10-Q 1 body.txt ENERGY CORPORATION OF AMERICA 10-Q 12-31-2004 UNITED STATES OF AMERICA SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED DECEMBER 31, 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 No.) 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) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes _X_ No ___ Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [_] No [X] The number of shares of the Registrant's common stock, par value $1.00 per share, outstanding at February 8, 2005 was 601,613 shares.

ENERGY CORPORATION OF AMERICA TABLE OF CONTENTS PAGES PART I FINANCIAL INFORMATION Item 1. Financial Statements Unaudited Condensed Consolidated Balance Sheets ~~September~~December 3031, ~~2003~~2004 ~~(Unaudited)~~ and June 30, ~~2003~~2004 . . . . . . . . . . . . . . . . . . 3 Unaudited Condensed Consolidated Statements of Operations For the three and six months ended ~~September~~December 3031, ~~2003~~2004 and ~~2002.~~2003 . . . . . ~~. . .~~ 5 Unaudited Condensed Consolidated Statements of Cash Flows For the ~~three~~six months ended ~~September~~December 3031, ~~2003~~2004 and ~~2002~~2003 . . . . . . . . . . 6 Unaudited Condensed Consolidated Statements of Comprehensive Income . . . For the three and six months ended ~~September~~December 3031, ~~2003~~2004 and ~~2002.~~2003 ~~. . . . . . . .~~ 7 Notes to Unaudited Condensed Consolidated Financial Statements. . . . . . ~~. . . . .~~ 8 Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . . . . . . . . . . . . . . . 1114 Item 3. Quantitative and Qualitative Disclosures About Market Risk. . . . 1724 Item 4. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . 1825 PART II OTHER INFORMATION Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 1826 Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . . . 1926 Item 3. Defaults Upon Senior Securities . . . . . . . . . . . . . . . . . 1926 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . 2026 Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . . . 2026 Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . . . 2026 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2027

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PART I FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ENERGY CORPORATION OF AMERICA UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (~~UNAUDITED -~~ AMOUNTS IN THOUSANDS) ------------------------------------------------------------------------------------ ~~SEPTEMBER~~DECEMBER 3031, JUNE 30, ~~2003~~2004 ~~2003~~2004 --------------- ---------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 25,~~636~~325 $ 45,~~831~~821 Accounts receivable: Oil and gas sales 710,~~678~~992 108,~~380~~632 Gas aggregation and pipeline 914,~~114~~328 9,~~458~~079 Other 74,~~449~~066 4,~~616~~000 --------------- ---------- Accounts receivable 2429,~~241~~386 2421,~~454~~711 Less allowance for doubtful accounts (~~1,280~~898) (1,~~616~~022) --------------- ---------- Accounts receivable, net of allowance 2228,~~961~~488 2220,~~838~~689 Deferred income tax asset 41612 412,087 Deferred taxes, - other comprehensive ~~income~~loss ~~385~~563 ~~787~~2,889 Notes receivable, related party ~~1,596~~54 59 Derivatives 1,~~609~~650 - Prepaid and other current assets 2,~~218~~164 14,~~410~~141 --------------- ---------- Total current assets 2938,~~837~~856 3135,~~516~~686 Property, plant and equipment, net of accumulated depreciation and depletion of $~~132~~150,~~871~~475 and $~~128~~143,~~765~~846 ~~252~~254,~~369~~927 ~~253~~246,~~270~~391 OTHER ASSETS: Deferred financing costs, net of accumulated amortization of $67,~~030~~446 and $56,~~750~~833 2,~~819~~126 32,~~098~~015 Notes receivable, related party ~~136~~369 ~~146~~113 Derivatives 428 - Other 75,~~776~~940 76,~~804~~007 --------------- ---------- Total other assets 108,~~731~~863 118,~~048~~135 --------------- ---------- TOTAL $ ~~292~~302,~~937~~646 $ ~~295~~290,~~834~~212 =============== ========== The accompanying notes are an integral part of the condensed consolidated financial statements.

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ENERGY CORPORATION OF AMERICA UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (~~UNAUDITED -~~ AMOUNTS IN THOUSANDS~~, EXCEPT SHARE DATA~~) ------------------------------------------------------------------------------------------- ~~SEPTEMBER~~DECEMBER 3031, JUNE 30, ~~2003~~2004 ~~2003~~2004 --------------- ---------- LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable and accrued expenses $ 149,~~694~~149 $ 1314,~~734~~823 Current portion of long-term debt ~~136~~152 ~~133~~1,145 Funds held for future distribution 1519,~~598~~746 1716,~~217~~701 Income taxes payable 12,~~872~~349 ~~1,484~~128 Accrued taxes, other than income 810,~~884~~022 9,~~643~~289 Derivatives ~~168~~1,350 ~~810~~7,303 Other current liabilities 1,~~429~~798 13,~~421~~562 --------------- ---------- Total current liabilities 4244,~~781~~566 4452,~~442~~951 LONG-TERM OBLIGATIONS: Long-term debt ~~171~~179,~~440~~124 ~~173~~162,~~197~~894 ~~Gas~~Deferred ~~delivery~~trust ~~obligation and deferred~~ revenue 2,~~812~~318 2,~~917~~511 Deferred income tax liability 2016,~~376~~739 2019,~~376~~552 Derivatives ~~828~~154 ~~1,319~~- Other 8long-term obligations 7,~~043~~867 8,~~311~~447 --------------- ---------- Total liabilities ~~246~~250,~~280~~768 ~~250~~246,~~562~~355 ~~COMMITMENTS AND CONTINGENCIES:~~ Minority Interest 1,~~580~~375 1,~~594~~495 COMMITMENTS AND CONTINGENCIES STOCKHOLDERS' EQUITY: Common stock, par value $1.00; 2,000,000 shares authorized; 730,039 shares issued 730 730 Class A non-voting common stock, no par value; 100,000 shares authorized; 5169,~~555~~893 and 68,237 shares issued 58,~~642~~264 58,~~092~~027 Additional paid -in capital 5,503 5,503 Retained earnings 4551,~~438~~935 4548,~~150~~200 Treasury stock and notes receivable arising from the issuance of common stock (1215,~~163~~438) (1114,~~824~~954) Deferred compensation on restricted stock (1,677) (1,887) Accumulated other comprehensive ~~loss~~income (73loss) 1,186 (~~973~~3,257) --------------- ---------- Total stockholders' equity 4550,~~077~~503 4342,~~678~~362 --------------- ---------- TOTAL $ ~~292~~302,~~937~~646 $ ~~295~~290,~~834~~212 =============== ========== The accompanying notes are an integral part of the condensed consolidated financial statements.

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ENERGY CORPORATION OF AMERICA UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (~~UNAUDITED -~~ AMOUNTS IN THOUSANDS~~, EXCEPT PER SHARE DATA~~) ------------------------------------------------------------------------------------------------------------ THREE MONTHS ENDED ~~SEPTEMBER~~SIX 30MONTHS ENDED DECEMBER 31, DECEMBER 31, ------------------------ ---------------------- 2004 2003 ~~2002~~2004 2003 ----------- ----------- --------- ----------- REVENUES: Oil and gas sales $ 16,562 $ 14,~~141~~379 $ 929,~~164~~902 $ 28,520 Gas aggregation and pipeline sales 1518,~~509~~891 1114,~~922~~567 34,940 30,076 Well operations and service revenues 1,~~391~~319 1,~~467~~277 2,664 2,669 Other - 3648 467 48 ----------- ----------- --------- ----------- Total revenues 3136,~~041~~772 2230,~~589~~271 67,973 61,313 ----------- ----------- --------- ----------- COST AND EXPENSES: Field operating expenses 2,~~717~~795 2,~~485~~993 5,616 5,710 Gas aggregation and pipeline cost 14of sales 17,~~246~~529 1013,~~755~~750 32,132 27,996 General and administrative 3,~~732~~720 3,~~493~~757 7,351 7,489 Taxes, other than income ~~938~~1,314 ~~632~~895 2,246 1,834 Depletion and depreciation, of oil and gas ~~related~~properties 3,~~478~~132 3,~~052~~439 5,966 6,917 Depreciation of pipelines, other property and equipment 1,~~026~~049 1,~~037~~023 2,081 2,049 Exploration and impairment ~~997~~481 ~~572~~1,624 2,434 2,621 Gain on sale of assets (2,104) (103) (2,917) (108) ----------- ----------- --------- ----------- Total costs and expenses 27,~~134~~916 2227,~~026~~378 54,909 54,508 ----------- ----------- --------- ----------- Income from operations 38,~~907~~856 ~~563~~2,893 13,064 6,805 OTHER (INCOME) EXPENSE: Interest expense 3,~~807~~171 43,~~700~~782 ~~(Gain)~~6,388 ~~loss~~7,588 ~~on sale of assets (5) 229~~ Interest income and other 1,078 (~~805~~271) 1,357 (1,~~918~~075) ----------- ----------- ~~Income~~--------- ~~(loss)~~----------- Income before income taxes and minority interest ~~910~~4,607 (~~2,448~~618) 5,319 292 Income tax expense (benefit) ~~387~~1,281 (~~824~~229) 1,012 158 ----------- ----------- --------- ----------- Income (loss) before minority interest ~~523~~3,326 (~~1,624~~389) 4,307 134 Minority interest, ~~net~~62 of41 ~~tax~~120 64105 62----------- ----------- --------- ----------- NET INCOME (LOSS) $ ~~587~~3,388 $ (~~1,562~~348) $ 4,427 $ 239 =========== =========== ~~Basic and diluted earnings per common share: Basic $ 0.91 $ (2.38)~~ ========= =========== ~~Diluted~~The ~~(see~~accompanying ~~Note~~notes 4)are $an ~~0.89~~integral ~~N/A~~part ~~========~~of ~~========~~the condensed consolidated financial statements.

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ENERGY CORPORATION OF AMERICA UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (~~UNAUDITED -~~ AMOUNTS IN THOUSANDS) ------------------------------------------------------------------------------------ ~~THREE~~SIX MONTHS ENDED ~~SEPTEMBER~~DECEMBER 3031 ---------------------- 2004 2003 ~~2002~~ --------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES Net income ~~(loss)~~ $ ~~587~~4,427 $~~(1,562)~~ 239 Adjustments to reconcile net income ~~(loss)~~ to net cash provided (used) by operating activities: Depletion, depreciation and amortization 48,~~504~~047 48,~~088~~967 (Gain) ~~loss~~ on sale of assets (52,917) ~~229~~(108) (Gain) loss on ~~purchase~~redemption of senior bonds 249 (546) Deferred income taxes (1,~~765~~337) - Exploration and impairment ~~871~~2,387 ~~487~~2,578 Other, net ~~434~~182 ~~(466)~~548 --------- ----------- 511,~~845~~038 111,~~011~~678 Changes in assets and liabilities: Accounts receivable 27(7,800) 13,~~425~~810 Income taxes ~~387~~payable ~~(625)~~2,222 172 Prepaid and other assets (~~795~~1,514) (~~1,785~~949) Accounts payable ~~226~~and ~~697~~accrued expenses (5,336) (6,275) Funds held for future distribution 3,045 (13,~~619~~610) ~~132~~ Other (~~407) (1~~2,~~069~~297) 647 --------- ----------- Net cash provided (used) by operating activities ~~3,664~~ (~~214~~642) 5,473 CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (417,~~036~~616) (47,~~802~~745) Proceeds from sale of assets ~~5 2~~3,~~422~~895 620 Notes receivable and other 13(251) (~~152~~6) --------- ----------- Net cash used by investing activities (413,~~018~~972) (27,~~532~~131) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 10109,~~279~~691 1021,~~000~~026 Principal payments on long-term debt (1194,~~465~~453) (319,~~892~~598) Purchase of treasury stock and other financing activities (~~358~~505) (~~207~~531) Proceeds from issuance of stock - 257 Dividends paid (~~297~~615) (~~263~~595) --------- ----------- Net cash ~~used~~provided by financing activities (114,~~841)~~118 ~~5,638~~559 --------- ----------- Net decrease in cash and cash equivalents (~~2,195~~496) 2(1,~~892~~099) Cash and cash equivalents, beginning of period 5,821 4,831 ~~17,775~~ --------- ----------- Cash and cash equivalents, end of period $ 25,~~636~~325 $20 3,~~667~~732 ========= =========== The accompanying notes are an integral part of the condensed consolidated financial statements.

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ENERGY CORPORATION OF AMERICA UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (~~UNAUDITED -~~ AMOUNTS IN THOUSANDS) ------------------------------------------------------------------------------------------------- THREE MONTHS ENDED ~~SEPTEMBER~~SIX 30MONTHS ENDED DECEMBER 31, DECEMBER 31, ------------------------ ---------------------- 2004 2003 ~~2002~~2004 2003 ----------- ----------- --------- ----------- Net income (loss) $ ~~587~~3,388 $ (~~1,562~~348) $ 4,427 $ 239 Other comprehensive income (loss), net of tax: Foreign currency translation adjustment: Current period change ~~143~~582 ~~(323)~~750 ~~Marketable~~916 ~~securities~~893 Oil and gas derivatives: Current period ~~change~~transactions -2,913 (6683) 1,005 126 Reclassification to earnings -1,762 (16227) ~~Oil~~2,655 ~~and~~(279) ~~gas~~Interest ~~derivatives~~rate hedging: Current period transactions ~~731~~(134) - (~~428~~134) - Reclassification to earnings 26- 75- - - ----------- ----------- --------- ----------- Other comprehensive income (loss), net of tax ~~900~~5,123 (~~698~~160) 4,442 740 ----------- ----------- --------- ----------- Comprehensive income (loss) $1 8,~~487~~511 $ (~~2,260~~508) $ 8,869 $ 979 =========== =========== ========= =========== The accompanying notes are an integral part of the condensed consolidated financial statements.

- 7 - ENERGY CORPORATION OF AMERICA NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2004 1. Nature of Organization 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 in 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. 2. Accounting Policies Reference is hereby made to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2004, which contains a summary of major accounting policies followed in preparation of its consolidated financial statements. Those policies were also followed in preparing the quarterly report included herein. Management of the Company believes that all adjustments, consisting of only normal recurring accruals, necessary for a fair presentation of the results of such interim periods have been made. The results of operations for the period ended December 31, 2004 are not necessarily indicative of the results to be expected for the full year. Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period presentation. Recent Accounting Pronouncements - On December 16, 2004, the Financial Accounting Standards Board ("FASB") published Statement of Financial Accounting Standards No. 123 (Revised 2004), Share Based Payment ("SFAS 123R"). SFAS 123R requires that compensation cost related to share-based payment transactions be recognized in the financial statements. Share-based payment transactions within the scope of SFAS 123R include stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee share purchase plans. The provisions of SFAS 123R are effective as of the first interim period that begins after June 15, 2005. Accordingly, the Company will implement the revised standard in the first quarter of fiscal year 2006. Currently, the Company accounts for its share-based payment transactions under the provisions of APB 25, which does not necessarily require the recognition of compensation cost in the financial statements. Management is assessing the implications of this revised standard and the effect of the adoption of SFAS 123R will have on our financial position, results of operations, or cash flow. 3. Note Repurchases The Company purchased $34.0 million of its 9 1/2% Senior Subordinated Notes ("Notes") during the six months ended December 31, 2004 pursuant to an Asset Sale Offer as defined in the Indenture for the Notes. The Company purchased $2.04 million - 8 - of its Notes during the six months ended December 31, 2003 in privately negotiated transactions. 4. 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 gas aggregation and pipeline segment arise from the marketing of both Company and third party produced natural gas volumes and the related transportation. Management utilizes earnings before interest, taxes, depreciation, depletion, amortization and exploration and impairment costs ("EBITDAX") to evaluate the operations of each segment. Summarized financial information for the Company's reportable segments for operations is as follows (in thousands) for the three months ended December 31, 2004 and 2003:

~~NET~~Exploration ~~INCOME~~& ~~(LOSS)~~Gas ~~(IN~~Aggregation ~~THOUSANDS)~~Production ~~SHARES~~& ~~PER~~Pipeline ~~SHARE~~Other Consolidated -------------- ----------------- -------- ------------- ~~Three~~For the three months ended ~~September~~December 3031, ~~2003~~2004 ~~Basic~~-------------------------------------------- $Revenue ~~587~~from ~~645~~unaffiliated customers $ 17,~~909~~881 $ ~~0.91~~18,891 ~~Diluted~~$ - $ ~~587~~36,772 ~~660~~Depreciation,~~175~~ $depletion, ~~0.89~~amortization ~~Three~~3,545 ~~months~~152 ~~ended~~484 ~~September~~4,181 30Exploration and impairment costs 481 - - 481 Interest expense, ~~2002~~net ~~Basic~~5,558 $(2,065) (345) 3,148 EBITDAX 13,200 556 (1,~~562~~254) ~~655~~12,~~643~~502 Total assets 176,653 108,955 17,038 302,646 Capital expenditures 10,360 95 309 10,764 ======================================================================================================== For the three months ended December 31, 2003 -------------------------------------------- Revenue from unaffiliated customers $ ~~(2.38)~~15,657 ~~Diluted~~$ ~~(a)~~14,566 $ 48 $ 30,271 Depreciation, depletion, amortization 3,770 158 534 4,462 Exploration and impairment costs 1,624 - - 1,624 Interest expense, net 5,628 (1,~~562~~817) ~~655~~(85) 3,~~643~~726 ~~N/A~~EBITDAX 9,969 300 (978) 9,291 Total assets 179,105 89,842 18,627 287,574 Capital expenditures 3,660 7 42 3,709 ========================================================================================================

- 9 - Reconciliation of EBITDAX is as follows (in thousands) for the three months ended December 31, 2004 and 2003:

~~September~~Three 30Months Ended December 31, ~~September~~December 3031, 2004 2003 ~~2002~~ -------------- -------------- Net income (loss) $ ~~587~~3,388 $ (~~1,562~~348) Add: Interest expense 3,~~807~~171 43,~~700~~782 Depletion, and depreciation, ~~amortization-o&g~~of oil and gas properties 3,~~478~~132 3,~~052~~439 ~~Depletion,~~Depreciation ~~depreciation~~of pipelines, ~~amortization-~~other property and equipment 1,~~026~~049 1,~~037~~023 ~~Impairment~~Exploration &and ~~exploratory~~impairment ~~costs~~481 ~~997~~1,624 ~~572~~ Income tax expense (benefit) ~~387~~1,281 (~~824~~229) -------------- --------------- EBITDAX $ 1012,~~282~~502 $ 69,~~975~~291 ============== ===============

Summarized financial information for the Company's reportable segments for operations is as follows (in thousands) for the six months ended December 31, 2004 and 2003:

~~Summarized financial information for the Company's reportable segments for operations is as follows (in thousands):~~ Exploration & Gas Aggregation Production & Pipeline Other Consolidated -------------- ----------------- -------- ------------- For the ~~three~~six months ended ~~September~~December 3031, ~~2003~~2004 ------------------------------------------~~---~~ Revenue from unaffiliated customers $ 1532,~~532~~566 $ 1534,~~509~~940 $ -467 $ 3167,~~041~~973 Depreciation, depletion, amortization 36,~~808~~783 ~~160~~306 ~~536~~958 48,~~504~~047 Exploration and impairment costs ~~981~~2,434 16- - ~~997 Income (loss) from operations 3~~2,~~478~~434 ~~614 (185) 3,907~~ Interest expense, net 511,~~698~~014 (14,~~780~~098) (~~191~~585) 36,~~727~~331 EBITDAX 922,~~426~~561 ~~753~~1,384 ~~103~~(1,637) 1022,~~282~~308 Total assets ~~188~~176,~~371~~653 89108,~~111~~955 1517,~~455~~038 ~~292~~302,~~937~~646 Capital expenditures 316,~~937~~704 3197 96715 417,~~036~~616 ~~----------------------------------------------------------------------------------------------------------~~====================================================================================================== For the ~~three~~six months ended ~~September~~December 3031, ~~2002~~2003 ------------------------------------------~~---~~ Revenue from unaffiliated customers $ 1031,~~632~~188 $ 1130,~~922~~076 $ 3549 $ 2261,~~589~~313 Depreciation, depletion, amortization 37,~~355~~577 ~~203~~319 ~~531~~1,070 48,~~089~~966 Exploration and impairment costs ~~572~~2,605 -16 - ~~572~~2,621 ~~Income (loss) from operations 563 454 (454) 563~~ Interest expense, net 511,~~256~~325 (13,~~483~~597) ~~769~~(276) 47,~~542~~452 EBITDAX 519,~~003~~395 ~~622~~ 1,~~350~~055 6(878) 19,~~975~~572 Total assets ~~184~~179,~~781~~105 7689,~~284~~842 4218,~~330~~627 ~~303~~287,~~395~~574 Capital expenditures 47,~~593~~598 3610 ~~173~~137 47,~~802~~745 ~~----------------------------------------------------------------------------------------------------------~~======================================================================================================

- 10 - Reconciliation of EBITDAX is as follows (in thousands) for the six months ended December 31, 2004 and 2003:

~~THREE~~Six ~~MONTHS~~Months ~~ENDED~~Ended ~~SEPTEMBER~~December 3031, ~~VARIANCE~~December ~~----------------~~31, ~~-----------------~~2004 2003 ~~2002 AMOUNT PERCENT~~ ------- ------- ------- -------- ~~Natural~~Net ~~Gas~~income ~~Production~~$ ~~(Mmcf) 2~~4,~~768~~427 ~~2,531 237 9.4% Average sales price received (~~$~~/Mcf)~~ ~~5.01~~239 ~~3.33~~Add: ~~1.68~~Interest ~~50.5%~~expense ~~------- ------- ------- -------- Sales ($ in thousands) 13~~6,~~873~~388 87,~~436~~588 ~~5,437~~Depletion ~~64.4%~~and ~~Oil~~depreciation ~~Production~~of (Mbbl) 33 30 3 10.0% Average sales price received ($/Bbl) 27.79 23.17 4.62 19.9% ------- ------- ------- -------- Sales ($ in thousands) 917 695 222 31.9% Hedging ($ in thousands) (745) (62) (683) 1101.6% Other ($ in thousands) 96 95 1 1.1% ------- ------- ------- -------- Total oil and gas ~~sales~~properties ~~($ in thousands) 14~~5,~~141~~966 ~~9,164 4,977 54.3% ======= ======= ======= ======== Gas Aggregation Revenue Volume (Mdth) 2,347 2,432 (85) -3.5% Average sales price received ($ per Dth) 4.98 3.70 1.28 34.~~6~~% ------- ------- ------- -------- Sales ($ in thousands) 11~~,~~678~~917 ~~9,002~~Depreciation ~~2,676~~of ~~29.7% Pipeline Revenue Volume (Mdth) 1~~pipelines,~~411~~ ~~1,479~~other ~~(68)~~property ~~-4.6%~~and ~~Average~~equipment ~~sales price received ($ per Dth)~~ 2~~.72 1.97 0.75 38.1% ------- ------- ------- -------- Sales ($ in thousands) 3~~,~~831~~081 2,~~920~~049 ~~911~~Exploration ~~31.2% ------- ------- ------- -------- Total Gas Aggregation~~ and ~~Pipeline~~impairment ~~Revenues ($ in thousands) 15,509 11,922 3,587 30.1% ======= ======= ======= ======== Gas Aggregation Cost Volume (Mdth)~~ 2,~~347~~434 2,~~432~~621 ~~(85)~~Income ~~-3.5%~~tax ~~Average~~expense ~~price paid ($ per Dth) 4.78 3.46~~ 1~~.32 38.2% ------- ------- ------- -------- Cost ($ in thousands) 11~~,~~218~~012 ~~8,416~~158 ~~2,802 33.3% Pipeline Gas Cost Volume (Mdth) 1,115 1,184 (69)~~ -~~5.8% Average price paid ($ per Dth) 2.72 1.98 0.74 37.4%~~ ------- ------- ------- -------- ~~Cost~~EBITDAX ($ ~~in thousands) 3~~22,~~028~~308 ~~2,339 689 29.5% ------- ------- ------- -------- Total Gas Aggregation and Pipeline Cost (~~$ ~~in thousands) 14~~19,~~246~~572 ~~10,755 3,491 32.5%~~ ======= ======= ======= ========

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 total assets of the exploration and production segment are net long-lived assets located in New Zealand of $10.3 million and $6.9 million as of December 31, 2004 and 2003 with no significant revenues recorded for the three or six months ended December 31, 2004 and $0.2 million recorded for the three months ended December 31, 2003 and $0.3 million recorded for the six months ended December 31, 2003. 5. Derivative Instruments The Company periodically hedges a portion of its gas production through futures, swaps, floors and collar agreements. The purpose of the hedges is to provide a measure of stability in the volatile environment of oil and gas prices and to manage its exposure to commodity price risk under existing sales commitments. All of the Company's swap, floor and collar agreements in place are designated as cash flow hedges, except for one swap agreement designated as a fair value hedge. For swaps in place at December 31, 2004, the Company had recorded a $0.9 million other comprehensive loss, $0.6 million short-term deferred tax asset, $1.3 million short-term derivative liability, and $0.2 million long-term derivative liability. 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 $0.8 million. The Company has partially hedged its exposure to the variability in future cash flows through March 2006. For floors and collars in place at December 31, 2004, the Company had recorded a $0.2 million other comprehensive gain, $0.1 million short-term deferred tax liability, $1.6 million short-term derivative asset, and $0.2 million long-term derivative asset. No amount of the existing gains within other comprehensive income is expected to be reclassified into earnings within the next twelve months. The Company has partially hedged its exposure to the variability in future cash flows through March 2006. - 11 - In August 2004, the Company entered into four interest rate cap agreements with Foothill, in an effort to reduce the potential impact of increases in interest rates on floating-rate long-term debt. The agreements range from two to three years covering $40,000,000 in long-term debt and cap the one month London Interbank Offered Rate ("LIBOR") at 3.5%. At December 31, 2004, the Company has recorded a $0.1 million other comprehensive loss, $0.1 million short-term deferred tax asset, $0.1 million short-term derivative asset, and $0.2 million long-term derivative asset. No amount of the existing losses within other comprehensive income that are expected to be reclassified into earnings within the next twelve months. The Company has partially hedged its exposure to the variability in future cash flows through July 2007. 6. Commitments and Contingencies The Company is involved in legal actions and claims arising in the ordinary course of business. While the outcome of these 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. 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 December 31, 2004, the Company's remaining repurchase obligation under the Agreement is approximately $2.6 million of which $1.4 million was classified as a liability and the remaining $1.2 million is included in stockholders' equity as third parties have agreed to purchase such amount. During June 2004, the Company sold its membership interest in Breitburn Energy Company, LLC and established a $1.8 million 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. This requirement was fulfilled during the quarter ended December 31, 2004 with no such claims from the buyer and was recorded as gain on sale of assets. 7. Related Party Transaction Pursuant to an Agreement dated December 31, 2004, the Company advanced $0.3 million to a certain officer bearing 5% interest. The principal amount is due in full, unless paid sooner, on December 31, 2008 and is secured by a stock pledge agreement. 8. Income Taxes The Company is currently under examination by the U.S. Internal Revenue Service of its federal income tax returns for the tax years ending June 30, 2002 and 2003. At December 31, 2004, the Company recorded a $2.3 million current income taxes payable and corresponding reduction to deferred tax liability resulting from a deferral in the timing of certain deductions arising from - 12 - abandoned properties. Management of the Company continues to believe that it has adequately provided for any potential tax liability that may be ultimately assessed by the IRS. 9. Debt 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%. Based upon the original terms of the agreement, the line was to reduce by $1.0 million in November 2004 and expire on June 30, 2005. The unsecured revolving line of credit was renegotiated during the quarter ended December 31, 2004 to extend the terms of the agreement. Under the new agreement the Company has an unsecured line of credit totaling $3.0 million, which reduces by $1.0 million in June 2005 and expires on April 1, 2007. - 13 - ITEM 2. 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-Q, 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 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 Part I, Item 1. COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED DECEMBER 31, 2004 -------------------------------------------------------------------------------- AND 2003 -------- The Company recorded net income of $3.4 million for the quarter ended December 31, 2004 compared to net loss of $0.3 million for the quarter ended December 31, 2003. The increase in net income of $3.7 million is primarily attributable to the net of a $6.5 million increase in revenues, a $0.5 million increase in costs and expenses, a $0.6 million decrease in interest expense, a $1.3 million decrease in interest income and other, and a $1.5 million increase in income tax expense. - 14 - Production, gas aggregation and pipeline volumes, revenue and average sales prices for the quarters ended December 31 and their related variances are as follows:

~~Total~~THREE ~~Average~~MONTHS ~~Market~~ENDED ~~Volumes~~DECEMBER ~~Contract~~31 ~~Unrealized~~VARIANCE ~~Time~~--------------------- ~~period~~----------------- ~~Index~~2004 2003 AMOUNT PERCENT ---------- --------- ------- -------- Natural Gas Production (~~MMBtu~~Mmcf) ~~Price~~2,557 2,781 (~~Gains~~224) ~~Losses~~-8.1% Average sales price received ($/Mcf) 7.35 4.77 2.58 54.1% ---------- --------- ------- -------- Sales ($in thousands) 18,785 13,266 5,519 41.6% Oil Production (Mbbl) 18 30 (12) -40.0% Average sales price received ($/Bbl) 44.78 27.80 16.98 61.1% ---------- --------- ------- -------- Sales ($in thousands) 806 834 (28) -3.4% Hedging gain (loss) (3,118) 190 (3,308) -1741.1% Other 89 89 - 0.0% ---------- --------- ~~Derivatives~~------- ~~Natural~~-------- ~~Gas~~Total ~~Swaps~~oil ~~October~~and ~~2003~~gas -sales ~~June~~($in ~~2004~~thousands) ~~NYMEX~~16,562 ~~822~~14,~~000~~379 $2,183 415.052% $========== ~~683,883~~========= ~~February~~======= ~~2004~~======== -Aggregation ~~March~~Revenue ~~2004~~Volume ~~NYMEX~~(Million 60Mmbtu) 1,~~000~~884 62,147 (263) -12.232% Average sales price received (~~62,153~~$/Mmbtu) ~~July~~7.12 ~~2004~~5.17 1.95 37.7% ---------- ~~June~~--------- ~~2005~~------- ~~NYMEX~~-------- 3Sales ($in thousands) 13,~~240~~408 11,~~000~~091 42,317 20.549% ~~962~~Pipeline Revenue Volume (Million Mmbtu) 2,~~665~~202 1,404 798 56.8% Average sales price received ($/Mmbtu) 2.49 2.48 0.01 0.4% ---------- --------- ------- ~~Unrealized~~-------- Sales (~~Gains~~$in thousands) ~~Losses~~5,483 43,~~122~~476 2,~~000~~007 $57.7% ~~1,584,395~~---------- --------- ------- -------- Total aggregation and pipeline sales ($in thousands) 18,891 14,567 4,324 29.7% ========== ========= ~~Physical~~======= ~~Contracts~~======== ~~Fixed~~Aggregation ~~Price~~Gas ~~Delivery~~Cost ~~Contracts~~Volume ~~October~~(Million ~~2003~~Mmbtu) 1,884 2,147 (263) -12.2% ~~June~~Average ~~2004~~price 4paid ($/Mmbtu) 6.85 5.10 1.75 34.3% ---------- --------- ------- -------- Cost ($in thousands) 12,~~953~~914 10,~~500~~956 1,958 17.9% Pipeline Gas Cost Volume (Million Mmbtu) 976 1,166 (190) -16.3% Average price paid ($/Mmbtu) 4.5073 ~~July~~2.40 ~~2004~~2.33 97.1% ---------- ~~October~~--------- ~~2004~~------- ~~338,250~~-------- Cost ($in thousands) 4,615 2,794 1,821 65.852% ---------- --------- ------- -------- Total ~~Hedged~~aggregation ~~Production~~and 9pipeline cost ($in thousands) 17,~~413~~529 13,750 3,779 27.5% ========== ========= ======= ========

REVENUES. Total revenues increased $6.5 million between the periods. The -------- increase was due to a $2.2 milion increase in oil and gas sales and a $4.3 million increase in gas aggregation and pipeline sales. Well operations and service revenues remained relatively constant. - 15 - Revenues from oil and gas sales increased a net of $2.2 million from $14.4 million for the quarter ended December 31, 2003 to $16.6 million for the quarter ended December 31, 2004. Natural gas sales increased $5.5 million. The net increase in natural gas sales is attributable to an increase in gas prices, offset by a decrease in gas production. The price increase corresponds with the rise in the related natural gas indexes. The decrease in production is primarily due to wells sold in California and certain pipeline curtailments in the Appalachian Basin. Gas sales were reduced by recognized losses on related hedging transactions and other revenue, which totaled a loss of $3.0 million for the quarter ended December 31, 2004 compared to a gain of $0.3 million for the quarter ended December 31, 2003. Revenues from gas aggregation and pipeline sales increased $4.3 million from $14.6 million during the period ended December 31, 2003 to $18.9 million in the period ended December 31, 2004. Gas aggregation revenue increased $2.3 million primarily because of an increase in average sales prices and corresponds to the rise in related gas indexes for this period compared to the prior period. Offsetting this increase in sales prices was a decrease in gas volumes due to curtailments and natural production declines. Pipeline revenue, which has a sales and gathering component, increased $2.0 million primarily because of an increase in the average sales price related to the non-gathering volumes and an increase in revenue related to the gathering component for this period compared to the prior period. The increase in revenues and volumes related to the gathering component primarily is the result of the acquisition of a 100-mile long natural gas gathering system located in northeastern West Virginia finalized during the first quarter of the current fiscal year. The increase in the average sales price related to the non-gathering volumes corresponds to the increase in related gas indexes for the period as compared to the prior period. COSTS AND EXPENSES. The Company's costs and expenses increased $0.5 -------------------- million between the periods primarily as a net result of a $0.2 million decrease in field and lease operating expense, a $3.8 million increase in gas aggregation and pipeline costs, a $0.4 million increase in taxes other than income, a $0.3 million decrease in depreciation, depletion, and amortization costs for oil and gas properties, a $1.1 million decrease in exploration and impairment costs, and a $2.0 million increase in gain on sale of property as further described below. Field and lease operating expense decreased $0.2 million from $3.0 million during the period ended December 31, 2003 to $2.8 million in the period ended December 31, 2004. This decrease is a result of decrease in operating expenses in New Zealand and due to wells sold in California. Gas aggregation and pipeline costs increased $3.8 million from $13.8 million during the period ended December 31, 2003 to $17.5 million in the period ended December 31, 2004. Gas aggregation costs increased $2.0 million and pipeline costs increased $1.8 million. The increase in costs is primarily attributable to the increase in the average purchase price that corresponds to the rise in the related natural gas indexes, offset by a decrease in volume for this period compared to the prior period. Pipeline costs increased $1.8 million. The increase in costs is primarily attributable to an increase in the average purchase price, which corresponds to the rise in the related natural gas indexes, offset by a decline in gas volumes. Taxes other than income increased $0.4 million during the period to $1.3 million. This increase is primarily the result of an increase in wellhead oil and gas sales during the period compared to the prior period. Production taxes are based on wellhead oil and gas sales, which were higher this period compared to the prior period. Depletion and depreciation for oil and gas properties decreased $0.3 million primarily due to a decrease in oil and gas production. - 16 - Exploration and impairment costs decreased $1.1 million and is primarily the result of a decline in dry hole expense during the period compared to the prior period. Gain on sale of assets increased $2.0 million primarily due to the recognition of $1.8 million gain in the current period, related to the reversal of a reserve established at June 30, 2004, against items for which the Company was required to indemnify the buyer of the Company's membership interest in Breitburn Energy Company, LLC ("BEC") for a period of 180 days after closing of the agreement. The Company also sold certain field equipment in the Appalachian Basin during the current period. INTEREST EXPENSE. Interest expense decreased $0.6 million when comparing ------------------ the periods primarily due to the purchase of a portion of the Company's senior notes resulting in a decrease in the average interest rate paid on outstanding debt. INTEREST INCOME AND OTHER. Other income decreased $1.3 million when ---------------------------- comparing the periods and is primarily attributable to an accrual of a contingent liability and profit sharing costs recorded in the current period. INCOME TAX. Income tax expense increased by $1.5 million to an income tax ----------- expense of $1.3 million as compared to an income tax benefit for the prior period of $0.2 million. The increase is primarily due to the increase in income before taxes of $5.2 million and the adjustment of the tax contingency balance of $0.6 million for items that are closed or no longer applicable. At December 31, 2004, the Company recorded a $2.3 million current income taxes payable and corresponding reduction to deferred tax liability resulting from a deferral in the timing of certain deductions arising from abandoned properties due to the current IRS examination of the Company's federal income tax returns for the tax years ending June 30, 2002 and 2003. COMPARISON OF RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED DECEMBER 31, 2004 -------------------------------------------------------------------------------- AND 2003 -------- The Company recorded net income of $4.4 million for the six months ended December 31, 2004 compared to net income of $0.2 million for the six months ended December 31, 2003. The increase in net income of $4.2 million is primarily attributable to the net of a $6.7 million increase in revenues, $0.4 million increase in costs and expenses, $1.2 million decrease in interest expense, $2.4 million decrease in interest income and other, and a $0.8 million increase in income tax expense. - 17 - Production, gas aggregation and pipeline volumes, revenue and average sales prices for the six months ended December 31 and their related variances are as follows:

REVENUES. Total revenues increased $6.7 million between the periods. The -------- increase was due to a $1.4 million increase in oil and gas sales, $4.9 million increase in gas aggregation and pipeline sales and a $0.4 million increase in other revenues. Well operations and service revenues remained relatively constant. - 18 - Revenues from oil and gas sales increased a net of $1.4 million from $28.5 million for six months ended December 31, 2003 to $29.9 million for the six months ended December 31, 2004. Natural gas sales increased $6.2 million and oil sales decreased $0.3 million. The net increase in natural gas sales is the result of an increase in average gas prices, offset by a decline in production. The price increase corresponds with the rise in related natural gas indexes. The production decline is primarily due to the sale of several California properties and certain pipeline curtailments in the Appalachian Basin. Gas sales were reduced by recognized losses on related hedging transactions and a decrease in other revenue, which totaled a loss of $4.9 million for the six months ended December 31, 2004 compared to a loss of $0.4 million for the six months ended December 31, 2003. Revenues from gas aggregation and pipeline sales increased $4.9 million from $30.0 million for the six months ended December 31, 2003 to $34.9 million for the six months ended December 31, 2004. Gas aggregation revenue increased $2.0 million because of an increase in average sales prices, offset by a decrease in gas volumes due to curtailments and natural production declines. The increase in average sales price corresponds to the rise in related natural gas price indexes for this period compared to the prior period. Pipeline revenue, which has a sales and gathering component, increased $2.9 million from $7.3 million to $10.2 million primarily because of an increase in the average sales price related to the non-gathering volumes and an increase in revenue related to the gathering component for this period compared to the prior period. The increase in revenues and volumes related to the gathering component primarily is the result of the acquisition of a 100-mile long natural gas gathering system located in northeastern West Virginia finalized during the first quarter of the current fiscal year. The increase in the average sales price related to non-gathering volumes corresponds to the increase in related natural gas indexes for the period as compared to the prior period. Other revenues increased $0.4 million between periods. This increase is the result of the company receiving a partnership distribution from a limited partnership in which the Company owns an interest. COSTS AND EXPENSES. The Company's costs and expenses increased $0.4 -------------------- million between the periods primarily as a net result of a $4.1 million increase in gas aggregation and pipeline costs, $0.1 million decrease in general and administrative costs, $0.4 million increase in taxes other than income, a $1.0 million decrease in depreciation, depletion, and amortization costs for oil and gas properties, a $0.2 million decrease in exploration and impairment costs, and a $2.8 million increase in gain on sale of assets. Gas aggregation and pipeline costs increased $4.1 million. Gas aggregation costs increased $1.5 million and is primarily the result of an increase in the average price of gas that corresponds to the rise in the related natural gas indexes, offset by a decline in gas volumes for this period compared to the prior period. Pipeline costs increased $2.6 million and is primarily the result of an increase in the average purchase price that corresponds to the rise in the related natural gas indexes, offset by a decline in volumes. Taxes other than income increased $0.4 million due to an increase in wellhead sales in the period compared to the prior period. Production taxes are based on wellhead oil and gas sales, which where higher during the period compared to the prior period. Depletion and depreciation of oil and gas properties decreased $1.0 million due to a decrease in production. Gain on sale of assets increased $2.8 million primarily due to the recognition of $1.8 million gain in the current period, related to the reversal of a reserve established at June 30, 2004, against items for which the Company was required to indemnify the buyer of the Company's membership interest in - 19 - Breitburn Energy Company, LLC ("BEC") for a period of 180 days after closing of the agreement. The Company also realized a gain on the sale of undeveloped acreage and certain field equipment in the Appalachian Basin during the current period. INTEREST EXPENSE. Interest expense decreased $1.2 million when comparing ------------------ the periods primarily due to the purchase of a portion of the Company's senior notes resulting in a decrease in the average interest rate paid on outstanding debt. INTEREST INCOME AND OTHER. Other income decreased $2.4 million when ---------------------------- comparing the periods and is primarily attributable to a decrease in recognized gains on the purchase of senior bonds, an accrual of a contingent liability and profit sharing costs recorded in the current period. INCOME TAX. Income tax expense increased by $0.8 million to an income tax ----------- expense of $1.0 million as compared to income tax expense for the prior period of $0.2 million. The increase is primarily due to the increase in income before taxes of $5.0 million and the adjustment of the tax contingency balance of $1.2 million for items that are closed or no longer applicable. At December 31, 2004, the Company recorded a $2.3 million current income taxes payable and corresponding reduction to deferred tax liability resulting from a deferral in the timing of certain deductions arising from abandoned properties due to the current IRS examination of the Company's federal income tax returns for the tax years ending June 30, 2002 and 2003. LIQUIDITY AND CAPITAL RESOURCES ---------------------------------- The Company's financial condition and liquidity have improved since June 30 2004. Stockholders' equity has increased from $42.4 at June 30, 2004 to $50.5 at December 31, 2004. The Company's cash decreased from $5.8 million at June 30, 2004 to $5.3 million at December 31, 2004. The Company's cash at February 8, 2005 was $1.6 million. The change in cash during the six months of approximately $0.5 million resulted from various operating, investing and financing activities of the Company. The activities were primarily comprised of: the borrowing of $50 million under the Company's $50 million term loan of the Amended and Restated Credit Agreement (the "Restated Credit Agreement"); the reduction of $0.6 million under the Company's $50 million revolving credit facility of the Restated Credit Agreement; payments of $34 million for the purchase of a portion of the Company's outstanding Notes; the investment of approximately $17.6 million; proceeds from the sale of assets of approximately $3.9 million; payments of approximately $1.1 million for the acquisition of treasury stock and dividends; and approximately $0.6 million of cash used by operations during the quarter. 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 a Restated Credit Agreement dated June 10, 2004. 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. - 20 - 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. 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%. Based upon the original terms of the agreement, the line was to reduce by $1.0 million in November 2004 and expires on June 30, 2005. The unsecured revolving line of credit was renegotiated during the quarter ended December 31, 2004 to extend the terms of the agreement. Under the new agreement the Company has an unsecured line of credit totaling $3.0 million, which reduces by $1.0 million in June 2005 and expires on April 1, 2007. At December 31, 2004, the Company's principal source of liquidity consisted of $5.3 million of cash, $0.3 million available under an unsecured credit facility currently in place, plus amounts available under the revolving loan of the Restated Credit Agreement. At December 31, 2004, $1.0 million was outstanding and $1.7 million was committed through letters of credit under the credit facility, $35.4 million was outstanding on the revolving loan and $50 million was outstanding on the term loan under the Restated Credit Agreement. As of February 8, 2005, there is $50 million in outstanding borrowings under the term loan and $29.4 million in outstanding borrowings under the revolving loan. Additional borrowings must comply with the terms of the Indenture and 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. - 21 - Management utilizes earnings before interest, taxes, depreciation, depletion, amortization and exploration and impairment cost ("EBITDAX") to evaluate the operation of each business segment. Additionally, EBITDAX and similar measures are utilized by the Company's lenders to evaluate the business and in calculating various financial coverages required in the debt agreements. Reconciliation of the non-GAAP financial measure is as follows (in thousands):

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. There can be no assurance given that the Company will be able to achieve these goals. 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 capital expenditures of $40.7 million, debt service obligations, working capital needs and other cash requirements for the current 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 and its expected fiscal year 2005 results of operations and cash flows from operating activities will be sufficient for the Company to remain in - 22 - 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. - 23 - ITEM 3. 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 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 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. Ineffectiveness is recorded in current earnings. The Company does not hold or issue derivative instruments for trading purposes. The Company currently has elected to enter into derivative hedge transactions on its estimated production covering approximately 60% to 70% for the fiscal year ending June 30, 2005; and 50% to 60% for the fiscal year ending June 30, 2006. As of December 31, 2004, the Company's open gas derivative instruments as follows:

- 24 - 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, pricing, and the percentage of gas production hedged under physical delivery contracts and derivative instruments remain at December 2004 levels, a 10% change in the average unhedged prices realized would change the Company's gas and oil revenues by approximately $0.4 million on a quarterly basis. 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. 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. In August 2004, the Company entered into four interest rate cap agreements with Foothill, in an effort to reduce the potential impact of increases in interest rates on floating-rate long-term debt. The agreements range from two to three years covering $40,000,000 in long-term debt and cap the one month London Interbank Offered Rate ("LIBOR") at 3.5%. Assuming the variable interest debt remained at the December 31, 2004 level, a 10% change in rates would have a $0.2 million impact on interest expense on an annual basis. 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. ITEM 4. 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 as of the end of the period covered by this quarterly 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. - 25 - PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The Company is involved in legal actions and claims arising in the ordinary course of business. While the outcome of these 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. ITEM 2. CHANGES IN SECURITIES None ITEM 3. DEFAULTS UPON SENIOR SECURITIES None ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a) Exhibits: 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 b) Reports on Form 8-K: None - 26 - SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the under signed thereunto, duly authorized, in the City of Denver, State of Colorado, on the 8th day of February 2005. ENERGY CORPORATION OF AMERICA By: /s/John Mork --------------------------------- John Mork Chief Executive Officer and Director By: /s/Michael S. Fletcher --------------------------------- Michael S. Fletcher Chief Financial Officer - 27 - EXHIBIT 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 15 U.S.C. SEC. 7241 AND 17 C.F.R. 240.13A-14(A) I, John Mork, certify that: 1. I have reviewed this Form 10-Q of Energy Corporation of America (the "Company"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the company's most recent fiscal quarter (the company's first fiscal quarter) that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and 5. The company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting. Date: February 8, 2005 /s/ John Mork --------------------------------------- JOHN MORK President and Chief Executive Officer EXHIBIT 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 15 U.S.C. SEC. 7241 AND 17 C.F.R. 240.13A-14(A) I, Michael S. Fletcher, certify that: 1. I have reviewed this Form 10-Q of Energy Corporation of America (the "Company"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the company's most recent fiscal quarter (the company's first fiscal quarter) that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and 5. The company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting. Date: February 8, 2005 /s/ Michael S. Fletcher ---------------------------------------- MICHAEL S. FLETCHER Chief Financial Officer

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