. . . UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED JUNE 30, 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 1-5507 MAGELLAN PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 06-0842255 State or other jurisdiction of (I.R.S. Employer incorporation or organization Identification No.) 10 COLUMBUS BOULEVARD, HARTFORD, CT 06106 (Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (860) 293-2006 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED ------------------- ------------------------ Common stock, par value $.01 per share Boston Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT
TITLE OF CLASS -------------- Common stock, par value $.01 per share NASDAQ SmallCap Market
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 Regulation S-K (sec. 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at the $1.31 closing price on December 31, 2003 (the last business day of the most recently completed second quarter) was $33,453,370. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: Common stock, par value $.01 per share, 25,784,983 shares outstanding as of October 4, 2004. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2004, are incorporated by reference in Part III of this Form 10-K to the extent stated herein. TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.................................................... 2 Item 2. Properties.................................................. 9 Item 3. Legal Proceedings........................................... 13 Item 4. Submission of Matters to a Vote of Security Holders......... 14 PART II Item 5. Market for the Company's Common Stock, Related Stockholder Matters and Issuer Purchase of Equity Securities............ 14 Item 6. Selected Financial Data..................................... 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................ 26 Item 8. Financial Statements and Supplementary Data................. 27 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................... 51 Item 9A. Controls and Procedures..................................... 52 Item 9B. Other Information........................................... 52 PART III Item 10. Directors and Executive Officers of the Company............. 52 Item 11. Executive Compensation...................................... 52 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.................. 52 Item 13. Certain Relationships and Related Transactions.............. 52 Item 14. Principal Accounting Fees and Services...................... 52 PART IV Item 15. Exhibits and Financial Statement Schedules.................. 53
Unless otherwise indicated, all dollar figures set forth herein are in United States currency. Amounts expressed in Australian currency are indicated as "A.$00". The exchange rate at October 8, 2004 was approximately A.$1.00 equaled U.S.$.74. 1 PART I ITEM 1. BUSINESS Magellan Petroleum Corporation (the Company or MPC) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2004, MPC's principal asset was a 55.06% equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL), which has one class of stock that is publicly held and traded in Australia. MPAL's major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest) and one petroleum production lease covering the Palm Valley gas field (52% working interest). Both fields are located in the Amadeus Basin in the Northern Territory of Australia. Santos Ltd., a publicly owned Australian company, owns a 48% interest in the Palm Valley field and a 65% interest in the Mereenie field. Santos Ltd owned 18.2% of MPAL's outstanding stock at June 30, 2003. It sold all of its interest during 2004. Origin Energy Limited, a publicly owned Australian company, owned 17.1% of MPAL's outstanding stock at June 30, 2003. On July 10, 2003, a subsidiary of Origin Energy, Sagasco Amadeus Pty. Limited, agreed to exchange 1.2 million shares of MPAL for 1.3 million shares of the Company's common stock. After the exchange was completed on September 2, 2003, MPC's interest in MPAL increased to 55% and Origin Energy's interest decreased to 14.5%. During July 2004, MPAL reached an agreement with Voyager Energy Limited for the purchase of its 40.936% working interest (38.703% net revenue interest) in its Nockatunga assets in southwest Queensland. The assets comprise several producing oil fields in Petroleum Leases 33, 50 and 51 together with exploration acreage in ATP 267P at a purchase price of approximately $1.4 million. The project is currently producing about 285 barrels of oil per day (MPAL share 115 bbls). MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. During September 2003, the litigants in the Kotaneelee litigation entered into a settlement agreement. During October 2003, the Company received approximately $851,000, after Canadian withholding taxes and reimbursement of certain past legal costs. The plaintiffs terminated all litigation against the defendants related to the field, including the claim that the defendants failed to fully develop the field. Since each party agreed to bear its own legal costs, there were no taxable costs assessed against any of the parties. See Item 3 -- Legal Proceedings. The following chart illustrates the various relationships between MPC and the various companies discussed above. The following is a tabular presentation of the omitted material: MPC -- MPAL RELATIONSHIPS CHART MPC owns 55% of MPAL. MPC owns 2.67% of the Kotaneelee Field, Canada. MPAL owns 52% of the Palm Valley Field, Australia. MPAL owns 35% of the Mereenie Field, Australia. MPAL owns 40.94% of the Nockatunga Field, Australia. Origin Energy Limited owns 14.5% of MPAL. SANTOS owns 48% of the Palm Valley Field, Australia. SANTOS owns 65% of the Mereenie Field, Australia. SANTOS owns 59.06% of the Nockatunga Field, Australia. (a) General Development of Business. Operational Developments Since the Beginning of the Last Fiscal Year. 2 AUSTRALIA MEREENIE MPAL (35%) and Santos (65%), the operator, (together known as the Mereenie Producers) own the Mereenie field which is located in the Amadeus Basin of the Northern Territory. MPAL's share of the Mereenie field proved developed oil reserves was approximately 249,000 barrels and 8.2 billion cubic feet (bcf) of gas at June 30, 2004. The Mereenie Producers installed during fiscal 2004 additional compression equipment in the field at an estimated cost of $13.1 million (MPAL share $4.6 million) that will increase field deliverability and partially meet certain gas contract requirements. In addition, two gas wells will be drilled later in 2004 to meet the gas contractual requirements until June 2007. During fiscal 2004, MPAL's share of oil sales was 131,000 barrels and 3.9 bcf of gas sold, which is subject to net overriding royalties aggregating 4.0625% and the statutory government royalty of 10%. The oil is transported by means of a 167-mile eight-inch oil pipeline from the field to an industrial park near Alice Springs. The oil is then shipped south approximately 950 miles by road to the Port Bonython Export Terminal, Whyalla, South Australia for sale. The cost of transporting the oil to the terminal is being borne by the Mereenie Producers. The Mereenie Producers are providing Mereenie gas in the Northern Territory to the Power and Water Corporation (PAWC) and Gasgo Pty. Ltd. (Gasgo), a company PAWC wholly owns, for use in Darwin and other Northern Territory centers. See "Gas Supply Contracts" below. The petroleum lease covering the Merenie field expires in November 2023. PALM VALLEY MPAL has a 52% interest in, and is the operator of, the Palm Valley gas field which is also located in the Amadeus Basin of the Northern Territory. Santos, the operator of the Mereenie field, owns the remaining 48% interest in Palm Valley which provides gas to meet the Alice Springs and Darwin supply contracts with PAWC and Gasgo. See "Gas Supply Contracts" below. MPAL's share of the Palm Valley proved developed reserves was 13.9 bcf at June 30, 2004. During fiscal 2004, MPAL's share of gas sales was 2.9 bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.3125%. MPAL drilled an additional development well, Palm Valley-11, in 2004. The well was a dry hole. Gasgo will pay for the cost of the well under the gas supply agreement. The producers and Gasgo have agreed to install additional compression equipment in the field that will assist field deliverability during the remaining Darwin gas contract period. Gasgo will pay for the cost of the additional compression under the gas supply agreement. The production lease covering the Palm Valley field was renewed in November 2003 for an additional term of 21 years. GAS SUPPLY CONTRACTS In 1983, the Palm Valley Producers (MPAL and Santos) commenced the sale of gas to Alice Springs under a 1981 agreement. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PAWC for use in the PAWC's Darwin generating station and at a number of other generating stations in the Northern Territory. The gas is being delivered via the 922-mile Amadeus Basin to the Darwin gas pipeline which was built by an Australian consortium. Since 1985, there have been several additional contracts for the sale of Mereenie gas. The Palm Valley Darwin contract expires in the year 2012 and Mereenie contracts expire in the year 2009. Under the 1985 contracts, there is a difference in price between Palm Valley gas and most of the Mereenie gas for the first 20 years of the 25 year contracts which takes into account the additional cost to the pipeline consortium to build a spur line to the Mereenie field and increase the size of the pipeline from Palm Valley to Mataranka. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. 3 At June 30, 2004, MPAL's commitment to supply gas under the above agreements was as follows:
PERIOD BCF - ------ ----- Less than one year.......................................... 7.22 Between 1-5 years........................................... 26.73 Greater than 5 years........................................ 4.55 ----- Total....................................................... 38.50 =====
DINGO GAS FIELD MPAL has a 34.3% interest in the Dingo gas field which is held under a retention license. No market has emerged for the gas volumes that have been discovered in the Dingo gas field, which is located in the Amadeus Basin in the Northern Territory. MPAL's share of potential production from this permit area is subject to a 10% statutory government royalty and overriding royalties aggregating 4.8125%. The license was renewed for a further term of five years from October 2003 to October 2008. BROWSE BASIN During fiscal year 2000, MPAL (100%) was granted exploration permits WA-287-P and WA-288-P in the eastern Browse Basin, offshore Western Australia. During fiscal 2002, MPAL was granted a permit over area WA-311-P which is adjacent to WA-288-P. In 2002, INPEX Corporation, a Japanese company, earned a 65% interest in WA-288-P and WA-311-P by paying for the cost (except for MPAL's share of $150,000) of drilling the Strumbo-1 well that was a dry hole. MPAL has withdrawn from all of these permits. During fiscal year 2001, MPAL acquired a 50% working interest in each of exploration permits WA-306-P and WA-307-P in the Barcoo Sub-basin of the southern Browse Basin, offshore Western Australia. Antrim Energy, a Canadian company, is the operator of the joint venture. During October 2004, Antrim Energy and ONGC Videsh Limited, an Indian company, funded the drilling of the South Galapagos-1 well in WA-306-P, including MPAL's estimated share of the well cost of $1,175,000. MPAL's interest in WA-306-P has reduced to 12.5%. At June 30, 2004, MPAL's share of the work obligations of the two permits totaled $4,603,000, of which $9,000 is committed. CARNARVON BASIN During fiscal year 1999, MPAL was awarded permit WA-291-P, offshore Western Australia in the Carnarvon Basin. Tap Oil, an Australian company, has agreed to participate in exploration on the permit and has a 50% interest in the permit. MPAL and Tap Oil are seeking additional partners to share the cost of drilling a well. At June 30, 2004, MPAL's share (50%) of the work obligations of the permit totaled $2,510,000, of which is $35,000 is committed. MARYBOROUGH BASIN MPAL holds a 100% interest in exploration permit ATP 613P in the Maryborough Basin in Queensland, Australia. MPAL (100%) also has applications pending for permits ATP 674P and ATP 733P which are adjacent to ATP 613P. Novus Australia Energy Company Limited earned a 50% interest in the North Area of the permit by drilling the Gregory River-3 well in 2003. The well was a dry hole and Novus withdrew from the area. At June 30, 2004, MPAL's share of the work obligations of permit ATP 613P totaled $1,119,000, of which $227,000 is committed. COOPER/EROMANGA BASIN PEL 94 & PEL 95 During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum NL were successful in bidding for two exploration blocks (PEL 94 and PEL 95) in South Australia's Cooper Basin. Aldinga-1 was 4 completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. By June 2004, production had declined to about 30 barrels of oil per day. During November 2003, the Waitpinga-1 well was drilled in PEL 94 and the Seacliff-1 well in PEL 95. Both wells were dry holes. In June 2004, an additional two wells were drilled, Myponga-1 in PEL 94 and Noarlunga-1 in PEL 95. Both these wells were dry holes. Black Rock Petroleum NL contributed to the cost of drilling the Myponga-1 well to earn a 15% interest in the PEL 94 permit. MPAL's interest in PEL 94 is reducing to 35%. MPAL's share of the cost of the four wells was approximately $1,000,000. These have been reflected as exploration and production costs in the consolidated financial statements. At June 30, 2004, MPAL's share of the work obligations of the two permits totaled $1,071,000, of which $17,000 is committed. PEL 110 & PELA 116 During fiscal year 2001, MPAL and its partner Beach Petroleum NL were also successful in bidding for two additional exploration blocks, PEL 110 (37.5%) and PELA 116 (50%) in the Cooper Basin. PEL 110 was granted in February 2003 and PEL 116 remains under application. During October 2003, the Semaphore-1 well was drilled in PEL 110. The well was a dry hole. Cooper Energy NL contributed to the cost of the well to earn a 25% interest in PEL 110. At June 30, 2004, MPAL's share of the work obligations of the PEL 110 permit totaled $841,000, of which $420,000 is committed. PL33 -- PL50 -- PL 51 -- ATP 267P, NOCKATUNGA During July 2003, MPAL reached an agreement with Voyager Energy Limited for the purchase of its 40.936% working interest (38.703% net revenue interest) in its Nockatunga assets in southwest Queensland. The assets comprise several producing oil fields in PLs 33, 50 and 51 together with exploration acreage in ATP 267P at a purchase price of approximately $1.4 million. The project is currently producing about 285 barrels of oil per day (MPAL share 115 bbls). A development well, Thungo-8, was drilled in PL 51 in October 2003 and is currently producing at around 10 barrels of oil per day. Callisto-1 was drilled in ATP 267P during November 2003. The well was a dry hole. A 3D seismic survey is planned for late 2004 over PL51 and parts of PL33 and ATP 267P. MPAL's share of the cost is approximately $1,065,000. At June 30, 2004, MPAL's share of the work obligations of ATP 267P totaled $315,000, of which none is committed. NEW ZEALAND PEP 38222 & PEP 38225 During fiscal 2002, MPAL (100%) was granted exploration permit PEP 38222, offshore south of the South Island of New Zealand. At June 30, 2004, MPAL's share of the work obligations of the permit totaled $11,678,000, all of which is discretionary. In November 2003, MPAL (100%) was granted permit PEP 38225, which is adjacent to PEP 38222. At June 30, 2004, MPAL's obligations of the PEP 38225 permit totaled $11,748,000, of which none is committed. PEP 38746 -- PEP 38748 -- PEP 38753 -- PEP 38765 -- PEP 38766 MPAL has a 25% interest in permits PEP 38746, PEP 38748 and PEP 38753 in the Taranaki Basin in the North Island, New Zealand. MPAL and its partners spudded the Warwiri-1 well in PEP 38753 during September 2003 at an approximate cost of $268,000 to MPAL, and the Bluff-1 well in PEP 38746 during October. Both wells were dry holes. MPAL has withdrawn from the PEP 38753 permit. At June 30, 2004, MPAL's share of the work obligations of the PEP 38746 and PEP 38748 permits totaled $105,000, of which none is committed. The drilling plans for the Hihi-1 and Kakariki-1 wells in PEP 38753 are in progress and spudding of these wells is expected in 2004. MPAL was granted exploration permits PEP 38765 (12.5%) and PEP 38766 (25%) during February 2004. The drilling plan for the Miromiro-1 well in PEP 38765 is in progress and spudding of this well is expected later in calendar 2004. At June 30, 2004, MPAL's share of the work obligations of the PEP 38765 and PEP 38766 permits totaled $717,000, of which $175,000 is committed. 5 UNITED KINGDOM PEDL 098 & PEDL 099 During fiscal year 2001, MPAL acquired an interest in two licenses in southern England in the Weald-Wessex basin. The two licenses, PEDL 098 (22.5%) in the Isle of Wight and PEDL 099 (40%) in the Portsdown area of Hampshire, were each granted for a period of six years. The drilling plan for the Sandhills-2 well as the PEDL 098 obligation well is in progress and spudding of this well is expected in 2004. At June 30, 2004, MPAL's share of the work obligations of the permits totaled $660,000, of which none is committed. The UK companies, Northern Petroleum and Montrose Industries, will fund MPAL's share of the cost of the Sandhills-2 well. PEDL 112 & PEDL 113 During fiscal year 2002, MPAL acquired two additional licenses in southern England. The two licenses, PEDL 113 (22.5%, formerly 45%) in the Isle of Wight and PEDL 112 (33.3%) in the Kent area on the margin of the Weald-Wessex basin, were each granted for a period of six years. At June 30, 2004, MPAL's share of the work obligations of the permits totaled $818,000, of which $22,000 is committed. PEDL 125 & PEDL 126 Effective July 1, 2003, MPAL acquired two additional licenses each granted for a period of six years in southern England, PEDL 125 (50%) in Hampshire and PEDL 126 (50%) in West Sussex. At June 30, 2004, MPAL's share of the work obligations of the two permits totaled $1,114,000, of which $28,000 is obligatory. The drilling plan for the Hedge End-2 well in PEDL 125 is in progress and spudding of this well is expected in 2005. MPAL's (50%) share of the cost of the well is estimated at approximately $1,130,000, of which $28,000 is committed. CANADA MPC owns a 2.67% carried interest in a lease (31,885 gross acres, 850 net acres) in the southeast Yukon Territory, Canada, which includes the Kotaneelee gas field. Devon Canada Corporation is the operator of this partially developed field which is connected to a major pipeline system. Production at Kotaneelee commenced in February 1991. During September 2003, MPC entered into a settlement agreement with the litigants in the Kotaneelee litigation. In October 2003, the Company received approximately $851,000, after Canadian withholding taxes and reimbursement of certain past legal costs from the settlement. The plaintiffs, including MPC, terminated all litigation against the defendants related to the field, including the claim that the defendants failed to fully develop the field. Since each party agreed to bear its own legal costs, there were no taxable costs assessed against any of the parties. See Item 3. Legal Proceedings. (b) Financial Information About Industry Segments. The Company is engaged in only one industry, namely, oil and gas exploration, development, production and sale. The Company conducts such business through its two operating segments; MPC and its majority owned subsidiary MPAL. (c) (1) Narrative Description of the Business. MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. MPC is directly engaged in the exploration for, and the development and production and sale of oil and gas reserves in Canada, and indirectly through its subsidiary MPAL in Australia, New Zealand and the United Kingdom. 6 (i) Principal Products. MPAL has an interest in the Palm Valley gas field and in the Mereenie oil and gas field. See Item 1(a) -- Australia -- for a discussion of the oil and gas production from the Mereenie and Palm Valley fields. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in Canada. (ii) Status of Product or Segment. See Item 1(a) -- Australia and Canada -- for a discussion of the current and future operations of the Mereenie and Palm Valley fields in Australia, the Nockatunga fields in Australia and MPC's interest in the Kotaneelee field in Canada. (iii) Raw Materials. Not applicable. (iv) Patents, Licenses, Franchises and Concessions Held. MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs.
PERMIT EXPIRATION DATE LOCATION - ------ --------------- -------- Petroleum Lease No. 4 and No. 5 (Mereenie) (Amadeus Basin) November 2023 Northern Territory, Australia Petroleum Lease No. 3 (Palm Valley)(Amadeus Basin) November 2024 Northern Territory, Australia Retention License 2 (Dingo) (Amadeus Basin) October 2008 Northern Territory, Australia ATP 613P (Maryborough Basin) March 2007 Queensland, Australia ATP 674P (Maryborough Basin) Application pending Queensland, Australia ATP 733P (Maryborough Basin) Application pending Queensland, Australia ATP 267P (Nockatunga, Cooper Basin) November 2007 Queensland, Australia ATP 732P (Cooper Basin) Application pending Queensland, Australia WA-291-P (Carnarvon Basin) February 2006 Offshore Western Australia WA-306-P (Canning Basin) July 2006 Offshore Western Australia WA-307-P (Canning Basin) August 2006 Offshore Western Australia PEL 94 (Cooper Basin) November 2006 South Australia PEL 95 (Cooper Basin) October 2006 South Australia PEL110 (Cooper Basin) February 2008 South Australia PELA 116 (Cooper Basin) Application pending South Australia PEP 38746 (Taranaki Basin) August 2007 New Zealand PEP 38748 (Taranaki Basin) August 2007 New Zealand PEP 38753 (Taranaki Basin) August 2007 New Zealand PEP 38765 (Taranaki Basin) February 2009 New Zealand PEP 38766 (Taranaki Basin) February 2009 New Zealand PEP 38222 (Great South Basin) April 2008 New Zealand PEP 38225 (Great South Basin) November 2009 New Zealand PEP 38256 (Taranaki Basin) August 2007 New Zealand PEDL 098 (Weald/Wessex Basins) September 2006 United Kingdom PEDL 099 (Weald/Wessex Basins) September 2006 United Kingdom PEDL 112 (Weald Basin) January 2008 United Kingdom PEDL 113 (Weald/Wessex Basins) January 2008 United Kingdom PEDL 125 (Hampshire) July 2009 United Kingdom PEDL 126 (West Sussex) July 2009 United Kingdom
7 Leases issued by the Northern Territory are subject to the Petroleum (Prospecting and Mining) Act of the Northern Territory. Lessees have the exclusive right to produce petroleum from the land subject to a lease upon payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Rental payments may be offset against the royalty paid. The term of a lease is 21 years, and leases may be renewed for successive terms of 21 years each. Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL's properties. (v) Seasonality of Business. Although the Company's business is not seasonal, the demand for oil and especially gas is subject to fluctuations in the Australian weather. (vi) Working Capital Items. See Item 7 -- Liquidity and Capital Resources for a discussion of this information. (vii) Customers. Although the majority of MPAL's producing oil and gas properties are located in a relatively remote area in central Australia (See Item 1 -- Business and Item 2 -- Properties), the completion in January 1987 of the Amadeus Basin to Darwin gas pipeline has provided access to and expanded the potential market for MPAL's gas production. Natural Gas Production MPAL's principal customer and the most likely major customer for future gas sales is PAWC, a governmental authority of the Northern Territory Government, which also has substantial regulatory authority over MPAL's oil and gas operations. The loss of PAWC as a customer would have a material adverse effect on MPAL's business. Oil Production Presently all of the crude oil production from Mereenie is being shipped and sold through the Port Bonython Export Terminal, Whyalla, South Australia. Crude oil production from Aldinga and Nocatunga is shipped and sold through the IOR refinery at Eromanga, Southwest Queensland. (viii) Backlog. Not applicable. (ix) Renegotiation of Profits or Termination of Contracts or Subcontracts at the Election of the Government. Not applicable. (x) Competitive Conditions in the Business. The exploration for and production of oil and gas are highly competitive operations. The ability to exploit a discovery of oil or gas is dependent upon such considerations as the ability to finance development costs, the availability of equipment, and the possibility of engineering and construction delays and difficulties. The Company also must compete with major oil and gas companies which have substantially greater resources than the Company. Furthermore, various forms of energy legislation which have been or may be proposed in the countries in which the Company holds interests may substantially affect competitive conditions. However, it is not possible to predict the nature of any such legislation which may ultimately be adopted or its effects upon the future operations of the Company. 8 At the present time, the Company's principal income producing operations are in Australia and for this reason, current competitive conditions in Australia are material to the Company's future. Currently, most indigenous crude oil is consumed within Australia. In addition, refiners and others import crude oil to meet the overall demand in Australia. The Palm Valley Producers and the Mereenie Producers are developing and separately marketing the production from each field. Because of the relatively remote location of the Amadeus Basin and the inherent nature of the market for gas, it would be impractical for each working interest partner to attempt to market its respective share of production from each field. (xi) Research and Development. Not applicable. (xii) Environmental Regulation. The Company is subject to the environmental laws and regulations of the jurisdictions in which it carries on its business, and existing or future laws and regulations could have a significant impact on the exploration for and development of natural resources by the Company. However, to date, the Company has not been required to spend any material amounts for environmental control facilities. The federal and state governments in Australia strictly monitor compliance with these laws but compliance therewith has not had any adverse impact on the Company's operations or its financial resources. At June 30, 2004, the Company had accrued approximately $4.9 million for asset retirement obligations for the Mereenie, Palm Valley, Kotaneelee, Nockatunga and Dingo fields. See Note 2 of the Consolidated Financial Statements under Item 8. Financial Statements and Supplementary Data. (xiii) Number of Persons Employed by Company. At June 30, 2004, MPC had one full-time employee in the United States and MPAL had 31 employees in Australia. MPC relies to a great extent on consultants for legal, accounting, administrative and geological services. (d) (2) Financial Information Relating to Foreign and Domestic Operations. See Note 10 to the Consolidated Financial Statements. (3) Risks Attendant to Foreign Operations. Most of the properties in which the Company has interests are located outside the United States and are subject to certain risks involved in the ownership and development of such foreign property interests. These risks include but are not limited to those of: nationalization; expropriation; confiscatory taxation; changes in foreign exchange controls; currency revaluations; price controls or excessive royalties; export sales restrictions; limitations on the transfer of interests in exploration licenses; and other laws and regulations which may adversely affect the Company's properties, such as those providing for conservation, proration, curtailment, cessation, or other limitations of controls on the production of or exploration for hydrocarbons. Thus, an investment in the Company represents a speculation with risks in addition to those inherent in domestic petroleum exploratory ventures. Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL's properties. (4) Data Which are Not Indicative of Current or Future Operations. None. ITEM 2. PROPERTIES. (a) MPC has interests in properties in Australia through its 55% equity interest in MPAL which holds interests in the Northern Territory, Queensland, South Australia and Western Australia. MPAL also has 9 interests in New Zealand and the United Kingdom. In Canada, MPC has a direct interest in one lease. For additional information regarding the Company's properties, See Item 1 -- Business. (b) (1) The information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows and results of operations is contained in Supplementary Oil & Gas Information under Item 8 -- Financial Statements and Supplementary Data. The following graphic presentation has been omitted, but the following is a description of the omitted material: AUSTRALIAN MAP WITH MPAL PROJECTS SHOWN The following graphic presentation has been omitted, but the following is a description of the omitted material: AMADEUS BASIN PROJECTS MAP The map indicates the location of the Amadeus Basin interests in the Northern Territory of Australia. The following items are identified: Palm Valley Gas Field Mereenie Oil & Gas Field Dingo Gas Field Nockatunga Oil Field Palm Valley -- Alice Springs Gas Pipeline Palm Valley -- Darwin Gas Pipeline Mereenie Spur Gas Pipeline The following graphic presentation has been omitted, but the following is a description of the omitted material: CANADIAN PROPERTY INTERESTS MAP The map indicates the location of the Kotaneelee Gas Field in the Yukon Territories of Canada. The map identifies the following items: Kotaneelee Gas Field Pointed Mountain Gas Field Beaver River Gas Field The following graphic presentation has been omitted, but the following is a description of the omitted material: UNITED KINGDOM PROPERTY INTERESTS MAP The map indicates the location of the MPAL property interests in the United Kingdom. The following graphic presentation has been omitted, but the following is a description of the omitted material: NEW ZEALAND PROPERTY INTERESTS MAP The map indicates the location of the MPAL property interests in New Zealand. (2) Reserves Reported to Other Agencies. None 10 (3) Production. MPC's net production volumes for gas and oil during the three years ended June 30, 2004 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material)
JUNE 30, --------------------------- 2004 2003 2002 ------- ------- ------- Australia: Gas (bcf)............................................... 7 6 7 Crude oil (bbl)......................................... 151,582 126,000 161,650
The average sales price per unit of production for Australia for the following fiscal years is as follows:
JUNE 30, ------------------------------ 2004 2003 2002 -------- -------- -------- Australia: Gas (per mcf)........................................ A.$ 2.61 A.$ 2.65 A.$ 2.53 Crude oil (per bbl).................................. A.$42.12 A.$42.82 A.$41.70
The average production cost per unit of production for the following fiscal years has been impacted by transportation costs on Mereenie oil in Australia. During fiscal 2004, 2003 and 2002, the cost of remedial work on various wells in the Mereenie field and lower production levels increased production costs.
JUNE 30, ------------------------------ 2004 2003 2002 -------- -------- -------- Australia: Gas (per mcf)........................................ A.$ .49 A.$ .48 A.$ .46 Crude oil (per bbl).................................. A.$.25.68 A.$29.15 A.$25.09
Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the year ended June 30, 2004, 2003 and 2002 the average foreign exchange rates were .7179, .5852, and .5238, respectively. (4) Productive Wells and Acreage. Productive wells and acreage at June 30, 2004:
PRODUCTIVE WELLS --------------------------- OIL GAS DEVELOPED ACREAGE ------------ ------------ ----------------------- GROSS NET GROSS NET GROSS ACRES NET ACRES ----- ---- ----- ---- ----------- --------- Australia............................ 42.0 15.6 13.0 5.40 78,771 32,551 Canada............................... -- -- 2.0 .05 3,350 89 ---- ---- ---- ---- ------ ------ 42.0 15.6 15.0 5.45 82,121 32,640 ==== ==== ==== ==== ====== ======
11 (5) Undeveloped Acreage. The Company's undeveloped acreage (except as indicated below) is set forth in the table below: GROSS AND NET ACREAGE AS OF JUNE 30, 2004 MPAL has interests in the following properties (before royalties). MPC has an interest in these properties through its 55% interest in MPAL.
MPAL MPC ----------------------------------- -------------------- INTEREST INTEREST GROSS ACRES NET ACRES % NET ACRES % ----------- ---------- -------- --------- -------- Australia Northern Territory -- (Amadeus Basin) Mereenie (OL4&5)(1).................... 69,407 24,292 35.00 13,376 19.27 Palm Valley (OL3)(2)................... 157,833 82,109 52.00 45,209 28.64 Dingo (RL2)............................ 115,596 39,696 34.34 21,857 18.91 ---------- ---------- --------- 342,836 146,097 80,440 ---------- ---------- --------- Queensland: Maryborough Basin (ATP 613P)........... 288,002 288,002 100.00 158,574 55.06 Maryborough Basin (ATP 674P)........... 1,954,017 1,954,017 100.00 1,075,882 55.06 Maryborough Basin (ATP 733)............ 326,534 326,534 100.00 179,790 55.06 ---------- ---------- --------- 2,568,553 2,568,553 1,414,246 ---------- ---------- --------- South Australia: Cooper Basin (PELA 94)(4).............. 669,370 234,280 35.00 128,995 19.27 Cooper Basin (PELA 95)................. 960,830 480,415 50.00 264,516 27.53 Cooper Basin (PELA 110)................ 361,114 135,418 37.50 74,561 20.65 Cooper Basin (PELA 116)................ 705,185 352,593 50.00 194,138 27.53 Cooper Basin (PL 33/50/51)............. 88,179 36,101 40.94 19,877 22.54 Cooper Basin (ATP 267)................. 177,346 72,605 40.94 39,976 22.54 Cooper Basin (ATP 732)................. 654,056 654,056 100.00 360,123 55.06 ---------- ---------- --------- 3,616,080 1,965,468 1,082,186 ---------- ---------- --------- Western Australia: Carnarvon WA-291-P..................... 2,221,518 1,110,759 50.00 611,584 27.53 Browse WA-306.......................... 1,194,739 149,342 12.50 82,228 6.88 Browse WA-307.......................... 856,843 428,422 50.00 235,889 27.53 ---------- ---------- --------- 4,273,100 1,688,523 929,701 ---------- ---------- --------- United Kingdom PEDL 098.................. 56,810 12,782 22.50 7,038 12.39 PEDL 099............................... 39,273 15,709 40.00 8,649 22.02 PEDL 112............................... 98,800 32,933 33.33 18,133 18.35 PEDL 113............................... 27,170 6,113 22.50 3,368 12.39 PEDL 125/126........................... 112,385 56,193 50.00 30,940 27.53 ---------- ---------- --------- 334,438 123,730 68,128 ---------- ---------- --------- New Zealand PEP 38222.............................. 3,002,779 3,002,779 100.00 1,653,330 55.06 PEP 38746/48/53........................ 64,961 16,240 25.00 8,942 13.77
12
MPAL MPC ----------------------------------- -------------------- INTEREST INTEREST GROSS ACRES NET ACRES % NET ACRES % ----------- ---------- -------- --------- -------- PEP 38256.............................. 688,389 172,097 25.00 94,757 13.77 PEP 38765.............................. 3,211 401 12.50 221 6.88 PEP 38766.............................. 494 124 25.00 68 13.77 PEP 38225.............................. 2,908,919 2,908,919 100.00 1,601,651 55.06 ---------- ---------- ------ --------- ----- 6,668,753 6,100,560 3,358,969 ---------- ---------- --------- Total MPAL............................... 17,803,760 12,592,931 6,933,670 ---------- ---------- --------- PROPERTIES HELD DIRECTLY BY MPC: Canada Yukon and Northwest Territories: Carried interest(3)................. 31,885 850 2.67 ---------- --------- Total.................................... 17,835,645 6,934,520 ========== =========
- --------------- (1) Includes 41,644 gross developed acres and 14,575 net acres. (2) Includes 31,567 gross developed acres and 16,422 net acres. (3) Includes 3,350 gross developed acres and 89 net acres. (4) Includes 346 gross developed acres and 173 net acres. (6) Drilling Activity. Productive and dry net wells drilled during the following years (data concerning Canada and the United States is insignificant):
AUSTRALIA/NEW ZEALAND ------------------------------------- EXPLORATION DEVELOPMENT YEAR ENDED ------------------ ---------------- JUNE 30, PRODUCTIVE DRY PRODUCTIVE DRY - ---------- ---------- ----- ---------- --- 2004................................................ -- 3.11.. .41 .52 2003................................................ .50 1.90 -- -- 2002................................................ -- .35 -- --
(7) Present Activities. There were two wells being drilled at June 30, 2004. During August 2004, the Company decided to plug and abandon development well Palm Valley-11. See Item 1 -- Cooper Basin and New Zealand for a discussion of the present activities of MPAL. (8) Delivery Commitments. See discussion under Item 1 concerning the Palm Valley and Mereenie fields. ITEM 3. LEGAL PROCEEDINGS. KOTANEELEE GAS FIELD MPC's 2.67% carried interest in the Kotaneelee gas field is held in trust by Canada Southern Petroleum Ltd. (Canada Southern) which has a 30.7% carried interest in the field. Canada Southern and MPC (the plaintiffs) had believed that the working interest owners in the Kotaneelee gas field had not adequately pursued the attainment of contracts for the sale of Kotaneelee gas. In October 1989 and March 1990, Canada Southern filed statements of claim in the Court of Queens Bench of Alberta, Judicial District of Calgary, Canada, against the working interest partners in the Kotaneelee gas field. MPC was subsequently added as a Plaintiff in the action. The named defendants were Amoco 13 Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco Canada Resources Ltd.), and Amoco Production Company (collectively the Amoco Dome Group), Columbia Gas Development of Canada Ltd., Mobil Oil Canada Ltd. and Esso Resource of Canada Ltd. (collectively the defendants). During September 2003, the litigants in the Kotaneelee litigation entered into a settlement agreement. In October 2003, the Company received approximately $851,000, after Canadian withholding taxes and reimbursement of certain past legal costs. The plaintiffs terminated all litigation against the defendants related to the field, including the claim that the defendants failed to fully develop the field. Since each party agreed to bear its own legal costs, there were no taxable costs assessed against any of the parties. The components of the settlement payment, which was recorded in September 2003 are as follows: Gas sales................................................... $1,135,000 Interest income............................................. 102,000 Canadian withholding taxes.................................. (386,000) ---------- Total....................................................... $ 851,000 ==========
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None. EXECUTIVE OFFICERS OF THE REGISTRANT The following information with respect to the current and former executive officers of the Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
LENGTH OF SERVICE OTHER POSITIONS HELD NAME AGE OFFICE HELD AS AN OFFICER WITH COMPANY - ---- --- ----------- ----------------- -------------------- James R. Joyce(1)..... 62 President and Chief Since 1993 Since Director Financial Officer 1990 T. Gwynn Davies....... 57 General Manager -- Since 2001 None MPAL Daniel J. Samela(2)... 56 Treasurer Since 2004 None
- --------------- (1) Retired as officer and director effective June 30, 2004. (2) Effective July 1, 2004 office held is President and Chief Financial Officer. All officers of MPC are elected annually by the Board of Directors and serve at the pleasure of the Board of Directors. MPC is not aware of any arrangements or understandings between any of the individuals named above and any other person pursuant to which any individual named above was selected as an officer. PART II ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF SECURITIES (a) Principal Market The principal market for MPC's common stock is the NASDAQ SmallCap market under the symbol MPET. The stock is also traded on the Boston Stock Exchange under the symbol MPC. The quarterly high 14 and low prices and the number of shares traded on the most active market, NASDAQ, during the calendar quarterly periods indicated were as follows:
2004 1ST QTR. 2ND QTR. 3RD QTR. 4TH QTR. - ---- -------- -------- -------- -------- High............................................... 1.37 1.57 2.32 1.80 Low................................................ .98 1.00 1.36 1.02
2003 1ST QTR. 2ND QTR. 3RD QTR. 4TH QTR. - ---- -------- -------- -------- -------- High............................................... 1.03 1.27 1.37 1.57 Low................................................ .81 .79 .98 1.00
2002 1ST QTR. 2ND QTR. 3RD QTR. 4TH QTR. - ---- -------- -------- -------- -------- High............................................... .95 1.11 1.07.. .91 Low................................................ .64 .80 .63... .68
(b) Approximate Number of Holders of Common Stock at October 12, 2004
TITLE OF CLASS NUMBER OF RECORD HOLDERS - -------------- ------------------------ Common stock, par value $.01 per share...................... 7,752
(c) Frequency and Amount of Dividends MPC has never paid a cash dividend on its common stock. RECENT SALES OF UNREGISTERED SECURITIES On September 2, 2003, the Company completed its previously announced acquisition of 1,200,000 shares of its majority-owned subsidiary, MPAL, from Sagasco Amadeus Pty Limited (Sagasco), a subsidiary of Origin Energy Limited, a diversified energy company based in Sydney, Australia. The acquisition of MPAL shares by the Company was made pursuant to a share sale agreement entered into by the Company and Sagasco, dated as of July 10, 2003 (Share Sale Agreement). The MPAL share acquisition followed the receipt of governmental approval in Australia and has increased the Company's holdings in MPAL from 52.4% to approximately 55%. In consideration for its receipt of the MPAL shares, the Company issued to Sagasco 1,300,000 shares of its common stock, par value $.01 per share in a private placement transaction conducted outside the United States pursuant to the exemption from registration provided by Regulation S under the Securities Act of 1933. The fair value of the 1,300,000 shares on July 10, 2003 was $1,508,000, based on the closing price of the Company's common stock on the Nasdaq SmallCap Market on that date. At the closing, the Company also entered into a registration rights agreement with Sagasco, dated as of September 2, 2003 (Registration Rights Agreement), pursuant to which the Company has agreed to register, upon receipt of a written demand by Sagasco, the 1,300,000 shares of common stock for public resale by Sagasco under the Securities Act. Sagasco exercised its rights under the Registration Rights Agreement to cause the Company to prepare and file a registration statement under the Securities Act covering the public resale by Sagasco of the 1,300,000 shares. On October 8, 2003, the Company filed a registration statement on Form S-3 to register the 1.3 million shares issued to Origin Energy for resale that was declared effective on February 20, 2004. As of April 21, 2004, Origin Energy had resold all of the 1.3 million shares of the Company's common stock. 15 ISSUER PURCHASES OF EQUITY SECURITIES The following table sets forth the number of shares that the Company has repurchased under any of its repurchase plans for the stated periods, the cost per share of such repurchases and the number of shares that may yet be repurchased under the plans:
MAXIMUM TOTAL NUMBER OF NUMBER OF TOTAL NUMBER OF AVERAGE PRICE SHARES PURCHASED SHARES THAT MAY SHARES PAID AS PART OF PUBLICLY YET BE PURCHASED PERIOD PURCHASED PER SHARE ANNOUNCED PLAN(1) UNDER PLAN - ------ --------------- ------------- ------------------- ---------------- April 1-30, 2004.......... 0 0 0 319,150 May 1-31, 2004............ 0 0 0 319,150 June 1-30, 2004........... 0 0 0 319,150
- --------------- (1) The Company through its stock repurchase plan may purchase up to one million shares of its common stock in the open market. Through June 30, 2004, the Company had purchased 680,850 of its shares at an average price of $1.01 per share, or a total cost of approximately $686,000, all of which shares have been cancelled. 16 ITEM 6. SELECTED FINANCIAL DATA. The following table sets forth selected data (in thousands) and other operating information of the Company. The selected consolidated financial data in the table are derived from the consolidated financial statements of the Company. This data should be read in conjunction with the consolidated financial statements, related notes and other financial information included herein.
YEARS ENDED JUNE 30, ---------------------------------------------------- 2004 2003 2002 2001 2000 -------- -------- -------- -------- -------- FINANCIAL DATA Operating revenues...................... $ 19,424 $ 14,736 $ 13,700 $ 14,008 $ 16,330 ======== ======== ======== ======== ======== Total revenues.......................... 20,524 15,596 14,352 14,900 17,147 ======== ======== ======== ======== ======== Net income before cumulative effect of accounting change..................... 350 890 92 1,072 1,490 Net income.............................. 350 152 92 1,072 1,490 ======== ======== ======== ======== ======== Net income per share (basic and diluted).............................. .01 .01 -- .04 .06 ======== ======== ======== ======== ======== Working capital......................... 21,897 21,798 17,862 15,398 15,046 ======== ======== ======== ======== ======== Cash provided by operating activities... 11,503 9,074 8,157 4,668 8,157 ======== ======== ======== ======== ======== Property and equipment (net)............ 24,421 21,592 17,046 16,482 21,741 ======== ======== ======== ======== ======== Total assets............................ 52,894 50,741 40,166 37,498 43,976 ======== ======== ======== ======== ======== Long-term liabilities................... 5,256 5,629 3,974 3,982 5,190 ======== ======== ======== ======== ======== Minority interests...................... 16,533 16,931 13,933 12,701 14,696 ======== ======== ======== ======== ======== Stockholders' equity: Capital............................... 44,660 43,152 43,332 43,426 43,838 Accumulated deficit................... (15,248) (15,598) (15,751) (15,843) (16,914) Accumulated other comprehensive loss............................... (4,491) (5,407) (8,965) (10,410) (7,827) -------- -------- -------- -------- -------- Total stockholders' equity............ 24,920 22,147 18,616 17,173 19,097 ======== ======== ======== ======== ======== Exchange rate A.$ = U.S. at end of period................................ .70 .67 .56 .51 .60 ======== ======== ======== ======== ======== Common stock outstanding shares end of period................................ 25,783 24,427 24,607 24,698 25,108 ======== ======== ======== ======== ======== Book value per share.................... .97 .91 .76 .70 .76 ======== ======== ======== ======== ======== Quoted market value per share........... 1.31 1.20 .88 1.07 1.28 ======== ======== ======== ======== ======== OPERATING DATA Standardized measure of discounted future cash flow relating to proved oil and gas reserves. (approximately 45% attributable to minority interests)............................ 30,000 26,000 26,000 33,000 44,000 ======== ======== ======== ======== ======== Annual production (net of royalties) Gas (bcf)............................. 5.7 6.0 6.0 5.7 6.0 ======== ======== ======== ======== ======== Oil (bbls) (In thousands) (net of royalties)......................... 151 126 141 148 172 ======== ======== ======== ======== ========
17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. FORWARD LOOKING STATEMENTS Statements included in Management's Discussion and Analysis of Financial Condition and Results of Operations which are not historical in nature are intended to be, and are hereby identified as, forward looking statements for purposes of the "Safe Harbor" Statement under the Private Securities Litigation Reform Act of 1995. The Company cautions readers that forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward looking statements. Among these risks and uncertainties are pricing and production levels from the properties in which the Company has interests, and the extent of the recoverable reserves at those properties. In addition, the Company has a large number of exploration permits and there is the risk that any wells drilled may fail to encounter hydrocarbons in commercial quantities. The Company undertakes no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CRITICAL ACCOUNTING POLICIES OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. The Company records its proportionate share in joint venture operations in the respective classifications of assets, liabilities and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Company estimates the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Other exploration costs, including geological and geophysical expenses, leasehold expiration costs and delay rentals, are expensed as incurred. Because the Company follows the successful efforts method of accounting, the results of operations may vary materially from quarter to quarter. An active exploration program may result in greater exploration and dry hole costs. ASSET RETIREMENT OBLIGATIONS Effective July 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards ("SFAS") 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on a units-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves. See Note 2 to the consolidated financial statements regarding the cumulative effect of the accounting change and its effect on net income. The estimated liability is based on the future estimated cost of land reclamation, plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley, Mereenie, Kotaneelee, Nockatunga and Dingo fields. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. A market risk premium was excluded from the estimate of asset retirement obligations because the amount was not capable of being estimated. Revisions to the liability could occur due to changes in the estimates of these costs, acquisition of additional properties and as new wells are drilled. 18 Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred. REVENUE RECOGNITION The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company's share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Shipping and handling costs in connection with such deliveries are included in production costs (cost of goods sold). Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. As a result, net revenues from carried interests may lag the production month by one or more months. LIQUIDITY AND CAPITAL RESOURCES During September 2003, the litigants in the Kotaneelee litigation entered into a settlement agreement. In October 2003, the Company received approximately $851,000, after Canadian withholding taxes and reimbursement of certain past legal costs. The plaintiffs terminated all litigation against the defendants related to the field, including the claim that the defendants failed to fully develop the field. Since each party has agreed to bear its own legal costs, there were no taxable costs assessed against any of the parties. The settlement was recorded during the quarter ending September 30, 2003. See Note 2 to the consolidated financial statements. CONSOLIDATED At June 30, 2004, the Company on a consolidated basis had approximately $20.4 million of cash and cash equivalents and marketable securities. Net cash provided by operations was $11,503,323 in 2004 compared to $9,073,000 in 2003. The increase is primarily related to the cash received from the Kotaneelee settlement and increased collections from MPAL's largest customer. Cash flow from operations is primarily the result of MPAL's oil and gas activities. During 2004, the Company had net investments in marketable securities of $990,000 compared to $493,000 in 2003. The increase in investments was the result of MPC investing the cash received from the Kotaneelee settlement. The Company invested $9,723,210 and $6,365,000 in oil and gas exploration activities during 2004 and 2003, respectively. The net increase resulted from an increase in investment in the Mereenie and Palm Valley fields and the acquisition of Nockatunga. The Company continues to invest in exploratory projects that result in exploratory and dry hole expenses in the consolidated financial statements. AS TO MPC (UNCONSOLIDATED) At June 30, 2004, MPC, on an unconsolidated basis, had working capital of approximately $3.6 million. Working capital is comprised of current assets less current liabilities. MPC's current cash position, its annual MPAL dividend and the anticipated revenue from the Kotaneelee field should be adequate to meet its current cash requirements. MPC has in the past invested and may in the future invest substantial portions of its cash to maintain or increase its majority interest in its subsidiary, MPAL. On July 10, 2003, a subsidiary of Origin Energy, Sagasco Amadeus Pty. Limited, agreed to exchange 1.2 million shares of MPAL for 1.3 million shares of the Company's common stock. After the exchange was completed on September 2, 2003, the Company's interest in MPAL increased to 55%. In addition to the aforementioned stock exchange, during fiscal 2004, MPC purchased 24,259 shares of MPAL's stock at a cost of $22,259 and increased its interest in MPAL from 55.00% to 55.06%. 19 During fiscal 2004, MPC received a dividend from MPAL of approximately $911,000. During the fiscal year 2001, MPC announced a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2004, MPC had purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal 2004. AS TO MPAL At June 30, 2004, MPAL had working capital of approximately $18.3 million. MPAL has budgeted approximately $5.3 million for specific exploration projects in fiscal year 2004 as compared to the $5.0 million expended during fiscal 2004. However, the total amount to be expended may vary depending on when various projects reach the drilling phase. The current composition of MPAL's oil and gas reserves are such that MPAL's future revenues in the long term are expected to be derived from the sale of gas in Australia. MPAL's current contracts for the sale of Palm Valley and Mereenie gas will expire during fiscal year 2012 and 2009, respectively. Unless MPAL is able to obtain additional contracts for its remaining gas reserves or be successful in its current exploration program, its revenues will be materially reduced after 2009. MPAL expects to fund its exploration costs through its cash and cash equivalents and cash flow from Australian operations. MPAL also expects that it will seek partners to share its exploration costs. If MPAL's efforts to find partners are unsuccessful, it may be unable or unwilling to complete the exploration program for some of its properties. OFF BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS We do not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company does not engage in trading or risk management activities and does not have material transactions involving related parties. The following is a summary of our consolidated contractual obligations:
PAYMENTS DUE BY PERIOD ------------------------------------------------------------- LESS THAN MORE THAN CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS - ----------------------- ----------- ---------- --------- ---------- --------- Long-Term Debt Obligations............. -- -- -- -- -- Capital Lease Obligations............. -- -- -- -- -- Operating Lease Obligations............. 858,000 163,000 347,000 348,000 -- Purchase Obligations(1)... 4,496,000 4,102,000 394,000 -- -- Other Long-Term Liabilities Reflected on the Registrant's Balance Sheet Under GAAP........ 4,852,000 34,000 155,000 4,663,000 -- ----------- ---------- -------- ---------- ---- Total................ $10,206,000 $4,299,000 $896,000 $5,011,000 -- =========== ========== ======== ========== ====
- --------------- (1) Represents firm commitments for exploration and capital expenditures. Exploration contingent expenditures of $36,419,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $17,195, 000 (less than 1 year), $16,649,000 (1-3 years), $2,575,000 (3-5 years). In January 2003, the FASB issued Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," was effective for the Company on December 31, 2003. FIN 46 requires that the party to a VIE that absorbs the majority of the VIE's losses, defined as the "primary beneficiary," consolidate the VIE. The Company has determined that it is not required to consolidate or disclose information about a VIE. In December 2003, the FASB issued a revised version of FIN 46R that was effective for the Company for fiscal year 2004. FIN 46R did not have an impact on the Company's consolidated financial statements. 20 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for the Company for the first quarter of fiscal 2004. The adoption of SFAS No. 150 did not have an impact on the Company's financial statements. In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits." (SFAS No. 132R) This statement revises employers' disclosures about pension plans and other postretirement benefit plans, requires additional disclosures about the assets, obligations, cash flows, and the net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans and requires companies to disclose various elements of pension and postretirement benefit costs in interim period financial statements. The annual disclosures in SFAS No. 132R are effective for the Company's defined benefit pension plan for the fiscal year ended June 30, 2004. The required disclosures are included in Note 8. Pension plan costs. RESULTS OF OPERATIONS 2004 VS. 2003 Revenues Oil sales increased 48% in 2004 to $4,923,000 from $3,329,000 in 2003 because of a 23% Australian foreign exchange rate increase discussed below and new oil sales from the Cooper Basin and the Nockatunga project. Oil unit sales are expected to continue to decline in the Mereenie field unless additional development wells are drilled to maintain production levels. MPAL is dependent on the operator (65% control) of the Mereenie field to maintain production. Oil unit sales (net of royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:
TWELVE MONTHS ENDED JUNE 30, ------------------------------------------------- 2004 SALES 2003 SALES ----------------------- ----------------------- AVERAGE PRICE AVERAGE PRICE BBLS A.$ PER BBL BBLS A.$ PER BBL ------- ------------- ------- ------------- Australia: Mereenie Field......................... 110,955 43.44 124,553 42.87 Cooper Basin........................... 6,522 37.29 800 34.41 Nockatunga Project..................... 34,105 38.73 -- -- ------- ----- ------- ----- Total.................................... 151,582 42.12 125,353 42.82 ======= ===== ======= =====
Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2004, 2003 and 2002 the average foreign exchange rates were .7179, .5852, and .5238, respectively. Gas sales increased 26% to $12,870,000 in 2004 from $10,182,000 in 2003 because of the 23% Australian foreign exchange rate increase discussed below and the $1,135,000 in gross proceeds from the Canadian Kotaneelee gas field settlement. In addition, the recurring portion of Kotaneelee revenues declined from $536,000 in 2003 to $423,000 in 2004 due to reduced production. This trend is likely to continue. These increases were partially offset by a 2% decrease in volume and a 3% decrease in Australian gas prices. 21 The volumes in billion cubic feet (bcf) (net of royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:
TWELVE MONTHS ENDED JUNE 30, ----------------------------------------------------- 2004 SALES 2003 SALES ------------------------- ------------------------- A.$ AVERAGE PRICE A.$ AVERAGE PRICE BCF PER MCF BCF PER MCF ----- ----------------- ----- ----------------- Australia: Palm Valley................. 2.376 2.25 2.604 2.43 Australia: Mereenie.................... 3.287 2.86 3.218 2.82 ----- ----- Total................................ 5.663 2.61 5.822 2.65 ===== =====
Other production related revenues increased 33% to $1,632,000 in 2004 from $1,225,000 in 2003. Other production related revenues are primarily MPAL's share of gas pipeline tariff revenues which increased as a result of the higher volumes of gas sold at Mereenie, and because of the 23% Australian foreign exchange rate increase discussed below. Interest and other income increased 28% to $1,099,000 in 2004 from $860,000 in 2003 primarily because of the $102,000 interest received from the funds held in escrow from the Kotaneelee settlement and because of the 23% Australian foreign exchange rate increase discussed below. Costs and Expenses Production costs increased 21% in 2004 to $5,416,000 from $4,461,000 in 2003 in part because of the 23% Australian foreign exchange rate increase discussed below. During 2004, production costs also increased because of the new costs of $545,000 for the Nockatunga project. These increases were partially offset by a decrease in production costs applicable to two wells that were plugged and abandoned in the Mereenie field in 2003. In addition, a Mereenie two well workover program was completed during the 2003 period. Exploration and dry hole costs increased 10% to $3,225,000 in 2004 from $2,920,000 in 2003. The 2004 and 2003 costs related to the exploration work being performed on MPAL's properties. The primary reason for the increase in 2004 is the 23% Australian foreign exchange rate increase discussed below. For the 2004 period, exploration costs totaled $1,509,000 and dry hole costs totaled $1,716,000. For the 2003 period, exploration costs totaled $2,043,000 and dry hole costs totaled $877,000. The dry holes were drilled on MPAL properties in Australia and New Zealand. Salaries and employee benefits increased 95% to $3,812,000 in 2004 from $1,958,000 in 2003. During the 2004 period, there was a 23% increase in the Australian foreign exchange rate discussed below. In addition, MPAL curtailed its pension plan in 2004 which resulted in a $1,248,000 charge, of which $961,000 was non cash. Depletion, depreciation and amortization increased 71% from $3,719,000 in 2003 to $6,342,000 in 2004. During the 2004 period, there was a 23% increase in the Australian foreign exchange rate as discussed below. Depletion expense for the Palm Valley and Mereenie fields increased 55% during the period primarily because of the increase in oil and gas properties related to MPC's increased interest in MPAL and the current Mereenie development program. In addition, in 2004, $528,000 in DD&A was also recorded for the Nockatunga project and the Cooper Basin. The reserves in the Cooper Basin were reduced by 50% from 50,000 barrels to 25,000 barrels during the current period because of lower oil production than estimated. In the 2003 period the Palm Valley gas reserves were increased by 35% and DD&A decreased by approximately $405,000 because of this change in gas reserves. Auditing, accounting and legal expenses increased 2% in 2004 to $414,000 from $404,000 in 2003 primarily because of the 23% Australian foreign exchange rate increase discussed below. The increase was partially offset because the 2003 period included higher audit fees in connection with the adoption of the new accounting standard for asset retirement obligations. 22 Accretion expense increased 47% in the 2004 period from $243,000 in 2003 to $357,000 in 2004. Accretion expense represents the accretion on the asset retirement obligations (ARO) under SFAS 143 that was adopted effective July 1, 2002. The increase in the 2004 period results from the 23% increase in the Australian foreign exchange rate as discussed below and the additions for the Nockatunga project and the Kotaneelee gas field. Shareholder communications costs increased 5% from $171,000 in 2003 to $180,000 in 2004 primarily because of MPC and MPAL's increased costs related to their status as public companies. Other administrative expenses increased 78% from $370,000 in 2003 to $660,000 in 2004. During the 2004 period, there was a 23% increase in the Australian foreign exchange rate as discussed below. In addition, there were increases in consultants' fees ($134,000), directors' fees and expenses ($101,000), insurance costs ($120,000), rent ($72,000) and travel expenses ($26,000) during the 2004 period that were partially offset by an increase in the amount of overhead charges that MPAL as operator was able to charge its partners. The Company anticipates that it will be required in the future to incur significant administrative, auditing and legal expenses with respect to new SEC and accounting rules adopted pursuant to the Sarbanes-Oxley Act of 2002, particularly the requirements to document, test and audit the Company's internal controls to comply with Section 404 of the Act and rules adopted thereunder. Income tax benefits for the years ended June 30, 2004 and 2003 were $778,085 and $773,548, respectively. The income tax benefits were reduced $362,000 in 2004 related to Canadian withholding taxes as a result of increased revenues from the Kotaneelee Settlement. Income tax benefits were further reduced as a result of a decrease from $1,202,000 in 2003 to $929,000 in 2004 of financing related benefits received by MPAL. As a result of a change in Australian tax law during 2004, MPAL does not expect to receive similar financing benefits in the future. These reductions were offset by tax benefits from MPAL's operating losses. EXCHANGE EFFECT THE VALUE OF THE AUSTRALIAN DOLLAR RELATIVE TO THE U.S. DOLLAR INCREASED to $.6993 at June 30, 2004 compared to $.6737 at June 30, 2003. This resulted in a $915,000 credit to accumulated translation adjustments for fiscal 2004. The 4% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2004 from the June 30, 2003 amounts. The annual average exchange rate used to translate MPAL's operations in Australia for fiscal 2004 was $.7179, which is a 23% increase compared to the $.5852 rate for fiscal 2003. 2003 VS. 2002 Revenues OIL SALES INCREASED 2% IN 2003. Oil sales in Australia in 2003 amounted to $3,329,000 as compared to $3,259,000 in 2002 because of a 3% increase in oil prices and the 12% Australian foreign exchange increase discussed below which was partially offset by the 10% decrease in the number of units produced. Cooper Basin production began in May 2003. Oil unit sales (before deducting royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:
FISCAL 2003 SALES FISCAL 2002 SALES ----------------------- ----------------------- AVERAGE PRICE AVERAGE PRICE BBLS PER BBL BBLS PER BBL ------- ------------- ------- ------------- Australia -- Amadeus Basin............... 144,934 A.$42.87 161,650 A.$41.70 Australia -- Cooper Basin................ 930 A.$34.41 -- --
23 GAS SALES INCREASED 17% IN FISCAL 2003. Gas sales increased from $8,667,000 in 2002 to $10,182,000 in 2003 primarily because of the 5% increase in the average price of gas sold in Australia and the 12% Australian foreign exchange increase discussed below. Gas sales in 2003 include $535,000 ($483,000 in 2002) of gas sales from the Kotaneelee gas field in Canada. The volumes in billion cubic feet (bcf) (before deducting royalties) and the average price of gas per thousand cubic feet (mcf) sold in Australia during the periods indicated were as follows:
FISCAL 2003 SALES FISCAL 2002 SALES --------------------- --------------------- AVERAGE PRICE AVERAGE PRICE BCF PER MCF BCF PER MCF ----- ------------- ----- ------------- (A.$) (A.$) Australia -- Amadeus Basin: Palm Valley Alice Springs contract..................... 0.838 3.29 0.959 3.15 Darwin contract............................ 2.225 2.11 2.285 2.08 Mereenie Darwin contract............................ 3.704 2.80 3.233 2.55 Other...................................... 0.082 3.62 0.368 3.56 ----- ----- Total................................... 6.849 6.845 ===== =====
OTHER PRODUCTION INCOME DECREASED 31% TO $1,225,000 IN 2003 from $1,774,000 in 2002. Other production income includes royalties and MPAL's share of gas pipeline tariffs. The primary reason for this decrease was that MPAL's share of gas pipeline tariffs in 2002 included an additional amount of $855,000 of pipeline tariff revenue to reflect a resolution of a dispute regarding the calculation of the pipeline tariffs. The decrease in 2003 was partially offset by the 12% Australian foreign exchange increase as discussed below. INTEREST INCOME IN 2003 INCREASED 32%. Interest income in 2003 amounted to $860,000 as compared to $652,000 in 2002. More funds were available in Australia for investment at higher interest rates than in 2002 and there was a 12% Australian foreign exchange increase as discussed below. Costs and Expenses PRODUCTION COSTS INCREASED 18% IN 2003 to $4,461,000 from $3,770,000 in 2002 primarily because of the 12% increase in the Australian foreign exchange rate discussed below. During 2003, two wells were plugged and abandoned in the Mereenie field at a cost of approximately $86,000. The $27,000 difference between the amount of the asset retirement obligation of $59,000 and the abandonment costs of $86,000 is included in production costs. In addition, a Mereenie two well workover program was completed in 2003. EXPLORATORY AND DRY HOLE COSTS DECREASED 30% TO $2,920,000 IN 2003 from $4,143,000 in 2002. The 2003 and 2002 costs related primarily to the geological and geophysical work and seismic acquisition on MPAL's exploration permits. The costs in 2003 include MPAL's share of the dry hole costs of the Strumbo-1 well ($150,000) located offshore Western Australia, two Cooper Basin wells ($600,000) and the Gregory River-3 well ($524,000) in the Maryborough Basin in Queensland. In addition, the costs in 2002 include the dry hole costs (a total of $2.7 million incurred primarily in the second quarter of fiscal 2002) of the Carbine-1 and the Maribo-1 wells which were drilled in the Browse Basin offshore Western Australia. SALARIES AND EMPLOYEE BENEFITS INCREASED 57% TO $1,958,000 IN 2003 from $1,248,000 in 2002. During 2003, MPAL changed its classification of salary costs as overhead charged to its joint venture partners. Although this change resulted in an amount of $433,000 being charged to salaries and employee benefits there was a corresponding credit of $433,000 in other administrative expenses. The information necessary to reclassify 2002's expense amounts is not available. In addition, there was a 12% increase in the Australian foreign exchange rate as discussed below. There were also regular annual increases in salaries. DEPRECIATION, DEPLETION AND AMORTIZATION INCREASED 8% IN 2003 to $3,719,000 from $3,447,000 in 2002. During 2003, the Palm Valley gas reserves were increased by approximately 35% to reflect the current 24 operating performance of the field and the capability of the field to produce additional quantities of gas. This change reduced DD&A expense for 2003 by approximately $207,000. In addition, based on a 2003 study, salvage value was included in the calculation of DD&A. This change reduced DD&A expense by approximately $177,000 for 2003. The decrease in DD&A was offset by the 12% increase in the Australian exchange rate discussed below. AUDITING, ACCOUNTING AND LEGAL EXPENSES INCREASED 45% from $278,000 in 2002 to $404,000 in 2003 because of an increase in MPC's and MPAL's audit fees and the 12% increase in the Australian exchange rate discussed below. ACCRETION EXPENSE WAS $243,000 IN 2003 which represents the accretion on the Asset Retirement Obligation under SFAS 143 which was adopted effective July 1, 2002. The corresponding expense for 2002 would have been $261,000. SHAREHOLDER COMMUNICATIONS COSTS INCREASED 13% to $171,000 in 2003 compared to $152,000 in 2002 primarily because of MPAL's increased costs in satisfying its statutory obligations in Australia as a public company and MPC's costs in holding its Annual Meeting of Shareholders and an increase in its Nasdaq listing fees. OTHER ADMINISTRATIVE EXPENSES DECREASED 52% from $776,000 in 2002 to $370,000 in 2003 primarily because of an increase in the amount of overhead that MPAL, as operator, charged its partners during 2003. During 2003, MPAL also changed its classification of salary costs as overhead charged to its joint venture partners. Although this change of $433,000 resulted in an amount being charged to salaries and employee benefits, there was a corresponding credit of $433,000 in other administrative expenses. The information necessary to reclassify 2002's expense amounts is not available. The increase in the amount of overhead charged was partially offset by a 12% increase in the Australian foreign exchange rate and increases in consultants expenses ($51,000), directors fees ($52,000), insurance ($41,000) and rent ($51,000). Income Taxes INCOME TAX BENEFIT FOR 2003 WAS $774,000 compared to an income tax provision of $39,000 for 2002. The components of income tax expense (benefit) in thousands were as follows:
2003 2002 ------ ----- Pretax consolidated income.................................. $1,349 $ 537 MPC's losses not recognized............................... 326 236 Permanent differences..................................... (682) (872) ------ ----- Book taxable income (loss).................................. $ 993 $ (99) ====== ===== Australian tax rate......................................... 30% 30% ====== ===== Australian income tax (provision) benefit................... $ (298) $ 30 Tax benefit attributable to reconciliation of year end deferred tax liability.................................... 1,202 43 ------ ----- MPAL Australian benefit for income tax...................... 904 73 MPC income tax provision.................................... (130) (112) ------ ----- Consolidated income tax (provision) benefit................. $ 774 $ (39) ====== ===== Effective tax rate.......................................... (57)% 7% ====== =====
MPC's 2003 and 2002 income tax represents the 25% Canadian withholding tax on its Kotaneelee net proceeds. The tax benefits of $1,202,000 in fiscal 2003 and $43,000 in fiscal 2002 relate primarily to tax deductions taken in connection with financing current year exploration activities in Australia. 25 Exchange Effect THE VALUE OF THE AUSTRALIAN DOLLAR RELATIVE TO THE U.S. DOLLAR INCREASED to $.6737 at June 30, 2003 compared to $.5635 at June 30, 2002. This resulted in a $3,508,000 credit to accumulated translation adjustments for fiscal 2003. The 20% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2003 from the June 30, 2002 amounts. The annual average exchange rate used to translate MPAL's operations in Australia for fiscal 2003 was $.5852, which is a 12% increase compared to the $.5238 rate for fiscal 2002. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. The Company does not have any significant exposure to market risk, other than as previously discussed regarding foreign currency risk and the risk of fluctuations in the world price of crude oil, as the only market risk sensitive instruments are its investments in marketable securities. For the twelve months ended June 30, 2004, oil sales represented approximately 28% of production revenues, therefore, an increase in the world price of crude oil would only have a modest positive impact on the Company's earnings, while a decrease in crude oil prices would have a similar negative impact on earnings. Gas sales, which represented approximately 72% of production revenues in 2004, are derived primarily from the Palm Valley and Mereenie fields in the Northern Territory of Australia and the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index. At June 30, 2004, the carrying value of such investments including those classified as cash and cash equivalents was approximately $24 million, which approximates the fair value of the securities. Since the Company expects to hold the investments to maturity, the maturity value should be realized. 26 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Magellan Petroleum Corporation We have audited the accompanying consolidated balance sheet of Magellan Petroleum Corporation ("the Company") as of June 30, 2004, and the related consolidated statements of income, changes in stockholders' equity, and cash flows for the year then ended. 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 audit. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of June 30, 2004, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP October 13, 2004 Hartford, CT 27 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders Magellan Petroleum Corporation We have audited the accompanying consolidated balance sheet of Magellan Petroleum Corporation as of June 30, 2003 and the related consolidated statements of income, changes in stockholders' equity and cash flows for each of the two years in the period ended June 30, 2003. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Magellan Petroleum Corporation at June 30, 2003 and the consolidated results of its operations and its cash flows for each of the two years in the period ended June 30, 2003, in conformity with U.S. generally accepted accounting principles. As discussed in Notes 1 and 2 to the consolidated financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations. /s/ Ernst & Young LLP Stamford, Connecticut September 19, 2003 28 MAGELLAN PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS
JUNE 30, --------------------------- 2004 2003 ------------ ------------ ASSETS Current assets: Cash and cash equivalents................................. $ 20,406,620 $ 20,041,464 Accounts receivable -- Trade.............................. 2,931,609 4,174,869 Accounts receivable -- Working Interest Partners.......... 1,044,619 1,099,130 Marketable securities..................................... 2,584,296 1,796,503 Inventories............................................... 595,948 423,931 Other assets.............................................. 318,141 297,118 ------------ ------------ Total current assets................................... 27,881,233 27,833,015 ------------ ------------ Marketable securities....................................... 592,138 390,000 Property and equipment: Oil and gas properties (successful efforts method)........ 69,970,134 59,407,254 Land, buildings and equipment............................. 2,264,004 2,093,555 Field equipment........................................... 1,482,639 1,421,636 ------------ ------------ 73,716,777 62,922,445 Less accumulated depletion, depreciation and amortization........................................... (49,295,770) (41,330,271) ------------ ------------ Net property and equipment............................. 24,421,007 21,592,174 ------------ ------------ Other assets.............................................. -- 926,168 ------------ ------------ Total assets.............................................. $ 52,894,378 $ 50,741,357 ============ ============ LIABILITIES, MINORITY INTERESTS AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 4,367,305 $ 4,709,281 Accrued liabilities....................................... 1,550,045 1,218,997 Income taxes payable...................................... 267,645 106,246 ------------ ------------ Total current liabilities.............................. 6,184,995 6,034,524 ------------ ------------ Long term liabilities: Deferred income taxes..................................... 403,261 1,770,727 Asset retirement obligations.............................. 4,852,416 3,858,263 ------------ ------------ Total long term liabilities............................ 5,255,677 5,628,990 ------------ ------------ Minority interests.......................................... 16,533,491 16,930,838 Commitments (Note 11)....................................... -- -- Stockholders' equity: Common stock, par value $.01 per share: Authorized 200,000,000 shares outstanding 25,783,243 and 24,427,376 shares................................ 257,832 244,274 Capital in excess of par value............................ 44,402,182 42,907,741 ------------ ------------ Total capital............................................. 44,660,014 43,152,015 Accumulated deficit....................................... (15,248,422) (15,598,483) Accumulated other comprehensive loss...................... (4,491,377) (5,406,527) ------------ ------------ Total stockholders' equity.................................. 24,920,215 22,147,005 ------------ ------------ Total liabilities, minority interests and stockholders' equity.................................................... $ 52,894,378 $ 50,741,357 ============ ============
See accompanying notes. 29 MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED JUNE 30, --------------------------------------- 2004 2003 2002 ----------- ----------- ----------- REVENUES: Oil sales........................................... $ 4,922,585 $ 3,329,243 $ 3,259,213 Gas sales........................................... 12,870,065 10,182,104 8,667,431 Other production related revenues................... 1,631,613 1,224,729 1,773,808 Interest income..................................... 1,099,440 859,865 651,653 ----------- ----------- ----------- Total revenues...................................... 20,523,703 15,595,941 14,352,105 ----------- ----------- ----------- COSTS AND EXPENSES: Production costs.................................... 5,416,465 4,461,365 3,770,438 Exploratory and dry hole costs...................... 3,225,066 2,920,104 4,143,449 Salaries and employee benefits...................... 3,812,012 1,958,371 1,248,136 Depletion, depreciation and amortization............ 6,341,998 3,718,660 3,447,444 Auditing, accounting and legal services............. 413,754 404,215 278,045 Accretion expense................................... 356,981 242,854 -- Shareholder communications.......................... 179,840 171,385 151,897 Other administrative expenses....................... 659,751 369,942 776,077 ----------- ----------- ----------- Total costs and expenses............................ 20,405,867 14,246,896 13,815,486 ----------- ----------- ----------- Income before income taxes, minority interests and cumulative effect of accounting change.............. 117,836 1,349,045 536,619 Income tax (provision) benefit........................ 778,085 773,548 (39,099) ----------- ----------- ----------- Income before minority interests and cumulative effect of accounting change................................ 895,921 2,122,593 497,520 Minority interests.................................... (545,860) (1,232,200) (405,799) ----------- ----------- ----------- Income before cumulative effect of accounting change.............................................. 350,061 890,393 91,721 Cumulative effect of accounting change -- net......... -- (737,941) -- ----------- ----------- ----------- NET INCOME............................................ $ 350,061 $ 152,452 $ 91,721 =========== =========== =========== Average number of shares: Basic............................................... 25,644,566 24,560,068 24,622,980 =========== =========== =========== Diluted............................................. 25,682,160 24,560,068 24,622,980 =========== =========== =========== Per share (basic and diluted) Income before cumulative effect of accounting change........................................... $ .01 $ .04 $ -- Cumulative effect of accounting change -- net....... -- (.03) -- ----------- ----------- ----------- Net income............................................ $ .01 $ .01 $ -- =========== =========== ===========
See accompanying notes. 30 MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY THREE YEARS ENDED JUNE 30, 2004
ACCUMULATED CAPITAL IN OTHER TOTAL NUMBER COMMON EXCESS OF ACCUMULATED COMPREHENSIVE COMPREHENSIVE OF SHARES STOCK PAR VALUE DEFICIT LOSS TOTAL INCOME ---------- -------- ----------- ------------ ------------- ----------- ------------- JUNE 30, 2001........... 24,698,226 $246,982 $43,179,475 $(15,842,656) $(10,410,321) $17,173,480 Net income.............. -- -- -- 91,721 -- 91,721 $ 91,721 Foreign currency translation adjustments........... -- -- -- -- 1,729,157 1,729,157 1,729,157 Unrealized loss on available-for-sale securities............ -- -- -- -- (283,360) (283,360) (283,360) ---------- Total comprehensive income................ -- -- -- -- -- -- $1,537,518 ========== Repurchases of common stock................. (90,850) (908) (93,634) -- -- (94,542) ---------- -------- ----------- ------------ ------------ ----------- JUNE 30, 2002........... 24,607,376 $246,074 $43,085,841 $(15,750,935) $ (8,964,524) $18,616,456 ---------- -------- ----------- ------------ ------------ ----------- Net income.............. -- -- -- 152,452 -- 152,452 $ 152,452 Foreign currency translation adjustments........... -- -- -- -- 3,507,783 3,507,783 3,507,783 Reclassification adjustment on available-for-sale securities............ -- -- -- -- 50,214 50,214 50,214 ---------- Total comprehensive income................ -- -- -- -- -- -- $3,710,449 ========== Repurchases of common stock................. (180,000) (1,800) (178,100) -- -- (179,900) ---------- -------- ----------- ------------ ------------ ----------- JUNE 30, 2003........... 24,427,376 $244,274 $42,907,741 $(15,598,483) $ (5,406,527) $22,147,005 ---------- -------- ----------- ------------ ------------ ----------- Net income.............. -- -- -- 350,061 -- 350,061 350,061 Foreign currency translation adjustments........... -- -- -- -- 915,150 915,150 915,150 ---------- Total comprehensive income................ -- -- -- -- -- -- 1,265,211 ---------- Stock exchange.......... 1,300,000 13,000 1,495,000 1,508,000 Issuance of common stock................. 55,867 558 (559) -- -- (1) ---------- -------- ----------- ------------ ------------ ----------- JUNE 30, 2004........... 25,783,243 $257,832 $44,402,182 $(15,248,422) $ (4,491,377) $24,920,215 ---------- -------- ----------- ------------ ------------ -----------
See accompanying notes. 31 MAGELLAN PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED JUNE 30, ---------------------------------------- 2004 2003 2002 ------------ ----------- ----------- OPERATING ACTIVITIES: Net income......................................... $ 350,061 $ 152,452 $ 91,721 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of accounting change.......... -- 2,025,690 -- Depletion, depreciation and amortization........ 6,341,998 3,718,660 3,447,444 Accretion expense............................... 356,981 242,854 -- Deferred income taxes........................... (1,445,241) (1,494,621) (608,454) Minority interests.............................. 545,860 552,158 405,799 Exploration and dry hole costs.................. 3,225,066 2,920,104 4,143,449 Increase (decrease) in operating assets and liabilities: Accounts and notes receivable................... 1,553,110 (1,372,029) (244,207) Other assets.................................... 905,146 (214,946) (204,813) Inventories..................................... (142,397) (69,275) 85,178 Accounts payable and accrued liabilities........ (353,739) 2,794,805 1,249,511 Income taxes payable............................ 166,477 (123,087) (675,909) Settlement of asset retirement obligation....... -- (58,901) -- Reserve for future site restoration costs....... -- -- 467,030 ------------ ----------- ----------- Net cash provided by operating activities............ 11,503,322 9,073,864 8,156,749 ------------ ----------- ----------- INVESTING ACTIVITIES: Additions to property and equipment................ (6,498,243) (3,445,159) (1,751,643) Oil and gas exploration activities................. (3,225,066) (2,920,104) (4,143,449) Sale of available-for-sale securities.............. -- 93,334 -- Marketable securities matured...................... 5,760,239 2,071,687 2,540,151 Marketable securities purchased.................... (6,750,171) (2,564,501) (2,426,263) ------------ ----------- ----------- Net cash used in investing activities................ (10,713,241) (6,764,743) (5,781,204) ------------ ----------- ----------- FINANCING ACTIVITIES: Dividends to MPAL minority shareholders............ (744,971) (628,209) (586,379) Repurchases of common stock........................ -- (179,900) (94,542) ------------ ----------- ----------- Net cash used in financing activities................ (744,971) (808,109) (680,921) ------------ ----------- ----------- Effect of exchange rate changes on cash and cash equivalents........................................ 320,046 2,755,601 1,298,036 ------------ ----------- ----------- Net increase in cash and cash equivalents............ 365,156 4,256,613 2,992,660 Cash and cash equivalents at beginning of year....... 20,041,464 15,784,851 12,792,191 ------------ ----------- ----------- Cash and cash equivalents at end of year............. $ 20,406,620 $20,041,464 $15,784,851 ============ =========== =========== Cash Payments: Income taxes....................................... 12,000 173,000 1,360,776 Interest........................................... -- -- 9,808
See accompanying notes. 32 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION Magellan Petroleum Corporation (the Company or MPC) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2004 and 2003, MPC's principal asset was a 55% and 52.44%, respectively, equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL), which has one class of stock that is publicly held and traded in Australia. MPAL's major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest), one petroleum production lease covering the Palm Valley gas field (52% working interest), and three petroleum production leases covering the Nockatunga oil field (41% working interest). Both fields are located in the Amadeus Basin in the Northern Territory of Australia. MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. On July 10, 2003, a subsidiary of Origin Energy, Sagasco Amadeus Pty. Limited, agreed to exchange 1.2 million shares of MPAL for 1.3 million shares of the Company's common stock. After the exchange was completed on September 2, 2003, MPC's interest in MPAL increased to 55%. In fiscal 2004 and 2003, MPC purchased 24,000 (for $22,000) and 184,000 shares (for $174,000), respectively of MPAL. The accompanying consolidated financial statements include the accounts of MPC and its majority owned subsidiary, MPAL, collectively the Company. All intercompany transactions have been eliminated. REVENUE RECOGNITION The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Company's share of production. Revenues from the purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered. Shipping and handling costs in connection with such deliveries are included in production costs (cost of goods sold). Revenue under carried interest agreements is recorded in the period when the net proceeds become receivable, measurable and collection is reasonably assured. The time the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator. As a result, net revenues from carried interests may lag the production month by one or more months. OIL AND GAS PROPERTIES Oil and gas properties are located in Australia, New Zealand, Canada and the United Kingdom. The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. The Company records its proportionate share in its working interest agreements in the respective classifications of assets, liabilities and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book value of proved oil and gas properties. Oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Company estimates the future undiscounted cash flows from the affected properties to determine the recoverability of carrying amounts. In general, analyses are based on proved developed reserves, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Other exploration costs, including geological and geophysical expenses, leasehold expiration costs and delay rentals, are expensed as incurred. Effective July 1, 2002, the Company adopted the provisions of SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition 33 of a liability, that cost is capitalized as part of the related long-lived asset (oil & gas properties) and amortized on a units-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related reserves. The estimated liability is based on the future estimated cost of plugging the existing oil and gas wells and removing the surface facilities equipment in the Palm Valley and Mereenie fields in the Northern Territory of Australia, the Nockatunga fields in Queensland, the Aldinga fields in South Australia, and the Kotaneelee fields in Southeast Yukon Territory of Canada. The liability is a discounted liability using a credit-adjusted risk-free rate, based on the date the liability was recorded and the geographic locations of the fields as follows: Mereenie and Palm Valley, approximately 8%; Nockatunga, 6.25%; Aldinga, 6.3%; and Kotaneelee, 4.5%. A market risk premium was excluded from the estimate of asset retirement obligations because the amount was not capable of being estimated. Revisions to the liability could occur due to changes in the estimates of these costs, acquisition of additional properties and as new wells are drilled. Effective July 1, 2002, the Company adopted the provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS 144 supersedes previous guidance related to the impairment or disposal of long-lived assets. For long-lived assets to be held and used, it resolves certain implementation issues of the former standards, but retains the basic requirements of recognition and measurement of impairment losses. For long-lived assets to be disposed of by sale, it broadens the definition of those disposals that should be reported separately as discontinued operations. There was no impact on the Company in adopting SFAS 144. USE OF ESTIMATES The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. LAND, BUILDINGS AND EQUIPMENT AND FIELD EQUIPMENT Land, buildings and equipment and field equipment are carried at cost. Depreciation and amortization are provided on a straight-line basis over their estimated useful lives. The estimated useful lives are: buildings -- 40 years, equipment and field equipment -- 3 to 15 years. INVENTORIES Inventories consist of crude oil in various stages of transit to the point of sale and are valued at the lower of cost (determined on an average cost basis) or market. FOREIGN CURRENCY TRANSLATIONS The accounts of MPAL, whose functional currency is the Australian dollar, are translated into U.S. dollars in accordance with Statement of Financial Accounting Standards No. 52. The translation adjustment is included as a component of stockholders' equity and comprehensive income (loss), whereas gain or loss on foreign currency transactions is included in the determination of income. All assets and liabilities are translated at the rates in effect at the balance sheet dates. Revenues, expenses, gains and losses are translated using quarterly weighted average exchange rates during the period. At June 30, 2004 and 2003, the Australian dollar was equivalent to U.S. $.70 and $.67, respectively. The annual average exchange rate used to translate MPAL's operations in Australia for the fiscal years 2004, 2003 and 2002 was $.72, $.59 and $.52, respectively. ACCOUNTING FOR INCOME TAXES The Company follows FASB Statement 109, the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between the financial 34 reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered. FINANCIAL INSTRUMENTS The carrying value for cash and cash equivalents, accounts receivable, marketable securities and accounts payable approximates fair value based on anticipated cash flows and current market conditions. CASH AND CASH EQUIVALENTS The Company considers all highly liquid short term investments with maturities of three months or less at the date of acquisition to be cash equivalents. Cash and cash equivalents are carried at cost which approximates market value. The components of cash and cash equivalents are as follows:
JUNE 30, ------------------------- 2004 2003 ----------- ----------- Cash....................................................... $ 1,648,074 $ 179,696 U.S. government obligations................................ 398,852 274,310 Australian money market accounts and short-term commercial paper.................................................... 18,359,694 19,587,458 ----------- ----------- $20,406,620 $20,041,464 =========== ===========
MARKETABLE SECURITIES At June 30, 2004 and 2003, MPC had the following marketable securities which are expected to be held until maturity:
JUNE 30, 2004 PAR VALUE MATURITY DATE AMORTIZED COST FAIR VALUE - ------------- ---------- ------------- -------------- ---------- Short-term securities U.S. government agency note..... $ 800,000 Jul. 7, 2004 $ 796,896 $ 799,840 U.S. government agency note..... 300,000 Aug. 24, 2004 298,785 299,430 U.S. government agency note..... 500,000 Sep. 15, 2004 497,813 498,600 U.S. government agency note..... 400,000 Oct. 7, 2004 398,104 398,360 State of Connecticut bond....... 200,000 Nov. 15, 2004 200,514 200,582 U.S. government agency note..... 100,000 Nov. 23, 2004 99,378 99,360 Lewiston, Maine Pension bond.... 290,000 Dec. 15, 2004 292,806 293,213 ---------- ---------- ---------- Total short-term................ $2,590,000 $2,584,296 $2,589,385 ========== ========== ========== Long-term securities State of Connecticut bond....... $ 200,000 Nov. 15, 2005 $ 202,138 $ 201,378 Lewiston, Main Pension bond..... 390,000 Dec. 15, 2005 390,000 401,532 ---------- ---------- ---------- Total long-term................. $ 590,000 $ 592,138 $ 602,910 ========== ========== ==========
35
JUNE 30, 2003 PAR VALUE MATURITY DATE AMORTIZED COST FAIR VALUE - ------------- ---------- ------------- -------------- ---------- Short-term securities State of Connecticut bond....... $ 400,000 Jul. 1, 2003 $ 400,000 $ 400,000 U.S. Treasury Bill.............. 200,000 Aug. 7, 2003 199,216 199,834 U.S. Treasury Bill.............. 400,000 Sep. 11, 2003 398,312 399,312 U.S. Treasury Bill.............. 500,000 Oct. 2, 2003 498,975 498,840 State of Connecticut bond....... 300,000 Nov. 15, 2003 300,000 300,528 ---------- ---------- ---------- Total short-term................ $1,800,000 $1,796,503 $1,798,514 ========== ========== ========== Long-term securities Lewiston, Maine Pension bond.... $ 390,000 Dec. 15, 2005 $ 390,000 $ 416,735 ========== ========== ==========
EARNINGS PER SHARE Earnings per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The only reconciling item in the calculation of diluted EPS is the dilutive effect of stock options which was computed using the treasury stock method. In 2004, the Company had 595,000 stock options that were issued that had a strike price below the year end stock price and resulted in 37,594 incremental diluted shares. There were no other potentially dilutive items at June 30, 2004. The exercise price of outstanding stock options exceeded the average market price of the common stock during the years 2003 and 2002. The Company's basic and diluted calculations of EPS are the same in 2003 and 2002 because the exercise of options is not assumed in calculating diluted EPS, as the result would be anti-dilutive. STOCK OPTIONS The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25) and related interpretations in accounting for its stock options. Under APB No. 25, because the exercise price of the Company's stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. See Note 4 Capital and Stock Options for the pro forma impact of stock options on net income and earnings per share. For the purpose of pro forma disclosures required by SFAS 123, "Accounting for Stock Based Compensation," as amended by SFAS 148 "Accounting for Stock-Based Compensation -- Transition and Disclosure," the estimated fair value of the stock options is generally expensed in the year of grant since most of the options are vested and immediately exercisable. See Note 4, Capital and Stock Options for the pro forma impact of stock options on net income and earnings per share. ACCUMULATED OTHER COMPREHENSIVE LOSS Accumulated other comprehensive loss at June 30, 2004 and 2003 was as follows:
2004 2003 ----------- ----------- Foreign currency translation adjustments................... $(4,491,377) $(5,406,527) =========== ===========
SALES TAXES Government sales taxes related to MPAL's oil and gas production revenues are collected by MPAL and remitted to the Australian government. Such amounts are excluded from revenue and expenses. 36 2. OIL AND GAS PROPERTIES MPC had the following amounts recorded in oil and gas properties at June 30, 2004 and 2003.
LOCATION 2004 2003 - -------- ----------- ----------- Mereenie and Palm Valley (Australia)....................... $66,945,763 $58,819,439 Nockatunga (Australia)..................................... 2,258,338 -- Aldinga (Australia)........................................ 604,747 581,837 Kotaneelee (Canada)........................................ 148,765 -- Other...................................................... 12,521 5,978 ----------- ----------- $69,970,134 $59,407,254 =========== ===========
ACCUMULATED DEPLETION, DEPRECIATION AND AMORTIZATION
LOCATION 2004 2003 - -------- ----------- ----------- Mereenie and Palm Valley (Australia)....................... $45,644,688 $38,639,460 Nockatunga (Australia)..................................... 218,594 -- Aldinga (Australia)........................................ 428,863 12,672 Kotaneelee (Canada)........................................ 30,059 -- ----------- ----------- $46,322,204 $38,652,132 =========== ===========
DEPLETION, DEPRECIATION AND AMORTIZATION During the years ended June 30, 2004, 2003 and 2002, the depletion rate of Mereenie and Palm Valley was 20.9%, 17.6% and 17.3%, respectively. During the year ended June 30, 2004, the depletion rate for Nockatunga, Aldinga and Kontaneelee was 9.5% 70.2% and 25%, respectively. NOCKATUNGA ACQUISITION During July 2003, MPAL reached an agreement with Voyager Energy Limited for the purchase of its 40.936% working interest (38.703% net revenue interest) in its Nockatunga assets in southwest Queensland. The assets comprise several producing oil fields in PLs 33, 50 and 51 together with exploration acreage in ATP 267P at a purchase price of approximately $1.4 million. EXPLORATORY AND DRY HOLE COSTS The 2004, 2003 and 2002 costs relate primarily to the geological and geophysical work and seismic acquisition on MPAL's exploration permits. The costs (in thousands) for MPAL by location were as follows:
2004 2003 2002 ------ ------ ------ U.S./Belize................................................ $ -- $ (38) $ 62 Australia/New Zealand...................................... 3,225 2,958 4,081 ------ ------ ------ Total...................................................... $3,225 $2,920 $4,143 ====== ====== ======
See Note 11 commitments for a summary of MPAL's required and contingent commitments for exploration expenditures for the five year period beginning July 1, 2004. 3. ASSET RETIREMENT OBLIGATIONS Upon the adoption of SFAS 143 on July 1, 2002, the Company recorded a discounted liability (asset retirement obligation) of $3,794,000, increased oil and gas properties by $526,000 and recognized a one-time, cumulative effect after-tax charge of $738,000 (net of $316,000 deferred tax benefit and minority interest of $680,000) which has been reflected as a cumulative effect of accounting change. 37 If the provisions of SFAS 143 had been adopted in prior years, net income would have decreased by approximately $77,000 for the fiscal year ended June 30, 2002. The adoption of SFAS 143 decreased net income before cumulative effect of accounting change by approximately $76,000 for the fiscal year ended June 30, 2003. The pro forma effects for the year ended June 30, 2002, assuming the adoption of SFAS 143 as of July 1, 2001, had no impact on earnings per share. A reconciliation of the Company's asset retirement obligations for the year ended June 30, 2004 and 2003, is as follows:
2004 2003 ---------- ---------- Balance at beginning of year................................ $3,858,000 $3,794,000 Liabilities incurred........................................ 489,000 29,000 Liabilities settled......................................... -- (59,000) Accretion expense........................................... 357,000 243,000 Revisions to estimate....................................... -- (923,000) Exchange effect............................................. 148,000 774,000 ---------- ---------- Balance at end of year...................................... $4,852,000 $3,858,000 ========== ==========
During fiscal year 2003, two wells were plugged and abandoned in the Mereenie field at a cost of approximately $86,000. The $27,000 difference between the amount of the asset retirement obligation of $59,000 and the abandonment costs of $86,000 is included in production costs. 4. CAPITAL AND STOCK OPTIONS MPC's certificate of incorporation provides that any matter to be voted upon must be approved not only by a majority of the shares voted, but also by a majority of the stockholders casting votes present in person or by proxy and entitled to vote thereon. On December 8, 2000, MPC announced a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2003, MPC had purchased 680,850 of its shares at a cost of approximately $686,000, all of which were cancelled. No shares have been repurchased during 2004. On July 10, 2003, a subsidiary of Origin Energy, Sagasco Amadeus Pty. Limited, agreed to exchange 1.2 million shares of MPAL for 1.3 million shares of the Company's common stock. The exchange was completed on September 2, 2003. The fair value of the 1,300,000 shares on July 10, 2003 was $1,508,000, based on the closing price of the Company's common stock on the Nasdaq SmallCap market on that date. The Company's Stock Option Plan provides for options to be granted at a price of not less than fair value on the date of grant and for a term of not greater than ten years. As of June 30, 2004, 205,000 options were available for future issuance under the plan. 38 The following is a summary of option transactions for the three years ended June 30, 2004:
EXPIRATION NUMBER OF OPTIONS OUTSTANDING DATES SHARES EXERCISE PRICES ($) - ------------------- ---------- --------- ----------------------------- June 30, 2001...................... 921,000 1.28-1.57 Expired.......................... (50,000) 1.57 -------- June 30, 2002...................... 871,000 1.28-1.57 Granted.......................... Jan. 2008 50,000 .85 -------- June 30, 2003...................... 921,000 .85-1.57 Expired.......................... (126,000) 1.57 Cancelled........................ (25,000) .85 Exercised........................ (175,000) .85-1.28 -------- June 30, 2004...................... 595,000 (1.28 weighted average price) ========
SUMMARY OF OPTIONS OUTSTANDING AT JUNE 30, 2004
EXPIRATION EXERCISE DATES TOTAL VESTED PRICES ($) ---------- ------- ------- ---------- Granted 2000................................ Feb. 2005 595,000 595,000 1.28
All of the options have been granted at the fair value at the date of grant. Upon exercise of options, the excess of the proceeds over the par value of the shares issued is credited to capital in excess of par value. No charges have been made against income in accounting for options during the three year period ended June 30, 2004. The pro forma information regarding net income and earnings per share as required by Statement 123, as amended, has been determined as if the Company had accounted for its stock options under the fair value method of that Statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model. Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The assumptions used in the 2000 valuation model were: risk free interest rate -- 6.65%, expected life -- 5 years, expected volatility -- .419, expected dividend -- 0. The assumptions used in the 2003 valuation model were: risk free interest rate -- 3.16%, expected life -- 5 years, expected volatility -- .439, expected dividend -- 0. The Company's pro forma information follows:
NET INCOME BASIC DILUTED ---------- ----- ------- Net income as reported -- June 30, 2002.................... $ 92,000 $ -- $ -- Stock option expense....................................... (31,000) -- -- -------- ---- ---- Pro forma net income -- June 30, 2002...................... $ 61,000 $ -- $ -- ======== ==== ==== Net income as reported -- June 30, 2003.................... $152,000 $.01 $.01 Stock option expense....................................... (22,000) -- -------- ---- ---- Pro forma net income -- June 30, 2003...................... $130,000 $.01 $.01 ======== ==== ==== Net income as reported -- June 30, 2004.................... $350,000 $.01 $.01 Stock option expense....................................... -- -- -------- ---- ---- Pro forma net income -- June 30, 2004...................... $350,000 $.01 $.01 ======== ==== ====
39 5. INCOME TAXES Components of income before income taxes, minority interests and cumulative effect of accounting change by geographic area (in thousands) are as follows:
YEARS ENDED JUNE 30, ---------------------- 2004 2003 2002 ----- ------ ----- United States............................................... $(548) $ (329) $(313) Foreign..................................................... 666 1,678 850 ----- ------ ----- Total....................................................... $ 118 $1,349 $ 537 ===== ====== =====
Reconciliation of the provision for income taxes (in thousands) computed at the Australian statutory rate to the reported provision for income taxes is as follows:
YEARS ENDED JUNE 30, ------------------------ 2004 2003 2002 ------- ------ ----- Income before income taxes, minority interests and cumulative effect of accounting change................... $ 118 $1,349 $ 537 MPC's non-Australian (income) losses....................... (550) 326 236 Permanent differences -- Australia......................... (706) (682) (872) ------- ------ ----- Book taxable income (loss) -- Australia.................... $(1,138) $ 993 $ (99) ======= ====== ===== Australian tax rate........................................ 30% 30% 30% ======= ====== ===== Australian income tax (provision) benefit.................. $ 341 $ (298) $ 30 Reversal of prior year reserve on MPAL Deferred Tax Assets................................................... 929 1,202 43 ------- ------ ----- MPAL Australian tax (provision) benefit.................... 1,270 904 73 MPC income tax provision(a)................................ (492) (130) (112) ------- ------ ----- Consolidated income tax (provision) benefit................ $ 778 $ 774 $ (39) ======= ====== ===== Current income tax provision............................... $ (667) $ (130) $(648) Deferred income tax benefit................................ 1,445 904 609 ------- ------ ----- Consolidated income tax (provision) benefit................ $ 778 $ 774 $ (39) ======= ====== ===== Effective tax rate......................................... -- (57)% 7% ======= ====== =====
- --------------- (a) MPC's income tax provisions represent the 25% Canadian withholding tax on its Kotaneelee gas field carried interest net proceeds. 40 Significant components of the Company's deferred tax assets and liabilities were as follows:
JUNE 30, JUNE 30, 2004 2003 ----------- ----------- Deferred tax liabilities Acquisition and development costs........................ $(2,068,000) $(3,192,000) Deferred tax assets Asset retirement obligations............................. 1,665,000 1,421,000 Net operating losses..................................... 2,633,000 3,400,000 Foreign tax credits...................................... 223,000 329,000 Interest................................................. 214,000 214,000 ----------- ----------- Total deferred tax assets.................................. 4,735,000 5,364,000 Valuation allowance........................................ (3,070,000) (3,943,000) ----------- ----------- Net deferred tax liabilities............................... $ (403,000) $(1,771,000) =========== ===========
The net deferred tax liabilities at June 30, 2004 and 2003, respectively, consist of deferred tax liabilities of $2,068,000 and $3,192,000, primarily relating to the deduction of acquisition and development costs which are capitalized for financial statement purposes, offset by deferred tax assets of $1,665,000 and $1,421,000, primarily relating to asset retirement obligations which will result in tax deductions when paid. The tax benefits of $929,000 in fiscal 2004 and $1,202,000 in fiscal 2003 relate primarily to additional tax benefits taken in connection with financing prior year exploration activities in Australia. These benefits were reserved in prior years and as a result of the benefits becoming recoverable during the current year, such reserves were reversed. UNITED STATES At June 30, 2004, the Company had approximately $12,216,000 and $853,000 of net operating loss carry forwards for federal and state income tax purposes, respectively, which are scheduled to expire periodically between the years 2004 and 2023. Of this amount, MPC has federal loss carry forwards that expire as follows: $265,000 in 2007, $2,055,000 in 2008, $408,000 in 2020, $52,000 in 2021 and 110,000 in 2023. MPAL's U.S. subsidiary has federal loss carry forwards that expire as follows: $220,000 in 2005, $2,392,000 in 2006, $1,669,000 in 2010, $1,764,000 in 2011, $2,855,000 in 2012, $229,000 in 2013, $96,000 in 2019, $25,000 in 2021, $73,000 in 2022 and $2,000 in 2023 and $1,000 in 2024. MPC also has approximately $223,000 of foreign tax credit carryovers, which are scheduled to expire periodically between the years 2005 and 2006. MPC's state loss carry forwards expire periodically between the years 2005 and 2024. For financial reporting purposes, a valuation allowance has been recognized to offset the deferred tax assets related to those carry forwards and other deductible temporary differences. 6. RELATED PARTY AND OTHER TRANSACTIONS G&O'D INC, a firm that provides accounting and administrative services, office facilities and support staff to MPC, was paid $24,723, $20,830 and $34,120 in fees for fiscal years 2004, 2003 and 2002 respectively. James R. Joyce, the former President and Chief Financial Officer of MPC, is the owner of G&O'D INC. Mr. Joyce retired from his position effective June 30, 2004. Effective January 1, 2000, Mr. Joyce became a paid officer of MPC and received an annual salary of $175,000 for calendar year 2004 ($175,000 for 2003 and $160,000 for 2002). Mr. Timothy L. Largay, a director of the Company is a member of the law firm of Murtha Cullina LLP, which firm was paid fees of $120,563, $69,459 and $36,597 for fiscal years 2004, 2003 and 2002, respectively. 41 7. LEASES At June 30, 2004, future minimum rental payments applicable to MPC's and MPAL's non-cancelable operating (office) lease were $163,000, $170,000, $177,000, $183,000, and $165,000 for 2005, 2006, 2007, 2008 and 2009, respectively. Operating lease rental expenses for each of the years ended June 30, 2004, 2003 and 2002 were $311,497, $239,026 and $188,494, respectively. On August 6, 2004, MPC entered into a four-year operating lease of its corporate offices, with estimated annual payments of $24,000. 8. PENSION PLAN MPAL maintains a defined benefit pension plan and contributes to the plan at rates which (based on actuarial determination) are sufficient to meet the cost of employees' retirement benefits. No employee contributions are required. Plan participants are entitled to defined benefits on normal retirement, death or disability. MPAL is only legally obligated to pay employees their pro rata share of the fair value of plan assets. However, MPAL is committed to making up any shortfall in the plan's assets to meet payments to employees as they become due. On August 31, 2004, the MPAL Board formally terminated the Plan. The termination was effective as of June 30, 2004 and a settlement and curtailment loss of $1,237,425 was recognized for the year ended June 30, 2004. The following table sets forth the actuarial present value of benefit obligations and funded status for the MPAL pension plan:
JUNE 30, ----------------------- 2004 2003 ---------- ---------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year..................... $1,980,930 $1,507,445 Service cost.............................................. 148,075 144,216 Interest cost............................................. 94,212 96,803 Actuarial gains and losses................................ (46,378) 11,690 Benefits paid............................................. (447,277) -- Settlement and curtailment................................ 414,694 Expenses paid............................................. (71,763) (74,025) Foreign currency effect................................... 72,901 294,801 ---------- ---------- Benefit obligation at end of year........................... $2,145,394 $1,980,930 ========== ========== CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year.............. $1,911,692 $1,606,083 Actual return on plan assets.............................. 226,341 (90,703) Contributions by employer................................. 164,368 156,247 Benefits paid............................................. (447,277) -- Foreign currency effect................................... 75,320 314,090 Other (expenses).......................................... (71,763) (74,025) ---------- ---------- Fair value of plan assets at end of year.................... $1,858,681 $1,911,692 ========== ==========
42
JUNE 30, ----------------------- 2004 2003 ---------- ---------- RECONCILIATION OF FUNDED STATUS Funded Status............................................... $ (286,713) $ (69,238) Unamortized transition asset.............................. -- (29,970) Unamortized loss.......................................... -- 1,025,376 ---------- ---------- (Accrued) Prepaid benefit costs............................. $ (286,713) $ 926,168 ========== ==========
The net pension expense for the MPAL pension plan was as follows:
YEARS ENDED JUNE 30, --------------------------------- 2004 2003 2002 ---------- -------- --------- Settlement and curtailment......................... 1,237,425 -- -- Service cost....................................... 148,075 $144,216 $ 185,256 Interest cost...................................... 94,212 96,803 132,530 Expected return on plan assets..................... (94,104) (97,205) (175,691) Net amortization and deferred items................ 26,835 15,299 (17,011) ---------- -------- --------- Net pension cost................................... $1,412,443 $159,113 $ 125,084 ========== ======== ========= Plan contributions by MPAL......................... $ 228,958 $156,247 $ 142,467 ========== ======== =========
Significant assumptions used in determining pension cost and the related obligations were as follows:
2004 2003 2002 ---- ---- ---- Assumed discount rate....................................... 5.0% 5.5% 5.5% Rate of increase in future compensation levels.............. 3.5% 3.5% 4.0% Expected long term rate of return on plan assets............ 5.0% 5.0% 5.0% Australian exchange rate.................................... $.70 $.67 $.56
At June 30, 2004, Plan assets were held 98% in equity mutual funds and 2% in cash. Such assets are held for distribution to plan participants. As a result of the Plan's termination, the Plan assets are expected to be distributed during 2005 with no additional pension plan expenditures anticipated. 9. SEGMENT INFORMATION The Company has two reportable segments, MPC and its majority owned subsidiary, MPAL. Although each company is in the same business, MPAL is also a publicly held company with its shares traded on the Australian Stock Exchange. MPAL issues separate audited consolidated financial statements and operates independently of MPC. Segment information (in thousands) for the Company's two operating segments is as follows:
YEARS ENDED JUNE 30, ----------------------------- 2004 2003 2002 -------- -------- ------- Revenues: MPC................................................. $ 2,629 $ 1,313 $ 1,222 MPAL................................................ 18,806 14,969 13,754 Elimination of intersegment dividend................ (911) (686) (624) -------- -------- ------- Total consolidated revenues......................... $ 20,524 $ 15,596 $14,352 ======== ======== =======
43
YEARS ENDED JUNE 30, ----------------------------- 2004 2003 2002 -------- -------- ------- Interest income: MPC................................................. $ 160 $ 85 $ 115 MPAL................................................ 939 775 537 -------- -------- ------- Total consolidated.................................. $ 1,099 $ 860 $ 652 ======== ======== ======= Net income before cumulative effect of accounting change: MPC................................................. $ 969 $ 229 $ 276 Equity in earnings of MPAL, net of related costs(1)......................................... 292 1,347 440 Elimination of intersegment dividend................ (911) (686) (624) -------- -------- ------- Consolidated net income before cumulative effect of accounting change:............................... $ 350 $ 890 $ 92 ======== ======== ======= Net income: MPC................................................. $ 969 $ 229 $ 276 Equity in earnings of MPAL, net of related costs(1)......................................... 292 609 440 Elimination of intersegment dividend................ (911) (686) (624) -------- -------- ------- Consolidated net income............................. $ 350 $ 152 $ 92 ======== ======== ======= Assets: MPC................................................. $ 25,339 $ 22,268 MPAL................................................ 47,884 47,038 Equity elimination.................................. (20,329) (18,565) -------- -------- Total consolidated assets........................... $ 52,894 $ 50,741 ======== ======== Other significant items: Depletion, depreciation and amortization: MPC.............................................. $ 30 $ -- $ -- MPAL............................................. 6,311 3,719 3,447 -------- -------- ------- Total consolidated............................... $ 6,341 $ 3,719 $ 3,447 ======== ======== ======= Exploratory and dry hole costs: MPC................................................. $ -- $ -- $ -- MPAL................................................ 3,225 2,920 4,143 -------- -------- ------- Total consolidated.................................. $ 3,225 $ 2,920 $ 4,143 ======== ======== ======= Income tax expense (benefit): MPC................................................. $ 492 $ 130 $ 112 MPAL................................................ (1,270) (904) (73) -------- -------- ------- Total consolidated.................................. $ (778) $ (774) $ 39 ======== ======== =======
- --------------- (1) Equity in earnings of MPAL of $670,000 is reported net of $378,000 in oil and gas property depletion related to MPC book value of oil and gas property and resulting from its step reporting of MPAL. 44 10. GEOGRAPHIC INFORMATION As of each of the stated dates, the Company's revenue, operating income, net income or loss and identifiable assets (in thousands) were geographically attributable as follows:
YEARS ENDED JUNE 30, --------------------------- 2004 2003 2002 ------- ------- ------- Revenue: Australia............................................. $18,806 $14,968 $13,757 United States......................................... 160 92 113 Canada................................................ 1,558 535 482 ------- ------- ------- $20,524 $15,595 $14,352 ======= ======= ======= Operating income (loss): Australia............................................. $ (103) $ 1,732 $ 396 New Zealand........................................... (909) (628) (64) United States-Canada.................................. 1,525 569 407 ------- ------- ------- 513 1,673 739 Corporate overhead and interest, net of other income (expense).......................................... (395) (324) (202) ------- ------- ------- Consolidated operating income before income taxes, minority interests and cumulative effect of accounting change.................................. $ 118 $ 1,349 $ 537 ======= ======= ======= Net income (loss): Australia............................................. $ 718 $ 835 $ 504 New Zealand........................................... (425) (246) (23) United States......................................... 57 (437) (389) ------- ------- ------- $ 350 $ 152 $ 92 ======= ======= ======= Identifiable assets: Australia............................................. $48,652 $47,495 Corporate assets...................................... 4,242 3,246 ------- ------- $52,894 $50,741 ======= =======
Substantially all (99% in 2004, 99% in 2003 and 92% in 2002) of MPAL's gas sales were to the Power and Water Corporation (PAWC) of the Northern Territory of Australia (NTA). All of MPAL's crude oil production was sold to the Mobil Port Stanvac Refinery near Adelaide during the three years ended June 30, 2004. 45 11. COMMITMENTS We do not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company does not engage in trading or risk management activities and does not have material transactions involving related parties. GAS SUPPLY CONTRACTS In 1983, the Palm Valley Producers (MPAL and Santos) commenced the sale of gas to Alice Springs under a 1981 agreement. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PAWC for use in PAWC's Darwin generating station and at a number of other generating stations in the Northern Territory. The gas is being delivered via the 922-mile Amadeus Basin to Darwin gas pipeline which was built by an Australian consortium. Since 1985, there have been several additional contracts for the sale of Mereenie gas. The Palm Valley Darwin contract expires in the year 2012 and Mereenie contracts expire in the year 2009. Under the 1985 contracts, there is a difference in price between Palm Valley gas and most of the Mereenie gas for the first 20 years of the 25 year contracts which takes into account the additional cost to the pipeline consortium to build a spur line to the Mereenie field and increase the size of the pipeline from Palm Valley to Mataranka. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. At June 30, 2004, MPAL's commitment to supply gas under the above agreements was as follows:
PERIOD BCF - ------ ----- Less than one year.......................................... 7.22 Between 1-5 years........................................... 26.73 Greater than 5 years........................................ 4.55 ----- Total....................................................... 38.50 =====
MPC owns a 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory which has been in production since February 1991 with two producing wells. For financial statement purposes in fiscal 1987 and 1988, MPC wrote down its costs relating to the Kotaneelee field to a nominal value because of the uncertainty as to the date when sales of Kotaneelee gas might begin and the immateriality of the carrying value of the investment. Since October 1989, the field has been the subject of litigation, because the carried interest owners (including MPC) believed that the working interest parties had not adequately pursued the attainment 46 of contracts for the sale of Kotaneelee gas. A decision in the litigation was rendered on September 14, 2001. The decision of the trial court was generally favorable to the Company but the decision was appealed by all of the parties. During September 2003, the litigants in the Kotaneelee litigation entered into a settlement agreement. In October 2003 the Company received approximately $851,000, after Canadian withholding taxes and reimbursement of certain past legal costs. The plaintiffs terminated all litigation against the defendants related to the field, including the claim that the defendants failed to fully develop the field. Since each party agreed to bear its own legal costs, there were no taxable costs assessed against any of the parties. The components of the settlement payment, which was recorded in September 2003 are as follows: Gas sales................................................... $1,135,000 Interest income............................................. 102,000 Canadian withholding taxes.................................. (386,000) ---------- Total....................................................... $ 851,000 ==========
The Kotaneelee settlement agreement provides that the carried interest partners will share in the abandonment of the Kotaneelee field wells and facilities. 12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary (in thousands, except for per share amounts) of the quarterly results of operations for the years ended June 30, 2004 and 2003:
2004 QTR 1 QTR 2 QTR 3 QTR 4 - ---- ------- ------- ------- ------- Total revenues................................. $ 5,732 $ 4,841 $ 5,110 $ 4,841 Costs and expenses............................. (3,900) (5,634) (4,599) (6,273) Income tax (provision) benefit................. (411) 61 (115) 1,243 Minority interests............................. (354) 226 (254) (164) ------- ------- ------- ------- Net income (loss).............................. 1,067 (506) 142 (353) ======= ======= ======= ======= Per share (basic & diluted).................... .04 (.02) .01 (.01) Average number of shares outstanding........... 25,092 25,727 25,894 25,820 ======= ======= ======= =======
2003 QTR 1 QTR 2 QTR 3 QTR 4 - ---- ------- ------- ------- ------- Total revenues................................. $ 3,188 $ 3,884 $ 4,071 $ 4,452 Costs and expenses............................. (3,373) (3,200) (3,377) (4,297) Income tax (provision) benefit................. (1) (212) (190) 1,177 Minority interests............................. 14 (317) (274) (655) ------- ------- ------- ------- Net income (loss) before cumulative effect of accounting change............................ (172) 155 230 677 ------- ------- ------- ------- Cumulative effect of accounting change......... (738) -- -- -- ------- ------- ------- ------- Net income (loss).............................. (910) 155 230 677 ======= ======= ======= ======= Per share (basic & diluted) Before cumulative effect of accounting change.................................... (.01) .01 .01 .03 Cumulative effect of accounting change....... (.03) -- -- -- ------- ------- ------- ------- Net Income................................... (.04) .01 .01 .03 ======= ======= ======= ======= Average number of shares outstanding........... 24,607 24,607 24,571 24,560 ======= ======= ======= =======
47 13. SUPPLEMENTARY OIL AND GAS DISCLOSURE (UNAUDITED) The consolidated data presented herein include estimates which should not be construed as being exact and verifiable quantities. The reserves may or may not be recovered, and if recovered, the cash flows there from, and the costs related thereto, could be more or less than the amounts used in estimating future net cash flows. Moreover, estimates of proved reserves may increase or decrease as a result of future operations and economic conditions, and any production from these properties may commence earlier or later than anticipated. ESTIMATED NET QUANTITIES OF PROVED DEVELOPED AND PROVED OIL AND GAS RESERVES:
NATURAL GAS OIL --------------------- ------------ (BCF) (1,000 BBLS) --------------------- ------------ PROVED RESERVES: AUSTRALIA* CANADA** AUSTRALIA - ---------------- ---------- -------- ------------ June 30, 2001........................................ 52.169 .587 523 Revision of previous estimates....................... (5.828) -- 138 Extensions and discoveries........................... -- -- -- Purchase of reserves................................. .353 -- -- Production........................................... (5.914) (.053) (141) ------ ----- ----- June 30, 2002........................................ 40.780 .534 520 Extensions and discoveries........................... -- -- 35 Revision of previous estimates....................... 2.497 -- 125 Production........................................... (5.893) (.107) (126) ------ ----- ----- June 30, 2003........................................ 37.384 .427 554 ====== ===== ===== Extensions and discoveries........................... -- -- -- Revision of previous estimates....................... (.631) (.180) (.110) Purchase of reserves................................. -- -- 322 Production........................................... (5.728) (.077) (150) ------ ----- ----- June 30, 2004........................................ 31.025 .170 616 ====== ===== ===== Proved Developed Reserves: June 30, 2001........................................ 52.169 .587 496 ====== ===== ===== June 30, 2002........................................ 29.102 .534 520 ====== ===== ===== June 30, 2003........................................ 28.855 .427 554 ====== ===== ===== June 30, 2004........................................ 22.346 .170 616 ====== ===== =====
- --------------- * The amount of proved reserves applicable to the Palm Valley and Mereenie fields only reflects the amount of gas committed to specific contracts. Approximately 44.9% of reserves are attributable to minority interests at June 30, 2004 (47.6% for 2003 and 48% for 2002). ** On January 19, 2001, MPC's carried interest account in the Kotaneelee reached undisputed payout status. COSTS OF OIL AND GAS ACTIVITIES (IN THOUSANDS):
AUSTRALIA/NEW ZEALAND --------------------------------------- EXPLORATION DEVELOPMENT ACQUISITION FISCAL YEAR COSTS COSTS COSTS - ----------- ----------- ----------- ----------- 2004............................................... $3,741 $3,926 $2,086 2003............................................... 4,484 2,753 3 2002............................................... 4,082 1,288 270
48 CAPITALIZED COSTS SUBJECT TO DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) (IN THOUSANDS):
JUNE 30, 2003 ------------------- AUSTRALIA/NEW ZEALAND 2004 2003 - --------------------- -------- -------- Costs subject to DD&A....................................... $ 69,970 $ 59,407 Costs not subject to DD&A................................... -- -- Less accumulated DD&A....................................... (45,949) (38,652) -------- -------- Net capitalized costs....................................... $ 24,021 $ 20,755 ======== ========
DISCOUNTED FUTURE NET CASH FLOWS: The following is the standardized measure of discounted (at 10%) future net cash flows (in thousands) relating to proved oil and gas reserves during the three years ended June 30, 2004. At June 30, 2004, approximately 44.9% (47.6% for 2003 and 48.% for 2002) of the reserves and the respective discounted future net cash flows are attributable to minority interests.
AUSTRALIA ------------------------------ 2004 2003 2002 -------- -------- -------- Future cash inflows.................................. $ 82,449 $ 78,192 $ 74,503 Future production costs.............................. (19,361) (20,844) (13,481) Future development costs............................. (16,599) (15,681) (11,735) Future income tax expense............................ (9,369) (5,292) (12,421) -------- -------- -------- Future net cash flows................................ 37,120 36,375 36,866 10% annual discount for estimating timing of cash flows.............................................. (7,639) (10,675) (11,079) -------- -------- -------- Standardized measures of discounted future net cash flows.............................................. $ 29,841 $ 25,700 $ 25,787 ======== ======== ========
CANADA ----------------------- 2004 2003 2002 ----- ------ ------ Future cash inflows......................................... $ 754 $1,460 $1,029 Future production costs..................................... (125) (213) (229) Future development costs.................................... -- -- -- Future income tax expense................................... (157) (312) (200) ----- ------ ------ Future net cash flows....................................... 472 935 600 10% annual discount for estimating timing of cash flows..... (72) (149) (76) ----- ------ ------ Standardized measures of discounted future net cash flows... $ 400 $ 786 $ 524 ===== ====== ======
TOTAL ------------------------------ 2004 2003 2002 -------- -------- -------- Future cash inflows.................................. $ 83,203 $ 79,652 $ 75,532 Future production costs.............................. (19,486) (21,057) (13,710) Future development costs............................. (16,599) (15,681) (11,735) Future income tax expense............................ (9,526) (5,604) (12,621) -------- -------- -------- Future net cash flows................................ 37,592 37,310 37,466 10% annual discount for estimating timing of cash flows.............................................. (7,711) (10,824) (11,155) -------- -------- -------- Standardized measures of discounted future net cash flows.............................................. $ 29,881 $ 26,486 $ 26,311 ======== ======== ========
49 The following are the principal sources of changes in the above standardized measure of discounted future net cash flows (in thousands):
2004 2003 2002 -------- ------- ------- Net change in prices and production costs.............. $ 7,597 $(5,020) $ 581 Extensions and discoveries............................. -- 360 -- Revision of previous quantity estimates................ 981 1,059 (6,850) Changes in estimated future development costs.......... (2,156) (4,587) (2,868) Sales and transfers of oil and gas produced............ (10,314) (8,070) (7,763) Previously estimated development cost incurred during the period........................................... 3,110 3,110 1,327 Accretion of discount.................................. 2,344 2,992 2,975 Acquisitions........................................... 3,213 -- -- Net change in income taxes............................. (2,345) 6,100 3,958 Net change in exchange rate............................ 965 4,231 2,428 -------- ------- ------- $ 3,395 $ 175 $(6,212) ======== ======= =======
ADDITIONAL INFORMATION REGARDING DISCOUNTED FUTURE NET CASH FLOWS: AUSTRALIA Reserves -- Natural Gas Future net cash flows from net proved gas reserves in Australia were based on MPAL's share of reserves in the Palm Valley and Mereenie fields which has been limited to the quantities of gas committed to specific contracts and the ability of the fields to deliver the gas in the contract years. Gas prices are computed on the prices set forth in the respective gas sales contracts at June 30, 2004. Reserves and Costs -- Oil At June 30, 2004, future net cash flows from the net proved oil reserves in Australia were calculated by the Company. Estimated future production and development costs were based on current costs and rates for each of the three years ended at June 30, 2004. All of the crude oil reserves are developed reserves. Undeveloped proved reserves have not been estimated since there are only tentative plans to drill additional wells. Income Taxes Future Australian income tax expense applicable to the future net cash flows has been reduced by the tax effect of approximately A.$22,005,000, A.$$25,658,000 and A.$13,982,000 in unrecouped capital expenditures at June 30, 2004, 2003 and 2002, respectively. The tax rate in computing Australian future income tax expense was 30%. CANADA Reserves and Costs On January 19, 2001, the Company's carried interest account in the Kotaneelee gas field reached undisputed payout status. During the 4th quarter of the fiscal year 2001, the Company began accruing its share of Kotaneelee net proceeds as income. Future net cash flows from net proved gas reserves in Canada were based on the Company's share of reserves in the Kotaneelee gas field which was prepared by independent petroleum consultants, Paddock Lindstrom & Associates Ltd., Calgary, Canada. The estimates were based on the selling price of gas Can. $5.90 at June 30, 2004 (Can. $4.61 -- 2003) and estimated future production and development costs at June 30, 2004. 50 RESULTS OF OPERATIONS The following are the Company's results of operations (in thousands) for the oil and gas producing activities during the three years ended June 30, 2004:
AMERICAS AUSTRALIA/NEW ZEALAND ---------------------- --------------------------------- 2004 2003 2002 2004 2003 2002 ------ ----- ----- --------- --------- --------- Revenues: Oil sales....................... $ -- $ -- $ -- $ 4,923 $ 3,329 $ 3,259 Gas sales....................... 1,557 535 482 11,312 9,647 8,185 Other production income......... -- -- -- 1,632 1,214 1,781 ------ ----- ----- --------- --------- --------- Total revenues.................. 1,557 535 482 17,867 14,190 13,225 ------ ----- ----- --------- --------- --------- Costs: Production costs................ -- -- -- 5,416 4,424 3,770 Depletion, exploratory and dry hole costs................... 30 (38) 62 9,009 6,620 7,419 ------ ----- ----- --------- --------- --------- Total costs..................... 30 (38) 62 14,425 11,044 11,189 ------ ----- ----- --------- --------- --------- Income before taxes and minority interest........................ 1,527 573 420 3,442 3,146 2,036 Income tax provision*........... (382) (134) (121) (1,027) (944) (611) ------ ----- ----- --------- --------- --------- Income before minority interests....................... 1,145 439 299 2,415 2,202 1,425 Minority interests**............ -- (18) 30 (1,085) (1,047) (684) ------ ----- ----- --------- --------- --------- Net income from operations........ $1,145 $ 421 $ 329 $ 1,330 $ 1,155 $ 741 ====== ===== ===== ========= ========= ========= Depletion per unit of production...................... $ .39 -- -- A.$ 7.25 A.$ 5.27 A.$ 5.35 ====== ===== ===== ========= ========= =========
- --------------- * Income tax provision Australia 30%. Americas 25% due to a 25% Canadian withholding tax on Kotaneelee gas sales. ** Minority interests 44.9% in 2004, 47.6% in 2003 and 48.0% in 2002. ITEM 9. PREVIOUS INDEPENDENT ACCOUNTANTS On August 15, 2003, the Audit Committee of the Board of Directors of the Company determined to dismiss Ernst & Young LLP as the Company's independent auditors, effective upon completion of the annual audit for the fiscal year ended June 30, 2003. This decision was subject to the condition that Magellan Petroleum Australia Limited (MPAL), the Company's majority owned subsidiary, make a similar determination to dismiss Ernst & Young as its independent auditors. Ernst & Young had served as the Company's independent auditors for many years. On September 4, 2003, the audit committee of the Board of Directors of MPAL made a similar determination to dismiss Ernst & Young as its independent accountants, effective upon the completion of the annual audit for the fiscal year ended June 30, 2003. The reports of Ernst & Young on the Company's financial statements for the two fiscal years ended June 30, 2003 did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to audit scope or accounting principles. Ernst & Young LLP was dismissed on September 26, 2003, upon filing of the Company's annual report on Form 10-K for the fiscal year ended June 30, 2003. The report of Ernst & Young LLP was dated September 19, 2003. 51 In connection with the audits of the Company's financial statements for each of the two fiscal years ended June 30, 2003 and through September 19, 2003, there were no disagreements with Ernst & Young on any matter of accounting principles or practices, financial statement disclosure, or auditing scope and procedures which, if not resolved to Ernst & Young's satisfaction, would have caused Ernst & Young to make reference to the matter in their report. In addition, there were no "reportable events" as that term is described in Item 304(a)(1)(v) of Regulation S-K. NEW INDEPENDENT ACCOUNTANTS Effective October 30, 2003, the Audit Committee of the Company's Board of Directors retained Deloitte & Touche LLP as the Company's new independent auditors for the fiscal year ended June 30, 2004. During the Company's two most recent fiscal years and the subsequent interim period(s) prior to engaging Deloitte & Touche LLP, neither the Company nor anyone acting on behalf of the Company consulted Deloitte & Touche LLP regarding (i) either (a) the application of accounting principles to a specified transaction, either completed or proposed, or (b) the type of audit opinion that might be rendered on the Company's financial statements; or (ii) any matter that was either the subject of a disagreement (as defined in paragraph 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K) or a reportable event (as described in paragraph 304(A)(1)(v) of Regulation S-K). In addition, during the Company's two most recent fiscal years and the subsequent interim period(s) prior to engaging Deloitte & Touche LLP, no written report was provided by Deloitte & Touche LLP to the Company and no oral advice was provided that Deloitte & Touche LLP concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing, or financial reporting issue. ITEM 9A. CONTROLS AND PROCEDURES DISCLOSURE CONTROLS AND PROCEDURES An evaluation was performed under the supervision and with the participation of the Company's management, including Daniel J. Samela, the Company's President, Chief Executive Officer and Chief Financial and Accounting Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities and Exchange Act of 1934) as of June 30, 2004. Based on this evaluation, the Company's President concluded that the Company's disclosure controls and procedures were effective such that the material information required to be included in the Company's Securities and Exchange Commission reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms relating to the Company, including its consolidated subsidiaries, and was made known to him by others within those entities, particularly during the period when this report was being prepared. INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of the Company's fiscal year ended June 30, 2004 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. ITEM 9B. OTHER INFORMATION None PART III For information concerning Item 10 -- Directors and Executive Officers of the Company, Item 11 -- Executive Compensation, Item 12 -- Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder Matters Item 13 -- Certain Relationships and Related Transactions and Item 14 -- Principal Accounting Fees and Services, see the Proxy Statement of Magellan Petroleum Corporation relative 52 to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2004, to be filed with the Securities and Exchange Commission, which information is incorporated herein by reference. For information concerning the Executive Officers of the Company, see Part I. EQUITY COMPENSATION PLAN INFORMATION The following table provides information about the Company's common stock that may be issued upon the exercise of options and rights under the Company's existing equity compensation plan as of June 30, 2004.
NUMBER OF WEIGHTED SECURITIES TO BE AVERAGE EXERCISE NUMBER OF SECURITIES ISSUED UPON PRICE OF REMAINING AVAILABLE FOR EXERCISE OF OUTSTANDING ISSUANCE UNDER EQUITY OUTSTANDING OPTIONS, COMPENSATION PLANS OPTIONS, WARRANTS WARRANTS AND (EXCLUDING SECURITIES AND RIGHTS RIGHTS REFLECTED IN COLUMN (A)) PLAN CATEGORY (A) (#) (B) ($) (C) (#) - ------------- ----------------- ---------------- ------------------------ Equity compensation plans approved by security holders........................ 595,000 $1.28 205,000
PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) (1) Financial Statements. The financial statements listed below and included under Item 8 are filed as part of this report.
PAGE REFERENCE --------- Reports of Independent Registered Public Accounting Firms... 27 Consolidated balance sheets as of June 30, 2004 and 2003.... 29 Consolidated statements of income for each of the three years in the period ended June 30, 2004................... 30 Consolidated statements of changes in stockholders' equity for each of the three years in the period ended June 30, 2004...................................................... 31 Consolidated statements of cash flows for each of the three years in the period ended June 30, 2004................... 32 Notes to consolidated financial statements.................. 33-47 Supplementary oil and gas information (unaudited)........... 48-51
(2) Financial Statement Schedules. All schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and the notes thereto. (c) Exhibits. The following exhibits are filed as part of this report: ITEM NUMBER 2. Plan of acquisition, reorganization, arrangement, liquidation or succession. None. 3. Articles of Incorporation and By-Laws. (a) Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware and Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware filed as exhibit 4(b) 53 to Form S-8 Registration Statement, filed on January 14, 1999, are incorporated herein by reference. Certificate of Amendment to Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware, filed as Exhibit 3(a) to the Company's quarterly report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference. (b) Copy of the By-Laws, as amended on July 22, 2004 is filed herein. 4. Instruments defining the rights of security holders, including indentures. None. 9. Voting Trust Agreement. None. 10. Material contracts. (a) Petroleum Lease No. 4 dated November 18, 1981 granted by the Northern Territory of Australia to United Canso Oil & Gas Co. (N.T.) Pty Ltd. filed as Exhibit 10(a) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (b) Petroleum Lease No. 5 dated November 18, 1981 granted by the Northern Territory of Australia to Magellan Petroleum (N.T.) Pty. Ltd. filed as Exhibit 10(b) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (c) Gas Sales Agreement between The Palm Valley Producers and The Northern Territory Electricity Commission dated November 11, 1981 filed as Exhibit 10(c) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (d) Palm Valley Petroleum Lease (OL3) dated November 9, 1982 filed as Exhibit 10(d) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (e) Agreements relating to Kotaneelee. (1) Copy of Agreement dated May 28, 1959 between the Company et al and Home Oil Company Limited et al and Signal Oil and Gas Company filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (2) Copies of Supplementary Documents to May 28, 1959 Agreement (see (e)(1) above), dated June 24, 1959, consisting of Guarantee by Home Oil Company Limited and Pipeline Promotion Agreement filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (3) Copy of Modification to Agreement dated May 28, 1959 (see (e)(1) above), made as of January 31, 1961. Filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (4) Copy of Letter Agreement dated February 1, 1977 between the Company and Columbia Gas Development of Canada, Ltd. for operation of the Kotaneelee gas field filed as Exhibit 10(e) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (f) Palm Valley Operating Agreement dated April 2, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., C. D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, I.E.D.C. Australia Pty. Ltd., Southern Alloys Ventures Pty. Limited and Amadeus Oil N.L. filed as Exhibit 10(f) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (g) Mereenie Operating Agreement dated April 27, 1984 between Magellan Petroleum (N.T.) Pty., United Oil & Gas Co. (N.T.) Pty. Ltd., Canso Resources Limited, Oilmin (N.T.) Pty. Ltd., Krewliff 54 Investments Pty. Ltd., Transoil (N.T.) Pty. Ltd. and Farmout Drillers NL and Amendment of October 3, 1984 to the above agreement filed as Exhibit 10(g) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (h) Palm Valley Gas Purchase Agreement dated June 28, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., C. D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, IEDC Australia Pty Limited, Amadeus Oil N.L., Southern Alloy Venture Pty. Limited and Gasgo Pty. Limited. Also included are the Guarantee of the Northern Territory of Australia dated June 28, 1985 and Certification letter dated June 28, 1985 that the Guarantee is binding. All of the above were filed as Exhibit 10(h) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) and are incorporated herein by reference. (i) Mereenie Gas Purchase Agreement dated June 28, 1985 between Magellan Petroleum (N.T.) Pty. Ltd., United Oil & Gas Co. (N.T.) Pty. Ltd., Canso Resources Limited, Moonie Oil N.L., Petromin No Liability, Transoil No Liability, Farmout Drillers N.L., Gasgo Pty. Limited, The Moonie Oil Company Limited, Magellan Petroleum Australia Limited and Flinders Petroleum N.L. Also included is the Guarantee of the Northern Territory of Australia dated June 28, 1985. All of the above were filed as Exhibit 10(i) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) and are incorporated herein by reference. (j) Agreements dated June 28, 1985 relating to Amadeus Basin -Darwin Pipeline which include Deed of Trust Amadeus Gas Trust, Undertaking by the Northern Territory Electric Commission and Undertaking from the Northern Territory Gas Pty Ltd. filed as Exhibit 10(j) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (k) Agreement between the Mereenie Producers and the Palm Valley Producers dated June 28, 1985 filed as Exhibit 10(k) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (l) Form of Agreement pursuant to Article SIXTEENTH of the Company's Certificate of Incorporation and the applicable By-Law to indemnify the Company's directors and officers filed as Exhibit 10(l) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (m) 1998 Stock Option Plan, filed as Exhibit 4(a) to Form S-8 Registration Statement on January 14, 1999, filed as Exhibit 10(m) to Annual Report on Form 10-K for the year ended June 30, 1999 (File No. 001-5507) is incorporated herein by reference. (n) 1989 Stock Option Plan filed as Exhibit O to Annual Report on Form 10-K for the year ended June 30, 2002 (File No. 001-5507) is incorporated herein by reference. (o) Palm Valley Gas Purchase Agreement Deed of Amendment dated January 17, 2003 filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (file No. 001-5507) is incorporated herein by reference. (p) Share sale agreement dated July 10, 2003 between Sagasco Amadeus Pty. Limited and Magellan Petroleum Corporation filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (File No. 001-5507) is incorporated herein by reference. (q) Registration Rights Agreement date September 2, 2003 between 2003 between Sagasco Amadeus Pty. Limited and Magellan Petroleum Corporation filed as Exhibit 10(p) to Annual Report on Form 10-K for the year ended June 30, 2003 (File No. 001-5507) is incorporated herein by reference. (r) Employment Agreement between Daniel J. Samela and Magellan Petroleum Corporation effective March 1, 2004, filed as Exhibit 10(1) to Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 (File No. 001-5507) is incorporated herein by reference. (s) Palm Valley Renewal of Petroleum Lease dated November 6, 2003 is filed herein. 55 11. Statement re computation of per share earnings. Not applicable. 12. Statement re computation of ratios. None. 13. Annual report to security holders, Form 10-Q or quarterly report to security holders. Not applicable. 16. Letter re change in certifying accountant. Letter of Ernst & Young LLP dated August 27, 2003 filed as exhibit 16 to Current Report on Form 8-K filed on August 27, 2003 (File No. 001-5507) is incorporated herein by reference. 18. Letter re change in accounting principles. None. 21. Subsidiaries of the registrant. Filed herein. 22. Published report regarding matters submitted to vote of security holders. Not applicable. 23. Consent of experts and counsel. 1. Consent of Deloitte & Touche LLP is filed herein. 2. Consent of Ernst & Young LLP is filed herein. 3. Consent of Paddock Lindstrom & Associates, Ltd. is filed herein. 24. Power of attorney. None. 31. Rule 13a-14(a) Certifications. Certification of Daniel J. Samela, Chief Executive Officer and Chief Financial and Accounting Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, is filed herein. 32. Section 1350 Certifications. Certification of Daniel J. Samela, President, Chief Executive Officer and Chief Financial and Accounting Officer, pursuant to 18 U.S.C. sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, is filed herein. (d) Financial Statement Schedules. None. 56 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. MAGELLAN PETROLEUM CORPORATION (Registrant) /s/ DANIEL J. SAMELA -------------------------------------- Daniel J. Samela President, Chief Executive Officer, Chief Financial and Accounting Officer Dated: October 13, 2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ DANIEL J. SAMELA President, Chief Executive Dated: October 13, 2004 - -------------------------------------- Officer, Chief Financial Daniel J. Samela and Accounting Officer /s/ DONALD V. BASSO Director Dated: October 13, 2004 - -------------------------------------- Donald V. Basso /s/ TIMOTHY L. LARGAY Director Dated: October 13, 2004 - -------------------------------------- Timothy L. Largay /s/ WALTER MCCANN Director Dated: October 13, 2004 - -------------------------------------- Walter McCann /s/ RONALD P. PETTIROSSI Director Dated: October 13, 2004 - -------------------------------------- Ronald P. Pettirossi
57 INDEX TO EXHIBITS 3(b) By laws as amended on July 22, 2004. 10(s) Palm Valley Renewal of Petroleum Lease dated November 6, 2003. 21. Subsidiaries of the Registrant. 23. 1. Consent of Deloitte & Touche LLP 2. Consent of Ernst & Young LLP 3. Consent of Paddock Lindstrom & Associates, Ltd. 31. Rule 13a-14(a) Certifications. 32. Section 1350 Certifications.