10-K 1 doc1.txt SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED JUNE 30, 2004. or [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ________ TO ________. Commission file number 333-29001-01 ENERGY CORPORATION OF AMERICA (Exact name of registrant as specified in its charter) WEST VIRGINIA 84-1235822 (State or other jurisdiction of incorporation or organization) (IRS Employer Identification Number) 4643 SOUTH ULSTER STREET, SUITE 1100 DENVER, COLORADO 80237 (Address of principal executive offices and zip code) (303) 694-2667 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of the Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [_] No [X] The aggregate number of shares and market value of common stock held by non-affiliates of the registrant at September 23, 2004 was 38,350 shares. The market value held by non-affiliates is unavailable. The number of shares of the registrant's common stock, par value $1.00 per share, outstanding at September 23, 2004 was 602,426 shares. DOCUMENTS INCORPORATED BY REFERENCE: NONE 2

~~2003~~ENERGY ~~2002~~CORPORATION ~~2001~~OF ~~--------~~AMERICA ~~--------~~TABLE ~~--------~~OF ~~Net~~CONTENTS ~~proved:~~Page ~~Gas~~Part ~~(Mmcf)~~I ~~190,796~~Item ~~183,345~~1. ~~206,456~~Business ~~Oil~~. ~~(Mbbls)~~. ~~2,366~~. ~~2,951~~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Item 2~~,633~~. ~~Total~~Properties ~~(Mmcfe)~~. ~~204,992~~. ~~201,051~~. ~~222,254~~. ~~Net~~. ~~proved~~. ~~developed:~~. ~~Gas~~. ~~(Mmcf)~~. ~~161,796~~. ~~160,224~~. ~~175,784~~. . . . . . . . . . . . . . . . . . . . . . 7 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . 11 Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters . . 11 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition. . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . 24 Item 8. Consolidated Financial Statements and Supplementary Data Report of Independent Registered Public Accounting Firm. . . . . . . . . . 26 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . 29 Statements of Stockholders Equity. . . . . . . . . . . . . . . . . . . . . 30 Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . 31 Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . 32 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . 33 Supplemental Information on Oil and Gas Producing Activities (~~Mbbls~~Unaudited) ~~1,064~~. ~~1,135~~52 ~~987~~Item ~~Total~~9. ~~(Mmcfe)~~Changes ~~168,180~~In ~~167,034~~and ~~181,706~~Disagreements ~~Estimated~~With ~~future~~Accountants ~~net~~on ~~cash~~Accounting ~~flows~~and ~~before~~Financial ~~income~~Disclosure ~~taxes~~. ~~(in~~. ~~thousands)~~. ~~$916,885~~. ~~$471,927~~. ~~$557,352~~. ~~Present~~. ~~value~~. . . . . . . . . . . . . . . . . . . 57 Item 9A. Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Part III Item 10. Directors and Officers of ~~estimated~~Registrant ~~future~~. ~~net~~. ~~cash~~. ~~flows~~. ~~before~~. ~~income~~. ~~taxes~~. ~~(in~~. ~~thousands)~~. ~~(1)~~. ~~$382,094~~. ~~$200,087~~. ~~$232,866~~. ~~______________~~. ~~(1)~~. ~~Discounted~~. ~~using~~. an. ~~annual~~. ~~discount~~. ~~rate~~57 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Item 12. Security Ownership of ~~10%~~Certain Beneficial Owners and Management . . . . . . . 62 Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . 65 Item 14. Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . 66 Part IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . 68 Part V Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

3 PART I ------ ITEM 1. BUSINESS ------------------- GENERAL ------- Energy Corporation of America (the "Company") is a privately held energy company engaged in the exploration, development, production, gathering and aggregation of natural gas and oil, primarily in the Appalachian Basin and Gulf Coast regions in the United States and New Zealand. The Company conducts business primarily through its principal wholly owned subsidiaries and is one of the largest oil and gas operators in the Appalachian Basin. As used herein the "Company" refers to the Company alone or together with one or more of its subsidiaries. The Company was formed in June 1993 through an exchange of shares with the common stockholders of Eastern American Energy Corporation ("Eastern American"). As of June 30, 2004, the Company had approximately 229 full-time and 27 part-time employees. None of the employees were covered by a collective bargaining agreement. Management believes that its relationship with its employees is good. The principal offices of the Company are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and the telephone number is (303) 694-2667. Definitions - All defined terms under Rule 4-10 (a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (Mmcf), billion cubic feet (Bcf), dekatherm (Dth), or thousand dekatherms (Mdth). A dekatherm is equal to one million British Thermal Units (Btu). A Btu is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. With respect to information relating to the Company's working interest in wells or acreage, "net" oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company's working interest therein. Oil is quantified in terms of barrels (Bbls), thousand barrels (Mbbls) or million barrels (Mmbbls). Oil is compared to natural gas in terms of thousand cubic feet equivalent (Mcfe), million cubic feet equivalent (Mmcfe) or billion cubic feet equivalent (Bcfe). One barrel of oil is assumed to have the energy equivalent of six Mcf of natural gas. Unless otherwise specified, all references to wells and acres are gross. BUSINESS ACTIVITY ------------------ SEGMENT INFORMATION -------------------- The Company's businesses constitute two operating segments (i) gas and oil exploration and production and (ii) gas aggregation and pipelines. For financial information on these segments, see Note 16 to the Consolidated Financial Statements. 4 GAS AND OIL EXPLORATION AND PRODUCTION -------------------------------------- OPERATIONS AND SIGNIFICANT DEVELOPMENTS The Company's proved net gas and oil reserves are estimated as of June 30, 2004 at 215,475 Mmcf and 1,280 Mbbls, respectively. For the fiscal year ended June 30, 2004, the Company's net gas production was 10,718 Mmcf and net oil production was 107 Mbbls, for a total of 11,360 net Mmcfe. DEVELOPMENT ACTIVITY The Company, in fiscal year 2004, drilled 27 productive gross wells (17.6 net), and recompleted 2 wells, adding 5,234 gross Mcf of gas production per day. EXPLORATORY ACTIVITY Exploration wells and activity are summarized under their respective project areas. 1. Newburg/Silurian, Trenton/Black River -- West Virginia. The Company drilled one successful well, two dry holes and one well that is currently being tested and appears to be productive. Current production from the Trenton/Black River discovery is approximately 700 gross Mcf per day and 140 net Mcf per day. The Company plans to continue to pursue select extension and exploration opportunities in both trends. 2. Texas. The Company drilled four exploratory wells with a success rate of 50%. The principal producing formation is the Wilcox at depths ranging to 16,000 feet. The Company is working on a development drilling plan to capitalize on its exploration success. 3. New Zealand. The Company drilled an unsuccessful well in the Mt. Messenger formation in the Taranaki region. The Company continues with an active drilling program in New Zealand. 4. Rocky Mountains. The Company drilled four unsuccessful exploration wells in the northern Powder River Basin. COMPETITION ----------- The Company encounters substantial competition in acquiring properties, aggregating oil and gas, securing drilling equipment and personnel and operating its properties. The competitors in acquisitions, development, exploration and production include major oil companies, numerous independent oil and gas companies, gas marketers, individual proprietors and others. Natural gas competes with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for natural gas. REGULATIONS AFFECTING OPERATIONS ---------------------------------- The Company's operations are affected by extensive regulation pursuant to various federal, state and local laws and regulations relating to the exploration for and development, production, gathering, aggregation, transportation and storage of oil and gas. These regulations, among other things, can affect 5 the rate of oil and gas production. The Company's operations are subject to numerous laws and regulations governing plugging and abandonment, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling commences, restricts the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution which might result from the Company's operations. The Company believes it is within substantial compliance with regulations affecting the Company. GAS AGGREGATION AND PIPELINES --------------------------------- The Company, primarily through its wholly owned subsidiary Eastern Marketing Corporation ("Eastern Marketing"), aggregates natural gas through the purchase of production from properties in the Appalachian Basin in which the Company has an interest, the purchase of gas delivered through the Company's gathering pipelines located in the Appalachian Basin, and the purchase of gas in the spot market. The Company sells gas to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. The Company owns and operates approximately 2,280 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities. The Company finalized the purchase of an additional 100-mile long natural gas gathering system ("System 8000") from Columbia Gas Transmission during the first quarter of fiscal year 2005. System 8000 is located in northeastern West Virginia and is situate among one of the Company's existing operating areas. During the fiscal year ended June 30, 2004, Eastern Marketing aggregated and sold an average of 40.4 Mmcf of gas per day, of which 38.9 Mmcf per day represented sales of gas produced from wells operated by the Company. This represents a 2% decrease in the overall volumes compared to fiscal year 2003, during which Eastern Marketing aggregated and sold an average of 41.2 Mmcf of gas per day. GAS SALES AND PURCHASE CONTRACTS ------------------------------------- The Company has satisfied its obligations under all gas sales contracts (14.7 Bcf in fiscal year 2004) through gas production attributable to its own interests in oil and gas properties and through production attributable to third party interests in the same oil and gas properties (14.2 Bcf in fiscal 2004), and from natural gas purchased by the Company pursuant to its aggregation activities from third parties (0.5 Bcf in fiscal 2004). On November 30, 2001, the Company entered into a natural gas sales contract with Mountaineer Gas Company, doing business as Allegheny Power, to deliver 5,500 Dth per day. Under the pricing terms, the minimum price to be received by the Company is $2.75 per Dth plus the Columbia Gas Transmission ("TCO") Appalachia Basis and the maximum to be received is $4.85 per Dth plus the TCO Appalachia Basis. The pricing terms also allow the Company to fix the price on 50% of the volumes. The Company has locked the price on 50% of the volumes from July 1, 2003 through October 31, 2004 at a weighted average price of $4.85 per Dth plus the TCO Appalachia Basis. The contract began on December 1, 2001 and continues through October 31, 2004. The Company entered into a gas sales contract with AFG Industries, Inc. ("AFG") for the sale of up to 4,000 MMBtu per day from January 1, 2004 through December 31, 2004. AFG is a "Float Glass" plant adjacent to an existing Company pipeline. The sales contract price is based off the NYMEX settlement price for Natural Gas Henry Hub Futures Contracts each month plus an Appalachian Basis component. 6 In March 1993, the Company entered into a gas purchase contract with the Eastern American Natural Gas Trust (the "Royalty Trust") to purchase all gas production attributable to the Royalty Trust until its termination in May 2013. The purchase contract price is based off of the average of certain Hentry Hub Gas Futures Contracts related to the month of production plus an Appalachian Basis component. REGULATIONS AFFECTING MARKETING AND TRANSPORTATION ------------------------------------------------------- As a purchaser of natural gas, the Company depends on the transportation, gathering and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of its own gas supplies as well as those it processes and/or markets for others. Both the performance of transportation and storage services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the Federal Energy Regulatory Commission. In addition, the performance of transportation, gathering and storage services by intrastate pipelines and the rates charged for such services are subject to the jurisdiction of state regulatory agencies. ITEM 2. PROPERTIES ------- ----------- OIL AND GAS RESERVES ----------------------- The following information relating to estimated reserve quantities, reserve values and discounted future net revenues is derived from, and qualified in its entirety by reference to, the more complete reserve and revenue information and assumptions included in the Company's Supplemental Oil and Gas Disclosures at Item 8. The Company's estimates of proved reserve quantities of its properties have been subject to review by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve information represents estimates only and should not be construed as being exact. Future reserve values are based on year-end prices except in those instances where the sale of gas and oil is covered by contract terms. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalations. The following table sets forth the Company's estimated proved and proved developed reserves and the related estimated future value, as of June 30: 7

~~Present~~2004 ~~Value~~2003 2002 ---------- -------- -------- ~~Natural~~Net proved: Gas ~~Amount~~(Mmcf) ~~Oil~~215,475 ~~Natural~~190,796 ~~Gas~~183,345 ~~Equivalent~~Oil ~~Region~~ (~~thousands~~Mbbls) %1,280 ~~(Mbbls)~~2,366 ~~(Mmcf)~~2,951 Total (Mmcfe) ~~------------------~~223,155 ~~------------~~204,992 ~~------~~201,051 ~~------------~~Net ~~-----------~~proved ~~--------~~developed: ~~Appalachian~~Gas ~~Basin~~(Mmcf) ~~$ 306~~170,~~838~~131 ~~80.3% 631 166~~161,~~539~~796 ~~170~~160,~~325~~224 ~~Western~~Oil ~~Basins~~(Mbbls) ~~17,717~~626 ~~4.6%~~ 1,~~191~~064 41,~~285~~135 ~~11,431~~Total ~~Gulf~~(Mmcfe) ~~Coast~~173,887 53168,~~858~~180 ~~14.1%~~167,034 ~~225~~Estimated ~~18,933~~future ~~20,283~~net ~~New~~cash ~~Zealand~~flows ~~3,681~~before ~~1.0%~~income ~~319~~taxes (in thousands) $1,~~039~~074,207 2$916,~~953~~885 ~~------------~~$471,927 ~~------~~Present ~~------------~~value ~~-----------~~of ~~--------~~estimated ~~Total~~future $net ~~382,094~~cash ~~100.0%~~flows ~~2,366~~before ~~190,796~~income ~~204,992~~taxes ~~============~~(in ~~======~~thousands) ~~============~~(1) ~~===========~~$ ~~========~~435,387 $382,094 $200,087 _______________

(1) Discounted using an annual discount rate of 10%. The following table sets forth the Company's estimated proved reserves and the related estimated present value by region, as of June 30, 2004:

~~Gross~~Present ~~Wells~~Value ~~Net Wells~~ -------------------- Natural Gas Amount Oil Natural Gas Equivalent Region (thousands) % (Mbbls) (Mmcf) (Mmcfe) -- --------------- ------- ~~Oil Gas Total Oil Gas Total~~ ----- ------- ------- ---- -------- ------------ Appalachian Basin ~~12.0~~$ 5364,~~372.0~~258 ~~5,384~~83.0 7.0% 3422 178,~~223.0~~767 3181,~~230.0~~299 Western ~~Basins~~53,958 1112.~~0 2.0 13.0 3.~~4% ~~0.2~~362 ~~3.6~~30,881 ~~Gulf~~33,053 ~~Coast~~New -Zealand ~~13.0~~17,171 ~~13.0 -~~ 3.9% ~~3.9~~496 ~~New~~5,827 ~~Zealand~~8,803 - ~~4.0 4.0~~ - ~~4.0 4.0~~ ---- ------ ------ ------- ---- -------- ------------ Total ~~23.0~~$ 5435,~~391~~387 100.0% 51,~~414.0~~280 ~~10.4 3~~215,~~231.1~~475 3223,~~241.5~~155 ==== ======== ======= ======= ============ ============

PRODUCING WELLS ---------------- The following table sets forth certain information relating to productive wells at June 30, 2004. Wells are classified as oil or gas according to their predominant production stream.

~~Developed~~Gross ~~Acreage~~Wells ~~Undeveloped~~Net ~~Acreage~~Wells ======================= ====================== Region Oil Gas Total Oil Gas Total -----------------~~---~~ ----- -------~~------------~~ ~~Gross Net Gross Net~~ --------- ----~~-----~~ -------~~----~~ -------~~----~~ Appalachian Basin ~~402,870~~21.0 ~~310~~5,~~441~~299.0 ~~144~~5,~~041~~320.0 ~~117,982~~13.0 ~~Western Basins 1~~3,~~920~~347.0 13,~~457~~360.90 ~~86,864.4~~Western ~~45,228~~7.30 ~~Gulf Coast 1,913~~15.50 ~~670~~22.80 ~~33,758~~2.86 ~~20,024~~4.4 7.0 New Zealand ~~740~~- 4.0 ~~736~~4.30 ~~3,181,413~~- 4.10 ~~2,776,411~~4.90 ----- ---- --- ------- ---- ------- -------~~----~~ Total ~~407,443~~28.0 5,318.0 ~~313~~5,~~306~~346.0 15.6 3,~~446,077~~355.34 23,~~959,646~~371.60 ===== ==== === ======= ==== ======= =======~~====~~

8 ACREAGE ------- The following table sets forth the developed and undeveloped gross and net acreage held at June 30, 2004:

~~2003~~Developed ~~2002~~Acreage ~~2001~~Undeveloped Acreage ==================== ======================== Region Gross Net Gross Net ----------------- --------- --------- ~~Production~~----------- ~~Data:~~----------- ~~Oil~~Appalachian ~~(Mbbls)~~Basin ~~104~~405,030.0 ~~124~~312,105.4 ~~116~~115,940.9 ~~Natural~~98,410.9 ~~gas~~Western ~~(Mmcf)~~2,448.0 91,~~755~~244.3 957,~~941~~262.2 934,~~371~~523.5 ~~Natural~~New ~~gas~~Zealand ~~equivalent~~740.0 ~~(Mmcfe)~~736.3 102,~~379 10~~545,~~685~~848.3 101,~~067~~795,502.2 ~~Average~~--------- ~~Sales~~--------- ~~Price~~----------- ~~(before~~----------- ~~the~~Total ~~effect of hedging): Oil per Bbl $ 25~~408,218.970 ~~$ 21~~314,086.110 ~~$ 25~~2,719,051.944 ~~Natural gas per Mcf $ 5~~1,928,436.136 $========= ~~2.86~~========= $=========== ~~5.43~~===========

PRODUCTION ---------- The following table sets forth certain net production data and average wellhead sales prices attributable to the Company's properties for the years ended June 30:

2004 2003 2002 ~~2001~~ -------~~----~~ -------~~----~~ -------~~----~~ ~~Gross~~Production ~~Net Gross Net Gross Net ----- ---- ----- ---- ----- ---- Development~~Data: ~~Productive~~Oil ~~Appalachian~~(Mbbls) ~~45.0~~107 ~~39.1~~104 ~~53.0~~124 ~~47.8~~Natural ~~47.0~~gas ~~41.5~~(Mmcf) ~~Other~~10,718 ~~2.0~~9,756 ~~0.4 1.0 0.3 - - ----- ---- ----- ---- ----- ---- Total 47.0 39.5 54.0 48.1 47.0 41.5 ===== ==== ===== ==== ===== ==== Nonproductive Appalachian 3.0 2.7 1.0 0.~~9,941 ~~1.0~~Natural ~~0.5~~gas ~~Other~~equivalent -(Mmcfe) -11,360 -10,380 -10,685 -Average -Sales ~~-----~~Price ~~----~~(before ~~-----~~the ~~----~~effect ~~-----~~of ~~---- Total 3.0 2.7 1.0 0.9 1.0 0.5 ===== ==== ===== ==== ===== ==== Exploratory~~hedging): ~~Productive~~Oil ~~Appalachian~~per ~~4.0~~Bbl ~~1.4~~$ 429.094 ~~1.6~~$ ~~Other 9~~25.097 ~~4.0~~$ 421.011 ~~2.3~~Natural ~~3.0~~gas ~~2.6~~per ~~-----~~Mcf ~~----~~$ ~~----- ---- ----- ---- Total 13.0~~ 5.449 ~~8.0~~$ ~~3.9 3.0 2.6 ===== ==== ===== ==== ===== ==== Nonproductive Appalachian 2.0 1.0~~ 5.013 ~~2.1~~$ 2.~~0 0.3 Other 4.0 2.2 4.0 3.2 8.0 3.8 ----- ---- ----- ---- ----- ---- Total 6.0 3.2 9.0 5.3 10.0 4.1 ===== ==== ===== ==== ===== ====~~86

DRILLING ACTIVITIES -------------------- The Company's gas and oil exploratory and developmental drilling activities are as follows for the years ended June 30. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. A well is considered productive if it justifies the installation of permanent equipment for the production of gas or oil. 9

~~ITEM~~2004 6.2003 ~~SELECTED~~2002 ~~FINANCIAL~~=========== ~~DATA~~=========== =========== Gross Net Gross Net Gross Net ----- ---- ----- ---- ----- ----~~-------~~ ~~(Dollars~~DEVELOPMENT: inProductive ~~thousands,~~Appalachian ~~except~~26.0 ~~per~~17.5 ~~share~~45.0 ~~items)~~39.1 ~~Year~~53.0 ~~Ended~~47.8 ~~June~~Western/New ~~30,~~Zealand 1.0 0.1 2.0 0.4 1.0 0.3 ----- ---- ----- ---- ----- ---- Total 27.0 17.6 47.0 39.5 54.0 48.1 ===== ==== ===== ==== ===== ==== Nonproductive Appalachian - - 3.0 2.7 1.0 0.9 Western/New Zealand 1.0 0.1 - - - - ----- ---- ----- ----- ~~2003 2002 2001 2000 1999~~ -----~~---~~ ---- Total 1.0 0.1 3.0 2.7 1.0 0.9 ===== ==== ===== ==== ===== ==== EXPLORATORY: Productive Appalachian 2.0 1.1 4.0 1.4 4.0 1.6 Western/New Zealand - -~~---~~ 9.0 4.0 4.0 2.3 ----- ---- ----- ---- ----- ---- ~~Operating~~Total ~~revenue~~2.0 ~~$117,426~~1.1 $13.0 ~~86,142~~5.4 ~~$129,951~~8.0 ~~$101,919 $113,500 Income (loss) from continuing operations~~ 3.9~~,917~~ ~~(26,180)~~===== ~~(10,199)~~==== ~~(26,508)~~===== ~~(27,099)~~==== ~~Earnings~~===== ~~per~~==== ~~common~~Nonproductive ~~share,~~Appalachian ~~basic~~2.0 150.127 ~~(39~~2.~~80)~~0 ~~(15~~1.~~34)~~0 ~~(40~~5.~~11)~~0 ~~(40~~2.~~27)~~1 ~~diluted~~Western/New 14Zealand 8.790 ~~(39~~4.~~80)~~6 ~~(15~~4.~~34)~~0 ~~(40~~2.~~11)~~2 ~~(40~~4.~~27)~~0 ~~Total~~3.2 ~~assets~~----- ~~295,834~~---- ~~304,736~~----- ~~380,532~~---- ~~265,691~~----- ~~286,077~~---- ~~Long~~Total ~~term~~10.0 ~~debt~~5.3 ~~173,197~~6.0 ~~198,701 198,902 212,575 219,886 Dividends declared per common share $ 1~~3.722 ~~$ 1~~9.600 $ 5.803 $===== -==== $===== ~~0.95~~==== ===== ====

ITEM 3. LEGAL PROCEEDINGS ------------------------- As previously reported, the Company had been in litigation with certain Holders of its $200,000,000 9 1/2% Senior Subordinated Notes due 2007 (the "Noteholders") (the "Notes"). The dispute involved the calculation of the Net Proceeds of an Asset Sale as defined in the Indenture dated May 23, 1997 between the Company and The Bank of New York. The Company and the Noteholders have settled the dispute, as memorialized in the Settlement Agreement executed as of February 24, 2004, and attached to the Form 8-K filed by the Company on February 24, 2004 as Exhibit 99.11 (the "Settlement Agreement"). In settlement of the dispute the Company agreed to repurchase $38 million in Notes. The Company has met its obligations under the Settlement Agreement having finalized the first Asset Sale Offer (as defined under the Indenture) in the amount of $4 million on March 24, 2004 and the second Asset Sale Offer in the amount of $34 million on July 29, 2004. The United States District Court for the Southern District of West Virginia has entered a Dismissal Order dismissing the litigation with prejudice. The Company is involved in various other legal actions and claims arising in the ordinary course of business. While the outcome of these other lawsuits against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the Company's operations or financial position. 10 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ----------------------------------------------------------- None. PART II ------- ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK ------------------------------------------------ AND RELATED STOCKHOLDER MATTERS ------------------------------- The Company's common stock is not traded in a public market. As of September 23, 2004, the Company had 32 holders of record of its common stock. The Company declared dividends in fiscal years 2004, 2003 and 2002 of $1.2 million, $1.1 million and $1.1 million, respectively. ITEM 6. SELECTED FINANCIAL DATA -------------------------------

~~TWELVE~~(Dollars ~~MONTHS~~in ~~ENDED~~thousands, ~~JUNE~~except 30per ~~VARIANCE~~share ~~---------------~~items) ~~------------------~~Year ~~2003~~Ended ~~2002~~June ~~AMOUNT~~30, ~~PERCENT~~ ------- ------ -------- -------- ~~Natural Gas Production (Mmcf) 9,755 9,941 (186)~~ -~~1.9% Average sales price received ($/Mcf) 5.13 2.86 2.27 79.4%~~ ------- ------ -------- ~~--------~~2004 ~~Sales~~2003 ($2002 in2001 ~~thousands)~~2000 ~~50,031 28,462 21,569 75.8% Oil Production (Mbbl) 104 124 (20)~~ -~~16.1% Average sales price received ($/Bbl) 25.97 21.11 4.86 23.0%~~ ------- ------ --~~------~~ -------- ~~Sales ($ in thousands) 2,701 2,618 83 3.2% Hedging (4,843) 7,212 (12,055)~~ -~~167.2%~~ ~~Other 3,521 647 2,874 444.2%~~ ------- --~~----~~ -------- -~~-------~~ ~~Total~~Operating ~~oil~~revenue ~~and~~$123,373 ~~gas~~$117,426 ~~sales (~~$ ~~in thousands) 51~~86,~~410~~142 38$129,~~939~~951 12$101,~~471~~919 ~~32.0%~~Income ~~=======~~(loss) ~~======~~from ~~========~~operations ~~========~~4,295 ~~Marketing~~9,917 ~~Revenue Volume~~ (~~Mdth~~26,180) 9(10,~~285~~199) ~~9,903~~ (~~618~~26,508) ~~-6.2%~~Earnings ~~Average~~per ~~sales~~common ~~price~~share, ~~received~~basic (~~$ per Dth~~a) 46.8662 315.1412 ~~1.72 54.7% ------- ------ -------- -------- Sales~~ (~~$ in thousands~~39.80) ~~45,145 31,125 14,020 45.0% Pipeline Revenue Volume~~ (~~Mdth~~15.34) ~~5,675 6,003~~ (~~328~~40.11) ~~-5.5%~~Earnings ~~Average~~per ~~sales~~common ~~price~~share, ~~received~~diluted (~~$ per Dth~~a) 26.7052 114.6879 1(39.0280) 60(15.7%34) ~~------- ------ -------- -------- Sales~~ (~~$ in thousands~~40.11) ~~15,338 10,084 5,254 52.1% ------- ------ -------- --------~~ Total ~~marketing~~assets ~~and pipeline sales ($ in thousands) 60~~290,~~483~~212 41295,~~209~~834 19304,~~274~~736 ~~46.8% ======= ====== ======== ======== Marketing Gas Cost Volume (Mdth) 9~~380,~~285~~532 9265,~~902~~691 ~~(617)~~Long ~~-6.2%~~term ~~Average~~debt ~~price paid ($ per Dth) 4.48 2.98 1.50 50.3% ------- ------ -------- -------- Cost ($ in thousands) 41~~162,~~636~~894 29173,~~526~~197 12198,~~110~~701 ~~41.0% Pipeline Gas Cost Volume (Mdth) 4~~198,~~550~~902 4212,~~870~~575 ~~(320)~~Dividends ~~-6.6%~~declared ~~Average~~per ~~price~~common ~~paid~~share ($ ~~per Dth) 2.65~~ 1.6496 $ 1.0172 ~~61.6% ------- ------ -------- -------- Cost (~~$ ~~in thousands) 12,057 7,963 4,094 51~~1.4%60 ~~------- ------ -------- -------- Total marketing and pipeline cost (~~$ ~~in thousands) 53,693 37,489 16,204 43~~5.2%80 ~~=======~~$ ~~====== ======== ========~~ -~~--------------------------------------------------------------------------------------~~

(a) The effect of outstanding stock options was not included in the computation of diluted earnings per share for years ended 2002, 2001, or 2000, because to do so would have been antidilutive. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF ---------------------------------------------------------- OPERATIONS AND FINANCIAL CONDITION ---------------------------------- SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 -------------------------------------------------------------------------------- This discussion and analysis of financial condition and results of operations, and other sections of this Form 10-K, contain forward-looking statements that are based on management's beliefs, assumptions, current expectations, estimates, intentions and projections about the oil and gas industry, the economy and about the Company itself. Words such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "is likely," "plans," "predicts," "projects," variations of such words and similar expressions are intended to identify such forward-looking statements under the Private Securities Litigation Reform Act of 1995. The Company cautions that these statements are not guarantees of future performance and 11 involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, weather conditions, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources, the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and natural gas reserves, risks incident to the drilling and operation of oil and natural gas wells, future production and development costs, foreign currency exchange rates, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and New Zealand, the effect of hedging activities, and conditions in the capital markets. The following should be read in conjunction with the Company's Financial Statements and Notes (including the segment information) at Item 8 and the Selected Financial Data at Item 6. CRITICAL ACCOUNTING POLICIES AND ESTIMATES ----------------------------------------------- The discussion of financial condition and results of operation are based upon the information reported in the consolidated financial statements. The preparation of these financial statements requires the Company to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Decisions are based on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates due to changing business conditions or unexpected circumstances. The Company believes the following policies are critical to understanding our business and results of operations. For additional information on significant accounting policies, see Notes to Consolidated Financial Statements, particularly Note 2. REVENUE RECOGNITION - The Company is engaged in the exploration, development, acquisition, production and aggregation of natural gas and crude oil. The revenue recognition policy is significant because it is a key component of the results of operations and forward looking statements contained in the Liquidity and Capital Resources section. Revenue is derived primarily from the sale of produced natural gas and crude oil. Revenue is recorded in the month production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. Monthly, the Company makes estimates of the amount of production delivered to the purchaser and the price to be received. The Company uses its knowledge of properties, historical performance, NYMEX and local spot market prices and other factors as the basis for these estimates. Variances between the estimates and the actual amounts received, which historically have not been significant, are recorded in the month revenue is distributed. DERIVATIVE INSTRUMENTS - The estimated fair values of all derivative instruments are recorded on the consolidated balance sheet. All of the derivative instruments are entered into to mitigate risks related to the prices to be received for future natural gas and oil production. Derivative instruments are not used for trading purposes. Although derivatives are reported on the balance sheet at fair value, to the extent that instruments qualify for hedge accounting treatment, changes in fair value are recorded, net of taxes, directly to stockholders' equity as a component of other comprehensive income until the hedged oil or natural gas quantities are produced. To the extent changes in the fair values of derivatives relate to instruments not qualifying for hedge accounting treatment, such changes are recorded in operations in the period they occur. In determining the amounts to be recorded, the Company is required to estimate the 12 fair values of derivatives. The estimates are based upon various factors that include contract volumes and prices, contract settlement dates, quoted closing prices on the NYMEX or over-the-counter, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the derivatives agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and regional price differences. Periodically the valuations are validated using independent third party quotations. RESERVE ESTIMATES - The Company's estimate of gas and oil reserves are projections based on geologic and engineering data. There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows depend upon a number of variable factors and assumptions, such as expected future production rates, gas and oil prices, operating costs, severance taxes, and development costs, all of which may vary considerably from actual results. Expected cash flows are reduced to present value using a discount rate of 10%, as required by accounting standards. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of proved producing oil and gas properties. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's gas and oil properties and their rates of depletion. Changes in these calculations, caused by changes in reserve quantities or net cash flows are recorded on a prospective basis. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates and such variances may be material. VALUATION OF LONG-LIVED AND INTANGIBLE ASSETS - Property and equipment are recorded at cost. The carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Different pricing assumptions or discount rates would result in a different calculated impairment. INCOME TAXES - The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Federal and state income tax returns are generally not filed before the consolidated financial statements are prepared, therefore an estimate of the tax basis of assets and liabilities is determined at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to differences between the estimates and actual amounts are recorded in the period the income tax returns are filed. COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2004 AND 2003 -------------------------------------------------------------------------------- The Company realized net income of $4.3 million for the year ended June 30, 2004 compared to a net income of $9.8 million in 2003. The decrease of $5.5 million was primarily attributable to the net effect of a $5.9 million increase in revenue, a $3.9 million decrease in costs and expenses, a $1.3 million 13 decrease in interest expense, $27.5 million decrease in interest income and other and a $10.8 million decrease in income tax expense. OPERATING MARGINS. Operating Margins (defined as revenue less operating ------------------ costs and taxes other than income taxes) for the Company's operating subsidiaries totaled $51.7 million for the current year compared to $50.3 million for the prior period. The Company's Oil and Gas Operating Margin (defined as oil and gas sales and well operations and service revenues less field operating expenses and taxes other than income) totaled $46.8 million versus $43.5 million for the prior year. The Company's Aggregation and Pipeline Operating Margin (defined as gas aggregation and pipeline sales less gas aggregation and pipeline cost of sales) totaled $4.8 million for the current period versus $6.8 million for the prior period. 14 Production, aggregation and pipeline volumes, revenue and average sales prices for the years ended June 30 and their related variances are as follows:

~~Variance~~TWELVE MONTHS ENDED JUNE 30 VARIANCE ----------------------- ~~2002~~------------------------ ~~2001~~2004 ~~Amount~~2003 ~~Percent~~AMOUNT PERCENT ----------- ---------- ----------- ----------- Natural Gas Production (Mmcf) 910,~~941~~718 89,~~822(1)~~756 ~~1,119~~962 129.689% Average sales price received ($ ~~per~~ /Mcf) 25.8649 5.4513 (20.~~59)~~36 ~~-47~~7.520% ----------- ---------- ----------- ----------- Sales ($ in thousands) 2858,~~463~~851 4850,~~063~~031 ~~(19~~8,~~600)~~820 ~~-40~~17.786% Oil Production (Mbbl) ~~124~~107 ~~108(1)~~104 163 142.819% Average sales price received ($ ~~per~~ /Bbl) 2129.1194 25.9497 (43.~~83)~~97 ~~-18~~15.623% ----------- ---------- ----------- ----------- Sales ($ in thousands) 23,~~618~~204 2,~~812~~701 ~~(194)~~503 -618.906% Hedging 7(5,~~211~~213) (94,~~567~~843) ~~16,778~~(370) ~~175~~7.376% Other ~~647~~361 ~~247~~3,521 ~~400~~(3,160) ~~161~~-89.947% ----------- ---------- ----------- ----------- Total oil and gas sales ($ in thousands) ~~$38~~57,~~939~~203 ~~$ 41~~51,~~555~~410 ~~$ (2~~5,~~616)~~793 -611.303% =========== ========== =========== =========== ~~Marketing~~Aggregation Revenue Volume (~~Mdth~~Million Mmbtu) 98,~~903~~591 129,~~126~~285 (~~2,223~~694) -187.335% Average sales price received ($ ~~per Dth~~/Mmbtu) 35.1422 54.4286 (20.~~28)~~36 ~~-42~~7.074% ----------- ---------- ----------- ----------- Sales ($ in thousands) 3144,~~125~~854 6445,~~890~~145 (~~33,765~~291) -520.036% Pipeline Revenue Volume (~~Mdth~~Million Mmbtu) 65,~~003~~528 65,~~531~~675 (~~528~~147) -82.086% Average sales price received ($ ~~per Dth~~/Mmbtu) 12.6889 2.4770 (0.~~79)~~19 ~~-31~~7.980% ----------- ---------- ----------- ----------- Sales ($ in thousands) 1015,~~084~~965 1615,~~152~~338 ~~(6,068)~~627 ~~-37~~4.571% ----------- ---------- ----------- ----------- Total ~~marketing~~aggregation and pipeline sales ($ in thousands) ~~$41~~60,~~209~~819 ~~$ 81~~60,~~042~~483 ~~$(39,833)~~336 ~~-49~~0.156% =========== ========== =========== =========== ~~Marketing~~Aggregation Gas Cost Volume (~~Mdth~~Million Mmbtu) 98,~~902~~591 129,~~087~~285 (~~2,185~~694) -187.085% Average price paid ($ ~~per Dth~~/Mmbtu) 24.9899 54.1648 (20.~~18)~~51 ~~-42~~11.254% ----------- ---------- ----------- ----------- Cost ($ in thousands) 2942,~~525~~827 6241,~~219~~636 ~~(32~~1,~~694)~~191 ~~-52~~2.559% Pipeline Gas Cost Volume (~~Mdth~~Million Mmbtu) 4,~~870~~469 54,~~455~~550 (~~585~~81) -101.728% Average price paid ($ ~~per Dth~~/Mmbtu) 12.6496 2.7465 (10.~~10)~~31 ~~-40~~11.157% ----------- ---------- ----------- ----------- Cost ($ in thousands) 713,~~964~~232 1412,~~948~~057 (61,~~984)~~175 ~~-46~~9.727% ----------- ---------- ----------- ----------- Total ~~marketing~~aggregation and pipeline cost ($ in thousands) ~~$37~~56,~~489~~059 ~~$ 77~~53,~~167~~693 ~~$(39~~2,~~678)~~366 ~~-51~~4.424% =========== ========== =========== =========== ~~(1) Production does not include volumes related to the acquisition of certain properties between the effective date and the closing date.~~-------------------------------------------------------------------------------------------------------

REVENUES. Total revenues increased $5.9 million or 5.1% between the -------- years. The net increase was due to a 11.3% increase in oil and gas sales, a 0.6% increase in gas aggregation and pipeline sales, a 4.9% decrease in well operations and service revenues and a 248.6% increase in other operating revenue. 15 Revenues from oil and gas sales increased $5.8 million from $51.4 million for the year ended June 30, 2003 to $57.2 million for the year ended June 30, 2004. Natural gas sales increased $8.8 million and oil sales increased $0.5 million. The increase is a result of an increase in both price and production. The price increase corresponds with related indexes. The increase in production was attributable to a decrease in extended curtailments on third party transmission facilities compared to the prior year and the drilling of new wells. The increased production revenue was offset by recognized losses on related hedging transactions including derivative instruments and fixed price delivery contracts, which totaled a loss of $5.2 million for the year ended June 30, 2004 compared to a loss of $4.8 million for the year ended June 30, 2003. Other gas sales decreased $3.2 million as a result of $3.1 million being recognized in the year ended June 30, 2003 related to the termination and release of a certain gas contract. The average price per Mcfe, after hedging, was $5.03 and $4.95 for the years ended June 30, 2004 and 2003, respectively. Revenues from gas aggregation and pipeline sales increased $0.3 million from $60.5 million during the period ended June 30, 2003 to $60.8 million in the period ended June 30, 2004. Gas aggregation revenue decreased $0.3 million while pipeline revenue, which has sale and transportation components, increased $0.6 million. The increase in gas aggregation and pipeline sales is attributable to the increase in average sales price received offset by a decline in production. The price increase corresponds with related indexes. COSTS AND EXPENSES. The Company's costs and expenses decreased $3.9 -------------------- million or 3.5% between the periods primarily as a net result of a 13.1% increase in field and lease operating expenses, a 4.4% increase in gas aggregation and pipeline costs, a 0.9% increase in general and administrative expenses, a 26.9% increase in taxes other than income, a 9.6% increase in oil and gas related depletion, a 2.4% decrease in depreciation and amortization expenses of pipelines, property and equipment, a 8.0% decrease in exploration and impairment costs, and a gain on sale of assets compared to a loss in the prior year. Field and lease operating expenses increased $1.3 million. The increase in lease operating expenses is primarily related to an increase in payroll expenses, medical expense, and lease operating expenses for new wells drilled during the fiscal year. Gas aggregation and pipeline costs increased $2.4 million. Gas aggregation cost increased $1.2 million while pipeline cost also increased $1.2 million. The increase in gas aggregation and pipeline cost of sales is attributable to the increase in average price paid offset by a decline in production. The price increase corresponds with related indexes. Taxes other than income increased $0.9 million as a result of increased wellhead oil and gas sales. Oil and gas related depreciation, depletion and amortization expenses increased $1.2 million. The increase in depletion is primarily due to increased production volumes and an increase in depletion rate. Gain or loss on sale of property went from a loss of $0.4 million for the year ended June 30, 2003 to a gain of $8.3 million for the year ended June 30, 2004. The primary reason for the gain in the current fiscal year was the sale of the Company's membership interest in Breitburn Energy Company, LLC ("BEC") for gross proceeds of $9.2 million. A gain of $7.4 million was recognized and a liability of $1.8 million established as a reserve against items for which the Company was required to indemnify the buyer for a period of 180 days after closing pursuant to the agreement. The Company also sold acreage position holdings for a gain of $0.6 million during the current fiscal year. 16 Exploration and impairment expenses decreased $0.9 million. The decrease is a result of lower expenses primarily related to dry hole costs, impairment of oil and gas property and various other geological and geophysical costs. INTEREST EXPENSE. Interest expense decreased $1.3 million primarily due ------------------ to the reduction of outstanding debt and also replacing a portion of the Company's debt at a lower interest rate for the year ended June 30, 2004. INTEREST INCOME AND OTHER. Other non-operating income decreased $27.5 ---------------------------- million when compared to the prior year. The decrease is primarily the result of a decrease of $23.2 million associated with the gains recognized on the early retirement of bonds and a $4.5 million gain on a legal settlement that occurred in fiscal year 2003. INCOME TAX. Income tax expense decreased by $10.8 million in 2004 to an ----------- income tax benefit of $4.7 million as compared to an income tax expense in 2003 of $6.1 million. The decrease is primarily due to the adjustment of the tax contingency balance of $4.5 million for items that are closed or no longer applicable and the decrease in income before income taxes of $16.4 million. COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2003 AND 2002 -------------------------------------------------------------------------------- The Company recorded net income of $9.8 million for the year ended June 30, 2003 compared to a net loss of $26.2 million in 2002. The improvement of $36.0 million was primarily attributable to the net effect of a $31.3 million increase in revenue, a $0.5 million increase in costs and expenses, a $3.3 million decrease in interest expense, a $24.7 million increase in other non-operating income and a $22.9 million increase in income tax expense. OPERATING MARGINS. Operating Margins (defined as revenue less operating ------------------ costs and taxes other than income taxes) for the Company's operating subsidiaries totaled $50.3 million for the current year compared to $35.6 million for the prior period. The Company's Oil and Gas Operating Margin (defined as oil and gas sales and well operations and service revenues less field operating expenses and taxes other than income) totaled $43.5 million versus $31.3 million for the prior year. The Company's Aggregation and Pipeline Operating Margin (defined as gas aggregation and pipeline sales less gas aggregation and pipeline cost of sales) totaled $6.8 million for the current period versus $3.7 million for the prior period. Other revenue was $0.04 million for the current period versus $0.5 million for the prior period. 17 Production, aggregation and pipeline volumes, revenue and average sales prices for the years ended June 30 and their related variances are as follows:

TWELVE MONTHS ENDED JUNE 30 VARIANCE ---------------------- ------------------------ 2003 2002 ~~2001~~AMOUNT PERCENT ----------- --------- ----------- ~~Development~~----------- ~~$14~~Natural Gas Production (Mmcf) 9,~~105~~756 ~~$10~~9,~~977~~941 (186) -1.9% Average sales price received ($/Mcf) 5.13 2.86 2.27 79.1% ----------- --------- ----------- ----------- Sales ($ in thousands) 50,~~649~~031 ~~Exploration~~28,462 1521,~~292~~569 75.8% Oil Production (Mbbl) 104 124 (20) -16.1% Average sales price received ($/Bbl) 25.97 21.11 4.86 23.0% ----------- --------- ----------- ----------- Sales ($ in thousands) 2,~~737~~701 152,~~115~~618 ~~Acquisitions~~83 3.2% Hedging (4,843) 7,212 (12,055) -167.2% Other 3,521 647 2,874 444.2% ----------- --------- ----------- ----------- Total oil and gas sales ($ in thousands) 51,410 38,939 12,471 32.0% =========== ========= =========== =========== Aggregation Revenue Volume (Million Mmbtu) 9,285 9,903 (618) -6.2% Average sales price received ($/Mmbtu) 4.86 3.14 1.72 54.7% ----------- --------- ----------- ----------- Sales ($ in thousands) 45,145 31,125 14,020 45.0% Pipeline Revenue Volume (Million Mmbtu) 5,~~879~~675 ~~717~~6,003 80(328) -5.5% Average sales price received ($/Mnbtu) 2.70 1.68 1.02 60.9% ----------- --------- ----------- ----------- Sales ($ in thousands) 15,~~394~~338 10,084 5,254 52.1% ----------- --------- ----------- ----------- Total aggregation and pipeline sales ($35 in thousands) 60,~~276~~483 41,209 19,274 46.8% =========== ========= =========== =========== Aggregation Gas Cost Volume (Million Mmbtu) 9,285 9,902 (617) -6.2% Average price paid ($32/Mmbtu) 4.48 2.98 1.50 50.4% ----------- --------- ----------- ----------- Cost ($ in thousands) 41,~~431~~636 29,526 12,110 41.0% Pipeline Gas Cost Volume (Million Mmbtu) 4,550 4,870 (320) -6.6% Average price paid ($~~109~~/Mmbtu) 2.65 1.64 1.01 62.0% ----------- --------- ----------- ----------- Cost ($ in thousands) 12,~~158~~057 7,963 4,094 51.4% ----------- --------- ----------- ----------- Total aggregation and pipeline cost ($ in thousands) 53,693 37,489 16,204 43.2% =========== ========= =========== ===========

REVENUES. Total revenues increased $31.3 million or 36.3% between the -------- years. The net increase was due to a 32.0% increase in oil and gas sales, a 46.8% increase in gas aggregation and pipeline sales, a 0.1% increase in well operations and service revenues and a 93.1% decrease in other operating revenue. 18 Revenues from oil and gas sales increased a net of $12.5 million from $38.9 million for the year ended June 30, 2002 to $51.4 million for the year ended June 30, 2003. Natural gas sales increased $21.6 million and oil sales increased $0.08 million. The price increase corresponds with related indexes. The decrease in production was due in part to the sale of certain oil and gas properties, extended curtailments on third party transmission facilities, as well as normal production declines. The decrease in production was partially offset by the purchase of certain oil and gas properties and the drilling of new wells. The increased production revenue was offset by recognized losses on related hedging transactions including derivative instruments and fixed price delivery contracts, which totaled a loss of $4.8 million for the year ended June 30, 2003 compared to a gain of $7.2 million for the year ended June 30, 2002. The average price per Mcfe, after hedging, was $4.95 and $3.65 for the years ended June 30, 2003 and 2002, respectively. Revenues from gas aggregation and pipeline sales increased $19.3 million from $41.2 million during the period ended June 30, 2002 to $60.5 million in the period ended June 30, 2003. Gas aggregation revenue increased $14.0 million while pipeline revenue, which has sale and transportation components, increased $5.3 million. The increase in gas aggregation and pipeline sales is attributable to the increase in average sales price received. The price increase corresponds with related indexes. Other operating revenue decreased $0.5 million. The current year income of $0.03 million is related to revenue earned by the Company's participation in Deep Rig, L.P., while $0.5 million was recognized in the prior year. COSTS AND EXPENSES. The Company's costs and expenses increased $0.5 -------------------- million or 0.5% between the periods primarily as a net result of a 7.2% decrease in field and lease operating expenses, a 43.2% increase in gas aggregation and pipeline costs, a 11.1% decrease in general and administrative expenses, a 51.1% increase in taxes other than income, a 1.8% decrease in oil and gas related depreciation, a 46.4% increase in depletion and amortization expenses of pipelines, property and equipment, a 57.6% decrease in exploration and impairment costs, and a gain instead of a loss on sale of assets. Field and lease operating expenses decreased $0.8 million. The decrease in lease operating expenses is primarily related to a reduction in contract labor expenses, road and dike repair costs, and various other field and lease operating expenses. Gas aggregation and pipeline costs increased $16.2 million. Gas aggregation cost increased $12.1 million while pipeline costs increased $4.1 million. The increase in gas aggregation and pipeline cost of sales is attributable to the increase in average price paid. The price increase corresponds with related indexes. General and administrative expenses decreased $1.9 million primarily due to an increase in exploration and development drilling capitalized costs, lower bad debt expense, legal fees, and board fees. Taxes other than income increased $1.1 million as a result of increased oil and gas sales. Average wellhead oil and gas sales prices, on which production taxes are based, were higher for the current year. Oil and gas related depreciation, depletion and amortization expenses decreased $0.2 million. The decrease in depletion is primarily due to reduced production volumes resulting from the sale of certain oil and gas properties and normal production declines, partially offset by production related to the acquisition of certain oil and gas properties and from new wells drilled during the year. 19 Exploration and impairment expenses decreased $16.0 million. In the current year, the expenses were primarily due to dry hole costs, impairment of oil and gas property and various other geological and geophysical costs. INTEREST EXPENSE. Interest expense decreased $3.3 million primarily due ------------------ to the repurchase of $65.6 million face value of the Company's senior notes for the year ended June 30, 2003. INTEREST INCOME AND OTHER. Other non-operating income increased $24.7 ---------------------------- million when comparing the periods. This is primarily the result of the Company purchasing a portion of its senior bonds and recognizing a gain of $23.7 million. The Company also recognized $4.5 million in income from legal settlements and $1.4 million in net contract settlements associated with Allegheny Energy. Offsetting this increase in other non-operating income was a reduction in interest income of $1.1 million due to decreases in the cash balances and interest rates when comparing the periods. The Company also recognized a loss of $2.1 million due to the write down of its investment in Alliance Gas. INCOME TAX. Income tax expense increased by $22.9 million in 2003 to an ----------- income tax expense of $6.1 million as compared to an income tax benefit in 2002 of $16.8 million. This increase was due to a $58.8 million increase in income before income taxes. CAPITAL EXPENDITURES ---------------------- Expenditures for the exploration, development and acquisition of oil and gas properties are the Company's primary use of capital resources. The following table summarizes certain costs incurred for the years ended June 30 (in thousands): 2004 2003 2002 ------- ------- ------- Development $ 7,892 $14,105 $10,977 Exploration 10,449 15,292 20,737 Acquisitions 72 5,879 717 ------- ------- ------- Total $18,413 $35,276 $32,431 ======= ======= ======= ACQUISITIONS ------------ The Company finalized the purchase of an additional 100-mile long natural gas gathering system ("System 8000") from Columbia Gas Transmission for a purchase price of $1.2 million during the first quarter of fiscal year 2005. System 8000 is located in northeastern West Virginia and is situate among one of the Company's existing operating areas. On February 5, 2003, the Company purchased certain oil and gas properties located in southern West Virginia for $5.6 million, after certain adjustments. The purchase included proved developed producing gas reserves, estimated at 4 Bcf, 90 producing wells and over 30,000 acres. LIQUIDITY AND CAPITAL RESOURCES ---------------------------------- The Company's financial condition and liquidity have improved since June 30, 2003. Stockholders' equity has decreased from $43.7 million at June 30, 2003 to $42.4 million at June 30, 2004. The Company's cash increased from $4.8 million at June 30, 2003 to $5.8 million at June 30, 2004. The Company's cash at September 23, 2004 was $0.9 million. The change in cash during the year of approximately $1.0 million resulted from various operating, investing and financing activities of the 20 Company. The activities were primarily comprised of: the paydown of approximately $3.1 million under the Company's $50 million revolving loan; the net investment of approximately $22.0 million in property, plant and equipment; payments of approximately $5.5 million for the purchase of a portion of the Company's outstanding Notes; payments of approximately $3.0 million for the acquisition of treasury stock and dividends; cash received of approximately $10.8 million from the sale of assets; $1.5 million received from the collection of a note receivable; receipt of approximately $0.3 million of cash in connection with the Company's restricted Class A stock purchase plan for employees; and approximately $22.0 million of cash provided by operations during the year. On June 15, 2004 the Company sold its membership interest in Breitburn Energy Company, LLC ("BEC") for gross proceeds of $9.2 million. Pursuant to the terms of its Senior Subordinated Notes (the "Notes"), the Company has the option, within 360 days of receipt of the "Net Proceeds" (as defined in the Indenture dated May 23, 1997 between the Company as Issuer and The Bank of New York as Trustee, hereinafter the "Indenture") from the sale of the membership interest in BEC, to apply such proceeds to (a) reduce debt senior to or pari passu with the Notes (provided that in connection with the reduction of pari passu debt, a pro rata portion of the Notes is redeemed); (b) acquire a controlling interest in another business engaged in either natural gas distribution or the exploration, development or operation of oil, gas or other hydrocarbon properties (an "Energy Business"); (c) make capital expenditures in respect of the Company's or its restricted subsidiaries' Energy Business; (d) purchase long term assets that are used or useful in the Energy Business; or (e) repurchase the Notes. If the Company has not applied all of the Net Proceeds in accordance with one of the above options within 360 days of receipt of such proceeds, then with respect to those Net Proceeds that were not applied to one of the above options, such Net Proceeds are then deemed to constitute "Excess Proceeds". To the extent the Excess Proceeds exceed $10 million, the Company must make an offer to the holders of the Notes, (and holders of pari passu debt, to the extent required by the terms of the pari passu debt) to repurchase the maximum principal amount of the Notes and any pari passu debt that may be purchased out of the Excess Proceeds at an offer price in cash equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the date of the purchase. The Company anticipates that the requirement to reinvest the Net Proceeds will be met by its budgeted capital expenditures program for the year ending June 30, 2005. As previously reported, on July 10, 2002, the Company entered into a $50 million revolving Credit Agreement with Foothill Capital Corporation, now Wells Fargo Foothill, Inc. ("Foothill"). The Company and Foothill have entered into an Amended and Restated Credit Agreement dated June 10, 2004 (the "Restated Credit Agreement"). The Restated Credit Agreement provides for the $50 million revolving credit facility to be extended and for the Company to be provided with additional credit in the form of a single advance term loan in the amount of $50 million. The term loan contains requirements for principal payments of $1 million each at July 10, 2005, 2006 and 2007, with the remaining balance due on July 10, 2008. Depending on the Company's level of borrowing under the Restated Credit Agreement, the applicable interest rates for base rate loans are based on Wells Fargo's prime rate plus 0.25% to 0.75%. The Company has the ability under the Restated Credit Agreement to designate certain loans as Libor Rate Loans at interest rates based upon the rate at which dollar deposits are offered to major banks in the London interbank market plus 2.25% to 2.75%. The Restated Credit Agreement expires on July 10, 2008. The obligations under the Restated Credit Agreement are secured by certain of the existing proved producing oil and gas assets of the Company. The Restated Credit Agreement, among other things, restricts the ability of the Company and its subsidiaries to incur new debt, grant additional security interests in its collateral, engage in certain merger or reorganization activities, or dispose of certain assets. At June 30, 2004, the Company's principal source of liquidity consisted of $5.8 million of cash, $0.2 million available under an unsecured credit facility currently in place, plus amounts available under 21 both the term loan and revolving loan of the Restated Credit Agreement. At June 30, 2004, $1.0 million was outstanding and $1.8 million was committed through letters of credit under the short-term credit facility and $36.1 million was outstanding on the revolving loan under the Restated Credit Agreement. There were no amounts outstanding on the $50 million term loan available under the Restated Credit Agreement. As previously reported, the Company had been in litigation with certain Holders (the "Noteholders") of its Notes. The dispute involved the calculation of "Net Proceeds" of an "Asset Sale" as defined in the Indenture. A settlement agreement dated February 24, 2004, was negotiated with the Noteholders to resolve the dispute. In settlement of the dispute the Company agreed to repurchase $38 million in Notes. The repurchase was effected by the Company making Asset Sale Offers (as defined in the Indenture) totaling $38 million. The Company made an initial Asset Sale Offer of $4 million, which was completed on March 25, 2004. The Company consummated another Asset Sale Offer of $34 million which was completed on July 29, 2004. The United States District Court for the Southern District of West Virginia has entered a Dismissal Order dismissing the litigation with prejudice. Upon the Company meeting all of the terms and conditions of the Settlement Agreement it funded the $50 million term loan under the Restated Credit Agreement. As of September 23, 2004, there are $50 million in outstanding borrowings under the term loan and $15 million in outstanding borrowings under the revolving loan. Additional borrowings must comply with the terms of the Indenture and the Foothill Amended and Restated Credit Agreement. The Company's net cash requirements will fluctuate based on timing and the extent of the interplay of capital expenditures, cash generated by operations, cash generated by the sale of assets and interest expense. EBITDAX, before inclusion of the gain on the purchase of the Company's Notes, for fiscal year 2004 was $42.4 million. EBITDAX for fiscal years 2003 and 2002, measured on a similar basis, was $36.9 million and $19.7 million, respectively. Management anticipates that EBITDAX from oil and gas operations for fiscal year 2005 will approximate $44 million. The Company's ability to achieve EBITDAX of $44 million from oil and gas operations for fiscal year 2005 is highly dependant on product price and continued drilling success. Management believes that cash generated from oil and gas operations, together with the liquidity provided by existing cash balances and permitted borrowings, will be sufficient to satisfy commitments for budgeted capital expenditures of $29.8 million, debt service obligations, working capital needs and other cash requirements for the next fiscal year. In order to reduce future cash interest payments, as well as future amounts due at maturity or upon redemption, the Company may, from time to time, purchase its outstanding Notes in open market purchases and/or privately negotiated transactions. The Company will evaluate any such transactions in light of then existing market conditions, taking into account its liquidity, uses of capital and prospects for future access to capital. The amounts involved in any such transaction, individually or in the aggregate, may be material. The Company believes that its existing capital resources, permitted borrowings and its expected fiscal year 2005 results of operations and cash flows from operating activities will be sufficient for the Company to remain in compliance with the requirements of its Notes and the Restated Credit Agreement. However, since future results of operations, cash flow from operating activities, debt service capability, levels and availability of capital resources and continuing liquidity are dependent on future weather patterns, oil and gas commodity prices and production volume levels, future exploration and development drilling success and successful acquisition transactions, no assurance can be given that the Company will remain in compliance with the requirements of its Notes and the Restated Credit Agreement. 22 In addition to the Restated Credit Agreement, unsecured credit facility and Notes discussed above, the Company had various other obligations. The following table lists the Company's contractual obligations at June 30, 2004 (in thousands):

~~2004~~Payments ~~2005~~due ~~2006~~by ~~Thereafter~~period ~~Total~~(in thousands) More Less than 1 - 3 3 - 5 than 5 1 year years years years Total ---- ------ ------- ------- ------- --------- Senior subordinated notes (a) $ -34,000 $92,033 $ - $ - $ ~~132~~126,~~073~~033 ~~$132~~Revolving loan 1,~~073~~000 - 36,109 - 37,109 Installment notes payable ~~213~~145 ~~1,213~~224 ~~39,440~~127 ~~793~~401 ~~41,659~~897 ~~Operating~~Mandatorily ~~leases~~redeemable ~~909~~stock 202 479 702 - 1,~~019~~383 ~~402~~Operating leases 1,~~364~~131 883 677 543 3,~~694~~234 ------ ------ ------- ------- ------- --------- Total contractual cash obligations $1 36,~~122~~478 $293,~~232~~619 $3937,~~842~~615 $ ~~134,230~~944 $~~177~~ 168,~~426~~656 ====== ====== ======= ======= ======= =========

(a) The Company met its' current obligation through the Asset Sale Offer for $34 million of its Senior Subordinated Notes which was consummated on July 29, 2004. RECENT ACCOUNTING PRONOUNCEMENTS ---------------------------------- In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights Are Tangible or Intangible Assets," are tangible assets and that they should be removed as examples of intangible assets in SFAS No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets." The FASB has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Position ("FSP") FAS Nos. 141-1 and 142-1. In addition, proposed FSP 142-b confirms that SFAS 142 does not change the balance sheet classification or disclosures of mineral rights of oil and gas producing enterprises. Historically, the Company has included the costs of such mineral rights as tangible assets, which is consistent with the EITF's consensus. As such, EITF 04-02 and the related FSPs have not affected the Company's consolidated financial statements. In May 2003 the FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity, and requires instruments that fall within the scope of this pronouncement to be classified as liabilities. The Company early adopted SFAS No. 150 at the beginning of the fourth quarter of the year ended June 30, 2004. The effect of this adoption was an increase to other current liabilities of $0.2 million, other long term obligations of $1.2 million and a $1.4 million decrease in stockholders' equity. 23 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ------------------------------------------------- ABOUT MARKET RISK ----------------- COMMODITY RISK ---------------- The Company's operations consist primarily of exploring for, producing, aggregating and selling natural gas and oil. Contracts to deliver gas at pre-established prices mitigate the risk to the Company of falling prices but at the same time limit the Company's ability to benefit from the effects of rising prices. The Company occasionally uses derivative instruments to hedge its commodity price risk. The Company hedges a portion of its projected natural gas production through a variety of financial and physical arrangements intended to support natural gas prices at targeted levels and to manage its exposure to price fluctuations. The Company may use futures contracts, swaps, options and fixed price physical contracts to hedge its commodity prices. Realized gains and losses from the Company's price risk management activities are recognized in oil and gas sales when the associated production occurs. Unrecognized gains and losses are included as a component of other comprehensive income. See Note 4 to the Consolidated Financial Statements for additional information. The Company does not hold or issue derivative instruments for trading purposes. The Company has elected to enter into various transactions, covering approximately 45% to 50% of its estimated natural gas production for the fiscal year ended June 2005. As of June 30, 2004, the Company's open gas derivative instruments and fixed price delivery contracts were as follows:

~~As of June 30, 2003, the Company's open gas derivative instruments and fixed price delivery contracts were as follows:~~ Total Average Market Volumes Contract Unrealized Time period Index (MMBtu) Price (Gains) Losses --------------------------------- ------~~----~~ ----------- --------- ---------------- Derivatives: Natural Gas Swaps July ~~2003~~2004 - ~~March~~December 2004 NYMEX ~~720~~25,000 $ 65.3220 $ (~~456~~34,~~385~~727) ~~July~~December ~~2003~~2004 - ~~June~~February 2005 NYMEX 300,000 6.12 183,667 July 2004 - March 2005 NYMEX 1,~~098~~080,000 45.0557 1915,~~479~~180 July 2004 - March 2005 NYMEX 810,~~305~~000 5.61 654,857 July 2004 - June 2005 NYMEX 32,~~240~~160,000 4.54 15,~~319~~549,~~482~~623 ----------- ---------------- Unrealized ~~(Gains)~~ Losses 54,~~058~~375,000 $ 27,~~342~~268,~~402~~600 ----------- ================ Physical Contracts: Fixed Price Delivery Contracts July ~~2003 - June~~ 2004 ~~5,735,500 $ 4.50 July 2003~~ - ~~June~~October 2004 338,250 $ 4.85 ----------- Total 11Hedged Production 4,~~131~~713,~~750~~250 ===========

Notwithstanding the above, the Company's future cash flows from gas and oil production are exposed to significant volatility as commodity prices change. Assuming total oil and gas production and the percentage of gas production hedged or subject to fixed price contracts remain at June 2004 levels, a 10% change in the average unhedged prices realized during the year would change the Company's gas and oil revenues by approximately $0.8 million on an annual basis. 24 INTEREST RATE RISK -------------------- Interest rate risk is attributable to the Company's debt. The Company utilizes United States dollar denominated borrowings to fund working capital and investment needs. As of June 30, 2004, all but $36.9 million of the Company's debt has fixed interest rates. There is inherent rollover risk for borrowings as they mature and are renewed at current market rates. The extent of this risk is not predictable because of the variability of future interest rates and the Company's future financing needs. Assuming the variable interest debt remained at the June, 2004 level, a 10% change in rates would have a $0.2 million impact on interest expense on an annual basis. The Company has not attempted to hedge the interest rate risk associated with its debt. FOREIGN CURRENCY EXCHANGE RISK --------------------------------- Some of the Company's transactions are denominated in New Zealand dollars. For foreign operations with the local currency as the functional currency, assets and liabilities are translated at the period end exchange rates, and statements of income are translated at the average exchange rates during the period. Gains and losses resulting from foreign currency translation are included as a component of other comprehensive income. * * * * * 25 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ----------------------------------------------------- REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM -------------------------------------------------------------- To the Stockholders and Board of Directors of Energy Corporation of America: We have audited the accompanying consolidated balance sheets of Energy Corporation of America and subsidiaries (the "Company") as of June 30, 2004 and 2003, and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive income (loss) for each of the three years in the period ended June 30, 2004. These financial statements 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 standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of June 30, 2004 and 2003 and the results of their operations and their cash flows for each of the three years ended June 30, 2004 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated financial statements, in 2003 the Company adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" and in 2004 adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". DELOITTE & TOUCHE LLP Denver, Colorado September 27, 2004 26

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS AS OF JUNE 30 (AMOUNTS IN THOUSANDS) ---------------------------------------------------------------------------- ASSETS 2004 2003 ~~2002~~ ------------ ------------ CURRENT ASSETS: Cash and cash equivalents $ 45,~~831~~821 $ 174,~~775~~831 Accounts receivable: Oil and gas sales 8,632 10,380 ~~7,284~~ Gas ~~marketing~~aggregation and pipeline 9,~~458~~079 59,~~323~~458 Other 4,~~616~~000 64,~~924~~616 ------------ ------------ Accounts receivable 21,711 24,454 ~~19,531~~ Less allowance for doubtful accounts (1,~~616~~022) (1,~~366~~616) ------------ ------------ Accounts receivable, net of allowance 20,689 22,838 ~~18,165 Income taxes receivable - 1,596~~ Deferred income tax asset 41 2,~~237~~087 41 Deferred taxes - other comprehensive ~~income~~loss 2,889 787 -Notes ~~Derivatives~~receivable, -related ~~454~~party 59 1,609 Prepaid and other current assets 34,~~019~~141 41,~~234~~410 ------------ ------------ Total current assets 35,686 31,516 ~~44,461~~ NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 246,391 253,270 ~~244,155~~ ------------ ------------ OTHER ASSETS: Deferred financing costs, less accumulated amortization of $46,~~728~~833 and $35,~~722~~751 2,015 3,098 3Notes receivable,~~617~~ related party 113 146 Other 76,~~950~~007 127,~~503~~804 ------------ ------------ Total other assets 8,135 11,048 ~~16,120~~ ------------ ------------ TOTAL $~~295~~ 290,~~834~~212 $~~304~~ 295,~~736~~834 ============ ============ See notes to consolidated financial statements. (Continued)

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS AS OF JUNE 30 (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) ------------------------------------------------------------------------------------------- LIABILITIES AND STOCKHOLDERS' EQUITY 2004 2003 ~~2002~~ ------------ ------------ CURRENT LIABILITIES: Accounts payable and accrued expenses $ 1314,~~734~~823 $ 1513,~~683~~734 Current portion of long-term debt 1,145 133 ~~121~~ Funds held for future distribution 16,701 17,217 ~~11,414~~ Income taxes payable 128 1,484 - Accrued taxes, other than income 9,~~643~~289 89,~~221~~643 ~~Deferred taxes - comprehensive income - 180~~ Derivatives 7,303 810 - Other current liabilities 3,562 1,421 ~~7,078~~ ------------ ------------ Total current liabilities 52,951 44,442 ~~42,697~~ LONG-TERM OBLIGATIONS: Long-term debt 162,894 173,197 ~~198,701~~Deferred ~~Gas delivery obligation and deferred~~ trust revenue 2,~~917~~511 52,~~886~~917 Deferred income tax liability 19,552 20,376 ~~9,887~~ Derivatives - 1,319 - Other long-term obligations 8,~~311~~447 8,~~689~~311 ------------ ------------ Total liabilities 246,355 250,562 ~~265,860~~Minority ~~---------~~Interest ~~---------~~1,495 1,594 COMMITMENTS AND CONTINGENCIES (Note 1514) ~~Minority interest 1,594 1,732~~ STOCKHOLDERS' EQUITY: Common stock, par value $1.00; 2,000 shares authorized; 730 shares issued and outstanding 730 730 Class A non-voting common stock, no par value; 100 shares authorized; 68 and 46 shares issued 5and outstanding 8,~~092~~027 5,092 Additional paid-in capital 5,503 5,503 Retained earnings 48,200 45,150 ~~36,422~~ Treasury stock and notes receivable arising from issuance of common stock (14,954) (11,824) Deferred compensation on restricted stock (101,~~426~~887) - Accumulated other comprehensive loss (~~973~~3,257) (~~177~~973) ------------ ------------ Total stockholders' equity 42,362 43,678 ~~37,144~~ ------------ ------------ TOTAL $~~295~~ 290,~~834~~212 $~~304~~ 295,~~736~~834 ============ ============ See notes to consolidated financial statements.

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30 (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) -------------------------------------------------------------------------------------------------------------------- 2004 2003 2002 ~~2001~~ ----------- ----------- ----------- REVENUES: Oil and gas sales $ 57,203 $ 51,410 $ 38,939 ~~$ 41,555~~ Gas ~~marketing~~aggregation and pipeline sales 60,819 60,483 41,209 ~~81,042~~ Well operations and service revenues 5,~~498~~229 5,~~490~~498 5,~~899~~490 Other 122 35 504 ~~1,455~~ ----------- ----------- ----------- 123,373 117,426 86,142 ~~129,951~~ ----------- ----------- ----------- COSTS AND EXPENSES: Field operating expenses 11,452 10,128 10,916 ~~8,910~~ Gas ~~marketing~~aggregation and pipeline cost of sales 56,059 53,693 37,489 ~~77,167~~ General and administrative 15,573 15,437 17,360 ~~12,804~~ Taxes, other than income 4,170 3,287 2,175 ~~3,389~~ Depletion and depreciation of oil and gas properties 13,300 12,140 12,362 ~~9,290~~ Depreciation of pipelines, other property and equipment 4,190 4,294 2,934 ~~2,763~~ Exploration and impairment 10,796 11,729 27,694 19(Gain) loss on sale of assets (8,~~014~~289) 433 (319) ----------- ----------- ----------- ~~110~~107,~~708~~251 ~~110~~111,~~930~~141 ~~133~~110,~~337~~611 ----------- ----------- ----------- Income (loss) from operations 16,122 6,~~718~~285 (24,~~788~~469) ~~(3,386)~~ ----------- ----------- ----------- OTHER (INCOME) AND EXPENSE: Interest expense 15,069 16,383 19,671 ~~20,094 (Gain) loss on sale of assets 433 (319) (211)~~ Interest income and other 1,656 (25,848) (1,135) ~~(5,838)~~ ----------- ----------- ----------- 16,725 (9,~~032~~465) 18,~~217~~536 ~~14,045~~ ----------- ----------- ----------- Income (loss) ~~from continuing operations~~ before income taxes and minority interest (603) 15,750 (43,005) ~~(17,431)~~ Income tax expense (benefit) (4,722) 6,073 (16,822) ~~(7,232)~~ ----------- ----------- ----------- Income (loss) ~~from continuing operations~~ before minority interest 4,119 9,677 (26,183) ~~(10,199)~~ Minority interest 176 240 3 - --------- -~~--------~~ --------- ~~Income (loss) from continuing operations 9,917 (26,180) (10,199) Disposal of utility operations: Loss from utility operations, net of tax~~ - - ~~(1,847) Gain on sale of utility, net of tax~~ - - ~~84,402~~ --------- ~~--------- --------- Net income from disposal of utility operations - - 82,555 --------- --------- ---------~~ Income (loss) before cumulative effect of ~~changes~~change in accounting principle: 4,295 9,917 (26,180) ~~72,356~~ Change in accounting principle, net of tax - (73) - - ---------- ----------- ----------- NET INCOME (LOSS) $ 4,295 $ 9,844 $ (26,180) ~~$ 72,356~~ =========== =========== =========== Earnings (loss) per common share, basic: Income (loss) ~~from~~before ~~continuing~~change ~~operations~~in accounting principle $ 6.62 $ 15.23 $ (39.80) ~~$ (15.34) Discontinued operations - - 124.20~~ Change in accounting principle, net of tax - (0.11) - - ---------- ----------- ----------- Basic earnings (loss) per common share $ 6.62 $ 15.12 $ (39.80) ~~$ 108.86~~ ========== ============ =========== Earnings (loss) per common share, diluted: Income (loss) ~~from~~before ~~continuing~~change ~~operations~~in accounting principle $ 6.52 $ 14.90 $ (39.80) ~~$ (15.34) Discontinued operations - - 124.20~~ Change in accounting principle, net of tax - (0.11) - - ---------- ----------- ----------- Diluted earnings (loss) per common share $ 6.52 $ 14.79 $ (39.80) ~~$ 108.86~~ ========== ============ =========== See notes to consolidated financial statements.

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF ~~STOCKHOLDERSEQUITY~~OPERATIONS FOR THE YEARS ENDED JUNE 30 (AMOUNTS IN THOUSANDS~~, EXCEPT PER SHARE DATA~~) ------------------------------------------------------------------------------------------------------------------------------ Notes Class A Restricted Additional ~~Retained Notes~~ Received/ Common Common Class A Paid-In ~~Earnings~~Retained Treasury Issuance of Stock Stock Stock Capital ~~(Deficit)~~Earnings Stock Stock ------- -------- ------------ ----------- ---------- ---------- ------------- Balance, June, 30, ~~2000~~2001 $ ~~718~~730 $ 23,~~940~~732 $ 4- $ 5,~~615~~503 $ (463,~~833)~~653 $ (68,~~284~~204) $ (1,~~145~~089) ~~Comprehensive~~======= ~~income~~======== ~~72,356~~============ ~~Dividends~~=========== ~~(3,870)~~========== ~~Common~~========== ~~stock~~============= ~~issued~~Comprehensive ~~for~~loss ~~services~~(26,180) 12Dividends ~~888~~(1,051) Class A stock issued for services ~~792~~1,360 Purchase of treasury stock - common (1,~~455~~262) Purchase of treasury stock - Class A (~~465~~571) Reduction of notes receivable 56700 ------- -------- ------------ ----------- ---------- ---------- ------------- Balance, June 30, ~~2001~~2002 $ 730 $ 35,~~732~~092 $ - $ 5,503 $ 6336,~~653~~422 $ (810,~~204~~037) $ (~~1,089~~389) ======= ======== ============ =========== ========== ========== ============= Comprehensive ~~Loss~~income (~~26,180~~loss) 9,844 Dividends (1,~~051~~116) ~~Class A stock issued for services 1,360~~ Purchase of ~~treasury~~ stock - common (~~1,262~~854) Purchase of ~~treasury~~ stock - Class A (~~571~~639) Reduction of notes receivable ~~700~~95 ------- -------- ------------ ----------- ---------- ---------- ------------- Balance, June 30, ~~2002~~2003 $ 730 $ 5,092 $ - $ 5,503 $ 3645,~~422~~150 $ (1011,~~037~~530) $ (~~389~~294) ======= ======== ============ =========== ========== ========== ============= Comprehensive income (loss) 94,~~844~~295 Dividends (1,~~116~~245) ~~Purchase~~Issuance of ~~treasury~~stock - Class A 554 2,410 Restricted stock amortization Purchase of stock - common (~~854~~1,473) Purchase of ~~treasury~~ stock - Class A (~~639~~29) (336) Shares subject to mandatory redemption upon adoption of SFAS No. 150 (1,383) Reduction of notes receivable 9562 ------- -------- ------------ ----------- ---------- ---------- ------------- Balance, June 30, ~~2003~~2004 $ 730 $ 5,~~092~~646 $ 2,381 $ 5,503 $ 4548,~~150~~200 $ (1114,~~530~~722) $ (~~294~~232) ======= ======== ============ =========== ========== ========== ============= Accum. Other Total Deferred Comprehensive Stockholders' Compensation Income (Loss) Equity -------------- --------------- --------------- Balance, June, 30, ~~2000~~2001 $ ~~(134)~~- $ (4501 $ 64,~~123)~~826 ============== =============== =============== Comprehensive ~~income~~loss ~~635~~(678) 72(26,~~991~~858) Dividends (31,~~870~~051) ~~Common stock issued for services 900~~ Class A stock issued for services ~~792~~1,360 Purchase of treasury stock - common (1,~~455~~262) Purchase of treasury stock - Class A (~~465~~571) Reduction of notes receivable 56700 -------------- --------------- --------------- Balance, June 30, ~~2001~~2002 $ ~~501~~- $ 64(177) $ 37,~~826~~144 ============== =============== =============== Comprehensive ~~Loss~~income (~~678~~loss) (~~26,858~~796) 9,048 Dividends (1,~~051~~116) ~~Class A stock issued for services 1,360~~ Purchase of ~~treasury~~ stock - common (~~1,262~~854) Purchase of ~~treasury~~ stock - Class A (~~571~~639) Reduction of notes receivable ~~700~~95 -------------- --------------- --------------- Balance, June 30, ~~2002~~2003 $ - $ (~~177~~973) $ 3743,~~144~~678 ============== =============== =============== Comprehensive income (loss) (~~796~~2,284) 92,~~048~~011 Dividends (1,~~116~~245) ~~Purchase~~Issuance of ~~treasury~~stock - Class A (2,133) 831 Restricted stock amortization 246 246 Purchase of stock - common (~~854~~1,473) Purchase of ~~treasury~~ stock - Class A (~~639~~365) Shares subject to mandatory redemption upon adoption of SFAS No. 150 (1,383) Reduction of notes receivable 9562 -------------- --------------- --------------- Balance, June 30, ~~2003~~2004 $ (~~973~~1,887) $ 43(3,~~678~~257) $ 42,362 ============== =============== ===============

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED JUNE 30 (AMOUNTS IN THOUSANDS) -----------------------------------------------------------------------------------------------------------~~---------~~ 2004 2003 2002 ~~2001~~ --------- --------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES ~~Income~~Net income (loss) ~~from~~$ ~~continuing~~4,295 ~~operations~~ $ 9,~~917~~844 $(26,180) ~~$ (10,199)~~ Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: Depletion, depreciation and amortization 17,490 16,434 16,031 ~~12,911~~ (Gain) loss on sale of assets (8,289) 433 (319) ~~(211)~~ Gain on redemption of senior bonds (513) (23,672) - - Deferred income taxes (2,870) 12,685 (12,492) ~~28,359~~ Exploration and impairment 10,730 11,508 27,227 ~~18,591~~ Other, net 481 2,~~563~~636 2,322 ~~(4,711)~~ --------- --------- ---------- 21,324 29,868 6,589 ~~44,740~~ Changes in assets and liabilities: Accounts receivable 2,149 (4,817) 3,187 ~~(2,936)~~Income ~~Gas~~taxes inreceivable ~~storage~~- ~~(196)~~- ~~870~~ (~~304~~2,066) Income taxes ~~3,080~~payable (21,~~066~~357) ~~(33~~3,~~821)~~081 - Prepaid and other assets (~~1,364~~165) (1,~~900~~560) (321,030) Accounts payable and accrued expenses 521 (627) (2,218) ~~6,341~~ Funds held for future distributions (516) 5,803 (3,253) ~~1,678~~ Other 52 (8,~~521~~522) (23,405) ~~14,631~~ --------- --------- ---------- Net cash provided (used) by operating activities ~~from continuing operations 23,226 (~~22,~~196)~~008 ~~30,297 Net cash used by operating activities from disposed operations - - (48,335) --------- --------- ---------- Net cash provided (used) by operating activities~~ 23,226 (22,196) ~~(18,038) --------- --------- ----------~~ CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (21,910) (37,632) (38,294) ~~(112,863)~~ Proceeds from sale of assets 10,844 3,532 704 ~~1,517~~ Notes receivable and other 1,560 1,259 86 ~~(4,192)~~ --------- --------- ---------- Net cash used by investing activities from ~~continuing~~ operations (329,~~841~~506) (~~37,504) (115,538) Net cash provided by investing activities from disposed operations - - 224,765 --------- --------- ---------- Net cash (used) provided by investing activities (~~32,841) (37,504) ~~109,227 --------- --------- ----------~~ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 67,281 72,635 - ~~7,825~~ Principal payment on long-term debt (76,005) (73,434) (145) ~~(21,850)~~ Proceeds ~~(payment)~~from onissuance ~~short-term~~of ~~borrowing~~stock 257 - - ~~(2,000)~~ Purchase of treasury stock and other financing activities (1,~~447~~811) (1,~~663~~447) (1,~~072~~663) Dividends paid (1,~~083~~234) (1,~~053~~083) (31,~~605~~053) --------- --------- ---------- Net cash used by financing activities from ~~continuing~~ operations (311,~~329~~512) (~~2,861) (20,702) Net cash provided by financing activities from disposed operations - - 6,539 --------- --------- ---------- Net cash used by financing activities (~~3,329) (2,861) ~~(14,163)~~ --------- --------- ---------- Net (decrease) increase in cash and cash equivalents 990 (12,944) (62,561) ~~77,026~~ Cash and cash equivalents, beginning of period 4,831 17,775 80,336 ~~3,310~~ --------- --------- ---------- Cash and cash equivalents, end of period $ 5,821 $ 4,831 $ 17,775 ~~$ 80,336~~ ========= ========= ========== See notes to consolidated financial statements.

ENERGY CORPORATION OF AMERICA CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED JUNE 30 (AMOUNTS IN THOUSANDS) ------------------------------------------------------------------------------- 2004 2003 2002 ~~2001~~ -------- --------- --------- Net income (loss) $ 4,295 $ 9,844 $(26,180) ~~$72,356 -------- --------- --------~~ Other comprehensive income (loss), net of tax: Foreign currency translation adjustment: Current period change 755 854 1,627 ~~(1,980)~~ Marketable securities: Unrealized ~~gain (~~loss) - (5) (102) ~~136~~ Reclassification to earnings - (25) (4) Oil and gas derivatives: Net cumulative effect adjustment - - ~~(2,153)~~- Current period transactions (2,775) (2,351) 1,999 ~~(541)~~ Reclassification to earnings (264) 731 (4,198) ~~5,173~~ -------- --------- --------- Other comprehensive ~~income (~~loss), net of tax (2,284) (796) (678) ~~635~~ -------- --------- --------- Comprehensive income (loss) $ 2,011 $ 9,048 $(26,858) ~~$72,991~~ ======== ========= ========= See notes to consolidated financial statements.

32 ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002 -------------------------------------------------------------------------------- 1. NATURE OF ORGANIZATION Energy Corporation of America (the "Company") was formed in June 1993 through an exchange of shares with the common stockholders of Eastern American Energy Corporation ("Eastern American"). The Company is an independent energy company. All references to the "Company" include Energy Corporation of America and its consolidated subsidiaries. The Company's industry segments are discussed at Note 16. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The following is a summary of the significant accounting policies followed by the Company. Principles of Consolidation - The consolidated financial statements include --------------------------- the accounts of the Company and its subsidiaries. Investments in affiliates in which the Company owns greater than 50% are consolidated. Investments in which the Company owns from 20% to 50% are accounted for by the equity method if the Company has the ability to exert significant influence over the investee, but does not otherwise have the ability to control. Investments in less than 20% owned affiliates and affiliates in which the Company does not exhibit significant influence are accounted for under the cost method. The Company has investments in oil and gas limited partnerships and joint ventures and has recognized its proportionate share of these entities' revenues, expenses, assets and liabilities. All significant intercompany transactions have been eliminated in consolidation. Cash and Cash Equivalents - Cash and cash equivalents include short-term ---------------------------- investments maturing in three months or less from the date acquired. Property, Plant and Equipment - Oil and gas properties are accounted for -------------------------------- using the successful efforts method of accounting. Under this method, certain expenditures such as exploratory geological and geophysical costs, exploratory dry hole costs, delay rentals and other costs related to exploration are recognized currently as expenses. All direct and certain indirect costs relating to property acquisition, successful exploratory wells, development costs, and support equipment and facilities are capitalized. The Company computes depletion, depreciation and amortization of capitalized oil and gas property costs on the units-of-production method using proved developed reserves. Direct production costs, production overhead and other costs are charged against income as incurred. Gains and losses on the sale of oil and gas property interests are generally recognized in income. Other property, equipment, pipelines and buildings are stated at cost and are depreciated using straight-line and accelerated methods over estimated useful lives ranging from three to forty years. Repairs and maintenance costs are charged against income as incurred; significant renewals and betterments are capitalized. Gains and losses on dispositions of property, equipment, pipelines and buildings are recognized as income. 33 At June 30 property, plant and equipment consisted of the following (in thousands):

2004 2003 ~~2002~~ ---------- ---------- Oil and gas properties $ ~~337~~345,~~904~~556 $ ~~320~~337,~~148~~904 Pipelines 2021,~~594~~856 20,~~703~~594 Other property and equipment 22,825 23,537 ~~19,598~~ ---------- ---------- 390,237 382,035 ~~360,449~~ Less accumulated depletion, depreciation and amortization (~~128~~143,~~765~~846) (~~116~~128,~~294~~765) ---------- ---------- Net property, plant and equipment $ ~~253~~246,~~270~~391 $ ~~244~~253,~~155~~270 ========== ==========

Long-Lived Assets - Statement of Financial Accounting Standards ("SFAS") ------------------ No. 144, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", requires all companies to assess long-lived assets and assets to be disposed of for impairment. For the year ended June 30, 2004, the impairment recognized by the Company primarily consists of oil and gas property of $2.4 million and other property of $1.1 million. The other property is primarily related to the sale of an interest in a drilling rig held with Breitburn Energy Company L.P. ("BECLP") and is discussed further in Note 10. During the fiscal year ended June 30, 2003 the Company recognized impairment of oil and gas property of $3.1 million. Deferred Financing Costs - Certain legal, underwriting fees and other -------------------------- direct expenses associated with the issuance of credit agreements, lines of credit and other financing transactions have been capitalized. These financing costs are being amortized over the term of the related credit agreement. Foreign Currency Translation - The translation of applicable foreign ------------------------------ currencies into U.S. dollars is performed for accounts using current exchange rates in effect at the balance sheet date. The translation adjustment is included in stockholders' equity as a component of other comprehensive income. Income Taxes - Deferred income taxes reflect the impact of "temporary ------------- differences" between assets and liabilities recognized for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with SFAS No. 109, "Accounting For Income Taxes". A valuation allowance is established for any portion of a deferred tax asset for which it is more likely than not that a tax benefit will not be realized. Deferred Trust Revenue- In 1993, the Company sold working interests in ------------------------ certain Appalachian gas properties in connection with the formation of the Eastern American Natural Gas Trust ("the Royalty Trust"). A portion of the proceeds from the sale of these interests, representing term net profits interest, was accounted for as a production payment and was classified as deferred trust revenue. The deferred revenue is recognized as production occurs for the term properties. Revenues and Gas Costs - Oil and gas sales, and aggregation and pipeline ------------------------- revenues are recognized as income when the oil or gas is produced and sold. Monthly, the Company makes estimates of the amount of production delivered to the purchaser and the price to be received. The Company uses its knowledge of properties, historical performance, NYMEX and local spot market prices and other factors as the basis for these estimates. Gas costs are expensed as incurred. Stock Compensation - As permitted under SFAS No. 123, "Accounting for ------------------- Stock-Based Compensation", the Company has elected to continue to measure compensation costs for stock-based employee compensation plans using the intrinsic value method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Stock 34 compensation expense of $0.5 million and $0.9 million was recognized in June 30, 2004 and June 30, 2002, respectively, with no expense recorded for the year ended June 30, 2003. Use of Estimates - The preparation of financial statements in conformity ------------------ with generally accepted accounting principles in the United States of America 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. The Company's financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization and impairment of oil and gas properties. Management emphasizes that reserve estimates are inherently imprecise. In addition, realization of deferred tax assets is based largely on estimates of future taxable income. Derivatives - In accordance with SFAS No. 133, "Accounting for Derivative ----------- Instruments and Hedging Activities", as amended, all derivative instruments are recorded as assets or liabilities in the Company's balance sheet and measurement of those instruments at its' estimated fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income; to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured monthly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness and any derivatives not qualifying as hedges are recognized immediately in earnings. Accumulated Other Comprehensive Loss- At June 30 accumulated other --------------------------------------- comprehensive loss consisted of the following (in thousands): 2004 2003 -------- -------- Foreign currency translation $ 1,122 $ 367 Natural gas hedging (4,379) (1,340) -------- -------- Accumulated other comprehensive loss $(3,257) $ (973) ======== ======== Concentration of Credit Risk - The Company maintains its cash accounts ------------------------------- primarily with a single bank and invests cash in money market accounts, which the Company believes to have minimal risk. As operator of jointly owned oil and gas properties, the Company sells oil and gas production to numerous U.S. oil and gas purchasers, and pays vendors on behalf of joint owners for oil and gas services. Both purchasers and joint owners are located primarily in the northeastern United States and Texas. The risk of nonpayment by the purchasers or joint owners is considered minimal and has been considered in the Company's allowance for doubtful accounts. Environmental Concerns - The Company is continually taking actions it ----------------------- believes necessary in its operations to ensure conformity with applicable federal, state and local environmental regulations. As of June 30, 2004, the Company has not been fined or cited for any environmental violations, which would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company. 35 Prior Year Reclassifications - Certain amounts in the financial statements ----------------------------- of prior years have been reclassified to conform to the current year presentation. Recent Accounting Pronouncements - In March 2004, the Emerging Issues Task --------------------------------- Force ("EITF") reached a consensus that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights Are Tangible or Intangible Assets," are tangible assets and that they should be removed as examples of intangible assets in SFAS No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets." The FASB has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Position ("FSP") FAS Nos. 141-1 and 142-1. In addition, proposed FSP 142-b confirms that SFAS 142 does not change the balance sheet classification or disclosures of mineral rights of oil and gas producing enterprises. Historically, the Company has included the costs of such mineral rights as tangible assets, which is consistent with the EITF's consensus. As such, EITF 04-02 and the related FSPs have not affected the Company's consolidated financial statements. In May 2003 the FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity, and requires instruments that fall within the scope of this pronouncement to be classified as liabilities. The Company early adopted SFAS No. 150 at the beginning of the fourth quarter of the year ended June 30, 2004. The effect of this adoption was an increase to other current liabilities of $0.2 million, other long term obligations of $1.2 million and a $1.4 million decrease in stockholders' equity. Asset Retirement Obligations - The Company accounts for its' asset ------------------------------ retirement obligations according to SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. For the Company, asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. While assets such as pipelines and marketing assets may have retirement obligations covered by SFAS No. 143, certain of those obligations are not recognized since the fair value cannot be estimated due to the uncertainty of the settlement date of the obligation. The initial application of this accounting standard by ECA as of July 1, 2002, resulted in an increase in net plant assets of $0.4 million, an asset retirement obligation liability of $0.5 million, and a cumulative effect of a change in accounting principle of $0.1 million. Due to a change in estimate by ECA in fiscal year 2003 regarding SFAS No. 143, the initial application was changed to an asset retirement obligation liability of $0.7 million, a net plant asset increase of $0.6 million, and a cumulative effect of a change in accounting principle of $0.1 million as of June 30, 2003. 36 The following table presents a reconciliation of the beginning and ending carrying amounts of the asset retirement obligations.

~~2003~~(IN ~~2002~~THOUSANDS) ~~2001~~2004 ~~--------~~2003 -------- ------- ~~Cash~~Asset ~~paid~~retirement ~~for:~~obligation ~~Interest~~as ~~$16,383~~of the beginning of the year $~~18,935~~ 724 $~~19,210~~ ~~Income~~471 ~~taxes~~Accretion 15expense ~~114~~44 ~~37,983~~33 ~~Income~~Liabilities ~~taxes~~incurred ~~refunded~~22 181 Liabilities settled (~~9,809~~175) (~~111~~86) -Change ~~Noncash~~in ~~investing~~estimate ~~and~~58 ~~financing~~125 ~~activities:~~------ ~~Dividends~~------ ~~declared~~Asset ~~and~~retirement ~~unpaid~~obligation atas ~~year~~of the end ~~297~~of ~~262~~the ~~265~~year ~~Liabilities~~$ ~~assumed~~673 in$ ~~acquisition~~724 -====== ~~- 824~~======

Supplemental Disclosures of Cash Flow Information - Supplemental cash flow -------------------------------------------------- information for the years ended June 30 is as follows (in thousands):

~~2001~~2004 ~~(1)~~2003 --------- ~~Net sales $ 9,929~~ --------- ~~Loss~~Cash ~~before~~paid ~~income~~for: ~~taxes~~Interest (3$15,~~164)~~069 $16,383 Income taxes ~~benefit~~25 ~~(1,317)~~15 ~~---------~~Income ~~Loss~~taxes ~~from~~refunded ~~discontinued operations $~~ (~~1,847~~38) ~~=========~~ (19,809) ~~Discontinued~~Noncash ~~operations~~investing ~~for~~and ~~one~~financing ~~and~~activities: ~~one~~Dividends ~~half~~declared ~~months~~and inunpaid ~~fiscal~~at year ~~2001~~end 308 297

3. ACQUISITIONS The Company finalized the purchase of an additional 100-mile long natural gas gathering system ("System 8000") from Columbia Gas Transmission for a purchase price of $1.2 million during the first quarter of fiscal year 2005. System 8000 is located in northeastern West Virginia and is situate among one of the Company's existing operating areas. On February 5, 2003, the Company purchased certain oil and gas properties located in southern West Virginia for $5.6 million, after certain adjustments. The purchase included proved developed producing gas reserves, estimated at 4 Bcf, 90 producing wells and over 30,000 acres. 4. RISK MANAGEMENT The Company periodically hedges a portion of its oil and gas production through futures and swap agreements. The purpose of the hedge is to provide a measure of stability in the volatile environment of oil and gas prices and to manage exposure to commodity price risk under existing sales or purchase commitments. All of the Company's price swap agreements in place at June 30, 2004 are designated as cash flow hedges. At June 30, 2004, the Company had swap agreements maturing from July 2004 through June 2005 covering 4,375,000 Mmbtu. At June 30, 2004, the 37 Company had recorded a $4.4 million loss in accumulated other comprehensive income, $0.03 million of short term derivative assets, $7.3 million in short term derivative liabilities and $2.9 million in deferred tax asset. At June 30, 2003, the Company had swap agreements maturing from July 2003 through June 2005 covering 5,058,000 Mmbtu. As of June 30, 2003 the Company had recorded a $1.3 million loss in accumulated other comprehensive income, $0.8 million in short term derivative liabilities, $1.3 million in long term derivative liabilities, and $0.8 million in deferred tax asset. For the year ended June 30, 2004 the Company recognized a net loss in revenues on its natural gas hedging activities of $0.4 million. For the year ended June 30, 2003, the Company recognized a net loss in revenues on its natural gas hedging activities of $1.2 million and a net gain of $6.7 million for the year ended June 30, 2002. The estimated net amount of the existing losses within other comprehensive income that are expected to be reclassified into earnings within the next twelve months is approximately $4.4 million. 5. DEBT Long-Term Debt - At June 30 long-term debt consisted of the following (in --------------- thousands):

2004 2003 ~~2002~~ --------- --------- ECA senior subordinated notes, interest at 9.5% payable semi-annually, due May 15, 2007 $~~132~~126,~~073~~033 $~~197~~132,~~672~~073 Revolving credit agreements, variable rates 37,109 40,227 - Installment notes payable, at imputed interest rates ranging from from 8.0% to 9.5% 897 1,030 ~~1,150~~ --------- --------- 164,039 173,330 ~~198,822~~ Less current portion (~~133~~1,145) (~~121~~133) --------- --------- $~~173~~162,~~197~~894 $~~198~~173,~~701~~197 ========= =========

Scheduled maturities of the Company's long-term debt at June 30, 2004 for each of the next five years and thereafter are as follows (in thousands):

~~2004~~2005 $ ~~213 2005 1~~35,213 2006 ~~39,440~~213 2007 ~~132~~92,~~182~~142 2008 100 2009 36,209 Thereafter ~~584~~484 -------- Total payments ~~173~~164,~~732~~361 Less: imputed interest ~~402~~322 -------- Present value of scheduled maturities $~~173~~164,~~330~~039 ========

Senior Subordinated Notes -The Company has 9 1/2 % Senior Subordinated --------------------------- Notes ("Notes") that are due May 15, 2007. The agreement contains certain restrictions and conditions among which are limitations on indebtedness, dividends and investments, and certain interest coverage ratio requirements. 38 The Company purchased $6.04 million of its Notes during the twelve months ended June 30, 2004, $2.04 million in privately negotiated transactions and $4.0 million pursuant to an Asset Sale Offer as defined in the Indenture for the Notes that resulted in a gain of $0.5 million which was included in interest income and other. The Company purchased $34 million of the Notes on July 29, 2004 pursuant to an Asset Sale Offer as defined in the Indenture for the Notes. The Company classified this debt as long term at June 30, 2004 as a result of entering into an amended and restated credit agreement in place that allowed the Company to refinance the debt on a long term basis. See Note 18 for further discussion. For the year ended June 30, 2003 the Company purchased approximately $65.6 million of the Notes that resulted in a gain of $23.7 million which was included in interest income and other. Revolving Credit and Term Loan -As previously reported, on July 10, 2002, -------------------------------- the Company entered into a $50 million revolving Credit Agreement with Foothill Capital Corporation, now Wells Fargo Foothill, Inc. ("Foothill"). The Company and Foothill have entered into an Amended and Restated Credit Agreement dated June 10, 2004 (the "Restated Credit Agreement"). The Restated Credit Agreement provides for the $50 million revolving credit facility to be extended and for the Company to be provided with additional credit in the form of a single advance term loan in the amount of $50 million. The term loan contains requirements for principal payments of $1 million each at July 10, 2005, 2006 and 2007, with the remaining balance due on July 10, 2008. Depending on the Company's level of borrowing under the Restated Credit Agreement, the applicable interest rates for base rate loans are based on Wells Fargo's prime rate plus 0.25% to 0.75%. The Company has the ability under the Restated Credit Agreement to designate certain loans as Libor Rate Loans at interest rates based upon the rate at which dollar deposits are offered to major banks in the London interbank market plus 2.25% to 2.75%. The Restated Credit Agreement expires on July 10, 2008. The obligations under the Restated Credit Agreement are secured by certain of the existing proved producing oil and gas assets of the Company. The Restated Credit Agreement, among other things, restricts the ability of the Company and its subsidiaries to incur new debt, grant additional security interests in its collateral, engage in certain merger or reorganization activities, or dispose of certain assets. As of September 23, 2004, there are $50.0 million in outstanding borrowings under the term loan and $15 million in outstanding borrowings under the revolving loan. Other Credit Facilities - The Company has an unsecured revolving line of ------------------------- credit totaling $3.0 million with a financial institution with an interest rate of prime plus 0.25%, which reduces by $1.0 million in November 2004 and expires on June 30, 2005. As of June 30, 2004, there was $1.0 million outstanding under the line of credit and $1.8 million was committed through letters of credit. As of June 30, 2003, there was $1.0 million outstanding under the line of credit. Other Notes - In December 2000 the Company assumed a note which stipulated ------------ that the Company will pay consecutive equal monthly payments with the first scheduled payment to be made by the Company on January 15, 2000 and the final scheduled payment due on April 15, 2014. As of June 30, 2004 and 2003, the balance due was $1.0 million and $1.1 respectively. The Company purchased certain pipelines during 1998 constituting a natural gas gathering system in the State of West Virginia. The Company paid the seller $1.2 million for the facilities. In accordance with the agreement, the Company paid $0.3 million at closing with the balance due to the seller in one hundred consecutive equal monthly installments beginning in March 1998. As of June 30, 2004 and 2003, the balance due to the seller was $0.2 and $0.3 million respectively. 39 6. INCOME TAXES The following table summarizes components of the Company's provision (benefit) for income taxes for the years ended June 30 (in thousands):

2004 2003 2002 ~~2001~~ -------- --------- --------- Current: Federal $(1,523) $(6,610) $ (3,436) $State (~~27,749~~329) ~~State~~ (2) 1,385 ~~(7,842)~~ -------- --------- --------- Total current (1,852) (6,612) (2,051) ~~(35,591)~~ -------- --------- --------- Deferred: Federal (2,116) 11,502 (13,381) ~~23,115~~ State (754) 1,183 (1,390) ~~5,244~~ -------- --------- --------- Total deferred (2,870) 12,685 (14,771) ~~28,359~~ -------- --------- --------- Total provision (benefit) for income taxes $(4,722) $ 6,073 $(16,822) ~~$ (7,232)~~ ======== ========= =========

A reconciliation of the provision for income taxes computed at the statutory rate to the provision for income taxes as shown in the consolidated statements of operations for the years ended June 30 is summarized below (in thousands):

2004 2003 2002 ~~2001~~ -------- --------- --------- Tax provision (benefit) at the federal statutory rate $ (150) $5,513 $(15,051) ~~$(6,101)~~ State taxes, net of federal tax effects (25) 663 (2,516) ~~(1,151)~~ Effect of rate change - 12 103 ~~(176) Section 29 tax credits - (2,277)~~ Change in valuation allowance on federal, foreign and state deferred tax assets, net of federal effect - - (2,048) ~~Investment~~Change in tax ~~credit~~contingency ~~expiration~~(4,514) - - Other, net (33) (115) 2,690 ~~2,473~~ -------- --------- --------- ~~Provision~~Total provision (benefit) for income taxes $(4,722) $6,073 $(16,822) ~~$(7,232)~~ ======== ========= =========

40 Components of the Company's deferred tax assets and liabilities, as of June 30 are as follows (in thousands):

2004 2003 ~~2002~~ --------- --------- Deferred tax assets: Royalty ~~trust~~Trust agreements $ 4,~~640~~087 $ 74,~~830~~640 Tax credits and carryforwards 7,~~795~~236 107,~~113~~795 Other 3,294 2,512 ~~3,874~~ --------- --------- Total deferred tax assets 14,~~947~~617 2114,~~817~~947 --------- --------- Deferred tax liabilities: Property, plant and equipment (2831,~~920~~770) (2528,~~249~~920) Other liabilities (~~6,362~~312) (46,~~218~~362) --------- --------- Total deferred tax liabilities (3532,~~282~~082) (2935,~~467~~282) --------- --------- Net deferred ~~income~~ tax liability $(2017,~~335~~465) $(720,~~650~~335) ========= ========= Current deferred tax asset 41$ 2,~~237~~087 $ 41 Long-term deferred tax liability (19,552) (20,376) --------- --------- Net ~~long-term~~ deferred tax liability $(2017,~~376~~465) $ (920,~~887~~335) ========= =========

At June 30 the Company has the following federal and state tax credits and carryforwards (in thousands):

At2004 ~~June 30,~~ 2003 ~~and 2002 the Company has the following federal and state tax credits and carryforwards (in thousands): 2003 2002~~ Year of Year of Amount Expiration Amount Expiration ------- ---------- ------- ---------- AMT tax credits $ 43,~~444~~591 None $ 94,~~355~~444 None Charitable ~~Contribution~~contribution ~~Carryover~~carryforwards 3166 2007-2008 3 2007-2008 ------- ------- Total federal credits and carryforwards $ 43,~~447~~757 $ 94,~~355~~447 ======= ======= State net operating loss ~~carryovers~~carryforwards $ 3,~~348~~479 2005-2022 $ ~~758~~3,348 2005-~~2021~~2022 ------- ------- Total state ~~carryovers~~carryforwards $ 3,~~348~~479 $ ~~758~~3,348 ======= ======= Total federal and state ~~carryovers~~carryforwards $ 7,~~795~~236 $10 7,~~113~~795 ======= =======

At June 30, 2001, the Company had West Virginia state tax credits of $3.7 million. The Company was eligible for relocation incentives taken in the form of tax credits from West Virginia. The incentive amounts were based upon investments made and jobs created in that state. Tax credits generated by the Company were used primarily to offset the payment of severance, property and state income taxes. Based on the then existing future taxable temporary differences and projections of future West Virginia severance, property and state income taxes, management had provided a valuation allowance of $3.2 million for that portion of the credits that were not expected to be utilized. At June 30, 2003 the Company had utilized the entire $3.7 million of WV state tax credits and had reversed the related $3.2 million valuation allowance. During 2004, the Company utilized $0.9 million in AMT Credits. The $3.6 million in remaining AMT credits may be utilized in future periods. 41 In March 2004, the U.S. Internal Revenue Service ("IRS") notified the Company that it was initiating an audit of the Company's federal income tax return for the tax year ending June 30, 2002. The IRS is also reviewing the refund claim filed by the Company due to the amended federal income tax return for the tax year ending June 30, 1999. The Company has not received any notices of proposed adjustments and believes that it has adequately provided for any potential tax liability that may be assessed by the IRS. In connection with the evaluation of contingencies, the Company continues to perform periodic reviews. During 2004, the Company adjusted the contingency balance for items that are closed or no longer applicable. 7. EMPLOYEE BENEFIT PLANS The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock Plan (the "Plan") for the stated purpose of expanding and improving profits and prosperity and to assist the Company in attracting and retaining key personnel. The Plan is noncontributory, and its continuance from year to year is at the discretion of the Board of Directors. The annual profit sharing pool is based on calculations set forth in the Plan. Generally, to be eligible to participate, an employee must have been continuously employed for two or more years; however, employees with less than two years of employment may participate under certain circumstances. The Company recognized $1.7 million and $2.4 million of profit sharing expense during the years ended June 30, 2004 and 2003, respectively, while no profit sharing expense was recognized for the year ended June 30, 2002. The Company sponsors a Section 401(k) plan covering all full-time employees who wish to participate. The Company's contributions, which are principally based on a percentage of the employee contributions, and charged against income as incurred, totaled $0.29 million, $0.27 million and $0.25 million for the years ended June 30, 2004, 2003, and 2002. 8. CAPITAL STOCK Voting Common Stock- In May 1995, the Company was reincorporated in the --------------------- State of West Virginia. As part of this reincorporation, each outstanding share of then existing no-par value common stock was converted to one share of $1 par value common stock. Pursuant to an Agreement dated December 28, 1998, the Company is required to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's estate or promptly after the passage of two years from Mr. Brill's death if the estate does not sooner tender the shares. The Company entered into a repurchase agreement on January 21, 2004 with the KWB Trust to define the purchase price and establish the conditions for the repurchase of stock owned by the Kenneth W. Brill, estate. The agreement outlines the repurchase of 49,110 shares of stock by the Company or through third parties, at an anticipated value of approximately $3.7 million over the next five years, and provides for payments in twenty quarterly installments on the majority of the shares to be repurchased. The repurchase of shares is subject to certain restrictions in the Company's credit agreements. On June 30, 2004, the Company's remaining repurchase obligation under the Agreement is approximately $2.9 million. Upon adoption of SFAS No. 150, as described in Note 2, $1.4 million of the obligation was reclassified as a liability and the remaining $1.5 million is included in stockholders' equity as third parties have agreed to purchase such amount. Class A Non-Voting Common Stock - In August 1998, the Company amended its --------------------------------- articles of incorporation authorizing the issuance of up to 100,000 shares of Class A non-voting common stock. During October, 2003, ECA offered its employees that were participants in the 2003 Profit Sharing program, the opportunity to purchase Class A stock 42 having certain restrictions. Employees were awarded the right to purchase a specified number of shares, with the restrictions expiring over a specified period of time. As a result of this program, 16,850 shares of restricted stock were issued for $15 per share vesting over five years. Deferred compensation was recognized based on the fair value of the stock at issuance and is being amortized over the vesting period. The Company repurchased 201 shares of the restricted stock during the year ended June 30, 2004. Treasury Stock - At June 30, 2004, the Company had 126,613 shares of voting -------------- common stock in treasury, carried at cost. The Company purchased 15,367 and 6,262 shares of voting common stock during the years ended June 30, 2004 and 2003, respectively. At June 30, 2004, the Company had 21,202 shares of non-voting Class A stock in treasury, carried at cost. The Company purchased 2,349 and 4,473 shares of non-voting Class A stock during the years ended June 30, 2004 and 2003. Stock Plans - During fiscal 1999, the Company created an incentive stock ------------ purchase agreement, primarily for outside Directors. Under the agreement, options to purchase voting common stock were granted at $75 per share, based on the fair market value as determined by the Board of Directors and are exercisable based on the following schedule: Number of Exercise Period Shares ------------------------------------- --------- January 1, 2000 to December 31, 2004 10,002 January 1, 2001 to December 31, 2005 9,996 --------- 19,998 ========= No options were exercised for either of the years ended June 30, 2004 or 2003. Therefore, as of June 30, 2004, all the remaining options were exercisable. Fair value of the options at the grant dates, as estimated by management, was nominal. 9. EARNINGS PER SHARE In accordance with SFAS No. 128, "Earnings Per Share," basic earnings per share has been computed based upon the weighted average shares outstanding. Diluted earnings per share gives effect to outstanding stock options. 43 A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended June 30 is as follows:

~~Number~~2004 of2003 ~~Exercise~~2002 ~~Period~~-------- ~~Shares~~--------- --------- Income (loss) before cumulative effect of change in accounting principle $ 4,295 $ 9,917 $(26,180) Change in accounting principle, net of tax - (73) - ------------------------------ Net income (loss) $ 4,295 $ 9,844 $(26,180) ---------------------------------------------------------------------------- ~~January~~Weighted 1,average ~~1999~~common toshares: ~~December~~Basic 31648,835 ~~2003~~651,205 10657,~~002~~707 ~~January~~Diluted 1658,345 ~~2000~~665,471 to657,707 ~~December~~---------------------------------------------------------------------------- ~~31,~~Basic ~~2004~~net ~~10,002~~income ~~January~~(loss) 1,per ~~2001~~common toshare: ~~December~~Income ~~31,~~(loss) ~~2005~~from 9operations before extraordinary items $ 6.62 $ 15.23 $ (39.80) Change in accounting principle,~~996~~ net of tax - (0.11) - ---------------------------------------------------------------------------- 30Basic net income (loss) per common share $ 6.62 $ 15.12 $ (39.80) ---------------------------------------------------------------------------- Diluted net income (loss) per common share: Income (loss) from operations before extraordinary items $ 6.52 $ 14.90 $ (39.80) Change in accounting principle,~~000~~ ~~=========~~net of tax - (0.11) - ---------------------------------------------------------------------------- Diluted net income (loss) per common share $ 6.52 $ 14.79 $ (39.80) ----------------------------------------------------------------------------

For fiscal year 2002 the effect of 14,226 shares related to outstanding stock options were not included in the computation of diluted net loss per share because to do so would have been antidilutive 10. UNCONSOLIDATED AFFILIATE The Company owned a 25.35% members' interest in Breitburn Energy Company, LLC ("BEC"). The Company's investment in BEC was accounted for under the equity method. Although BEC had current year earnings, the Company's share of net losses since inception continued to exceed the carrying amount of the investment. Therefore, the investment had been reduced to zero and equity and earnings would not have been recognized until the Company's share of net income equaled its share of unrecognized net losses. During June 2004, the Company sold its' membership interest in BEC for gross proceeds of $9.2 million. A pre-tax gain of $7.4 million was recognized and a liability of $1.8 million established as a reserve against items for which the Company was required to indemnify the buyer for a period of 180 days after closing pursuant to the agreement. Net proceeds from the sale are subject to certain reinvestment provisions of the Company's Notes. 44 Summarized financial information for BEC as of and for the years ended December 31, is as follows (in thousands):

2003 2002 2001 --------- --------- --------- ~~Income~~Current ~~(loss)~~assets ~~from continuing operations~~ $ 97,~~917~~181 $~~(26~~ 6,~~180)~~679 $~~(10~~ 11,~~199)~~336 ~~Discontinued~~Oil ~~operations~~and ~~82,555~~gas ~~Change~~properties in96,846 ~~accounting~~110,555 ~~principle~~100,833 ~~net~~Other ofassets ~~tax~~1,326 $1,309 ~~(73)~~1,966 --------- --------- --------~~-----~~ ~~Net~~Total ~~income~~assets ~~(loss)~~ $ 9105,~~844~~353 $~~(26~~118,~~180)~~543 $ 72114,~~356~~135 ========= ========= ========~~====================================================~~ ~~Shares:~~Current ~~Basic~~liabilities ~~651,205~~$ ~~657~~55,~~707~~736 ~~664,673~~$ ~~Diluted 665~~14,~~471~~149 ~~657,707~~$ ~~664~~14,~~673~~505 ~~==============================================================================~~Long-term ~~Basic~~debt ~~net~~- ~~income~~63,900 ~~(loss)~~51,700 ~~per~~Other ~~common~~liabilities ~~share:~~6,459 ~~Income~~7,953 ~~(loss)~~8,092 ~~from~~Redeemable ~~continuing~~preferred ~~operations~~shares ~~before~~37,785 ~~extraordinary~~34,925 ~~items~~34,287 $Members' ~~15.23~~equity $ (~~39.80~~deficit) $14,674 ~~(15.34)~~2,262 ~~Discontinued~~1,764 ~~operations~~Accumulated -other -comprehensive ~~124.20~~(loss) ~~Change~~income ~~in accounting principle~~(9,301) ~~net of tax~~ (~~0.11~~4,646) -3,787 - -------- --------- --------~~-----------------------------------------------------~~ ~~Basic~~Total ~~net~~liabilities ~~income~~and ~~(loss)~~equity ~~per common share~~ $105,353 ~~15.12~~ $118,543 ~~(39.80)~~ $114,135 ~~108.86~~ ========= ========= ========~~====================================================~~ ~~Diluted~~Net ~~net~~sales ~~income (loss) per common share: Income (loss) from continuing operations before extraordinary items~~ $ ~~14.90~~42,181 $ ~~(39.80)~~38,002 $ ~~(15.34)~~44,173 ~~Discontinued~~Operating ~~operations~~income -18,892 -13,872 ~~124.20 Change in accounting principle~~16,737 ~~net~~Net ~~of tax (0.11) - - ------------------------------------------------------------------------------ Diluted net~~ income ~~(loss) per common share~~ $ ~~14.79~~17,112 $ ~~(39.80)~~4,782 $ 108.86 ============================================================================== For fiscal years 2002 and 2001 the effect of stock options was not included in the computation of diluted net loss per share because to do so would have been antidilutive.10,259

The Company owned working interest in certain oil and gas properties and an interest in a drilling rig with BECLP. The Company completed the sale of its' interest in these properties to BECLP for $2.5 million as of September 2004 with an effective date of June 30, 2004. As of June 30, 2004, the Company has recognized impairment for these assets of $2.0 million and has reclassified $2.5 million in property assets as assets held for sale which is included in other current assets. 11. OPERATING LEASES The Company has noncancelable operating lease agreements for the rental of office space, computers and other equipment. Certain of these leases contain purchase options or renewal clauses. Rental expense for operating leases was approximately $1.1 million for the year ended June 30, 2004 and $1.4 million for each of the years ended June 30, 2003 and 2002. At June 30, 2004 future minimum lease payments for each of the next five years and thereafter are as follows (in thousands): 2005 $1,131 2006 497 2007 386 2008 370 2009 307 Thereafter 543 ------ $3,234 ====== 45 12. RELATED PARTY TRANSACTIONS The Company has entered into a rental arrangement for office space from a corporation in which certain officers are shareholders. Rent payments totaled $0.56 million for each of the years ended June 30, 2004, 2003 and 2002. The Company sold its' Royalty Trust units to a Foundation controlled by a director of the Company, at the then fair market value in December 2003. The Company acquired interests in various Petroleum Exploration Permits in New Zealand during the year ended June 30, 2003 from an entity controlled by a former officer of the Company for approximately $300,000. The Company advanced funds to certain officers and other related parties, at 7% to 8% interest. Balances totaled $0.2 million at June 30, 2004 and $0.3 million at June 30, 2003. A provision in the agreements cancels the principal balance if the employee remains in the continuous employment of the Company for three to four years, depending on the agreement. In 1998, the Company issued promissory notes to certain employees as part of a Class A incentive stock purchase agreement, whereby 13,669 shares were issued at $75 per share. The carrying value of these notes was minimal at June 30, 2004 and $0.1 million at June 30, 2003. The notes have interest rates of 6.5% and 8%. A provision in the agreements cancels the principal balance over a period of four years if the employee remains in the continuous employment of the Company through December 31, 2005. Between 1995 and 1997, the Company issued 4,800 shares of common stock as part of an incentive stock option agreement with two officers for promissory notes. The carrying value of these notes was $0.2 million at June 30, 2004 and 2003. Interest rates are calculated at LIBOR plus 1.5%. No cancellation provision was included with this stock incentive program. During fiscal 1999, the Company purchased from certain officers and directors, for $2.4 million, volumetric production from wells in New Zealand. Future production, totaling 3.3 million Mcf, otherwise allocable to the officers and directors will be allocated to the Company. The Company has recorded the payment as an investment in oil and gas properties. During fiscal years 2003 and 2002, certain officers and directors representing approximately 74% of the total production, assigned back their interest in these properties for nominal consideration. The remaining book value of this asset at June 30, 2004 is $1.0 million. 13. CONTRACT SETTLEMENTS Effective May 14, 2003, the Company entered into a Settlement Agreement (the "Agreement") with Allegheny Energy ("Allegheny") which mutually resolved all outstanding issues and claims. Under the Agreement, the Company neither received nor paid any cash consideration, but recognized the following revenue and expenses as a result of the settlement for the year ended June 30, 2003: (i) gas sales of $3.1 million was recognized as a result of the termination and release of the Gas Sale and 46 Purchase Agreement ("Gas Contract") dated December 20, 1999 which called for a prepayment by Allegheny and subsequent delivery of gas volumes from the Company to Allegheny and (ii) net other income of $1.4 million was also recorded related to the transaction. 14. COMMITMENTS AND CONTINGENCIES In 1993, the Company sold working interests in certain Appalachian gas properties in connection with the formation of the Eastern American Natural Gas Trust ("Royalty Trust"). A portion of the proceeds from the sale of these interests, representing a term net profits interest, was accounted for as a production payment and is currently classified as other current and long-term liabilities. As of June 30, 2000, the Company determined that due to the rising cost of transporting gas, the total deferred revenue would not be realizable. Therefore, $4.9 million, the amount related to the royalty portion, was impaired and $6.2 million, the amount related to the term portion, was reclassified to other current and long-term liabilities. These amounts are amortized as the associated volumes are sold. The remaining unamortized other current and long-term liabilities are $7.1 and $8.1 million at June 30, 2004 and 2003, respectively. The Company entered into a gas sales contract with AFG Industries, Inc. ("AFG") for the sale of up to 4,000 MMBtu per day from January 1, 2004 through December 31, 2004. AFG is a "Float Glass" plant adjacent to an existing Company pipeline. The sales contract price is based off the NYMEX settlement price for Natural Gas Henry Hub Futures Contracts each month plus an Appalachian Basis component. On November 30, 2001, the Company entered into a natural gas sales contract with Mountaineer Gas Company, doing business as Allegheny Power, to deliver 5,500 Dth per day. Under the pricing terms, the Company will never receive less than $2.75 per Dth plus the Columbia Gas Transmission ("TCO") Appalachia Basis or more than $4.85 per day plus the TCO Appalachia Basis. The contract began on December 1, 2001 and continues through October 31, 2004. The Company is involved in various legal actions and claims arising in the ordinary course of business. Management does not expect these matters to have a material adverse effect on the Company's financial position or results of operations. 15. FINANCIAL INSTRUMENTS The estimated fair values of the Company's financial instruments, as of June 30, have been determined using appropriate market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments. The Company in estimating the fair value of its financial instruments used the following methods and assumptions: Notes Receivable - The notes receivable accrue interest at a fixed rate. ----------------- The carrying value approximates fair value which was estimated using discounted cash flows based on current interest rates for notes with similar credit characteristics and maturities. 47 Long-Term Debt - The Company's subordinated debt is traded publicly. The --------------- market value at the end of the year was used for valuation purposes. The remaining portion of the Company's long-term debt is comprised of revolving lines of credit with variable rates and fixed rate facilities. At June 30, 2004, the fair value of the Company's subordinated debt was $118.5 million and the book value was $126.0 million. At June 30, 2003, the fair value of the Company's subordinated debt was $92.4 million and the book value was $132.1 million. Derivative Financial Instruments - All derivative instruments held by the ---------------------------------- Company are designated as hedges, have high correlation with the underlying exposure and are highly effective in offsetting underlying price movements. Accordingly, gains and losses from changes in derivative fair values are deferred until the underlying transaction occurs. Gains or losses are then recognized in the income statement or recorded as part of the underlying assets or liability, depending on the circumstances. Derivative positions are settled if the underlying transaction is no longer expected to occur, with the related gains and losses recognized in earnings in the period settlement occurs. Option premiums paid are recorded as assets and expensed over the life of the option. Derivatives generally have initial terms of less than three years, and all currently hedged transactions are expected to occur within the next three years. See Note 5 for additional information regarding the Company's derivative holdings. 16. INDUSTRY SEGMENTS The Company's reportable business segments have been identified based on the differences in products and service provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. Revenues for the aggregation and pipeline segment arise from the aggregation of both Company and third party produced natural gas volumes and the related transportation. Management utilizes earnings before interest, income taxes, depreciation, depletion, amortization and impairment and exploratory costs ("EBITDAX"), a non-GAAP financial measure, to evaluate each segment's operations. 48 Reconciliation of non-GAAP financial measure is as follows (in thousands):

~~2002~~Twelve ~~2001~~Months ~~2000~~Ended June 30 (in thousands) --------- -------- ------------ ~~Current~~2004 ~~assets~~2003 $2002 ~~6,679 $ 11,336 $10,744 Oil and gas properties 110,555 100,833 84,050 Other assets 1,309 1,966 3,233~~ --------- -------- --------- ~~Total~~Net ~~assets~~income (loss) $~~118~~ 4,~~543~~295 $~~114~~ 9,~~135~~844 $98(26,~~027~~180) ~~=========~~Add: ~~========~~Interest ~~========~~expense ~~Current~~15,069 ~~liabilities~~16,383 ~~$ 14~~19,~~149~~671 $Depletion 14and depreciation of oil and gas properties 13,~~505~~300 $12,~~955~~140 ~~Long-term~~12,362 ~~debt~~Depreciation ~~63,900~~of 51pipelines,~~700~~ ~~54,200~~other ~~Other~~property ~~liabilities~~and 7equipment 4,~~953~~190 84,~~092~~294 12,~~433~~934 ~~Redeemable~~Exploration ~~preferred~~and ~~shares~~impairment 3410,~~925~~796 3411,~~287~~729 3327,~~650~~693 ~~Members'~~Income ~~equity~~tax expense (~~deficit~~benefit) 2(4,~~262~~722) 16,~~764~~073 (416,~~211~~822) ~~Accumulated~~Subtract: ~~other~~Change ~~comprehensive~~in ~~(loss)~~accounting ~~income~~principle, net of tax - (~~4,646~~73) ~~3,787~~ - --------- -------- --------- ~~Total~~EBITDAX ~~liabilities and equity~~ $~~118~~42,~~543~~928 $~~114~~60,~~135~~536 $~~98,027~~ ~~========= ======== ======== Net sales $ 38~~19,~~002~~658 $-------- ~~44,173~~-------- ~~$36,551 Operating income 13,872 16,737 9,338 Net income $ 4,782 $ 10,259 $ 5,267~~---------

49 Summarized financial information for the Company's reportable segments is shown in the following table. The "other" column includes items related to drilling rig operations and corporate items (in thousands):

Exploration Aggregation and and Production Pipeline Other Consolidated ------------- ------------- -------- -------------- 2004 Sales to unaffiliated customers $ ~~909~~62,432 ~~2005~~$ 60,819 $ 122 $ 123,373 Depreciation, depletion, amortization 14,721 630 2,139 17,490 Impairment and exploratory costs 10,780 16 - 10,796 Operating profit 15,381 2,218 (1,~~019~~477) ~~2006~~16,122 ~~402~~Interest ~~2007~~expense, ~~336~~net ~~2008~~22,180 ~~338~~(7,453) ~~Thereafter~~82 ~~690~~14,809 EBITDAX 42,388 2,710 (2,170) 42,928 Total assets 174,540 96,362 19,310 290,212 Capital expenditures 19,012 1,927 971 21,910 ---------------------------------------------------------------------------------------------- 2003 Sales to unaffiliated customers $ 56,907 $ 60,484 $ 35 $ 117,426 Depreciation, depletion, amortization 13,559 661 2,214 16,434 Impairment and exploratory costs 11,729 - - 11,729 Operating profit 1,106 3,922 1,257 6,285 Interest expense, net 21,982 (6,486) 273 15,769 EBITDAX 29,125 4,718 26,694 ~~======~~60,537 Total assets 191,190 88,831 15,812 295,833 Capital expenditures 36,147 241 1,244 37,632 ---------------------------------------------------------------------------------------------- 2002 Sales to unaffiliated customers $ 44,429 $ 41,209 $ 504 $ 86,142 Depreciation, depletion, amortization 13,741 859 696 15,296 Impairment and exploratory costs 26,127 89 1,478 27,694 Operating profit (loss) (22,507) 330 (2,292) (24,469) Interest expense, net 21,238 (6,922) 3,663 17,979 EBITDAX 18,795 1,498 (635) 19,658 Total assets 186,587 78,226 39,923 304,736 Capital expenditures 33,679 145 4,470 38,294 ----------------------------------------------------------------------------------------------

Operating profit represents revenues less costs which are directly associated with such operations. Revenues are priced and accounted for consistently for both unaffiliated and intersegment sales. The 'Other' column includes items related to non-reportable segments, including drilling rig, corporate and elimination items. Included in the exploration and production segment are net long-lived assets located in New Zealand of $7.4 million, $6.1 million and $3.4 million, as of June 30, 2004, 2003 and 2002, respectively and revenues of $0.3 million for the year ended June 30, 2004 with no significant revenue recorded for the years ended June 30, 2003 and June 30, 2002. 50 Revenues from two purchasers of the Company's production during the year ended June 30, 2004 represent $24.1 million and $12.8 million respectively of the Company's consolidated revenues within the Exploration and Production and Gas Aggregation and Pipeline segments. During the year ended June 30, 2003, revenues from three purchasers of the Company's production represented $17.0 million, $16.5 million and $14.6 million respectively of the Company's consolidated revenues within the Exploration and Production and Gas Aggregation and Pipeline segments. 17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following represents selected quarterly financial information for the years ended June 30 (in thousands, except per share data):

~~2003~~Quarter ~~2002~~Ended ~~2001~~ -------- --------- ---------------------------------- ~~Net~~2004 ~~income~~September ~~(loss)~~30 $December ~~9,844~~31 ~~$(26,180)~~March ~~$72,356~~31 ~~Add:~~June ~~Interest~~30 ~~expense~~-------------- ~~16,383~~------------- ~~19,671~~--------- ~~20,094~~--------- ~~Depletion,~~Total ~~depreciation,~~revenue ~~amortization-o&g~~$ 1231,~~140~~041 ~~12,362~~$ 930,~~290~~272 ~~Depletion,~~$ ~~depreciation~~32,204 ~~amortization-other~~$ 429,~~294~~856 ~~2,934~~Gross ~~2,763~~profit ~~Impairment~~(loss) &3,911 ~~exploratory costs 11~~2,~~729~~893 274,~~693~~510 194,~~015~~808 Income ~~tax~~per ~~expense~~share (~~benefit~~a) basic 0.91 (0.53) 6~~,073~~.98 (~~16,822~~0.91) diluted 0.89 (~~7,232~~0.53) ~~Subtract:~~6.88 ~~Change~~(0.91) inNet ~~accounting~~income ~~principle,~~(loss) ~~net~~587 of(348) ~~tax~~4,631 (73575) -Quarter Ended --------------------------------------------------- ~~Discontinued~~2003 ~~operations~~September -30 -December ~~82,555~~31 March 31 June 30 -------------- ------------- --------- ~~EBITDAX~~--------- Total revenue $60 22,~~536~~589 $ 1926,~~658~~383 $33 34,~~731~~038 ~~========~~$ ~~=========~~34,416 ~~========~~Gross profit (loss) 448 (1,735) 3,506 4,066 Income (loss) before change in accounting principle (1,562) 8,320 3,347 (188) Income per share basic (2.43) 12.77 5.15 (0.38) diluted (2.43) 12.49 5.04 (0.38) Net income (loss) (1,562) 8,320 3,347 (261)

18. SUBSEQUENT EVENT As previously reported, the Company had been in litigation with certain Holders of its $200,000,000 9 1/2% Senior Subordinated Notes due 2007 (the "Noteholders") (the "Notes"). The dispute involved the calculation of the Net Proceeds of an Asset Sale as defined in the Indenture dated May 23, 1997 between the Company and The Bank of New York. The Company and the Noteholders have settled the dispute, as memorialized in the Settlement Agreement executed as of February 24, 2004, and attached to the Form 8-K filed by the Company on February 24, 2004 as Exhibit 99.11 (the "Settlement Agreement"). In settlement of the dispute the Company agreed to repurchase $38 million in Notes. The Company met its obligations under the Settlement Agreement having finalized the first Asset Sale Offer (as defined under the Indenture) in the amount of $4 million on March 24, 2004 and the second Asset Sale Offer in the amount of $34 million, at face value, on July 29, 51 2004. The United States District Court for the Southern District of West Virginia has entered a Dismissal Order dismissing the litigation with prejudice. At June 30, 2004, the Company classified $34 million of the Notes that was paid on July 29, 2004 as long term debt as a result of having an amended and restated credit agreement in place that allowed the Company to refinance the debt on a long term basis. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Costs - The following tables set forth capitalized costs and costs incurred, ----- including capitalized overhead, for oil and gas producing activities for the years ended June 30 (in thousands):

~~Exploration~~2004 ~~Marketing~~2003 ~~and~~2002 ~~and Production Pipeline Other Consolidated~~ ----------~~---~~ ----------- --------- ~~--------------~~Capitalized ~~2003~~costs: ~~Sales~~Proved toproperties ~~unaffiliated customers~~ $ 56337,~~907~~451 $ 60327,~~484~~958 $ ~~35 $ 117~~310,~~426~~495 ~~Depreciation,~~Unproved ~~depletion,~~properties ~~amortization 13~~8,~~559~~105 ~~661 2~~9,~~214~~946 169,~~434~~653 ~~Impairment and exploratory costs 11,729~~ - - 11,729 Operating profit 1,556 3,922 1,240 6,718 Interest expense, net 21,982 (6,485) 273 15,770 EBITDAX 29,125 4,718 26,693 60,536 Total assets 191,191 88,831 15,812 295,834 Capital expenditures 36,147 241 1,244 37,632 -------- ---------- --------- Total 345,556 337,904 320,148 Less accumulated depletion and depreciation (119,613) (107,233) (97,523) ---------- ---------- ---------~~--------------------------------------~~ ~~2002~~Net ~~Sales~~capitalized tocosts ~~unaffiliated customers~~ $ 44225,~~429~~943 $ 41230,~~209~~671 $222,625 ~~504~~========== $========== ~~86,142~~========= ~~Depreciation,~~Company's ~~depletion,~~share ~~amortization~~of ~~13,741~~equity ~~859~~method ~~696~~investee's ~~15,296~~net ~~Impairment~~capitalized ~~and~~costs ~~exploratory~~(see ~~costs~~Note ~~26,127~~10) 89$ ~~1,478~~- $ 27,~~694~~167 ~~Operating~~$ ~~profit~~23,908 ~~(loss)~~========== ~~(22,775)~~========== ~~279~~========= ~~(2,292)~~Costs ~~(24,788)~~incurred: ~~Interest~~Acquisition ~~expense,~~of ~~net~~proved ~~21,238~~and ~~(6,922)~~unproved ~~3,663~~properties ~~17,979~~$ ~~EBITDAX~~72 ~~18,795~~$ 15,~~498~~879 ~~(635)~~$ ~~19,658~~717 ~~Total~~Development ~~assets~~costs ~~186~~7,~~587~~892 7814,~~226~~105 3910,~~923~~977 ~~304,736~~Exploration ~~Capital~~costs ~~expenditures 33~~10,~~679~~449 ~~145 4~~15,~~470~~292 3820,~~294~~737 ---------- ---------- ---------~~-----------------------------------------------------------------~~ ~~2001~~Total ~~Sales~~costs toincurred ~~unaffiliated customers~~ $ 4518,~~906~~413 $ 8135,~~042~~276 $ 132,~~455~~431 $========== ~~128,403~~========== ~~Intersegment~~========= ~~revenues~~Company's ~~1,548~~share -of -equity ~~1,548~~method ~~Depreciation,~~investee's ~~depletion,~~total ~~amortization 10,653 973 427 12,053 Impairment and exploratory~~ costs ~~11,458~~incurred ~~287~~(see ~~7,269~~Note ~~19,014 Operating profit (loss~~10) ~~(3,595)~~$ ~~41 168 (~~3,~~386)~~329 ~~Interest~~$ ~~expense~~7,674 ~~net~~$ 132,~~521~~309 ~~(5,355)~~========== ~~4,237~~========== 12,403 EBITDAX 19,759 1,316 12,656 33,731 Total assets 201,111 77,977 101,444 380,532 Capital expenditures 108,343 1,315 3,205 112,863 ----------------------------------------------------------------------------------------------=========

52 Results of Operations - The results of operations for oil and gas producing ----------------------- activities, excluding corporate overhead and interest costs for the years ended June 30 are as follows (in thousands):

~~Quarter~~2004 ~~Ended -----------------------------------------------------~~ 2003 ~~September~~2002 ~~30 December 31 March 31 June 30~~ -------~~--------~~ -------~~------~~ ---------- ~~---------~~Revenues ~~Total~~from ~~revenue~~sale $of ~~22,589~~oil $and ~~26,383~~gas $ 3457,~~038~~203 $51,410 34$38,~~416~~939 ~~Gross~~Less: ~~profit~~Production ~~(loss)~~costs ~~677~~6,454 (14,~~720)~~436 35,~~456~~001 Production taxes 4,~~305~~143 ~~Income~~3,233 ~~(loss)~~2,077 ~~from~~Exploration ~~continuing~~and ~~operations~~impairment (19,~~562)~~578 811,~~320~~729 327,~~348~~605 ~~(188)~~Depletion, ~~Income~~depreciation ~~(loss)~~and ~~per~~amortization ~~share on continuing operations~~13,300 ~~basic (2.43)~~ 12~~.77~~,140 ~~5.15 (0.38) diluted (2.37)~~ 12~~.49~~,362 ~~5.04~~Income ~~(0.37)~~tax ~~Net~~expense ~~income~~ (~~loss~~benefit) (19,~~562)~~432 87,~~320~~353 ~~3,347~~ (~~261~~2,999) ~~Quarter Ended~~ -------~~----------------------------------------------~~ ~~2002 September 30 December 31 March 31 June 30~~ -------~~--------~~ --------~~-----~~ ~~----------~~Income ~~---------~~(loss) ~~Total~~from ~~revenue~~oil $and ~~23,394~~gas $operations 21$14,~~157~~296 $ 1812,~~573~~519 $ 23(5,~~018~~107) ~~Gross~~======= ~~profit~~======= ~~(loss)~~======== ~~1,943~~Company's ~~1,119~~share ~~(3,585)~~of ~~(24,265)~~equity *method ~~Loss~~investee's ~~per~~income ~~share,~~from ~~basic~~oil and ~~diluted~~gas ~~(2.31)~~operations (~~3.17)~~see ~~(8.15)~~Note ~~(26.17~~10) ~~Net~~$ ~~loss (1~~5,~~517)~~846 ~~(2,086)~~$ (54,~~358)~~354 ~~(17~~$ 4,~~219)~~955 ======= ======= ========

Production costs include those costs incurred to operate and maintain productive wells and related equipment and include costs such as labor, repairs and maintenance, materials, supplies, fuel consumed and insurance. Production costs are net of well tending fees, which are included in well operations revenues in the accompanying consolidated statements of operations. Exploration and impairment expenses include the costs of geological and geophysical activity, unsuccessful exploratory wells and leasehold impairment allowances. Depletion, depreciation and amortization include costs associated with capitalized acquisitions, exploration and development costs. The provision for income taxes is computed at the statutory federal income tax rate and is reduced to the extent of permanent differences which have been recognized in the Company's tax provision, such as investment tax credits, and the utilization of Federal tax credits permitted for fuel produced from a non-conventional source. Reserve Quantity Information - Reserve estimates are subject to numerous ------------------------------ uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates, by their nature, are generally less precise than other financial statement disclosures. 53 The following table sets forth information for the years indicated with respect to changes in the Company's proved reserves, substantially all of which are in the United States.

~~2003~~Natural ~~2002~~Gas ~~2001~~Crude Oil (Mmcf) (Mbbls) ---------- --~~-------~~ ---------- ~~Capitalized~~Proved ~~costs~~reserves: ~~Proved~~June ~~properties~~30, $2001 ~~327~~206,~~958~~456 ~~$310~~2,~~495~~633 ~~$271~~Revisions of previous estimates (23,~~465~~812) ~~Unproved~~74 ~~properties~~Extensions 9and discoveries 10,~~946~~642 368 Purchases of reserves in place - - Production (9,~~653~~941) ~~45,760~~(124) ---------- --~~-------~~ ---------- ~~Total~~June ~~337~~30,~~904~~ ~~320~~2002 183,~~148~~345 ~~317~~2,~~225~~951 ~~Less~~Revisions ~~accumulated~~of ~~depletion~~previous estimates (11,847) (964) Extensions and ~~depreciation~~discoveries 23,623 580 Sales of reserves in place (~~107~~2,~~233~~941) (~~97,523~~16) Purchases of reserves in place 8,371 - Production (859,~~748~~755) (185) ---------- --~~-------~~ ---------- ~~Net~~June ~~capitalized~~30, ~~costs~~2003 ~~$ 230~~190,~~671~~796 ~~$222~~2,~~625~~366 ~~$231,477~~ ========== ==~~=======~~ ========== ~~Company's~~Revisions ~~share~~ of ~~equity~~previous ~~method~~estimates ~~investee's~~9,309 ~~net capitalized costs~~ (~~see Note 11~~252) *Extensions $and ~~27,167~~discoveries ~~$ 23~~28,~~908~~732 $176 ~~19,729~~Sales ~~========== ========= ========= Costs incurred: Acquisition~~ of ~~proved~~reserves ~~and~~in ~~unproved~~place ~~properties~~(2,644) $(903) ~~5,879~~Purchases $of ~~717~~reserves $in ~~80,394~~place ~~Development~~- ~~costs~~- ~~14,105~~Production (10,~~977~~718) ~~13,649~~(107) ~~Exploration costs 15,292 20,737 15,115~~ ---------- --~~-------~~ ---------- ~~Total~~June ~~costs incurred $ 35~~30,~~276~~ $2004 32215,~~431~~475 ~~$109~~1,~~158~~280 ========== ==~~=======~~ ========== Proved developed reserves: June 30, 2002 160,224 1,135 June 30, 2003 161,796 1,064 June 30, 2004 170,131 626 Company's share of equity method investee's ~~total~~proved ~~costs~~reserve ~~incurred~~at: ~~(see~~June ~~Note~~30, ~~11)~~2002 *7,445 $12,063 7June 30,~~674~~ $2003 27,~~309~~755 $11,427 2June 30,~~695~~ ~~==========~~2004 ~~=========~~(See ~~=========~~Note 10) - -

Standardized Measure of Discounted Future Net Cash Flows - Estimated discounted --------------------------------------------------------- future net cash flows and changes therein were determined in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying period-end prices of oil and gas relating to the Company's proved reserves to the period-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at period-end. 54 The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates and existing tax credits, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Company's proved oil and gas reserves. An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Information with respect to the Company's estimated discounted future net cash flows related to its proved oil and gas reserves as of June 30 is as follows (in thousands):

2004 2003 2002 ~~2001~~ ----------- ----------- ---------- ~~Revenues~~Future ~~from~~cash ~~sale~~in offlows ~~oil and gas~~ $511,~~410~~429,645 $381,~~939~~152,845 $41 715,~~555~~755 ~~Less:~~Future ~~Production~~production and development costs 4(355,~~436~~438) 5(235,~~001~~960) 3(243,~~011~~828) ~~Production~~Future ~~taxes~~income 3tax expense (308,~~233~~000) 2(290,~~077~~000) 3(116,000) ~~Exploration~~----------- ~~and~~----------- ~~impairment~~---------- ~~11,729~~Future ~~27,605~~net ~~11,458~~cash ~~Depletion,~~flows ~~depreciation~~before ~~and~~discount ~~amortization 12~~766,~~140~~207 12626,~~362~~885 9355,~~290~~927 ~~Income~~10% ~~tax~~discount ~~expense~~to present value (~~benefit~~455,663) 7(365,~~353~~662) (2205,~~999~~014) ~~5,475~~ ----------- ----------- ---------- ~~Income~~Standardized ~~(loss)~~measure ~~from~~of discounted future net cash flows related to proved oil and gas ~~operations~~reserves $12 310,~~519~~544 $(5 261,~~107)~~223 $ 9150,~~321~~913 =========== =========== ========== Company's share of equity method investee's ~~income~~standardized ~~from~~measure ~~oil~~of ~~and~~discounted ~~gas~~future ~~operations~~net cash flows (~~see~~See Note 1110) * $ ~~4,354~~- $ 467,~~955~~375 $ 353,~~224~~838 =========== =========== ==========

55 Principal changes in the standardized measure of discounted future net cash flow for the years ended June 30 are as follows (in thousands):

~~Natural~~2004 ~~Gas~~2003 ~~Crude~~2002 ~~Oil (Mmcf) (Mbbls)~~ --------- --- ------ --------- ~~Proved~~Standardized ~~reserves:~~measure ~~June~~of ~~30,~~discounted ~~2000~~future ~~157,490~~net ~~983~~cash ~~Revisions~~flows at beginning of ~~previous~~period ~~estimates~~$261,223 ~~(13~~$150,~~405)~~913 ~~(99)~~$172,281 ~~Extensions~~Sales of oil and ~~discoveries~~gas 22produced,~~077~~ ~~1,380~~net ~~Purchases~~ of ~~reserves~~production incosts ~~place 49~~(41,~~665~~724) ~~485 Production~~ (935,~~371~~155) (~~116~~26,525) ~~------------~~Net ~~----------~~changes ~~June~~in ~~30,~~prices ~~2001~~and ~~206~~production costs 21,~~456~~120 2175,~~633~~844 ~~Revisions~~(13,507) ofChanges ~~previous~~in ~~estimates~~production rates and other (2316,~~812~~394) 74(5,484) (5,867) Extensions, discoveries and ~~discoveries~~other 10additions,~~642~~ ~~368~~net ~~Purchases~~ of ~~reserves~~future production and development costs 60,609 52,407 13,622 Changes in ~~place~~estimated -future -development ~~Production~~costs (918,~~941~~826) (~~124~~16,243) ~~------------~~(4,820) ~~----------~~Development ~~June~~costs 30incurred 7,892 ~~2002 183~~14,~~345~~105 210,~~951~~977 Revisions of previous quantity estimates 15,866 (1134,~~847~~089) (124,~~045~~772) ~~Extensions~~Purchase ~~and discoveries 23,623 580 Sales~~ of reserves in place ~~(2,941)~~- (16),185 ~~Purchases~~- Accretion of ~~reserves~~discount in28,073 ~~place~~15,246 817,~~371~~228 -Net ~~Production~~change in income taxes (97,~~755~~295) (~~104~~72,506) 12,296 --------- --- ------ --------- ~~June~~Standardized ~~30,~~measure ~~2003~~of ~~190~~discounted future net cash flows at end of period $310,~~796~~544 2$261,~~366~~223 $150,913 ========= === ====== ==== Proved developed reserves: June 30, 2001 175,784 987 June 30, 2002 160,224 1,135 June 30, 2003 161,796 1,064 Company's share of equity method investee's proved reserve at: June 30, 2001 9,497 11,811 June 30, 2002 7,445 12,063 June 30, 2003 7,755 11,427=====

* * * * * 56 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ----------------------------------------------------- ON ACCOUNTING AND FINANCIAL DISCLOSURE -------------------------------------- There have been no changes in or disagreements with accountants on accounting and financial disclosure. ITEM 9A. CONTROLS AND PROCEDURES --------------------------------- Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the Company has evaluated the effectiveness of the design and operation of our disclosure controls and procedures within 90 days of the filing date of this annual report and, based on their evaluation, our principal executive officer and principal financial officer have concluded that these controls and procedures are effective. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. Disclosure controls and procedures are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Securities Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. PART III -------- ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT --------------------------------------------- The executive officers and Directors of the Company and the executive officers of its subsidiaries on June 30, 2004 are listed below, together with a description of their experience and certain other information. All of the Directors were elected or re-elected for a one year term at the Company's December 2003 annual meeting of stockholders. Executive officers are appointed by the Board of Directors.

~~2003~~Name ~~2002~~Position ~~2001~~with Company or Subsidiary ----------- ------------ ---------- ~~Future cash in flows $1,152,845 $ 715,755 $ 828,403 Future production and development costs (235,960) (243,828) (271,051) Future income tax expense (290,000) (116,000) (145,000)~~ ----------- ---------- ---------------------- ~~Future~~John ~~net~~Mork ~~cash~~56 ~~flows~~President ~~before~~and ~~discount~~Chief ~~626,885~~Executive ~~355,927~~Officer; ~~412,352~~Director ~~10%~~Joseph ~~discount~~E. toCasabona ~~present~~60 ~~value~~Executive ~~(365,662)~~Vice ~~(205,014)~~President; ~~(240,071)~~Director ~~-----------~~Michael ~~----------~~S. ~~----------~~Fletcher ~~Standardized~~55 ~~measure~~Chief ofFinancial ~~discounted~~Officer ~~future~~Donald ~~net~~C. ~~cash~~Supcoe ~~flows~~48 ~~related~~Senior toVice ~~proved~~President, ~~oil~~Secretary and ~~gas~~General ~~reserves~~Counsel $J. ~~261~~Michael Forbes 44 Vice President and Treasurer George V. O'Malley 52 Vice President Accounting K. Ralph Ranson,~~223~~ $II ~~150~~61 Vice President Marketing C. Clark Clement,~~913~~ $Jr. ~~172~~55 Vice President Western Operations Julie Ann Kitano 47 Assistant Secretary W. Gaston Caperton,~~281~~ ~~===========~~III ~~==========~~63 ~~==========~~Director ~~Company's~~Peter ~~share~~H. ofCoors ~~equity~~56 ~~method~~Director ~~investee's~~L. ~~standardized~~B. ~~measure~~Curtis of79 ~~discounted~~Director ~~future~~(Chairman) ~~net~~John ~~cash~~J. ~~flows~~Dorgan $79 67Director F. H. McCullough,~~375~~ $III 56 Director Julie Mork 53~~,838~~ $Director 69Arthur C. Nielsen,~~478~~ ~~===========~~Jr. ~~==========~~84 ~~==========~~Director Jay S. Pifer 67 Director

57 W. Gaston Caperton, III has been a Director of the Company since 1997. He served as the Governor of the State of West Virginia for two terms, from 1989 to 1997. Governor Caperton is President and Chief Executive Officer of The College Board and President of the Caperton Group. Governor Caperton presently serves on the Board of Directors of Owens Corning, United Bankshares, West Virginia Media Holdings, the Benedum Foundation, National Center for Learning Disabilities, Classroom, Inc. and Prudential Financial. Joseph E. Casabona is Executive Vice President of the Company and has been a Director since its formation. Mr. Casabona joined Eastern American in 1985 and was Executive Vice President of Eastern American and a Director from 1987 until 1993. Mr. Casabona was employed from 1967 to 1979 in the Pittsburgh, Pennsylvania office of KPMG Main Hurdman ("KPMG, Peat Marwick"), Certified Public Accountants, became a partner in the Firm in 1980 and was named Director of Accounting and Auditing of the Pittsburgh office in 1983. Mr. Casabona graduated from the University of Pittsburgh with a Bachelor of Science Degree in Business Administration and from the Colorado School of Mines with a Master of Science Degree in Mineral Economics. He has been a Certified Public Accountant since 1969. Mr. Casabona serves on the Board of Directors of Gonex, Inc. and has been a member of the Board of Directors of the West Virginia and Pennsylvania Independent Oil and Gas Associations. Clark Clement has been Vice-President of Western Operations since 2003 and is responsible for the Company's operations in the west, including New Zealand. Mr. Clement has thirty-four years of experience in the oil industry including positions with major service companies, independents, and a major oil company. Prior to joining the Company in 2001, he held positions with BP as Drilling Team Leader in the Mid-Continent Asset of the U.S. and Well Engineering and Operations Superintendent in Colombia, South America. Mr. Clement holds a Bachelor of Science Degree in Chemistry from New Mexico Highlands University and is a Registered Professional Engineer in Petroleum Engineering. He has written over fifty technical papers, holds five U.S. patents, several foreign patents, and is a member of the Society of Petroleum Engineers, American Petroleum Institute, American Association for Drilling Engineers and Oilfield Helping Hands. Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is Chairman of Coors Brewing Company and Chairman of Adolph Coors Company. He received his Bachelor Degree in Industrial Engineering from Cornell University in 1969 and he earned his Master Degree in Business Administration from the University of Denver in 1970. Mr. Coors also serves on the Board of Directors of U. S. Bancorp, Inc. and H.J. Heinz Company. Mr. Coors is a trustee and member of the executive board of the Denver Area Council of the Boy Scouts of America and a member of the executive committee for the National Western Stock Show Association. He is also a member of the International Chapter of Young Presidents' Organization, a member of the Board of University of Colorado Hospital, and a trustee for the Adolph Coors Foundation, Castle Rock Foundation and Seeds of Hope Foundation. L.B. Curtis has been a Director of the Company since 1993 and Chairman since 1998. Mr. Curtis was a Director of Eastern American from 1988 until 1993. Mr. Curtis is retired from a career at Conoco, Inc. where he held the position of Vice President of Production Engineering with Conoco Worldwide. Mr. Curtis was highly recognized across the Petroleum Industry in the upstream (exploration and production) segment of the industry. Mr. Curtis graduated from The Colorado School of Mines with an Engineer of Petroleum Professional Degree. John J. Dorgan has been a Director of the Company since 1993. He served as a Director for Eastern American in 1992. He is a former Executive Vice President and consultant to Occidental Petroleum Corporation where he had worked in various capacities starting in 1972. 58 Michael S. Fletcher has been Chief Financial Officer of the Company since December, 1999. He also held the position of Treasurer of the Company from December, 1999 through December, 2000. In addition, Mr. Fletcher was President of Mountaineer Gas Company from 1998 until the Company sold Mountaineer in August of 2000. Prior to becoming President in 1998, he held the positions of Senior Vice President and Chief Financial Officer of Mountaineer. Before joining Mountaineer in 1987, Mr. Fletcher was a partner of Arthur Andersen and Company and was employed by that firm for fifteen years. Mr. Fletcher is a Certified Public Accountant and a graduate from Utah State University with a Bachelor Degree in Accounting. J. Michael Forbes is Vice President and Treasurer of the Company. Mr. Forbes has been an officer of the Company since 1995 and prior to that was an officer with Eastern American, which he joined in 1982. Mr. Forbes graduated with a Bachelor of Arts in Accounting and Finance from Glenville State College and is a Certified Public Accountant. He also holds a Master of Business Administration from Marshall University and is a graduate of Stanford University's Program for Chief Financial Officers. Julie Ann Kitano has been Assistant Secretary of the Company since December, 2000. Ms. Kitano joined the Company in 1998 as a Paralegal. She holds a Bachelor of Arts Degree from Whitman College. F. H. McCullough, III has been a Director of the Company since 1993. Mr. McCullough was a Director of Eastern American from 1978 until 1993. Mr. McCullough joined Eastern American in 1977 and served in various capacities until 1999. Mr. McCullough is a graduate of the University of Southern California with a Bachelor of Arts Degree in International Economics and two Masters Degrees in Business Administration and Financial Systems Management. He is a graduate of the Northwestern University Kellogg Graduate School of Management Executive Marketing Program. John Mork has been President and Chief Executive Officer of the Company and a Director of the Company since its formation. Mr. Mork served in various capacities at Union Oil Company until 1972 when he joined Pacific States Gas and Oil, Inc. and subsequently founded Eastern American. Mr. Mork was President and a Director of Eastern American from 1973 until 1993. Mr. Mork is a past Director of the Independent Petroleum Association of America, and the Independent Oil and Gas Association of West Virginia. Mr. Mork was a member of and held various positions with the Young Presidents' Organization from 1984-1998. He also founded the Mountain State Chapter of the Young Presidents' Organization located in Charleston, West Virginia. He is currently a member of the Chief Executives Organization, the World President's Organization, the University of Southern California Engineering School Board of Councilors and a Trustee of the Denver Museum of Nature and Science. Mr. Mork holds a Bachelor of Science Degree in Petroleum Engineering from the University of Southern California and he is a graduate of the Stanford Business School Program for Chief Executive Officers. He is the husband of Julie Mork. Julie M. Mork has been a Director of the Company since 1993. She was a Director of Eastern American from 1974 until 1993. Mrs. Mork served as a founder and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern American. She is currently Managing Director of the ECA Foundation, Inc. Mrs. Mork received a Bachelor of Arts Degree in History from the University of California in Los Angeles. She is the wife of John Mork. George V. O'Malley has been Vice President of Accounting for the Company since December 2002. Before being elected Vice President, Mr. O'Malley served as Director of Accounting. Mr. O'Malley joined Eastern American in April 1991 and served in various capacities including Vice President and Treasurer. Prior to joining the Company, he held various positions in industry and public accounting. Mr. O'Malley currently serves as President of the West Virginia Society of CPA's and as a member of the Board of the Independent Oil and Gas 59 Association of West Virginia. Mr. O'Malley graduated from Marshall University with a Bachelor's Degree in Accounting and is a Certified Public Accountant. Arthur C. Nielsen, Jr. Chairman Emeritus of A.C. Nielsen Co., has been a Director of the Company since 1993. He was a Director of Eastern American from 1985 until 1993. He serves on the Board of Directors of General Binding Corporation. Jay S. Pifer has been a Director of the Company since 2003. Mr. Pifer recently retired as Chief Operating Officer of Allegheny Energy with over forty years of service, where he was responsible for managing over 12,000 megawatts of generating facilities and providing electric and gas service to over four million people in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. Mr. Pifer graduated from Clarion University and Penn State University where he received the Outstanding Engineering Alumni Award and the Alumni Fellow Award. Mr. Pifer serves on the boards of numerous community organizations. K. Ralph Ranson, II has been Vice President of Marketing and Land for the Company since December, 2000. He joined Eastern American in 1993 and has served in various capacities, most recently as Vice President of Land. Prior to joining Eastern American, Mr. Ranson worked as an independent oil and gas consultant, was an officer with Alamco, Inc. and an officer and director of Union Drilling, Inc. Mr. Ranson is past President of the Independent Oil & Gas Association of West Virginia, where he served two consecutive terms. Mr. Ranson received a Bachelor of Arts Degree from West Virginia Wesleyan College. Donald C. Supcoe is the Senior Vice President, Corporate Secretary and General Counsel of the Company and is responsible for the Company's operations in the east, which includes Eastern American. Mr. Supcoe was the Senior Vice President of Mountaineer Gas Company from 1998 until its sale in August of 2000. Prior to joining Mountaineer in 1998, he was the Vice President, General Counsel and Corporate Secretary of Eastern American with whom he had been employed in various positions since 1981. Mr. Supcoe is a past President of the Independent Oil and Gas Association of West Virginia and a past Vice President of the Independent Petroleum Association of America. Mr. Supcoe graduated from West Virginia University with a Bachelor of Science Degree in Business Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree from West Virginia University College of Law. 60 ITEM 11. EXECUTIVE COMPENSATION ------------------------------- The following table sets forth for fiscal year 2004 the total value of compensation of (i) the Company's Chief Executive Officer and (ii) each other executive officer of the Company.

~~2003~~Annual ~~2002~~Compensation ~~2001~~------------------------ All Other Year Salary Bonus Other Compensation (1) ---- -------- -------- ------- ---------------- ~~Standardized~~John ~~measure~~Mork of2004 ~~discounted~~$315,166 ~~future~~$372,880 ~~net~~(2) ~~cash~~$49,864 ~~flows~~$8,873 atPresident ~~beginning~~and ofChief ~~period~~Executive Officer 2003 265,376 125,000 77,045 5,867 2002 258,892 125,000 59,670 26,067 Joseph E. Casabona 2004 $~~150~~250,~~913~~919 $~~172~~259,~~281~~755 (3) $~~124~~19,~~871~~128 ~~Sales~~$5,803 ofExecutive ~~oil~~Vice ~~and~~President ~~gas~~2003 ~~produced~~243,595 ~~net~~80,000 of6,875 ~~production~~4,763 ~~costs~~2002 ~~(35~~238,~~155)~~277 ~~(26~~125,~~525)~~942 ~~(28~~2,~~347~~905 4,574 Michael S. Fletcher 2004 $244,536 $842,040 (4) ~~Net~~$20,275 ~~changes~~$6,077 inChief ~~prices~~Financial ~~and~~Officer ~~production~~2003 ~~costs~~238,504 ~~175~~45,~~844~~000 ~~(13~~2,~~507)~~477 34,~~338~~558 ~~Changes~~2002 in233,306 ~~production~~100,510 ~~rates~~352 ~~and~~4,504 ~~other~~Edward 1J. Davies 2004 $245,~~015~~434 $135,000 (5~~,867~~) 15$ - $6,~~526~~514 ~~Extensions~~Senior Vice President 2003 230,201 ~~discoveries~~45,000 ~~and~~408 ~~other~~6,113 ~~additions~~2002 223,930 ~~net~~95,714 of120 ~~future~~4,592 ~~production~~Donald ~~and~~C. ~~development~~Supcoe ~~costs~~2004 52$208,~~407~~919 $569,530 (6) $13,~~622~~111 33$4,~~991~~433 ~~Changes~~Senior inVice ~~estimated~~President ~~future~~2003 ~~development~~201,152 ~~costs~~65,000 ~~(16~~3,~~243)~~529 (4,~~820)~~005 ~~(31~~2002 197,~~981~~993 100,435 2,325 3,949 _______________________________ (1) ~~Development~~Includes ~~costs~~compensation ~~incurred~~related ~~14,105~~to ~~10,977~~insurance ~~9,232~~policies ~~Revisions~~provided for the benefit of ~~previous~~named ~~quantity~~officer ~~estimates~~and 401K matching contributions. (~~35,028~~2) ~~(24~~Includes stock based award of $22,~~772)~~880. (~~15,677~~3) ~~Purchase~~Includes ofstock ~~reserves~~based inaward ~~place~~of 16$22,~~185~~880 ~~58,868~~and ~~Sale~~Class ofA ~~reserves~~stock innote ~~place~~forgiveness (5of $46,~~560~~875. (4) ~~Accretion~~Includes ofClass ~~discount~~A ~~15,246~~stock 17note forgiveness of $46,~~228~~875, 12employment contract stock of $338,~~487~~910 ~~Net~~and ~~change~~employment incontract ~~income~~note ~~taxes~~forgiveness ~~(72,506)~~of 12$286,~~296~~255. (~~10,027~~5) ~~---------~~Mr. ~~---------~~Davies ~~---------~~left ~~Standardized~~the ~~measure~~Company as of ~~discounted~~June ~~future~~22, ~~net~~2004. ~~cash~~(6) ~~flows~~Includes atClass ~~end~~A ofstock ~~period~~note ~~$261,223~~forgiveness of $~~150~~28,~~913~~131, employment contract stock of $~~172~~201,~~281~~344 ~~=========~~and ~~=========~~employment ~~=========~~contract note forgiveness of $170,055.

DIRECTOR COMPENSATION. Directors are compensated $2,000 per meeting plus ---------------------- reimbursement for travel and related expenses. The Chairman of the Board receives an additional $50,000. Each Director also receives 160 shares of the Company's Class A Stock. The total Board of Directors' compensation for fiscal 2004 was $0.1 million. 61 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ------------------------------------------------------------------------ The following table sets forth certain information regarding (i) the share ownership of the Company by each person known to the Company to be the beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii) the share ownership of the Company by each Director, (iii) the share ownership of the Company by certain executive officers and (iv) the share ownership of the Company by all directors and executive officers as a group, in each case as of September 23, 2004. 62 The business address of each officer and director listed below is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100, Denver, Colorado 80237. Beneficial Ownership Common Stock ---------------------- Shares Percent ---------- ---------- W. Gaston Caperton, III 6,930 1.15% Joseph E. Casabona 31,376 5.21% Colstab & Co. (Nominee for KWB Trust) (1) 35,443 5.88% Peter H. Coors 3,196 * L. B. Curtis 11,210 1.86% John J. Dorgan 4,130 * J. Michael Forbes 2,200 * F. H. McCullough, III (2) 70,035 11.63% John Mork (3) 359,493 59.67% Julie Mork (3) 359,493 59.67% Arthur C. Nielsen, Jr. 36,480 6.06% Donald C. Supcoe 3,583 * ---------- ---------- 564,076 93.63% All officers and directors as a group (11 persons) 528,633 87.75% _______________ * Less than one percent. (1) Pursuant to an Agreement dated December 28, 1998, the Company is required to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's estate or promptly after the passage of two years from Mr. Brill's death if the estate does not sooner tender the shares. The Company entered into a repurchase agreement on January 21, 2004 with the KWB Trust to define the purchase price and establish the conditions for the repurchase of stock owned by the Kenneth W. Brill, estate. The agreement outlines the repurchase of 49,110 shares of stock by the Company or through third parties, at an anticipated value of approximately $3.7 million over the next five years, and provides for payments in twenty quarterly installments on the majority of the shares to be repurchased. The repurchase of shares is subject to certain restrictions in the Company's credit agreements. On June 30, 2004, the Company's remaining repurchase obligation under the Agreement is approximately $2.9 million. Upon adoption of SFAS No. 150, as described in Note 2, $1.4 million of the obligation was reclassified as a liability and the remaining $1.5 million is included in stockholders' equity as third parties have agreed to purchase such amount. (2) Includes 67,955 shares held by F.H. McCullough, III and Kathy McCullough as joint tenants, 880 shares held by the Katherine F. McCullough Trust, and 400 shares held by each of the Lesley McCullough Trust, the Meredith McCullough Trust and the Kristin McCullough Trust. (3) Includes 280,930 shares held by John and Julie Mork as joint tenants, 2,663 shares held by Julie Mork individually, and 37,950 shares held by each of the Alison Mork Trust and the Kyle Mork Trust. 63 The following table sets forth certain information regarding (i) the share ownership of the Company by each person known to the Company to be the beneficial owner of more than 5% of the outstanding shares of Class A Stock, (ii) the share ownership of the Company's Class A Stock by each Director, (iii) the share ownership of the Company's Class A Stock by certain executive officers and (iv) the share ownership of the Company's Class A Stock by all directors and executive officers as a group, in each case as of September 23, 2004. The business address of each officer and director listed below is: c/o Energy Corporation of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237. Beneficial Ownership Class A Stock ---------------------- Shares Percent ---------- ---------- W. Gaston Caperton, III 2,080 4.50% Joseph E. Casabona (2) 3,529 7.64% C. Clark Clement, Jr. (2) 450 * Peter H. Coors 2,750 5.95% L.B. Curtis 1,720 3.72% John J. Dorgan 2,480 5.37% Michael S. Fletcher (2) 4,105 8.89% J. Michael Forbes (2) 750 1.62% F.H. McCullough, III 1,246 2.70% John Mork (1) 5,377 11.64% Julie Mork (1) 5,377 11.64% Arthur C. Nielsen, Jr. 3,240 7.01% George V. O'Malley (2) 420 * K. Ralph Ranson, II (2) 987 2.14% Donald C. Supcoe (2) 3,685 7.98% ---------- ---------- 32,819 71.04% All officers and directors as a group (15 persons) 32,819 71.04% _______________ * Less than one percent. (1) Includes 1,116 shares held by John and Julie Mork as joint tenants and 1,822 shares held by Julie Mork individually and 1,220 shares held by the Alison Mork Trust and 1,219 shares held by the Kyle Mork Trust. (2) Includes shares of Restricted Class A stock. 64 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS -------------------------------------------------------- Certain officers and Directors of the Company and members of their families ("participants") regularly participate in the wells drilled by the Company on an actual costs basis and share in the costs and revenues on the same basis as the Company. The Company has the right to select the wells drilled and each participant is involved in all wells included within a Company drilling program (the "Drilling Program") and cannot selectively choose the wells in which to participate. The following table identifies the participants' aggregate investment in the calendar years shown (in thousands): 2004 2003 2002 ---------- --------- --------- (3) Gaston Caperton, III $ 100.01 $ 58.05 $ 77.58 Joseph E. Casabona 225.06 29.02 38.77 C. Clark Clement 30.00 23.22 - Peter Coors 30.00 78.36 77.58 L.B. Curtis 100.01 78.36 83.36 John J. Dorgan 30.00 17.40 19.39 Michael S. Fletcher 49.50 29.03 38.77 J. Michael Forbes 25.00 14.51 19.39 F.H. McCullough, III 50.00 29.03 - John Mork (1) 825.00 783.65 833.60 Alison Mork Trust (2) 49.50 29.03 38.77 Kyle Mork Trust (2) 49.50 29.03 38.77 Arthur C. Nielsen, Jr. 50.00 29.03 38.77 George O'Malley 33.00 15.67 - K. Ralph Ranson, II 25.00 14.51 - Donald C. Supcoe 25.00 14.51 19.39 ---------- --------- --------- $1,696.58 $1,272.41 $1,324.14 ========== ========= ========= (1) Interest of John Mork and Julie Mork held as joint tenants. (2) Trusts for the children of John Mork and Julie Mork. (3) These amounts represent only the amounts committed to the 2004 Drilling Program, the actual amount of investment may vary based on the number of wells drilled and the related costs. 65 Certain officers, Directors and key employees of the Company have notes payable to the Company related to employee incentive stock options that were granted and exercised. The notes bear various interest rates, ranging from LIBOR to 8% per annum. The Company is amortizing certain of the notes over their seven year life and assuming continued employment. Certain of these notes will be forgiven one-quarter per year, starting January 1, 2003 . The following were indebted to the Company (in thousands): Outstanding Unamortized Balance as of as of June 30, 2004 June 30, 2004 -------------- -------------- Joseph E. Casabona $ 94 $ 14 Michael S. Fletcher 94 14 J. Michael Forbes 96 96 K. Ralph Ranson, II 28 4 Donald C. Supcoe 152 104 -------------- -------------- Total $ 464 $ 232 ============== ============== During fiscal 1999, the Company purchased from certain officers and directors volumetric production from wells in New Zealand. Future production, otherwise allocable to the officers and directors will be allocated to the Company. The following table identifies the participants' interest as of June 30, 2004: Payment Volumes (in thousands) Mmcf --------------- ------- Joseph E. Casabona $ 50 66.7 L.B. Curtis 75 100.0 John J. Dorgan 50 66.7 F.H. McCullough, III 150 200.0 --------------- ------- $ 325 433.4 =============== ======= The Company rents office space in Charleston, West Virginia from Energy Centre, Inc. a corporation owned 54.54% by John Mork, 27.26% by Joseph E. Casabona and 9.10% by each of Donald C. Supcoe and J. Michael Forbes. The aggregate amount paid by the Company for rent to Energy Centre, Inc. was $0.56 million for fiscal year 2004. The Company believes that such rental terms are no less favorable than could have been obtained from an unaffiliated party. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES AUDIT FEES The aggregate fees, including expenses, Deloitte & Touche LLP, the Company's principal accounting firm, billed the Company for each of the last two fiscal years for professional services rendered in connection with the audits of the Company's annual financial statements and review of the Company quarterly interim financial statements were $326,182 for the year ended June 30, 2004 and $416,318 for the year ended June 30, 2003. 66 AUDIT-RELATED FEES Deloitte & Touche LLP did not bill the Company any additional fees in the last two fiscal years for assurance and related services that are reasonably related to the performance of the audit or review of the Company's Financial Statements. TAX FEES The aggregate fees, including expenses, Deloitte & Touche LLP billed the Company for each of the last two fiscal years for tax services related to compliance, advice, or planning was $458,241 for the year ended June 30, 2004 and $678,365 for the year ended June 30, 2003. ALL OTHER FEES Deloitte & Touche LLP did not bill the Company any additional fees in the last two fiscal years for products and services provided by Deloitte & Touche LLP, other than the services reported above. PRE-APPROVAL POLICIES The Company does not have an audit committee or body performing a similar function. Pre-approval of all services performed by Deloitte & Touche LLP and approval of the related fees is granted by a member or representative of the Board of Directors of the Company. 67 PART IV ------- ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES -------------------------------------------------- AND REPORTS ON FORM 8-K ------------------------

~~Name~~(a) ~~Position~~1 ~~with~~Financial ~~Company~~Statements The Financial Statements are filed as a part of this annual report at Item 8. 2 Financial Statement Schedules The Financial Statements are filed as a part of this annual report at Item 8. 3 Exhibits The following is a complete list of Exhibits filed as part of, or ~~Subsidiary~~incorporated by reference to this report: * 3.1 Articles of Incorporation of Energy Corporation of America. * 3.2 Amended Articles of Incorporation of Energy Corporation of America. * 3.3 Amended Bylaws of Energy Corporation of America. * 4.1 Intentionally omitted. * 4.2 Intentionally omitted. * 4.3 Indenture, dated as of May 23, 1997, between Energy Corporation of America and The Bank of New York, as Trustee, with respect to the 9 1/2% Senior Subordinated Notes Due 2007 (including form of 9 1/2% Senior Subordinated Note Due 2007. * 4.4 Form of 9 1/2% Senior Subordinated Note due 2007, Series A. * 4.5 Registration Rights Agreement, dated as of May 20, 1997, among Energy Corporation of America, as issuer, and Chase Securities Inc. and Prudential Securities Inc. * 10.1 Eastern American Energy Corporation Profit/Incentive Stock Plan dated as of June 4, 1997. * 10.2 Buy-~~----------------------~~Sell Stock Option Agreement dated as of May 19, 1997 among Energy Corporation of America, F.H. McCullough, III and Kathy L. McCullough. * 10.3 Buy-~~----------------------------------~~Sell ~~John~~Stock ~~Mork~~Option 54Agreement ~~President~~dated as of July 8, 1996 between Energy Corporation of America and ~~Chief~~Kenneth ~~Executive~~W. ~~Officer;~~Brill. ~~Director~~* ~~Joseph~~10.4 EGas Purchase Contract dated as of January 1, 1993 between Eastern American Energy Corporation and Eastern Marketing Corporation. ~~Casabona~~* 5910.5 ~~Executive~~Intentionally ~~Vice~~omitted. ~~President;~~* ~~Director~~10.6 Intentionally omitted. * 10.7 Intentionally omitted. 68 * 10.8 Intentionally omitted. * 10.9 Intentionally omitted. * 10.10 Intentionally omitted. * 10.11 Intentionally omitted. * 10.12 Intentionally omitted. * 10.13 Intentionally omitted. * 10.14 Intentionally omitted. * 10.15 Intentionally omitted. * 10.16 Intentionally omitted. * 10.17 Incentive Stock Purchase Agreement dated February 12, 1999 by and between Energy Corporation of America and Michael S. Fletcher. 54* ~~Chief~~10.18 ~~Financial~~Incentive ~~Officer~~Stock ~~Donald~~Purchase CAgreement dated December 16, 1998 by and between Energy Corporation of America and Joseph E. ~~Supcoe~~Casabona. 47* ~~Senior~~10.19 ~~Vice~~Incentive ~~President~~Stock Purchase Agreement dated December 16, ~~Secretary~~1998 by and ~~General~~between ~~Counsel~~Energy Corporation of America and Edward J. Davies. 61* ~~Senior~~10.20 ~~Vice~~Incentive ~~President~~Stock J.Purchase ~~Michael~~Agreement ~~Forbes~~dated 43December ~~Vice~~16, ~~President~~1998 by and ~~Treasurer~~between ~~George~~Energy V.Corporation ~~O'Malley~~of 51America ~~Vice~~and ~~President~~Donald ~~Accounting~~C. KSupcoe. ~~Ralph~~* ~~Ranson,~~10.21 IIIncentive 60Stock ~~Vice~~Purchase ~~President~~Agreement ~~Marketing~~dated ~~Julie~~March ~~Ann~~19, ~~Kitano~~1999 46by ~~Assistant~~and ~~Secretary~~between Energy Corporation of America and W. Gaston Caperton, III. 62* ~~Director~~10.22 Incentive Stock Purchase Agreement dated March 19, 1999 by and between Energy Corporation of America and Peter H. Coors. 55* ~~Director~~10.23 Incentive Stock Purchase Agreement dated March 19, 1999 by and between Energy Corporation of America and L. B. Curtis. 78* ~~Director~~10.24 ~~(Chairman)~~Incentive ~~John~~Stock Purchase Agreement dated March 19, 1999 by and between Energy Corporation of America and J. J. Dorgan. 78* ~~Director~~10.25 ~~Arthur~~Incentive Stock Purchase Agreement dated March 19, 1999 by and between Energy Corporation of America and A. C. Nielsen, Jr. 83* ~~Director~~10.26 FStock Purchase Agreement dated February 17, 1999 by and among Westech Energy Corporation, Westech Energy New Zealand Limited and Edward J. HDavies. ~~McCullough~~* 10.27 Intentionally omitted. * 10.28 Intentionally omitted. * 10.29 Intentionally omitted. * 10.30 Intentionally omitted. * 10.31 Gas Sale and Purchase Agreement dated December 20, ~~III~~1999 55between ~~Director~~Energy ~~Julie~~Corporation ~~Mork~~of 52America ~~Director~~and Allegheny Energy Service Corporation. * 10.32 Participation Agreement dated December 20, 1999 between Energy Corporation of America and Allegheny Energy, Inc. 69 * 10.33 Intentionally omitted. * 10.34 Intentionally omitted. * 10.35 Employment Agreement effective as of August 18, 2000 by and between Energy Corporation of America and Michael S. Fletcher. * 10.36 Employment Agreement effective as of August 18, 2000 by and between Energy Corporation of America and Donald C. Supcoe. * 10.37 Purchase and Sale Agreement dated June 28, 2001 between Tavener E&P Ltd and Westech Energy Corporation. * 10.38 Credit Agreement dated July 10, 2002 between Energy Corporation of America and Foothill Capital Corporation, as the Arranger and Administrative Agent for the Lenders. * 10.39 Purchase and Sale Agreement dated August 2, 2002 between East Resources, Inc. and Energy Corporation of America, without exhibits thereto. * 10.40 Amendment, effective as of June 29, 1997, to Buy-Sell Stock Option Agreement between Energy Corporation of America and Kenneth W. Brill. * 10.41 Agreement dated December 28, 1998 between Energy Corporation of America and Kenneth W. Brill. 21.1 Subsidiaries of Energy Corporation of America. 24.1 Power of Attorney set forth on the signature page contained in Part V. 31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 99.1 Order of the United States District Court for the Southern District of West Virginia entered January 25, 2002 in civil action number 3:01-1317. * 99.2 Order of the United States District Court for the Southern District of West Virginia entered June 3, 2002 in civil action number 3:01-1317. * 99.3 Order of the United States District Court for the Southern District of West Virginia entered July 2002 in civil action number 3:01-1317. * 99.4 Unpublished opinion of the United States Court of Appeals for the Fourth Circuit decided December 15, 2003 in appeal styled Energy Corporation of America v. MacKay Shields LLC, et al. * 99.5 Stipulation and Final Judgement dated December 3, 2002 in the case styled Energy Corporation of America v. MacKay Shields LLC, et al. * 99.6 Order of the United States District for the Southern District of West Virginia entered December 4, 2003 in the above styled case. * 99.7 January 9, 2004, order of the United States Court of Appeals for the Fourth Circuit in appeal styled Energy Corporation of America v. MacKay Shield LLC, et al. 70 * 99.8 Notice of Default from Wells Fargo Foothill, Inc. received January 23, 2004 * 99.9 Forbearance Agreement entered into January 23, 2004 between the Company and Wells Fargo Foothill, Inc. * 99.10 Intentionally omitted. * 99.11 Settlement Agreement among the Company and Noteholders. * 99.12 Energy Corporation of America commences asset sale offer to purchase up to $4,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated Notes due 2007. * 99.13 Energy Corporation of America commences asset sale offer to purchase up to $34,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated Notes due 2007. * Previously filed b) Reports on Form 8-K:

The Company filed a report on Form 8-K, Item 5, dated June 15, 2004, reporting that the Company and Wells Fargo Foothill, Inc., have entered into an amended and restated credit agreement dated June 10, 2004. The Company filed a report on Form 8-K, Item 5, dated June 30, 2004, announcing the commencement of an asset sale offer for the purchase of up to $34 million aggregate principal amount of its 9 1/2 % Senior Subordinated Notes. * * * * * * 71 PART V ------- 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 27th day of September 2004. ENERGY CORPORATION OF AMERICA By: /s/ John Mork -------------------------------------- John Mork President and Chief Executive Officer 72 POWER OF ATTORNEY ----------------- Each of the undersigned officers and directors of Energy Corporation of America (the "Company") hereby constitutes and appoints John Mork, Joseph E. Casabona and Michael S. Fletcher and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file this Form 10-K under the Securities Act of 1934, as amended, and any or all amendments (including, without limitation, post-effective amendments), with all exhibits and any and all documents required to be filed with respect thereto, with the Securities and Exchange Commission or any regulatory authority, granting unto such attorneys-in-fact and agents, and each of them acting alone, full power and authority to do and perform each of every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as full to all intents and purposes as he himself might or could do if personally present, hereby ratifying and confirming all the such attorneys-in-fact and agents, or any of them, or their substitute or substitutes, may lawfully do or cause to be done. Pursuant to the requirements of the Securities Act of 1934, this Form 10-K has been signed on the 27th day of September 2004, by the following persons in the capacities indicated. 73

~~Annual~~Signature ~~Compensation~~Title -------------------- ~~All Other Year Salary Bonus Other Compensation (1)~~ ------ -------- ---------- -------- ---------------------- /s/ John Mork ~~2003~~-------------------------- ~~$265,376~~John $Mork ~~125~~President,~~000~~ ~~$ 77,045 $ 5,867 President and~~ Chief Executive Officer ~~2002~~and ~~258,892~~Director ~~125,000~~(Principal ~~59,670~~executive ~~26,067~~officer) ~~2001~~/s/ ~~256,068~~Joseph ~~1,146,635~~E. ~~4,349~~Casabona ~~35,251~~-------------------------- Joseph E. Casabona ~~2003 $243,595 $ 80,000 $ 6,875 $ 4,763~~ Executive Vice President ~~2002~~and ~~238,277~~Director ~~125,942~~/s/ ~~2,905~~Michael ~~4,574~~S. ~~2001~~Fletcher ~~231,538~~-------------------------- ~~1,457,630 (2) 1,888 4,454~~ Michael S. Fletcher ~~2003 $238,504 $ 45,000 $ 2,477 $ 4,558~~ Chief Financial Officer ~~2002~~(Principal ~~233,306~~accounting ~~100,510~~and ~~352~~financial ~~4,504 2001 232,471 56,345 124,198 (3~~officer) ~~3,500~~/s/ ~~Edward~~F. JH. ~~Davies~~McCullough ~~2003~~III ~~$230,201~~-------------------------- $F. ~~45,000~~H. $McCullough ~~408~~III $Director ~~6,113~~/s/ ~~Senior~~Gaston ~~Vice~~Caperton ~~President~~-------------------------- ~~2002~~Gaston ~~223,930~~Caperton ~~95,714~~Director ~~120~~/s/ ~~4,592~~Peter ~~2001~~H. ~~207,308~~Coors ~~53,105~~-------------------------- ~~899~~Peter ~~4,181 Donald C~~H. ~~Supcoe~~Coors ~~2003~~Director ~~$201,152~~/s/ $L. ~~65,000~~B. $Curtis ~~3,529~~-------------------------- $L. ~~4,005~~B. ~~Senior~~Curtis ~~Vice~~Director ~~President~~/s/ ~~2002~~John ~~197,993~~J. ~~100,435~~Dorgan ~~2,325~~-------------------------- ~~3,949~~John ~~2001~~J. ~~188,447~~Dorgan ~~54,545~~Director ~~1,482~~/s/ ~~_______________________________~~Julie ~~(1)~~Mork ~~Includes~~-------------------------- ~~compensation~~Julie ~~related~~Mork toDirector ~~insurance~~/s/ ~~policies~~Arthur ~~provided for the benefit of named officer and 401K matching contributions~~C. ~~(2) Includes $900~~Nielsen,~~000~~ ~~received~~Jr. as-------------------------- ~~Class~~Arthur AC. ~~stock and $340~~Nielsen,~~000~~ ~~cash~~Jr. asDirector ~~related~~/s/ ~~tax~~Jay ~~protection~~S. ~~(3)~~Pifer ~~Includes~~-------------------------- ~~the~~Jay ~~forgiveness~~S. ofPifer ~~debt to the Company.~~Director

Beneficial Ownership Common Stock ----------------- Shares Percent ------- -------- W. Gaston Caperton, III 6,680 1.08% Joseph E. Casabona 31,376 5.09% Colstab & Co. (Nominee for KWB Trust) (1) 49,110 7.96% Peter H. Coors 2,946 * L. B. Curtis 11,610 1.88% Edward J. Davies 3,000 * John J. Dorgan 2,130 * J. Michael Forbes 2,200 * F. H. McCullough, III (2) 70,035 11.35% John Mork (3) 359,493 58.27% Julie Mork (3) 359,493 58.27% Arthur C. Nielsen, Jr. 36,480 5.91% Donald C. Supcoe 3,583 * ------- -------- 578,643 93.80% All officers and directors as a group (12 persons) 529,533 85.84% * Less than one percent. (1) Pursuant to an agreement dated December 28, 1998 (previously attached to the Company's Form 10-K as exhibit 10.41), the Company is required to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's estate or promptly after the passage of two years from Mr. Brill's death if the estate does not sooner tender the shares. Mr. Brill died on July 20, 2003. The Agreement provides that the Company shall make installment payments for the purchase of the stock over a five year period. (2) Includes 67,955 shares held by F.H. McCullough, III and Kathy McCullough as joint tenants, 880 shares held by the Katherine F. McCullough Trust, and 400 shares held by each of the Lesley McCullough Trust, the Meredith McCullough Trust and the Kristin McCullough Trust. (3) Includes 280,930 shares held by John and Julie Mork as joint tenants, 2,663 shares held by Julie Mork individually, and 37,950 shares held by each of the Alison Mork Trust and the Kyle Mork Trust.

Beneficial Ownership Class A Stock ---------------- Shares Percent ------ -------- W. Gaston Caperton, III 1,920 6.15% Joseph E. Casabona 3,619 11.60% Peter H. Coors 2,534 8.12% L.B. Curtis 1,560 5.00% John J. Dorgan 2,320 7.44% Michael S. Fletcher 3,355 10.75% F.H. McCullough, III 1,920 6.15% John Mork (1) 4,737 15.18% Julie Mork (1) 4,737 15.18% Arthur C. Nielsen, Jr. 3,080 9.87% K. Ralph Ranson, II 487 1.56% Donald C. Supcoe 2,785 8.93% ------ -------- 28,317 90.75% All officers and directors as a group (12 persons) 28,317 90.75% _______________ (1) Includes 956 shares held by John and Julie Mork as joint tenants and 1,342 shares held by Julie Mork individually and 1,220 shares held by the Alison Mork Trust and 1,219 shares held by the Kyle Mork Trust.

2003 2002 2001 ---------- --------- --------- (3) Gaston Caperton, III $ 100.01 $ 77.58 $ 56.76 Joseph E. Casabona 50.00 38.77 21.99 Peter Coors 135.00 77.58 28.38 L.B. Curtis 135.00 83.36 88.85 E.J. Davies 270.00 166.72 140.78 John J. Dorgan 29.97 19.39 14.19 Michael S. Fletcher 50.00 38.77 28.38 J. Michael Forbes 25.00 19.39 14.19 John Frederick 25.00 - 14.19 Thomas R. Goodwin 25.00 38.77 28.38 Denny McGowan 25.00 - - John Mork (1) 1,350.00 833.60 703.89 Alison Mork Trust (2) 50.00 38.77 28.38 Kyle Mork Trust (2) 50.00 38.77 28.38 Arthur C. Nielsen, Jr. 50.00 38.77 28.38 George O'Malley 27.00 - - Kent Schamp 28.35 21.17 15.34 Donald C. Supcoe 25.00 19.39 14.19 ---------- --------- --------- $2,450.33 $1,550.80 $1,254.65 ========== ========= ========= (1) Interest of John Mork and Julie Mork held as joint tenants. (2) Trusts for the children of John Mork and Julie Mork. (3) These amounts represent only the amounts committed to the 2003 Drilling Program, the actual amount of investment may vary based on the number of wells drilled and the related costs.

Outstanding Unamortized Balance as of as of June 30, 2003 June 30, 2003 -------------- -------------- Joseph E. Casabona $ 141 $ 33 Michael S. Fletcher 141 33 J. Michael Forbes 96 96 K. Ralph Ranson, II 28 16 Donald C. Supcoe 180 116 -------------- -------------- Total $ 586 $ 294 ============== ==============

Note Plus Unamortized Accrued as of Interest June 30, 2003 ---------- -------------- (1) Michael S. Fletcher $ 284 $ 7 (1) Linda Given 28 1 (1) David Jordan 56 1 (2) Dennis McGowan 166 133 (1) Donald C. Supcoe 169 4 ---------- -------------- $ 703 $ 146 ========== ============== (1) Promissory note is being amortized over three years, as of August 29, 2003 amounts have been forgiven. (2) Of the $166,000 in promissory notes, $33,000 is being forgiven and amortized over the next two years, assuming continuing employment.

Payment Volumes (in thousands) Mmcf --------------- ------- Joseph E. Casabona 50 66.7 L.B. Curtis 75 100.0 E.J. Davies 150 200.0 John J. Dorgan 50 66.7 F.H. McCullough, III 150 200.0 --------------- ------- $ 475 633.4 =============== =======

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