8,827,505 ----------- ----------- ------------
Cash Flows From Investing Activities Capital expenditures $(9,421,765) $(7,069,713) $ (8,795,653) ------------ ------------ ------------
Net cash used in investing activities $(9,421,765) $(7,069,713) $ (8,795,653) ------------ ----------- ------------
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows (continued)
For the Years Ended June 30, 2002 2001 2000
Cash Flows From Financing Activities Dividends on common stock $(2,916,418) $ (2,825,267) $ (2,777,372) Issuance of common stock, net 707,422 646,514 697,926 Repayment of long-term debt (1,375,000) (810,999) (1,735,000) Issuance of notes payable 36,860,000 52,415,000 27,810,000 Repayment of notes payable (34,305,000) (45,240,000) (23,880,000) ----------- ------------ ------------
Net cash provided by financing activities $(1,028,996) $ 4,185,248 $ 115,554 ----------- ------------ ------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 61,135 $ (231,893) $ 147,406
Cash and Cash Equivalents, Beginning of Year 164,101 395,994 248,588 ----------- ------------ ------------
Cash and Cash Equivalents, End of Year $ 225,236 $ 164,101 $ 395,994 =========== ============ ============
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for Interest $ 4,636,051 $ 4,970,327 $ 4,626,542 Income taxes (net of refunds) $ 1,130,566 $ 395,737 $ 533,908
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets
As of June 30, 2002 2001
Assets Gas Utility Plant, at cost $156,305,063 $147,792,390 Less - Accumulated provision for depreciation (49,142,976) (45,375,230) ------------ ------------
Net gas plant $107,162,087 $102,417,160 ------------ ------------
Current Assets Cash and cash equivalents $ 225,236 $ 164,101 Accounts receivable, less accumulated provisions for doubtful accounts of $165,000 and $575,000 in 2002 and 2001, respectively 2,884,025 4,651,766 Gas in storage, at average cost 5,216,772 4,659,901 Deferred gas costs 4,076,059 4,444,707 Materials and supplies, at first-in, first-out cost 523,756 593,419 Prepayments 388,794 1,090,515 ------------ ------------
Total current assets 13,314,642 $ 15,604,409 ------------ ------------
Other Assets Cash surrender value of officers' life insurance (face amount of $1,236,009) $ 344,687 $ 354,891 Note receivable from officer 158,000 128,000 Prepaid pension, unamortized debt expense and other (Notes 4 and 7) 6,969,109 5,674,678 ------------ ------------
Total other assets $ 7,471,796 $ 6,157,569 ------------ ------------
Total assets $127,948,525 $124,179,138 ============ ============
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets (continued)
As of June 30, 2002 2001
Liabilities and Shareholders' Equity
Capitalization (See Consolidated Statements of Capitalization) Common shareholders' equity $ 34,182,277 $ 32,754,560 Long-term debt (Notes 7 and 8) 48,600,000 49,258,902 ---------- ----------
Total capitalization $ 82,782,277 $ 82,013,462 ------------ ------------
Current Liabilities Notes payable (Note 6) $ 19,355,000 $ 16,800,000 Current portion of long-term debt (Notes 7 and 8) 1,750,000 2,450,000 Accounts payable 4,077,983 5,602,199 Accrued taxes 673,873 718,376 Refunds due customers 73,973 38,320 Customers' deposits 440,568 418,582 Accrued interest on debt 1,162,956 1,178,410 Accrued vacation 558,066 538,595 Other accrued liabilities 503,178 400,898 ------- ----------
Total current liabilities $ 28,595,597 $ 28,145,380 ------------ ------------
Deferred Credits and Other Deferred income taxes $ 14,078,273 $ 12,851,457 Investment tax credits 404,600 449,800 Regulatory liability (Note 3) 562,025 632,725 Additional minimum pension liability (Note 4) 1,461,440 -- Advances for construction and other 64,313 86,314 ----------- ----------
Total deferred credits and other $ 16,570,651 $ 14,020,296 ------------ ------------
Commitments and Contingencies (Note 9) ____________ ____________
Total liabilities and shareholders' equity $127,948,525 $124,179,138 ============ ============
The accompanying notes to consolidated financial statements are an integral part of these statements.
The accompanying notes to consolidated financial statements are an integral part of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Capitalization
As of June 30, 2002 2001
Common Shareholders' Equity Common shares, par value $1.00 per share (Notes 4 and 5) Authorized 6,000,000 shares Issued and outstanding 2,530,079 and 2,495,679 shares in 2002 and 2001, respectively $ 2,530,079 $ 2,495,679 Premium on common shares 30,330,330 29,657,308 Capital stock expense (1,925,431) (1,925,431) Retained earnings (Note 7) 3,247,299 2,527,004 ----------- -----------
Total common shareholders' equity $34,182,277 $32,754,560 ----------- -----------
Long-Term Debt (Notes 7 and 8) Debentures, 8.3%, due 2026 $14,816,000 $14,821,000 Debentures, 6 5/8%, due 2023 11,445,000 11,933,000 Debentures, 7.15%, due 2018 24,089,000 24,271,000 Promissory note from acquisition of under- ground storage, non-interest bearing, due through 2001 (less unamortized discount of $16,098 in 2001) - 683,902 ------------ -----------
Total long-term debt $50,350,000 $51,708,902
Less amounts due within one year, included in current liabilities (1,750,000) (2,450,000) ----------- -----------
Net long-term debt $48,600,000 $49,258,902 ----------- -----------
Total capitalization $82,782,277 $82,013,462 =========== ===========
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") has 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) Depreciation The Company determines its provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant. The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of 2.9%, 2.8% and 3.1% of average depreciable plant for 2002, 2001 and 2000, respectively.
(d) Maintenance All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal.
(e) Gas Cost Recovery Delta has a Gas Cost Recovery ("GCR") clause which provides for a dollar-tracker that matches revenues and gas costs and provides eventual dollar-for-dollar recovery of all gas costs incurred. The Company expenses gas costs based on the amount of gas costs recovered through revenue. Any differences between actual gas costs and those estimated costs billed are deferred and reflected in the computation of future billings to customers using the GCR mechanism.
(f) Revenue Recognition The Company records revenues as billed to its customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the latest date of each cycle meter reading to the month-end is unbilled.
(g) Revenues and Customer Receivables The Company serves 40,000 customers in central and southeastern Kentucky. Revenues and customer receivables arise primarily from sales of natural gas to customers and from transportation services for others. Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable.
(h) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(i) Rate Regulated Basis of Accounting The Company's regulated operations follow the accounting and reporting requirements of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". The economic effects of regulation can result in a regulated company recovering costs from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). The amounts recorded by the Company as regulatory assets and regulatory liabilities are as follows:
Regulatory assets ($000) 2002 2001 ---- ----
Deferred gas cost 4,076 4,445 Loss on extinguishment of debt 1,337 1,395 Rate case and gas audit expense 116 142 ------ ------ Total regulatory assets 5,529 5,982 ===== =====
Regulatory liabilities ($000)
Refunds from suppliers that are due customers 74 38 Regulatory liability for deferred income taxes 562 633 ------ ------- Total regulatory liabilities 636 671 ====== =======
The Company is currently earning a return on loss on extinguishment of debt and rate case expenses. Deferred gas costs are presented every three months to the PSC for recovery in accordance with the gas cost recovery rate mechanism.
(2) New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 eliminates the pooling-of-interests method and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. It also requires intangible assets acquired in a business combination to be recognized separately from goodwill. SFAS No. 141 had no impact on the Company's financial position or results of operations with respect to business combination transactions that occurred prior to June 30, 2001. SFAS No. 142 addresses how goodwill and other intangible assets should be accounted for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is that future goodwill and intangible assets with indefinite lives will no longer be amortized beginning in 2002. Instead of amortization, goodwill will be subject to an assessment for impairment by applying a fair-value-based test annually and more frequently if circumstances indicate a possible impairment. If the carrying amount of goodwill exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. The Company does not have recorded goodwill or intangible assets. Accordingly, these new accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No. 143 addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations as a liability when the liability is incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which is required to be adopted July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" and combines the two accounting models into a single model based on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment". This proposed SOP applies to all nongovernmental entities that acquire, construct or replace tangible property, plant and equipment ("PP&E") including lessors and lessees. A significant element of the SOP requires that entities use component accounting for PP&E to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The proposed effective date of the SOP is January 1, 2003. The Company is currently analyzing the impact of this proposed SOP.
(3) Income Taxes
The Company provides for income taxes on temporary differences resulting from the use of alternative methods of income and expense recognition for financial and tax reporting purposes. The differences result primarily from the use of accelerated tax depreciation methods for certain properties versus the straight-line depreciation method for financial purposes, differences in recognition of purchased gas cost recoveries and certain other accruals which are not currently deductible for income tax purposes. Investment tax credits were deferred for certain periods prior to fiscal 1987 and are being amortized to income over the estimated useful lives of the applicable properties. The Company utilizes the asset and liability method for accounting for income taxes, which requires that deferred income tax assets and liabilities are computed using tax rates that will be in effect when the book and tax temporary differences reverse. The change in tax rates applied to accumulated deferred income taxes may not be immediately recognized in operating results because of ratemaking treatment. A regulatory liability has been established to recognize the future revenue requirement impact from these deferred taxes. The temporary differences which gave rise to the net accumulated deferred income tax liability for the periods are as follows:
2002 2001 ---- ---- Deferred Tax Liabilities Accelerated depreciation $ 13,436,373 $12,440,957 Deferred gas cost 1,364,800 1,444,200 Accrued pension 1,104,200 1,157,200 Debt expense 406,300 426,900 ------------ -----------
Total $ 16,311,673 $15,469,257 ------------ -----------
Deferred Tax Assets Alternative minimum tax credits $ 1,365,200 $ 1,701,100 Regulatory liabilities 221,700 249,600 Investment tax credits 159,600 177,400 Other 486,900 489,700 ----------- -----------
Total $2,233,400 $ 2,617,800 ---------- -----------
Net accumulated deferred income tax liability $ 14,078,273 $12,851,457 ============ ===========
The components of the income tax provision are comprised of the following for the years ended June 30:
2002 2001 2000 ---- ---- ---- Components of Income Tax Expense Current Federal $ 776,200 $ (77,000) $ 568,100 State 296,100 (71,700) 137,500 ----------- ----------- ----------- Total $ 1,072,300 $ (148,700) $ 705,600
Deferred 1,177,200 2,381,200 1,362,900 ----------- ----------- -----------
Income tax expense $ 2,249,500 $ 2,232,500 $ 2,068,500 =========== =========== ===========
Reconciliation of the statutory federal income tax rate to the effective income tax rate is shown in the table below: 2002 2001 2000 ---- ---- ----
Statutory federal income tax rate 34.0 % 34.0 % 34.0 % State income taxes net of federal benefit 5.3 5.4 5.2 Amortization of investment tax credits (0.8) (0.9) (1.1) Other differences - net (0.2) (0.3) (0.4) ------ ------ -----
Effective income tax rate 38.3 % 38.2 % 37.7 % ======= ====== ======
(4) Employee Benefit Plans
(a) Defined Benefit Retirement Plan Delta has a trusteed, noncontributory, defined benefit pension plan covering all eligible employees. Retirement income is based on the number of years of service and annual rates of compensation. The Company makes annual contributions equal to the amounts necessary to fund the plan adequately. The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ended March 31, 2002, and a statement of the funded status as of March 31 of both years, as recognized in the Company's consolidated balance sheets at June 30:
2002 2001 ---- ---- Change in Benefit Obligation Benefit obligation at beginning of year $ 8,486,103 $ 8,188,361 Service cost 518,496 487,392 Interest cost 657,126 592,537 Amendments 1,514,620 -- Actuarial loss (84,009) 332,610 Benefits paid (411,217) (1,114,797) ------------ ------------ Benefit obligation at end of year $ 10,681,119 $ 8,486,103 ------------ ------------
Change in Plan Assets Fair value of plan assets at beginning of year $ 9,073,398 $ 10,176,049 Actual return (loss) on plan assets 14,243 (636,591) Employer contribution 543,255 648,737 Benefits paid (411,217) (1,114,797) ------------ ------------ Fair value of plan assets at end of year $ 9,219,679 $ 9,073,398 ------------ ------------
Funded status $ (1,461,440) $ 587,295 Unrecognized net actuarial loss 2,272,764 1,652,236 Unrecognized prior service cost 1,514,620 -- Net transition asset -- (29,262) ------------- ------------
Net pension asset $ 2,325,944 $ 2,210,269 ============ ============
In addition, the Company has recognized an additional minimum pension liability of $1,461,440 and a corresponding intangible pension asset in the accompanying balance sheet as of June 30, 2002. Effective April 1, 2002, the Company adopted a plan amendment which enhanced the formula for benefits paid under the plan.
The assets of the plan consist primarily of common stocks, bonds and certificates of deposit. Net pension costs for the years ended June 30 include the following: 2002 2001 2000 ---- ---- ---- Components of Net Periodic Benefit Cost Service cost $ 518,496 $ 487,392 $ 535,681 Interest cost 657,125 592,537 538,400 Expected return on plan assets (755,307) (800,303) (764,449) Amortization of unrecognized net loss 36,528 -- -- Amortization of net transition asset (29,262) (42,394) (42,394) --------- --------- --------- Net periodic benefit cost $ 427,580 $ 237,232 $ 267,238 ========= ========= =========
Weighted-Average Assumptions Discount rate 7.50% 7.75% 7.75% Expected return on plan assets 8.00% 8.00% 8.00% Rate of compensation increase 4.00% 4.00% 4.00%
During the plan year ended March 31, 2000, Delta eliminated 16 positions in conjunction with a workforce reduction plan. Subsequently, 7 additional positions were eliminated as a result of reorganization of Delta's branch offices, which was completed by June 30, 2000. These events constituted a curtailment under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". The combined impact of the curtailment gain, the savings in salary expense, and the cost of one time payments made to severed employees was not material to results of operations in 2000.
SFAS No. 106, "Employers' Accounting for Post-Retirement Benefits", and SFAS No. 112, "Employers' Accounting for Post-Employment Benefits", do not affect the Company, as Delta does not provide benefits for post-retirement or post-employment other than the pension plan for retired employees.
(b) Employee Savings Plan The Company has an Employee Savings Plan ("Savings Plan") under which eligible employees may elect to contribute any whole percentage between 2% and 15% of their annual compensation. The Company will match 50% of the employee's contribution up to a maximum Company contribution of 2.5% of the employee's annual compensation. For 2002, 2001, and 2000, Delta's Savings Plan expense was $165,500, $154,600, and $170,800, respectively.
(c) Employee Stock Purchase Plan The Company has an Employee Stock Purchase Plan ("Stock Plan") under which qualified permanent employees are eligible to participate. Under the terms of the Stock Plan, such employees can contribute on a monthly basis 1% of their annual salary level (as of July 1 of each year) to be used to purchase Delta's common stock. The Company issues Delta common stock, based upon the fiscal year contributions, using an average of the high and low sale prices of Delta's stock as quoted in NASDAQ's National Market System on the last business day in June and matches those shares so purchased. Therefore, stock with an equivalent market value of $96,300 was issued in July, 2002. The continuation and terms of the Stock Plan are subject to approval by Delta's Board of Directors on an annual basis. Delta's Board has continued the Stock Plan through June 30, 2003.
(5) Dividend Reinvestment and Stock Purchase Plan
The Company's Dividend Reinvestment and Stock Purchase Plan ("Reinvestment Plan") provides that shareholders of record can reinvest dividends and also make limited additional investments of up to $50,000 per year in shares of common stock of the Company. Under the Reinvestment Plan the Company issued 28,506, 28,958, and 37,499 shares in 2002, 2001, and 2000, respectively. Delta reserved 150,000 shares for issuance under the Reinvestment Plan in December, 2000, and as of June 30, 2002 there were 106,266 shares still available for issuance.
(6) Notes Payable and Line of Credit
The current available line of credit is $40,000,000, of which $19,355,000 and $16,800,000 was borrowed having a weighted average interest rate of 3.67% and 6.97% as of June 30, 2002 and 2001, respectively. The maximum amount borrowed during 2002 and 2001 was $29,005,000 and $21,445,000, respectively. The interest on this line is determined monthly at the London Interbank Offered Rate plus 1% on the used line of credit. The cost of the unused line of credit is 0.30%. The current line of credit must be renewed during October, 2002.
(7) Long-Term Debt
In March, 1998 Delta issued $25,000,000 of 7.15% Debentures that mature in March, 2018. Redemption of up to $25,000 annually will be made on behalf of deceased holders within 60 days of notice, subject to an annual aggregate $750,000 limitation. The 7.15% Debentures can be redeemed by the Company after April 1, 2003. Restrictions under the indenture agreement covering the 7.15% Debentures include, among other things, a restriction whereby dividend payments cannot be made unless consolidated shareholders' equity of the Company exceeds $21,500,000. No retained earnings are restricted under the provisions of the indenture.
In July, 1996 Delta issued $15,000,000 of 8.3% Debentures that mature in July, 2026. Redemption on behalf of deceased holders within 60 days of notice of up to $25,000 per holder will be made annually, subject to an annual aggregate limitation of $500,000. The 8.3% Debentures can be redeemed by the Company beginning in August, 2001 at a 5% premium, such premium declining ratably until it ceases in August, 2006.
In October, 1993 Delta issued $15,000,000 of 6 5/8% Debentures that mature in October, 2023. Each holder may require redemption of up to $25,000 annually, subject to an annual aggregate limitation of $500,000. Such redemption will also be made on behalf of deceased holders within 60 days of notice, subject to the annual aggregate $500,000 limitation. The 6 5/8% Debentures can be redeemed by the Company beginning in October, 1998 at a 5% premium, such premium declining ratably until it ceases in October, 2003. The Company may not assume any additional mortgage indebtedness in excess of $2 million without effectively securing the 6 5/8% Debentures equally to such additional indebtedness.
The Company amortizes debt issuance expenses over the life of the related debt on a straight-line basis, which approximates the effective yield method.
(8) Fair Values of Financial Instruments
The fair value of the Company's debentures is estimated using discounted cash flow analysis, based on the Company's current incremental borrowing rates for similar types of borrowing arrangements. The fair value of the Company's debentures at June 30, 2002 and 2001 was estimated to be $47,479,000 and $48,429,000, respectively. The carrying amount in the accompanying consolidated financial statements as of June 30, 2002 and 2001 is $50,350,000 and $51,025,000, respectively.
The carrying amount of the Company's other financial instruments including cash equivalents, accounts receivable, notes receivable, accounts payable and the non-interest bearing promissory note approximate their fair value.
(9) Commitments and Contingencies
The Company has entered into individual employment agreements with its five officers and an agreement with the Chairman of the Board. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company.
(10) Rates
Delta's retail natural gas distribution and its transportation services are subject to the regulatory authority of the Public Service Commission of Kentucky ("PSC") with respect to various aspects of Delta's business, including rates and service to retail and transportation customers. Delta monitors the need to file a general rate case as a way to adjust its sales prices.
On December 27, 1999, Delta received approval from the PSC for an annual revenue increase of $420,000. This resulted from Delta's last rate case that was filed by Delta in July, 1999. The approval included a weather normalization provision that permits Delta to adjust base rates for the billing months of December through April to reflect variations from normal winter weather.
Delta's rates include a Gas Cost Recovery ("GCR") clause, which permits changes in Delta's gas supply costs to be reflected in the rates charged to customers. The GCR requires Delta to make quarterly filings with the PSC, but such procedure does not require a general rate case.
During July, 2001, the PSC required an independent audit of the gas procurement activities of Delta and four other gas distribution companies as part of its investigation of increases in wholesale natural gas prices and their impacts on customers. The PSC indicated that Kentucky distributors had generally developed sound planning and procurement procedures for meeting their customers' natural gas requirements and that these procedures had provided customers with a reliable supply of natural gas at reasonable costs. The PSC noted the events of the prior year, including changes in natural gas wholesale markets, and required the audits to evaluate distributors' gas planning and procurement strategies in light of the recent more volatile wholesale markets, with a primary focus on a balanced portfolio of gas supply that balances cost issues, price risk and reliability. The consultants that were selected by the PSC are currently completing this audit. Delta has received a draft of the consultant's report and is in the process of reviewing and commenting on it. The draft report contains procedural and reporting-related recommendations in the areas of gas supply planning, organization, staffing, controls, gas supply management, gas transportation, gas balancing, response to regulatory change and affiliate relations. The report also addresses several general areas for the five gas distribution companies involved in the audit, including Kentucky natural gas price issues, hedging, GCR mechanisms, budget billing, uncollectible accounts and forecasting. Delta cannot predict how the PSC will interpret or act on any audit recommendations. As a result, Delta cannot predict the impact of this regulatory proceeding on the Company's financial position or results of operations.
In addition to PSC regulation, Delta may obtain non-exclusive franchises from the cities and communities in which it operates authorizing it to place its facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the PSC to bid on a local franchise. Delta holds franchises in four of the cities and seven other communities it serves. In the other cities and communities served by Delta, either Delta's franchises have expired, the communities do not have governmental organizations authorized to grant franchises, or the local governments have not required or do not want to offer a franchise. Delta attempts to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government could require Delta to cease its occupation of the streets and public grounds or prohibit Delta from extending its facilities into any new area of that city or community. To date, the absence of a franchise has had no adverse effect on Delta's operations.
(11) Operating Segments
The Company has two segments: (i) a regulated natural gas distribution, transmission and storage segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production. The regulated segment represents Delta and the non-regulated segment consists of Resources, Delgasco and Enpro. The Company operates in a single geographic area of central and southeastern Kentucky.
The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements. Intersegment revenues and expenses consist of intercompany revenues and expenses from the sale and purchase of gas as well as intercompany gas transportation services. Effective January 1, 2002, the non-regulated segment discontinued the practice of selling gas to the regulated segment. This led to a decline in intersegment revenues and expenses for 2002. Intersegment transportation revenue and expense is recorded at Delta's tariff rates. Transfer pricing for sales of gas between segments is at cost. Operating expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown below for the periods:
($000) 2002 2001 2000 ---- ---- ---- Revenues Regulated External customers 40,370 48,887 33,314 Intersegment 3,050 3,244 4,606 ------- --------- -------- Total regulated 43,420 52,131 37,920 Non-regulated External customers 15,560 21,883 12,613 Intersegment 1,688 27,609 16,249 ------- --------- -------- Total non-regulated 17,248 49,492 28,862 Eliminations for intersegment (4,738) (30,853) (20,855) -------- -------- -------- Total operating revenues 55,930 70,770 45,927 ======= ========= ========
Operating Expenses Regulated Depreciation 3,964 3,797 3,940 Income taxes 1,599 1,696 1,657 Other 30,485 38,662 24,792 ------- --------- -------- Total regulated 36,048 44,155 30,389 ------- --------- -------- Non-regulated Depreciation 117 43 49 Income taxes 651 536 412 Other 15,450 48,167 27,755 ------- --------- -------- Total non-regulated 16,218 48,746 28,216 Eliminations for intersegment (4,738) (30,853) (20,855) -------- -------- -------- Total operating expenses 47,528 62,048 37,750 ======= ========= ========
($000) 2002 2001 2000 ---- ---- ----
Other Income and Deductions Regulated 17 31 43 Non-regulated - - - --------- --------- ------ Total other income 17 31 43 and deductions ======== ========= ========
Interest Charges Regulated 4,768 5,191 4,766 Non-regulated 25 42 41 Eliminations for intersegment (11) (116) (52) -------- -------- -------- Total interest charges 4,782 5,117 4,755 ======== ========= ========
Net Income Regulated 2,621 2,817 2,808 Non-regulated 1,016 819 657 -------- --------- -------- Total net income 3,637 3,636 3,465 ======== ========= ========
Assets Regulated 124,764 120,710 108,876 Non-regulated 1,723 3,469 4,043 -------- --------- -------- Total assets 126,487 124,179 112,919 ======== ========= ========
Capital Expenditures Regulated 9,415 7,070 8,796 Non-regulated 7 - - --------- --------- ------ Total capital expenditures 9,422 7,070 8,796 ======== ========= ========
(12) Quarterly Financial Data (Unaudited)
The quarterly data reflects, in the opinion of management, all normal recurring adjustments necessary to present fairly the results for the interim periods. Basic and Diluted Earnings(Loss) Operating Operating Net Income per Common Revenues Income (Loss) Share(a) Quarter Ended
Fiscal 2002
September 30 $ 7,258,892 $ 479,305 $ (778,325) $ (.31) December 31 12,580,389 1,880,382 591,751 .24 March 31 25,158,025 4,843,984 3,745,226 1.49 June 30 10,932,474 1,197,781 78,061 .03
Fiscal 2001
September 30 $ 6,722,188 $ 152,070 $ (1,055,810) $ (.43) December 31 16,941,117 2,081,843 765,633 .31 March 31 32,330,755 5,315,853 3,983,175 1.60 June 30 14,776,096 1,171,953 (57,103) (.02)
(a) Quarterly earnings per share may not equal annual earnings per share due to changes in shares outstanding.
EXHIBIT 21
Subsidiaries of the Registrant
Delgasco, Inc., Enpro, Inc. and Delta Resources, Inc. are wholly-owned subsidiaries of the Registrant, are incorporated in the state of Kentucky and do business under their corporate names.
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in Registration Statement No. 333-52542 of Delta Natural Gas Company, Inc. on Form S-3 of our report dated August 19, 2002, appearing in this Form 10-K of Delta Natural Gas Company, Inc. for the year ended June 30, 2002.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio September 6, 2002