Tellurian (TELZ) 10-K 2005 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended June 30, 2005
or
o	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 incorporation or organization	(I.R.S. Employer 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 þ          No o

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 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.     þ

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).     Yes o          No þ

      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes o          No þ

      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, 2004 (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 September 22, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

      None

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		2
Item 2.	Properties		10
Item 3.	Legal Proceedings		13
Item 4.	Submission of Matters to a Vote of Security Holders		13
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		15
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		25
Item 8.	Financial Statements and Supplementary Data		26
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		50
Item 9A.	Controls and Procedures		51
Item 9B.	Other Information		51
PART III
Item 10.	Directors and Executive Officers of the Registrant		52
Item 11.	Executive Compensation		54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		56
Item 13.	Certain Relationships and Related Transactions		56
Item 14.	Principal Accountant Fees and Services		57
PART IV
Item 15.	Exhibits and Financial Statement Schedules		58

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 September 22, 2005 was approximately A.$1.00 equaled U.S.$.77.

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, 2005, MPC’s principal asset was a 55.125% equity interest of stock that is publicly held in Australia and listed on the Australian stock exchange under the trading symbol MAG.

      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%. At June 30, 2005 Origin Energy’s interest in MPAL is 11%.

      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 258 barrels of oil per day (MPAL share 100 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 55.125% 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 11% 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:

      The following is a summary of oil and gas properties that the Company has an interest in. The Company is committed to certain exploration and development expenditures, some of which may be farmed out to third parties.

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AUSTRALIA

Mereenie Oil and Gas Field

      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 (net of royalties), based upon contract amounts, was approximately 262,000 barrels and 14.6 billion cubic feet (bcf) of gas at June 30, 2005. Two gas development wells were drilled in late 2004 to increase gas deliverability in order to meet the gas contractual requirements until June 2009.

      During fiscal 2005, MPAL’s share of oil sales was 136,000 barrels and 4.3 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. Limited (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 Mereenie field expires in November 2023.

Palm Valley Gas Field

      MPAL has a 52.023% 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 47.977% 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, net of royalities, was 10.7 bcf at June 30, 2005 and is based upon contract amounts. During fiscal 2005, MPAL’s share of gas sales was 2.4 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 paid 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, which is scheduled to be commissioned in the field at the end of 2005. The production lease covering the Palm Valley field expires in November 2024.

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 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 the 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.

      The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. As indicated above, gas production from both fields is fully contracted through to 2009 and 2012, respectively. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.

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      At June 30, 2005, MPAL’s commitment to supply gas under the above agreements was as follows:

Period	Bcf
Less than one year		6.21
Between 1-5 years		23.06
Greater than 5 years		.80
Total		30.07

Nockatunga Oil Fields

      MPAL purchased its 40.936% working interest (38.703% net revenue interest) in the Nockatunga oil fields in southwest Queensland during 2004. Santos Ltd. is operator of the fields and holds the remaining interest. The assets comprise eight producing oil fields in Petroleum Leases 33, 50 and 51 together with exploration acreage in ATP 267P. The fields are currently producing about 258 barrels of oil per day (MPAL share 100 bbls). During fiscal 2005, MPAL’s share of oil sales was 35,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.0%. MPAL’s share of the Nockatunga fields’ proved developed oil reserves was approximately 253,000 barrels at June 30, 2005. Petroleum Lease 33 expires in April 2007 and Petroleum Leases 50 and 51 expire in June 2011.

      A 92 square mile 3D seismic survey was undertaken in late 2004 over PL51 and parts of PL33 and ATP 267P. The drilling of four wells, development as well as exploration, is planned for late 2005 at locations identified by the seismic data. MPAL’s share of the cost is approximately $1,065,000. At June 30, 2005, MPAL’s share of the work obligations of ATP 267P totaled $312,000, of which none was committed.

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 expires in October 2008.

Browse Basin

      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 $1,006,000. MPAL’s interest in WA 306-P reduced to 12.5%. The well was a dry hole and MPAL has withdrawn from both these permits.

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. At June 30, 2005, MPAL’s share of the work obligations of permit ATP 613P totaled $1,067,000, of which $114,000 is committed.

Cooper/ Eromanga Basin

PEL 94, PEL 95 & PPL 210

      During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum Ltd. were successful in bidding for two exploration blocks (PEL 94 and PEL 95) in South Australia’s Cooper Basin. Aldinga-1 was completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. By June

4

2005, production had declined to about 25 barrels of oil per day. Petroleum Production Licence 210 was granted over the Aldinga field in December 2004. During July 2004, the Waitpinga-1 well was drilled in PEL 95 and the Almonta-1 well was drilled in PEL 95 during April 2005. Both wells were dry holes. Black Rock Petroleum NL contributed to the cost of drilling the Myponga-1 well in June 2004 to earn a 15% interest in the PEL 94 permit. MPAL’s interest in PEL 94 was reduced to 35%. Black Rock Petroleum NL subsequently assigned its interest in PEL 94 to Victoria Petroleum NL. MPAL’s share of the cost of the two wells was approximately $301,000. These have been reflected as exploration and production costs in the consolidated financial statements. At June 30, 2005, MPAL’s share of the work obligations of the two permits totaled $513,000, of which $288,000 was committed.

PEL 110 & PELA 116

      During fiscal year 2001, MPAL and its partner Beach Petroleum Ltd. 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. The application for PEL 116 has been withdrawn. During July 2005, the Yanerbie-1 well was drilled in PEL 110. Cooper Energy NL contributed to the cost of the well to earn a 25% interest in PEL 110, and Enterprise Energy NL contributed to the cost of the well to earn 12.5% in any discovery. The well was a dry hole. MPAL has granted Enterprise Energy NL the option to earn a 6.25% interest in the PEL 110 by funding further exploration in the area. At June 30, 2005, MPAL’s share of the work obligations of the PEL 110 permit totaled $601,000, of which $143,000 was 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. Following a program of seismic reprocessing and interpretation, the permit was surrendered during May 2005. In November 2003, MPAL (100%) was granted permit PEP 38225, adjacent to PEP 38222. At June 30, 2005, MPAL’s work obligations on the PEP 38225 permit totaled $12,725,000, of which none is committed.

PEP 38746, PEP 38748, PEP 38765 & PEP 38766

      In August 2002, MPAL was granted a 25% interest in permits PEP 38746 and PEP 38748 in the Taranaki Basin in the North Island, New Zealand. MPAL and its partners drilled the Hihi-1 well in PEP 38748 during November 2004 and the Kakariki-1 well during February 2005 at an approximate cost of $422,000 to MPAL. Hihi located a sub-commercial gas pool and Kakariki-1 was a dry hole. MPAL has withdrawn from the PEP 38746 and PEP 38748 permits.

      MPAL was granted exploration permits PEP 38765 (12.5%) and PEP 38766 (25%) during February 2004. The Miromiro-1 well was drilled in PEP 38765 during December 2004. The well was a dry hole. MPAL has elected to withdraw from PEP 38766. At June 30, 2005, MPAL’s share of the work obligations of the PEP 38765 permit totaled $210,000, of which none was committed.

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 Sandhills-2 well spudded in the PEDL 098 permit during August 2005. At June 30, 2005, MPAL’s share of the work obligations of the permits totaled $1,112,000, of which $114,000 was committed. The UK companies, Northern Petroleum and Montrose Industries, funded part of MPAL’s share of the cost of the Sandhills-2 well.

5

PEDL 112 & PEDL 113

      During fiscal year 2002, MPAL acquired two additional licenses in southern England. The two licenses, PEDL 113 (22.5%) 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, 2005, MPAL’s share of the work obligations of the permits totaled $1,458,000, of which $60,000 was committed.

PEDL 125 & PEDL 126

      Effective July 1, 2003, MPAL acquired two licenses each granted for a period of six years in southern England, PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex. The drilling plans for the Hedge End-2 well in PEDL 125 and Horndean Extension-1 in PEDL 126 are in progress and spudding of these well is expected in 2006. The UK company, Oil Quest Resources Plc, will fund part of MPAL’s share of the cost of the two wells to acquire a 10% interest in each of the permits. At June 30, 2005, MPAL’s share of the work obligations of the two permits totaled $1,759,000, of which $1,686,000 was committed.

PEDL 135, PEDL 136 & PEDL 137

      Effective October 1, 2004, MPAL was granted 100% interest in PEDL 135, PEDL 136 and PEDL 137 in southern England for a term of six years, each with a drill or drop obligation at the end of the third year of the term. MPAL is undertaking a program of seismic data purchase and interpretation. At June 30, 2005, MPAL’s work obligation for the three licenses totaled $8,573,000, of which none was committed.

PEDL 151, PEDL 152, PEDL 153, PEDL 154 & PEDL 155

      Effective October 1, 2004, MPAL acquired an additional five licenses each granted for a period of six years in southern England, PEDL 151 (11.25%), PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%). Each licence has a drill or drop obligation at the end of the third year of the term. The UK company, Oil Quest Resources Plc, will fund part of MPAL’s share of the PEDL 155 exploration costs to acquire a 10% interest in the license. At June 30, 2005, MPAL’s work obligation for the five licenses totaled $4,159,000, of which none was 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. The Company received cash of $220,352 from this field in 2005.

      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 as well as the Nockatunga and Aldinga oil fields in South Australia’s Cooper Basin. 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) and (b) — 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
Petroleum Lease No. 33 (Nockatunga) (Cooper Basin)	April 2007	Queensland, Australia
Petroleum Lease No. 50 and No. 51(Nockatunga) (Cooper Basin)	June 2011	Queensland, 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-306-P (Browse Basin)	July 2006	Offshore Western Australia
WA-307-P (Browse 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
PEP 38746 (Taranaki Basin)	August 2007	New Zealand
PEP 38748 (Taranaki Basin)	August 2007	New Zealand
PEP 38765 (Taranaki Basin)	February 2009	New Zealand
PEP 38766 (Taranaki Basin)	February 2009	New Zealand
PEP 38225 (Great South Basin)	November 2009	New Zealand
PEDL 098 (Weald-Wessex Basins)	September 2006	United Kingdom
PEDL 099 (Weald-Wessex Basins)	September 2006	United Kingdom
PEDL 112 (Weald-Wessex Basins)	January 2008	United Kingdom
PEDL 113 (Weald Basin)	January 2008	United Kingdom
PEDL 125 (Weald-Wessex Basins)	July 2009	United Kingdom
PEDL 126 (Weald-Wessex Basins))	July 2009	United Kingdom

7

Permit	Expiration Date	Location
PEDL 135 (Weald Basin)	September 2010	United Kingdom
PEDL 136 (Weald Basin)	September 2010	United Kingdom
PEDL 137 (Weald Basin)	September 2010	United Kingdom
PEDL 151 (Weald-Wessex Basins)	September 2010	United Kingdom
PEDL 152 (Weald-Wessex Basin)	September 2010	United Kingdom
PEDL 153 (Weald Basin)	September 2010	United Kingdom
PEDL 154 (Weald Basin)	September 2010	United Kingdom
PEDL 155 (Weald-Wessex Basins)	September 2010	United Kingdom

      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 and condensate production from Mereenie is being shipped and sold through the Port Bonython Export Terminal, Whyalla, South Australia. Crude oil production from Aldinga is shipped and sold through the Moomba processing facility in northeastern South Australia, Nockatunga crude oil is shipped and sold through the IOR refinery at Eromanga, Southwest Queensland. Oil sales during 2005 were 66.6% to the Santos group of companies, 20.2% to Delphi Petroleum P/L and 13.2% to Origin Energy Resources Ltd.

      (viii) Backlog.

      Not applicable.

      (ix) Renegotiation of Profits or Termination of Contracts or Subcontracts at the Election of the Government.

      Not applicable.

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      (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.

      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, 2005, the Company had accrued approximately $5.7 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, 2005, MPC had two full-time employees 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.

9

      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 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

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

10

      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

      (3) Production.

      MPC’s net production volumes for gas and oil during the three years ended June 30, 2005 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material)

	2005		2004		2003
Australia:
Gas (bcf)		5.7		5.7		6.0
Crude oil (bbl)		151,000		150,000		126,000

      The average sales price per unit of production for Australia for the following fiscal years is as follows:

	2005		2004		2003
Australia:
Gas (per mcf)	A.$	2.67	A.$	2.61	A.$	2.65
Crude oil (per bbl)	A.$	62.74	A.$	42.12	A.$	42.82

      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 2005, 2004 and 2003, the cost of remedial work on various wells in the Mereenie field and lower production levels increased production costs.

	2005		2004		2003
Australia:
Gas (per mcf)	A.$	.49	A.$	.49	A.$	.48
Crude oil (per bbl)	A.$	21.20	A.$	25.68	A.$	29.15

      Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the year ended June 30, 2005, 2004 and 2003 the average foreign exchange rates were .7533, .7179, and .5852, respectively.

      (4) Productive Wells and Acreage.

      Productive wells and acreage at June 30, 2005:

	Productive Wells
	Oil				Gas				Developed Acreage
	Gross		Net		Gross		Net		Gross Acres		Net Acres
Australia		47.0		9.8		14.0		3.20		79,957		33,647
Canada		—		—		3.0		.08		3,350		89
		47.0		9.8		17.0		3.28		83,307		33,736

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, 2005

      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
	PL4/ PL5 Mereenie (Amadeus Basin)(1)		69,407		24,292		35.00		13,392		19.30
	PL3 Palm Valley (Amadeus Basin)(2)		157,833		82,109		52.02		45,267		28.68
	RL2 Dingo (Amadeus Basin)		115,596		39,696		34.34		21,882		18.93
			342,836		146,097				80,541
Queensland:
	ATP 613P (Maryborough Basin)		230,352		230,352		100.00		126,993		55.13
	ATP 267P (Cooper Basin)		177,445		72,605		40.94		40,046		22.57
	PL33/ PL50/ PL51 Nockatunga (Cooper Basin)(3)		87,932		36,101		40.94		19,845		22.57
			495,729		339,058				186,884
South Australia:
	PEL 94 (Cooper Basin)		669,296		234,254		35.00		129,144		19.30
	PEL 95/ PPL 210 (Cooper Basin)(4)		960,805		480,403		50.00		264,846		27.57
	PELA 110 (Cooper Basin)		361,188		135,446		37.50		74,671		20.67
			1,991,289		850,103				468,661
Western Australia:
	WA-306-P (Browse Basin)		1,145,413		143,177		12.50		78,933		6.89
	WA-307-P (Browse Basin)		856,769		428,384		50.00		236,168		27.57
			2,002,182		571,561				315,101
United Kingdom
	PEDL 098/113/152 (Weald-Wessex Basins)		82,407		18,542		22.50		10,222		12.40
	PEDL 099/154 (Weald-Wessex Basins)		52,514		21,006		40.00		11,580		22.05
	PEDL 112/153 (Weald Basin)		140,342		46,776		33.33		25,788		18.37
	PEDL 125/126 (Weald-Wessex Basins)		111,975		44,790		40.00		24,693		22.05
	PEDL 135/136/137 (Weald Basin)		123,152		123,152		100.00		67,894		55.13
	PEDL 151 (Weald Basin)		23,540		2,648		11.25		1,460		6.20
	PEDL 154 (Weald Basin)		84,834		42,417		50.00		23,385		27.57
			618,764		299,331				165,022
New Zealand
	PEP 38225 (Great South Basin)		2,908,870		2,908,870		100.00		1,603,660		55.13
	PEP 38746/38748/38766		36,037		9,009		25.00		4,967		13.78
	PEP 38765		3,137		392		12.50		216		6.89
			2,948,044		2,918,271				1,608,843
Total MPAL			8,398,844		5,124,421				2,825,052

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			MPAL			MPC
					Interest			Interest
			Gross Acres	Net Acres	%	Net Acres		%
Properties held directly by MPC:
Canada
	Yukon and Northwest Territories:
		Carried interest(5)	31,8858,430,729				8502,825,902		2.67
Total

(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 6,400 gross developed acres and 2,477 net acres.
(4)	Includes 346 gross developed acres and 173 net acres.
(5)	Includes 3,350 gross developed acres and 89 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
2005		—		1.88		.70		—
2004		—		3.11		.41		.52
2003		.50		1.90		—		—

      (7) Present Activities.

      There was one well being drilled at June 30, 2005. During July 2005, the Company decided to plug and abandon exploration well Yanerbie-1. The Sandhills-2 and Kiana 1wells spudded during August 2005. See Item 1 — Cooper Basin and United Kingdom 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.

      None.

Item 4. Submission of Matters to a Vote of Security Holders.

      None.

13

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 symbolMPET. The stock is also traded on the Boston Stock Exchange under the symbolMPC. The quarterly high and low prices on the most active market, NASDAQ, during the quarterly periods indicated were as follows:

2005	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
High		1.59		1.65		1.97		3.60
Low		1.19		1.22		1.23		1.05

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

      (b) Approximate Number of Holders of Common Stock at September 22, 2005

Title of Class	Number of Record Holders
Common stock, par value $.01 per share		6,752

      (c)Frequency and Amount of Dividends

      MPC has never paid a cash dividend on its common stock.

Recent Sales of Unregistered Securities

      None

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, 2005		0		0		0		319,150
May 1-31, 2005		0		0		0		319,150
June 1-30, 2005		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, 2005, 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. No shares were purchased during 2005 or 2004.

14

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,
		2005			2004			2003			2002			2001
Financial Data
Total revenues		$	21,871		$	19,424		$	14,736		$	13,700		$	14,008
Income before cumulative effect of accounting change			87			350			890			92			1,072
Net income			87			350			152			92			1,072
Net income per share (basic and diluted)			—			.01			.01			—			.04
Working capital			26,208			21,696			21,798			17,862			15,398
Cash provided by operating activities			8,527			10,781			7,109			8,157			4,668
Property and equipment (net)			24,265			24,421			21,592			17,046			16,482
Total assets			56,424			52,894			50,741			40,166			37,498
Long-term liabilities			5,729			5,256			5,629			3,974			3,982
Minority interests			18,583			16,533			16,931			13,933			12,701
Stockholders’ equity:
	Capital		44,660			44,660			43,152			43,332			43,426
	Accumulated deficit		(15,161	)		(15,248	)		(15,598	)		(15,751	)		(15,843	)
	Accumulated other comprehensive loss		(2,323	)		(4,491	)		(5,407	)		(8,965	)		(10,410	)
	Total stockholders’ equity		27,176			24,920			22,147			18,616			17,173
Exchange rate A.$ = U.S. at end of period			.76			.70			.67			.56			.51
Common stock outstanding shares end of period			25,783			25,783			24,427			24,607			24,698
Book value per share			1.05			.97			.91			.76			.70
Quoted market value per share (NASDAQ)			2.40			1.31			1.20			.88			1.07
Operating Data
Standardized measure of discounted future cash flow relating to proved oil and gas reserves (approximately 45% attributable to minority interests) (See Note 13)			31,000			30,000			26,000			26,000			33,000
Annual production (net of royalties)
	Gas (bcf)		5.7			5.7			6.0			6.0			5.7
	Oil (bbls) (In thousands)		151			150			126			141			148

15

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.

Executive Summary

      Magellan Petroleum Corporation (MPC) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. MPC’s principal asset is a 55.125% equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL).

      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.

      MPAL is refocusing its exploration activities into two core areas, the Cooper Basin in onshore Australia and the Weald Basin in the onshore southern United Kingdom with an emphasis on developing a low to medium risk acreage portfolio.

      MPC also has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. The Company received approximately $220,000 from this investment during fiscal 2005.

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, productive leases, and permit and concession costs 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. For Mereenie and Palm Valley, proved developed reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities.

      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

16

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 3 to the consolidated financial statements regarding the cumulative effect of the accounting change and its effect on net income for the year ended June 30, 2003.

      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 Aldinga 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.

      Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Judgments are based upon such things as field life and estimated 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 when 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 11 to the consolidated financial statements.

Consolidated

      At June 30, 2005, the Company on a consolidated basis had approximately $21.7 million of cash and cash equivalents and $3.2 million in marketable securities.

      Net cash provided by operations was $8,776,195 in 2005 compared to $10,717,936 in 2004. The decrease is primarily related to the absence in 2005 of cash received from the Kotaneelee settlement and decreased

17

collections from MPAL’s largest customer. Cash flow from operations is primarily the result of MPAL’s oil and gas activities.

      During 2005, the Company had net investments in marketable securities of $40,000 compared to $990,000 in 2004. The decrease in investments was the result of MPC investing less due to the absence of the Kotaneelee settlement in 2005.

      The Company invested $8,335,370 and $8,937,923 in oil and gas exploration activities during 2005 and 2004, 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, 2005, MPC, on an unconsolidated basis, had working capital of approximately $3.9 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 2005, MPC purchased 31,605 shares of MPAL’s stock at a cost of $29,466 and increased its interest in MPAL from 55.06% to 55.125%.

      During fiscal 2005, MPC received a dividend from MPAL of approximately $975,000.

      MPC has a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2005, MPC had purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal 2005 or 2004.

As to MPAL

      At June 30, 2005, MPAL had working capital of approximately $22.3 million. MPAL had budgeted approximately $6.2 million for specific exploration projects in fiscal year 2005 as compared to the $5.1 million expended during fiscal 2005. 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. The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the market and there are no assurances that the Palm Valley producers will be able to contract for the sale of the remaining uncontracted reserves.

      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 continue to 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.

18

Off Balance Sheet Arrangements

      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.

Contractual Obligations

      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			752,000		183,000		388,000		181,000		—
Purchase Obligations(1)			3,380,000		3,380,000		—		—		—
Asset Retirement Obligations			5,729,000		38,000		—		3,773,000		1,918,000
	Total	$	9,861,000	$	3,601,000	$	388,000	$	3,954,000		1,918,000

(1)  Represents firm commitments for exploration and capital expenditures. The Company is committed to these expenditures, however some may be farmed out to third parties. Exploration contingent expenditures of $30,083,000 which are not legally binding have been excluded from the table above and based on exploration decisions would be due as follows: $14,685, 000 (less than 1 year), $4,327,000 (1-3 years), $11,071,000 (3-5 years).

Recent Accounting Pronouncements

      In December 2004, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), (SFAS 123(R)) “Share Based Payment”. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 (APB 25), “Accounting for Stock Issued to Employees”, and generally requires that such transactions be accounted for using a fair-value-based method. SFAS 123(R) is effective as of the first annual reporting period of a registrant’s fiscal year that begins on or after June 15, 2005, therefore, the effective date for the Company is July 1, 2005. SFAS 123(R) applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date and as a consequence future employee stock option grants and other stock based compensation plans will be recorded as expense over the vesting period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) is to be recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company will recognize stock-based compensation expense from July 1, 2005 as if the fair value based accounting method had been used to account for all outstanding unvested employee awards granted, modified or settled in prior years. The ultimate impact on future years results of operation and financial position will depend upon the level of stock based compensation granted in future years.

      For further information regarding equity- based compensation, see Note 4 “capital and stock options” to the consolidated financial statements

      On March 30, 2005 the FASB issued FASB Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. FIN 47 is effective for the fiscal year end June 30, 2005.

19

      On April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSB 19-1 “Accounting for Suspended Well Costs” that amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In accordance with the guidance in the FSP, the Company applied the requirements prospectively in its fourth quarter of fiscal 2005. The adoption of FSP 19-1 by the Company during the fourth quarter of 2005 did not have an immediate affect on the consolidated financial statements. However, it could impact the timing of the recognition of expenses for exploratory well costs in future periods.

      In November 2004, the FASB issued SFAS No. 151 “Accounting for Inventory Costs” that amends Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” and requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 was effective for the Company for the fiscal year ended June 30, 2005 and did not have an effect on the financial statements.

      In December 2004, the FASB issued SFAS No. 153 “Exchanges of Nonmonetary Assets” that amends Accounting Principles Board (APB) Opinion No. 29, ”Accounting for Nonmonetary Transactions.” ARB No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged and SFAS 153 amended ABP 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaced it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 was effective for the Company for the fiscal year ended June 30, 2005 and did not have an effect on the financial statements.

      In May 2005, the FASB issued SFAS No. 154 “Accounting Changes and Error Corrections” to replace ABP No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim Financial Statements.” Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable. SFAS No. 154 is effective for the Company in the second quarter of fiscal 2006. Management is currently evaluating the impacts of SFAS 154 on the Company and cannot yet reasonably estimate the impact of SFAS 154 on the financial statements.

20

Results of Operations

2005 vs. 2004

Revenues

      Oil sales increased 54% in 2005 to $7,574,000 from $4,923,000 in 2004 because of the 5% Australian foreign exchange rate increase discussed below and a 49% increase in the average sales price per barrel. 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,
		2005 Sales				2004 Sales
				Average Price				Average Price
		Bbls		A.$ per bbl		Bbls		A.$ per bbl
Australia:
	Mereenie Field		116,920		64.15		110,955		43.44
	Cooper Basin		4,002		62.65		6,522		37.29
	Nockatunga Project		30,567		57.28		34,105		38.73
Total			151,489		62.74		151,582		42.12
		��

      Amounts presented above for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2005 and 2004, the average foreign exchange rates were .7533 and ..7179, respectively.

      Gas sales decreased 3% to $12,478,000 in 2005 from $12,870,000 in 2004. The decrease was primarily the result of the one time proceeds of $1,135,000 from the Kotaneelee gas field settlement recorded in 2004. This was partially offset by the 5% Australian foreign exchange rate increase discussed below, an increase in price per mcf sold and increased sales volume in 2005.

      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,
		2005 Sales				2004 Sales
				A.$ Average				A.$ Average
		Bcf		Price per mcf		Bcf		Price per mcf
Australia: Palm Valley			2.017		2.14		2.376		2.25
Australia: Mereenie			3.724		2.97		3.287		2.86
	Total		5.741		2.67		5.663		2.61

      Other production related revenues increased 11% to $1,818,000 in 2005 from $1,632,000 in 2004. 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 5% Australian foreign exchange rate increase discussed below.

Costs and Expenses

      Production costs increased 13% in 2005 to $6,144,000 from $5,416,000 in 2004. The increase in 2005 was primarily the result of increased expenditures in the Mereenie and Palm Valley fields ($789,000) and the 5% Australian foreign exchange rate increase discussed below, partially offset by lower expenditures for the Nockatunga project and the Cooper Basin.

      Exploration and dry hole costs increased 29% to $4,157,000 in 2005 from $3,225,000 in 2004. The 2005 and 2004 costs related to the exploration work being performed on MPAL’s properties. The primary reasons for the increase in 2005 were work performed on the Nockatunga project ($893,000), costs related to exploration activities in New Zealand ($567,000) and the 5% Australian foreign exchange rate increase

21

discussed below. These costs were partially offset by lower costs incurred in 2005 on properties in Southern Australia ($476,000).

      Salaries and employee benefits decreased 28% to $2,726,000 in 2005 from $3,812,000 in 2004. During the 2004 period, MPAL curtailed its pension plan, which resulted in a $1,248,000 charge, of which $961,000 was non cash. This reduction was partially offset by the 5% Australian foreign exchange rate increase discussed below.

      Depletion, depreciation and amortization increased 10% from $6,342,000 in 2004 to $6,994,000 in 2005. Depletion expense for the Palm Valley and Mereenie fields increased 16% during the 2005 period primarily because of a higher depletion rate for 2005 due to a change in reserve estimates. Depletion also increased due to the 5% Australian foreign exchange rate increase discussed below.

      Auditing, accounting and legal expenses increased 7% in 2005 to $442,000 from $414,000 in 2004 primarily because of the 5% Australian foreign exchange rate increase discussed below. 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 that is expected to apply to the Company for the first time with respect to its annual report for the fiscal year ending June 30, 2007.

      Accretion expense increased 14% in the 2005 period from $357,000 in 2004 to $407,000 in 2005. 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 2005 period is primarily the 5% increase in the Australian foreign exchange rate discussed below.

      Shareholder communications costs increased 26% from $180,000 in 2004 to $227,000 in 2005 primarily because of MPC and MPAL’s increased costs related to preparing public filings for distribution and the 5% increase in the Australian foreign exchange rate discussed below.

      Other administrative expenses increased 21% from $660,000 in 2004 to $800,000 in 2005 primarily due to increased consulting costs and the 5% increase in the Australian foreign exchange rate discussed below.

Interest Income

      Interest income increased 4% to $1,142,000 in 2005 from $1,099,000 in 2004 primarily because of the 5% Australian foreign exchange rate increase discussed below.

Income Taxes

      Income tax benefits for the years ended June 30, 2005 and 2004 were $82,153 and $775,085, respectively. Income tax benefits were reduced in 2005 as a result of the lack of the reversal of the reserve of $1,266,000 recognized in 2004 on MPAL deferred tax assets generated from MPAL’s financing subsidiary. This was offset by a reduction in Canadian income tax expense of $421,000 in 2005, as a result of reduced Canadian revenues. As a result of a change in Australian tax law during 2004, MPAL docs not expect to receive similar financing benefits in the future.

Exchange Effect

     The value of the Australian dollar relative to the U.S. dollar increased to $.7620 at June 30, 2005 compared to $.6993 at June 30, 2004. This resulted in a $2,169,000 credit to accumulated translation adjustments for fiscal 2005. The 9% increase in the value of the Australian dollar increased the reported asset and liability amounts in the balance sheet at June 30, 2005 from the June 30, 2004 amounts. The annual average exchange rate used to translate MPAL’s operations in Australia for fiscal 2005 was $.7533, which is a 5% increase compared to the $.7179 rate for fiscal 2004.

22

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 for oil prices and below for gas prices are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2004 and 2003 the average foreign exchange rates were .7179 and .5852 and 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.

      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				A.$ Average
		Bcf		Price per mcf		Bcf		Price 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.

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.

23

      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.

      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.

Interest Income

      Interest 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.

Income Taxes

      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. These reductions were offset by an increase in income income tax benefits of $639,000 resulting from pretax losses in Australia during 2004. As a result of a change in Australian tax law during 2004, MPAL does

24

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.

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. At June 30, 2005, the carrying value of such investments including those classified as cash and cash equivalents was approximately $25 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. A 10% change in the Australian foreign currency rate compared to the U.S. dollar would increase or decrease revenues and costs and expenses by $2.2 million and $2.1 million, respectively. For the twelve months ended June 30, 2005, oil sales represented approximately 38% of production revenues. Based on 2005 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by $757,000. Gas sales, which represented approximately 62% of production revenues in 2005, 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.

25

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 sheets of Magellan Petroleum Corporation (the “Company”) as of June 30, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years 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 audits. The financial statements of the Company for the year ended June 30, 2003 were audited by other auditors whose report, dated September 19, 2003, expressed an unqualified opinion on those statements and included an explanatory paragraph concerning a change in accounting for asset retirement obligations.

      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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such 2005 and 2004 consolidated financial statements present fairly, in all material respects, the financial position of Magellan Petroleum Corporation as of June 30, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/Deloitte & Touche LLP

Hartford, Connecticut

September 26, 2005

26

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Magellan Petroleum Corporation

      We have audited the accompanying consolidated statements of income, changes in stockholders’ equity and cash flows of Magellan Petroleum Corporation for the year 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 audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Magellan Petroleum Corporation for the year ended June 30, 2003 in conformity with U.S. generally accepted accounting principles.

      As discussed in Notes 1 and 3 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

27

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

			June 30,
			2005			2004
ASSETS
Current assets:
	Cash and cash equivalents		$	21,733,375		$	20,406,620
	Accounts receivable — Trade			4,210,174			2,931,609
	Accounts receivable — Working Interest Partners			864,922			1,044,619
	Marketable securities			3,216,541			2,584,296
	Inventories			591,997			595,948
	Other assets			526,703			318,141
		Total current assets		31,143,712			27,881,233
Marketable securities							592,138
Deferred income taxes				1,014,907			—
Property and equipment:
	Oil and gas properties (successful efforts method)			80,765,911			69,970,134
	Land, buildings and equipment			2,552,980			2,264,004
	Field equipment			1,620,909			1,482,639
				84,939,800			73,716,777
	Less accumulated depletion, depreciation and amortization			(60,674,306	)		(49,295,770	)
		Net property and equipment		24,265,494			24,421,007
	Total assets		$	56,424,113		$	52,894,378
LIABILITIES, MINORITY INTERESTS AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	3,602,085		$	4,367,305
	Accrued liabilities			1,308,004			1,550,045
	Income taxes payable			25,879			267,645
		Total current liabilities		4,935,968			6,184,995
Long term liabilities:
	Deferred income taxes			—			403,261
	Asset retirement obligations			5,729,180			4,852,416
		Total long term liabilities		5,729,180			5,255,677
Minority interests				18,583,046			16,533,491
Commitments (Note 11)				—			—
Stockholders’ equity:
	Common stock, par value $.01 per share:
		Authorized 200,000,000 shares outstanding; 25,783,243		257,832			257,832
	Capital in excess of par value			44,402,182			44,402,182
	Total capital			44,660,014			44,660,014
	Accumulated deficit			(15,161,462	)		(15,248,422	)
	Accumulated other comprehensive loss			(2,322,633	)		(4,491,377	)
Total stockholders’ equity				27,175,919			24,920,215
Total liabilities, minority interests and stockholders’ equity			$	56,424,113		$	52,894,378

See accompanying notes.

28

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

		Years Ended June 30,
		2005			2004			2003
Revenues:
	Oil sales	$	7,574,022		$	4,922,585		$	3,329,243
	Gas sales		12,478,293			12,870,065			10,182,104
	Other production related revenues		1,818,471			1,631,613			1,224,729
	Total revenues		21,870,786			19,424,263			14,736,076
Costs and expenses:
	Production costs		6,144,339			5,416,465			4,461,365
	Exploratory and dry hole costs		4,157,344			3,225,066			2,920,104
	Salaries and employee benefits		2,726,341			3,812,012			1,958,371
	Depletion, depreciation and amortization		6,994,253			6,341,998			3,718,660
	Auditing, accounting and legal services		441,642			413,754			404,215
	Accretion expense		406,960			356,981			242,854
	Shareholder communications		227,032			179,840			171,385
	Other administrative expenses		800,200			659,751			369,942
	Total costs and expenses		21,898,111			20,405,867			14,246,896
Operating income (loss)			(27,325	)		(981,604	)		489,180
Interest income			1,141,802			1,099,440			859,865
Income before income taxes, minority interests and cumulative effect of accounting change			1,114,477			117,836			1,349,045
Income tax benefit			82,152			778,085			773,548
Income before minority interests and cumulative effect of accounting change			1,196,629			895,921			2,122,593
Minority interests			(1,109,669	)		(545,860	)		(1,232,200	)
Income before cumulative effect of accounting change			86,960			350,061			890,393
Cumulative effect of accounting change — net			—			—			(737,941	)
Net income		$	86,960		$	350,061		$	152,452
Average number of shares:
	Basic		25,783,243			25,644,566			24,560,068
	Diluted		25,783,243			25,682,160			24,560,068
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.

29

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF

CHANGES IN STOCKHOLDERS’ EQUITY

Three Years Ended June 30, 2005

													Accumulated
							Capital in						Other						Total
	Number of			Common			Excess of			Accumulated			Comprehensive						Comprehensive
	Shares			Stock			Par Value			Deficit			Loss			Total			Income
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
Net income		—			—			—			86,960			—			86,960			86,960
Foreign currency translation adjustments		—			—			—			—			2,168,744			2,168,744			2,168,744
Total comprehensive income		—			—			—			—			—			—			2,255,704
June 30, 2005		25,783,243		$	257,832		$	44,402,182		$	(15,161,462	)	$	(2,322,633	)	$	27,175,919

See accompanying notes.

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MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Years Ended June 30,
			2005			2004			2003
Operating Activities:
	Net income		$	86,960		$	350,061		$	152,452
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect of accounting change					—			2,025,690
		Depletion, depreciation and amortization		6,994,253			6,341,998			3,718,660
		Accretion expense		406,960			356,981			242,854
		Deferred income taxes		(1,454,544	)		(1,445,241	)		(1,494,621	)
		Minority interests		1,109,669			545,860			552,158
		Exploration and dry hole costs		3,200,816			2,897,766			1,961,421
	Increase (decrease) in operating assets and liabilities:
		Accounts receivable		(978,727	)		1,456,833			(951,967	)
		Other assets		(208,563	)		905,146			(214,946	)
		Inventories		57,207			(142,397	)		(69,275	)
		Accounts payable and accrued liabilities		(191,341	)		(715,548	)		1,368,413
		Income taxes payable		(246,495	)		166,477			(123,087	)
		Settlement of asset retirement obligation		—			—			(58,901	)
Net cash provided by operating activities				8,776,195			10,717,936			7,108,851
Investing Activities:
	Additions to property and equipment			(5,154,554	)		(6,040,157	)		(2,438,829	)
	Oil and gas exploration activities			(3,200,816	)		(2,897,766	)		(1,961,421	)
	Sale of available-for-sale securities			—			—			93,334
	Marketable securities matured			5,599,328			5,760,239			2,071,687
	Marketable securities purchased			(5,639,435	)		(6,750,171	)		(2,564,501	)
Net cash used in investing activities				(8,395,477	)		(9,927,855	)		(4,799,730	)
Financing Activities:
	Dividends to MPAL minority shareholders			(821,732	)		(744,971	)		(628,209	)
	Repurchases of common stock			—			—			(179,900	)
Net cash used in financing activities				(821,732	)		(744,971	)		(808,109	)
Effect of exchange rate changes on cash and cash equivalents				1,767,769			320,046			2,755,601
Net increase in cash and cash equivalents				1,326,755			365,156			4,256,613
Cash and cash equivalents at beginning of year				20,406,620			20,041,464			15,784,851
Cash and cash equivalents at end of year			$	21,733,375		$	20,406,620		$	20,041,464
Cash Payments:
	Income taxes			13,000			12,000			173,000
	Interest			—			—			—

See accompanying notes.

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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, 2005 and 2004, MPC’s principal asset was a 55% equity interest in its subsidiary, Magellan Petroleum Australia Limited (MPAL), which has one class of stock that is publicly held and listed on the Australian Stock Exchange under the trading symbol MAG. 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 2005 and 2004, MPC purchased 32,000 (for $29,466) and 24,000 shares (for $22,000), 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. 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, productive leases, and permitted concession costs 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. For Mereenie and Palm Valley, proved developed natural gas reserves are limited to contracted quantities. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves or the contracted quantities.

      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 Statement of Financial Accounting Standard (SFAS)143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires legal obligations

32

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.

      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.

      The Company performs an annual impairment test by performing a discounted cash flow analysis.

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.

Accounts Receivable

      The Company has determined that an allowance for doubtful accounts was not necessary as all receivables were expected to be realized in full.

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 SFAS No. 52. The translation adjustment is included as a component of stockholders’ equity and comprehensive income (loss), whereas gains or losses on foreign currency transactions are 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, 2005 and 2004, the Australian dollar was equivalent to U.S. $.76 and $.70, respectively. The annual average exchange rates used to translate MPAL’s operations in Australia for the fiscal years 2005, 2004 and 2003 were $.75, $.72 and $.59, respectively.

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Accrued Liabilities

      At June 30, 2005 and 2004, balances in accrued liabilities which exceeded 5% of the total balance include $1,046,438 and $1,221,446 of employment benefits, respectively and $226,578 and $192,982 of payroll withholding taxes, 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 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,
	2005		2004
Cash	$	309,283	$	1,648,074
U.S. government obligations		—		398,852
Australian money market accounts and short-term commercial paper		21,424,092		18,359,694
	$	21,733,375	$	20,406,620

Marketable Securities

      At June 30, 2005 and 2004, MPC had the following marketable securities which are expected to be held until maturity:

June 30, 2005	Par Value		Maturity Date		Amortized Cost		Fair Value
Short-term securities
U.S. government agency note	$	300,000		Jul. 21, 2005	$	295,437	$	299,460
U.S. government agency note		575,000		Aug. 23, 2005		565,532		572,240
U.S. government agency note		210,000		Sep. 16, 2005		206,920		208,488
U.S. government agency note		100,000		Sep. 16, 2005		98,380		99,280
U.S. government agency note		200,000		Oct. 24, 2005		196,611		197,840
State of Connecticut bond		200,000		Nov. 15, 2005		200,585		199,852
Lewiston, Maine Pension bond		390,000		Dec. 15, 2005		390,000		392,336
U.S. government agency note		310,000		Jan. 10, 2006		302,863		304,141
U.S. government agency note		300,000		Feb. 24, 2006		291,980		292,950
U.S. government agency note		300,000		Mar. 28, 2006		300,000		298,500
U.S. government agency note		230,000		Apr. 28, 2006		223,035		223,008
U.S. government agency note		150,000		May 02, 2006		145,198		145,350
Total short-term	$	3,265,000			$	3,216,541	$	3,233,445

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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, Maine Pension bond		390,000		Dec. 15, 2005		390,000		401,532
Total long-term	$	590,000			$	592,138	$	602,910

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 were computed using the treasury stock method. In 2005, the Company did not have any stock options that were issued that had a strike price below the average stock price for the year. There were no other potentially dilutive items at June 30, 2005. At June 30, 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. The exercise price of outstanding stock options exceeded the average market price of the common stock during 2003. The Company’s basic and diluted calculations of EPS are the same in 2005 and 2003 because the exercise of outstanding options of 30,000 and 921,000 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 expensed over the vesting period. 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, 2005 and 2004 was as follows:

	2005			2004
Foreign currency translation adjustments	$	(2,322,633	)	$	(4,491,377	)

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.

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Reclassifications

      Certain reclassifications of prior period data included in the accompanying consolidated financial statements have been made to conform with the current period presentation. Reclassifications associated with the 2004 consolidated statement of cash flows resulted in a decrease in net cash provided by operating activities and a corresponding decrease in net cash used in investing activities of $785,386 related to decreases in exploration and dry hole costs, accounts receivable, and accounts payable and accrued liabilities of $327,300, $96,277, and $361,809, respectively. Reclassifications associated with the 2003 consolidated statement of cash flows resulted in a decrease in net cash provided by operating activities and a corresponding decrease in net cash used in investing activities of $1,965,013 related to changes in exploration and dry hole costs, accounts receivable, and accounts payable and accrued liabilities of $958,683, $(420,062) and $1,426,392, respectively.

2. Oil and Gas Properties

      MPC had the following amounts recorded in oil and gas properties at June 30, 2005 and 2004.

Location	2005		2004
Mereenie and Palm Valley (Australia)	$	77,376,081	$	66,945,763
Nockatunga (Australia)		2,487,986		2,258,338
Aldinga (Australia)		779,871		604,747
Kotaneelee (Canada)		108,777		148,765
Other		13,196		12,521
	$	80,765,911	$	69,970,134

Accumulated Depletion, Depreciation and Amortization

Location	2005		2004
Mereenie and Palm Valley (Australia)	$	56,083,919	$	45,644,688
Nockatunga (Australia)		464,523		218,594
Aldinga (Australia)		728,506		428,863
Kotaneelee (Canada)		53,492		30,059
	$	57,330,440	$	46,322,204

Depletion, Depreciation and Amortization

      During the years ended June 30, 2005, 2004 and 2003, the depletion rate by field was as follows:

	2005		2004		2003
Mereenie and Palm Valley (Australia)		25.6		20.9		17.6
Nockatunga (Australia)		12.1		9.5		—
Aldinga (Australia)		78.1		70.2		2.6
Kotaneelee (Canada)		8.3		25.0		25.0

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.

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Exploratory and Dry Hole Costs

      The 2005, 2004 and 2003 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:

	2005		2004		2003
U.S./ Belize	$	—	$	—	$	(38	)
Australia/ New Zealand		4,157		3,225		2,958
Total	$	4,157	$	3,225	$	2,920

      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, 2005.

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.

      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.

      A reconciliation of the Company’s asset retirement obligations for the years ended June 30, 2005 and 2004, is as follows:

	2005			2004
Balance at beginning of year	$	4,852,000		$	3,858,000
Liabilities incurred		85,000			489,000
Liabilities settled		—			—
Accretion expense		407,000			357,000
Revisions to estimate		(40,000	)		—
Exchange effect		425,000			148,000
Balance at end of year	$	5,729,000		$	4,852,000

      During 2005, an $85,000 liability was incurred for two wells drilled in the Mereenie field. In addition, revised estimates were established for restoration costs for the Kotaneelee field in Canada. 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 2005 or 2004. During 2003, 180,000 shares were repurchased at a cost of $179,900.

      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

37

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, 2005, 795,000 options were available for future issuance under the plan.

      The following is a summary of option transactions for the three years ended June 30, 2005:

		Expiration		Number of
Options Outstanding		Dates		Shares			Exercise Prices ($)
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	)
	Granted		Jul. 2014		30,000			1.45
	Expired				(595,000	)		1.28
June 30, 2005					30,000			1.45

Summary of Options Outstanding at June 30, 2005

	Expiration						Exercise
	Dates		Total		Vested		Prices ($)
Granted 2004		Jul. 2014		30,000		10,000		1.45

      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, 2005. Vested options are exercisable during non black out periods.

      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. The weighted average grant date fair value of the 30,000 options granted in 2005 was $29,700.

      Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. 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 assumptions used in the fiscal 2005 valuation model were: risk free interest rate — 4.95%, expected life — 10 years, expected volatility — .518, expected dividend — 0.

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      The Company’s pro forma information follows:

				Earnings per Share
	Net Income			Basic		Diluted
Net income as reported — June 30, 2003	$	152,000		$	.01	$	.01
Stock option expense (determined under fair value method)		(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 (determined under fair value method)		—			—		—
		—			—		—
Pro forma net income — June 30, 2004	$	350,000		$	.01	$	.01
Net income as reported — June 30, 2005	$	87,000		$	—	$	—
Stock option expense (determined under fair value method)		(18,000	)		—		—
Pro forma net income — June 30, 2005	$	69,000		$	—		—

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,
	2005			2004			2003
United States	$	(1,004	)	$	(548	)	$	(329	)
Foreign		2,118			666			1,678
Total	$	1,114		$	118		$	1,349

      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,
	2005			2004			2003
Tax provision computed at statutory rate (30%)	$	(334	)	$	(35	)	$	(405	)
MPC’s parent company (income) losses		(301	)		165			(98	)
Non-taxable revenue from Australian government sources		301			267			194
MPAL non-deductible foreign losses (New Zealand)		(513	)		(337	)		(197	)
MPAL write off of foreign advances (New Zealand)		1,000			—			—
Reversal of prior year reserve on MPAL Deferred Tax Assets(a)		—			1,266			1,399
MPC income tax provision(b)		(71	)		(492	)		(130	)
Other		—			(56	)		11
Consolidated income tax (provision) benefit	$	82		$	778		$	774
Current income tax provision	$	(1,375	)	$	(667	)	$	(130	)
Deferred income tax benefit		1,457			1,445			904
Consolidated income tax (provision) benefit	$	82		$	778		$	774
Effective tax rate		7	%		—			(57	)%

(a)  Tax benefits 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.

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(b) MPC’s income tax provisions represent the 25% Canadian withholding tax on its Kotaneelee gas field carried interest net proceeds.

      Significant components of the Company’s deferred tax assets and liabilities were as follows:

		June 30,			June 30,
		2005			2004
Deferred tax liabilities
	Acquisition and development costs	$	(981,000	)	$	(2,068,000	)
Deferred tax assets
	Asset retirement obligations		1,996,000			1,665,000
	Net operating losses		2,749,000			2,633,000
	Foreign tax credits		223,000			223,000
	Interest		214,000			214,000
Total deferred tax assets			5,182,000			4,735,000
Valuation allowance			(3,186,000	)		(3,070,000	)
Net deferred tax (liabilities)/asset		$	1,015,000		$	(403,000	)

Australia

      The net deferred tax asset (liability) at June 30, 2005 and 2004, respectively, consist of deferred tax liabilities of $981,000 and $2,068,000, primarily relating to the deduction of acquisition and development costs which are capitalized for financial statement purposes, offset by deferred tax assets of $1,996,000 and $1,665,000, primarily relating to asset retirement obligations which will result in tax deductions when paid.

United States

      At June 30, 2005, the Company had approximately $12,250,000 and $2,237,000 of net operating loss carry forwards for federal and state income tax purposes, respectively, which are scheduled to expire periodically between the years 2007 and 2025. 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, $110,000 in 2023, and $254,000 in 2025. MPAL’s U.S. subsidiary has federal loss carry forwards that expire as follows: $2,392,000 in 2006, $1,669,000 in 2010, $1,764,000 in 2011, $2,855,000 in 2012, $229,000 in 2013, and $197,000 between 2019 and 2025. MPC also has approximately $223,000 of foreign tax credit carryovers, which are scheduled to expire by the year 2006. MPC’s state loss carry forwards expire periodically between the years 2006 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 provided accounting and administrative services, office facilities and support staff to MPC, was paid $65,700, $24,723, and $20,830 in fees for fiscal years 2005, 2004 and 2003 respectively. In addition, MPC purchased $12,000 of office equipment from G&O’D INC. during 2005. 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. 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 $144,596, $120,563, and $69,459 for fiscal years 2005, 2004 and 2003, respectively.

7. Leases

      At June 30, 2005, future minimum rental payments applicable to MPC’s and MPAL’s non-cancelable operating (office) lease were $183,000, $191,000, $197,000, $181,000 and $0 for the years 2006, 2007, 2008, 2009 and 2010, respectively.

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      Operating lease rental expenses for each of the years ended June 30, 2005, 2004 and 2003 were $214,661, $311,497 and $239,026 respectively.

8. Pension Plan

      Prior to August 31, 2004, MPAL maintained a defined benefit pension plan and contributed to the plan at rates which (based on actuarial determination) were sufficient to meet the cost of employees’ retirement benefits. No employee contributions were required. 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. Therefore, there were no pension costs during fiscal 2005.

      The following table sets forth the actuarial present value of benefit obligations and funded status for the MPAL pension plan at June 30, 2005 and 2004:

		2005			2004
Change in Benefit Obligation
Benefit obligation at beginning of year		$	2,145,394		$	1,980,930
	Service cost		—			148,075
	Interest cost		—			94,212
	Actuarial gains and losses		—			(46,378	)
	Benefits paid		(2,145,394	)		(447,277	)
	Settlement and curtailment		—			414,694
	Expenses paid		—			(71,763	)
	Foreign currency effect		—			72,901
Benefit obligation at end of year		$	0		$	2,145,394
Change in Plan Assets
Fair value of plan assets at beginning of year			1,858,681		$	1,911,692
	Actual return on plan assets		286,713			226,341
	Contributions by employer		—			164,368
	Benefits paid		(2,145,394	)		(447,277	)
	Foreign currency effect		—			75,320
	Other (expenses)		—			(71,763	)
Fair value of plan assets at end of year			0		$	1,858,681
Reconciliation of Funded Status
Funded Status			0		$	(286,713	)
	Unamortized transition asset		—			—
	Unamortized loss		—			—
(Accrued) Prepaid benefit costs			0		$	(286,713	)

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      The net pension expense for the MPAL pension plan for 2004 and 2003 was as follows:

	2004			2003
Settlement and curtailment	$	1,237,425		$	—
Service cost		148,075			144,216
Interest cost		94,212			96,803
Expected return on plan assets		(94,104	)		(97,205	)
Net amortization and deferred items		26,835			15,299
Net pension cost	$	1,412,443		$	159,113
Plan contributions by MPAL	$	228,958		$	156,247

      Significant assumptions used in determining pension cost and the related obligations were as follows:

	2004			2003
Assumed discount rate		5.0	%		5.5	%
Rate of increase in future compensation levels		3.5	%		3.5	%
Expected long term rate of return on plan assets		5.0	%		5.0	%
Australian exchange rate	$	.70		$	.67

      At June 30, 2004, Plan assets were held 98% in equity mutual funds and 2% in cash. As a result of the Plan’s termination, the Plan’s assets were distributed during 2005 with no additional pension plan expenditures required.

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,
		2005			2004			2003
Revenues:
	MPC	$	1,256		$	2,469		$	1,228
	MPAL		21,590			17,866			14,194
	Elimination of intersegment dividend		(975	)		(911	)		(686	)
	Total consolidated revenues	$	21,871		$	19,424		$	14,736
Interest income:
	MPC	$	89		$	160		$	85
	MPAL		1,053			939			775
	Total consolidated	$	1,142		$	1,099		$	860
Net income (loss) before cumulative effect of accounting change:
	MPC	$	(101	)	$	969		$	229
	Equity in earnings of MPAL, net of related costs(1)		1,163			292			1,347
	Elimination of intersegment dividend		(975	)		(911	)		(686	)
	Consolidated net income before cumulative effect of accounting change:	$	87		$	350		$	890

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			Years Ended June 30,
			2005			2004			2003
Net income:
	MPC		$	(101	)	$	969		$	229
	Equity in earnings of MPAL, net of related costs(1)			1,163			292			609
	Elimination of intersegment dividend			(975	)		(911	)		(686	)
	Consolidated net income		$	87		$	350		$	152
Assets:
	MPC		$	25,523		$	25,339
	MPAL			50,659			47,884
	Equity elimination			(19,758	)		(20,329	)
	Total consolidated assets		$	56,424		$	52,894
Other significant items:
	Depletion, depreciation and amortization:
		MPC	$	27		$	30		$	—
		MPAL		6,967			6,312			3,719
		Total consolidated	$	6,994		$	6,342		$	3,719
Exploratory and dry hole costs:
	MPC		$	—		$	—		$	—
	MPAL			4,157			3,225			2,920
	Total consolidated		$	4,157		$	3,225		$	2,920
Income tax expense (benefit):
	MPC		$	71		$	492		$	130
	MPAL			(153	)		(1,270	)		(904	)
	Total consolidated		$	(82	)	$	(778	)	$	(774	)

(1)  Equity in earnings of MPAL for 2005 and 2004 of $1,363,000 and $670,000, respectively is reported net of $195,000 and $378,000 for 2005 and 2004, respectively of oil and gas property depletion related to MPC book value of oil and gas property and resulting from its step acquisition reporting of MPC’s investment in MPAL.

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,
		2005		2004		2003
Revenue:
	Australia	$	21,590	$	17,866	$	14,194
	United States		—		—		—
	Canada		281		1,558		542
		$	21,871	$	19,424	$	14,736

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		Years Ended June 30,
		2005			2004			2003
Operating income (loss):
	Australia	$	2,912		$	(103	)	$	1,732
	New Zealand		(1,441	)		(909	)		(628	)
	United States-Canada		258			1,525			569
			1,729			513			1,673
	Corporate overhead and interest, net of other income (expense)		(615	)		(395	)		(324	)
	Consolidated operating income before income taxes, minority interests and cumulative effect of accounting change	$	1,114		$	118		$	1,349
Net income (loss):
	Australia	$	1,831		$	718		$	835
	New Zealand		(668	)		(425	)		(246	)
	United States		(1,076	)		57			(437	)
		$	87		$	350		$	152
Identifiable assets:
	Australia	$	52,264		$	48,652
	Corporate assets		4,160			4,242
		$	56,424		$	52,894

      Substantially all 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, 2005.

11. Commitments

      The Company does 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 Company has firm commitments from purchase obligations of $3,380,000. See Part II Contractual Obligations.

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.

      The Palm Valley Producers are actively pursuing gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin. Gas production from both fields is fully contracted through to 2009 and 2012, respectively. While opportunities exist to contract additional gas sales in the Northern Territory market after these dates, there is strong competition within the

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market and there are no assurances that the Palm Valley Producers will be able to contract for the sale of the remaining uncontracted reserves.

      At June 30, 2005, MPAL’s commitment to supply gas under the above agreements was as follows:

Period	Bcf
Less than one year		6.21
Between 1-5 years		23.06
Greater than 5 years		.80
Total		30.07

      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.

      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 and legal expenses		(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.

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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, 2005 and 2004:

	QTR 1			QTR 2			QTR 3			QTR 4
2005
Total revenues	$	4,577		$	5,454		$	5,996		$	5,844
Costs and expenses		(5,137	)		(5,500	)		(5,599	)		(5,662	)
Interest income		356			377			104			305
Income tax (provision) benefit(a)		(5	)		(153	)		(102	)		342
Minority interests		(86	)		(254	)		(294	)		(476	)
Net income (loss)		(295	)		(76	)		105			353
Per share (basic & diluted)		(.01	)		—			—			.01
Average number of shares outstanding		25,783			25,783			25,783			25,783
2004
Total revenues	$	5,397		$	4,598		$	4,839		$	4,590
Costs and expenses		(3,900	)		(5,634	)		(4,599	)		(6,273	)
Interest income		335			243			271			251
Income tax (provision) benefit(b)		(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

(a)  During the fourth quarter of 2005, MPAL’s financing subsidiary determined that its loans to the New Zealand subsidiary were no longer collectible and this resulted in a permanent benefit in Australia of $1,000. This amount was offset by tax benefits from New Zealand losses that are not deductible in Australia of $513.

(b) During the fourth quarter of 2004, MPAL determined that prior deferred tax benefits that had been reserved of $1,266 were recoverable, resulting in lower income tax expense for the fourth quarter of 2004.

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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 therefrom, 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 and Proved Developed Oil and Gas Reserves:

	Natural Gas						Oil
	(Bcf)						(1,000 Bbls)
Proved Reserves:	Australia*			Canada			Australia
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
Extensions and discoveries		—			.012			—
Revision of previous estimates		(.024	)		—			22
Purchase of reserves		—			—			—
Production		(5.717	)		(.061	)		(151	)
June 30, 2005		25.284			.121			487
Proved Developed Reserves:
June 30, 2002		29.102			.534			520
June 30, 2003		28.855			.427			554
June 30, 2004		22.346			.170			616
June 30, 2005		25,284			.121			487

*  The amount of proved reserves applicable to the Palm Valley and Mereenie fields only reflects the amount of gas committed to specific contracts and are net of royalities. Approximately 44.9% of reserves are attributable to minority interests at June 30, 2005 (44.9% for 2004 and 47.6% for 2003).

Costs of Oil and Gas Activities (In thousands):

	Australia/New Zealand
	Exploration		Development		Acquisition
Fiscal Year	Costs		Costs		Costs
2005		4,028		9,292		—
2004		3,741		3,926		2,086
2003		4,484		2,753		3

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Capitalized Costs Subject to Depletion, Depreciation and Amortization (DD&A) (In thousands):

	June 30,
Australia/New Zealand	2005			2004
Costs subject to DD&A	$	80,766		$	69,970
Costs not subject to DD&A		—			—
Less accumulated DD&A		(57,330	)		(46,322	)
Net capitalized costs	$	23,436		$	23,648

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, 2005. At June 30, 2005, approximately 44.9% (44.9% for 2004 and 47.6.% for 2003) of the reserves and the respective discounted future net cash flows are attributable to minority interests.

	Australia
	2005			2004			2003
Future cash inflows	$	81,688		$	82,449		$	78,192
Future production costs		(18,443	)		(19,361	)		(20,844	)
Future development costs		(13,434	)		(16,599	)		(15,681	)
Future income tax expense		(10,342	)		(9,369	)		(5,292	)
Future net cash flows		39,469			37,120			36,375
10% annual discount for estimating timing of cash flows		(8,157	)		(7,639	)		(10,675	)
Standardized measures of discounted future net cash flows	$	31,312		$	29,481		$	25,700

	Canada
	2005			2004			2003
Future cash inflows	$	606		$	754		$	1,460
Future production costs		(60	)		(125	)		(213	)
Future development costs		—			—			—
Future income tax expense		(136	)		(157	)		(312	)
Future net cash flows		410			472			935
10% annual discount for estimating timing of cash flows		(89	)		(72	)		(149	)
Standardized measures of discounted future net cash flows	$	321		$	400		$	786

	Total
	2005			2004			2003
Future cash inflows	$	82,294		$	83,203		$	79,652
Future production costs		(18,503	)		(19,486	)		(21,057	)
Future development costs		(13,434	)		(16,599	)		(15,681	)
Future income tax expense		(10,478	)		(9,526	)		(5,604	)
Future net cash flows		39,879			37,592			37,310
10% annual discount for estimating timing of cash flows		(8,246	)		(7,711	)		(10,824	)
Standardized measures of discounted future net cash flows	$	31,633		$	29,881		$	26,486

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      The following are the principal sources of changes in the above standardized measure of discounted future net cash flows (in thousands):

	2005			2004			2003
Net change in prices and production costs	$	5,567		$	7,597		$	(5,020	)
Extensions and discoveries		—			—			360
Revision of previous quantity estimates		281			981			1,059
Changes in estimated future development costs		443			(2,156	)		(4,587	)
Sales and transfers of oil and gas produced		(13,725	)		(10,314	)		(8,070	)
Previously estimated development cost incurred during the period		3,827			3,110			3,110
Accretion of discount		2,337			2,344			2,992
Acquisitions		—			3,213			—
Net change in income taxes		410			(2,345	)		6,100
Net change in exchange rate		2,612			965			4,231
	$	1,752		$	3,395		$	175

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, 2005.

Reserves and Costs — Oil

      At June 30, 2005, 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, 2005. 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.$23,203,000, and A.$22,005,000 and A.$25,658,000 in unrecouped capital expenditures at June 30, 2005, 2004 and 2003, respectively. The tax rate in computing Australian future income tax expense was 30%.

Canada

Reserves and Costs

      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. $6.14 at June 30, 2005 (Can. $5.90 — 2004) and estimated future production and development costs at June 30, 2005.

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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, 2005:

		Americas									Australia/New Zealand
		2005			2004			2003			2005			2004			2003
Revenues:
	Oil sales	$	—		$	—		$	—		$	7,574		$	4,923		$	3,329
	Gas sales		282			1,557			535			12,196			11,312			9,647
	Other production income		—			—			—			1,819			1,632			1,214
	Total revenues		282			1,557			535			21,589			17,867			14,190
Costs:
	Production costs		—			—			—			6,144			5,416			4,424
	Depletion, exploratory and dry hole costs		23			30			(38	)		10,727			9,009			6,620
	Total costs		23			30			(38	)		16,871			14,425			11,044
Income before taxes and minority interest			259			1,527			573			4,718			3,442			3,146
	Income tax provision*		(65	)		(382	)		(134	)		(1,415	)		(1,027	)		(944	)
Income before minority interests			194			1,145			439			3,303			2,415			2,202
	Minority interests**		—			—			(18	)		(1,737	)		(1,085	)		(1,047	)
Net income from operations		$	194		$	1,145		$	421		$	1,566		$	1,330		$	1,155
Depletion per unit of production		$	—			—			—		A.$	7.40		A.$	7.25		A.$	5.27

*  Income tax provision used for Australia is based on a rate of 30%. Americas 25% is due to a 25% Canadian withholding tax on Kotaneelee gas sales.

**  Minority interests 44.90% in 2005, 44.9% in 2004 and 47.6% in 2003.

Item 9. — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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 report of Ernst & Young on the Company’s financial statements for the fiscal year ended June 30, 2003 did not contain an adverse opinion or a disclaimer of opinion, and was 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.

      In connection with the audit of the Company’s financial statements for the fiscal year 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

50

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, 2005. 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.

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, 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B.      Other Information

      None

51

PART III

Item 10. Directors and Executive Officers of the Registrant

      Following is information concerning each Director and executive officer of the Company including name, age, position with the corporation, and business experience during the last five years:

Directors

		Director		Position Held with
Name		Since		Company	Age and Business Experience
	Timothy L. Largay		1996	Director; member of Nominating Committee Chairman, Compensation Committee, Assistant Secretary	Mr. Timothy L. Largay has been a partner in the law firm of Murtha Cullina LLP, Hartford, Connecticut since 1974. Mr. Largay has been a director of MPAL since August 2001. He is also Assistant Secretary of Canada Southern Petroleum Ltd., Calgary, Alberta, Canada. Murtha Cullina has been retained by the Company for more than five years and is being retained during the current year. Age 62.
	Walter McCann		1983	Director, Chairman of the Board, Chairman of Compensation Committee, member of Audit Committee and Nominating Committee	Mr. Walter McCann, a former business school dean was the President of Richmond College, The American International University, located in London, England from January 1993 until his retirement in July 2002. Mr. McCann has been a director of MPAL since 1997. From 1985 to 1992, he was President of Athens College in Athens, Greece. He is a retired member of the Bars of Massachusetts and the District of Columbia. Age 68.
	Ronald P. Pettirossi		1997	Director; Chairman of the Audit Committee, member of Nominating Committee and Compensation Committee	Mr. Ronald P. Pettirossi has been President of ER Ltd., a consulting company since 1995. Mr. Pettirossi is a former audit partner of Ernst & Young LLP, who worked with public and privately held companies for 31 years. Age 62.
	Donald V. Basso		2000	Director; member of Audit Committee	Mr. Donald V. Basso was elected a director of the Company in 2000. Mr. Basso served as a consultant and Exploration Manager for Canada Southern Petroleum Ltd. from October 1997 to May 2000. He also served as a consultant to Ranger Oil & Gas Ltd. during 1997. From 1995 to 1997, Mr. Basso served as Exploration Manager for Guard Resources Ltd. Mr. Basso has over 40 years experience in the oil and gas business in the United States, Canada and the Middle East. Age 67.

52

Executive Officers

					Length of Service		Other Positions Held
Name	Age		Office Held		as an Officer		with Company
Daniel J. Samela		57	President and Chief Financial Officer			Since 2004		None
T. Gwynn Davies		58		General Manager — MPAL		Since 2001		None

*  All of the named companies are engaged in oil, gas or mineral exploration and/or development, except where noted.

      All officers are elected annually and serve at the pleasure of the Board of Directors. No family relationships exist between any of the directors or officers.

Section 16(a) Beneficial Ownership Reporting Compliance

      Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who beneficially own more than 10% of the Company’s Common Stock to file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission. Such persons are required by the SEC regulations to furnish the Company with copies of all Section 16(a) forms filed by such persons. Based solely on copies of forms received by it, or written representations from certain reporting persons that no Form 5’s were required for those persons, the Company believes that during the fiscal year ended June 30, 2005, its executive officers, directors, and greater than 10% beneficial owners complied with all applicable filing requirements.

Board Independence

      The Company’s Board of Directors has determined that Messrs. Basso, Largay, Pettirossi and McCann are independent directors under the listing standards of the Nasdaq Stock Market, Inc. and rules adopted by the Securities and Exchange Commission (“SEC”).

Audit Committee Financial Expert(s)

      The Company’s Board of Directors maintains an Audit Committee which is currently composed of the following directors: Messrs. Basso, McCann and Pettirossi (Chairman). The Board of Directors has determined that each of the members of the Audit Committee is financially literate and that Mr. Pettirossi is an audit committee financial expert, as such term is defined under SEC regulations, by virtue of having the following attributes through relevant education and/or experience:

      (1) an understanding of generally accepted accounting principles and financial statements;

      (2) the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

      (3) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Company’s financial statements, or experience actively supervising one or more persons engaged in such activities;

      (4) an understanding of internal controls and procedures for financial reporting; and

      (5) an understanding of audit committee functions.

Standards Of Conduct And Business Ethics

      The Company has previously adopted Standards of Conduct for the Company (the “Standards”). The Board amended the Standards in August 2004. Under the Standards, all directors, officers and employees (“Employees”) must demonstrate a commitment to ethical business practices and behavior in all business

53

relationships, both within and outside of the Company. All Employees who have access to confidential information are not permitted to use or share that information for stock trading purposes or for any other purpose except the conduct of the Company’s business. Any waivers of or changes to the Standards must be approved by the Board and appropriately disclosed under applicable law and regulation.

      The Company’s Standards are available on the Company’s website at www.magpet.com and it is our intention to provide disclosure regarding waivers of or amendments to the policy by posting such waivers or amendments to the website in the manner provided by applicable law.

Item 11 — Executive Compensation

      The following table sets forth certain summary information concerning the compensation of Mr. Daniel J. Samela, who is President, Chief Executive Officer and Chief Financial Officer of the Company, and each of the most highly compensated executive officers of the Company who earned in excess of $100,000 during fiscal year 2005 (collectively, the “Named Executive Officers”).

Summary Compensation Table

						Long Term
		Annual				Compensation
		Compensation				Awards
						Securities
						Underlying		All Other
		Fiscal		Salary		Options/SARs		Compensation
Name and Principal Position		Year		($)		(#)		($)
Daniel J. Samela			2005		175,000		—		26,250	(1)
	President, Chief Financial and		2004		41,667		30,000		6,250	(1)
	Accounting Officer		2003		—		—		—
T. Gwynn Davies			2005		188,857		—		72,301	(2)
	General Manager — MPAL		2004		177,144		—		65,436	(2)
	(Effective Oct. 30, 2001)		2003		138,000		—		51,000	(2)

(1)	Payment to a SEP-IRA pension plan.
(2)	Payment to pension plan similar to an individual retirement plan.

Stock Options

      The following tables provide information about stock options granted and exercised during fiscal 2005 and unexercised stock options held by the Named Executive Officers at the end of fiscal year 2005.

Options/ SAR Grants in Fiscal Year 2005

Potential Realized

Individual Grants

Value at Assumed

Annual Rates of

% of Total

Stock Price

Options/SARs

Appreciation for

Options/

Granted to

Exercise or

Option Terms

SARs Granted

Employees in

Base Price

Expiration

Name

(#)

Fiscal Year

($/Sh)

Date

5% ($)

10% ($)

Daniel J. Samela

0

0

0

—

0

0

T. Gwynn Davies

0

0

0

—

0

0

54

Aggregated Option/ SAR Exercises in Fiscal 2005 and June 30, 2005

Option/ SAR Values Table

					Number of Unexercised				Value of Unexercised
	Shares				Options/SARs at				In-the-Money Options/SARs
	Acquired on		Value		2005 Year-End (#)				at 2005 Year-End ($)
	Exercise		Realized
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
Daniel J. Samela		—		—		10,000		20,000		24,000		48,000
T. Gwynn Davies		—		—		—		—		—		—

Employment Agreement

      On March 1, 2004, the Company entered into a thirty-six month employment agreement with Mr. Daniel J. Samela. The thirty-six month term automatically renews each 30-day period during Mr. Samela’s term of employment, unless he elects to retire or the agreement is terminated according to its terms. The agreement provides for him to be employed as the President and Chief Executive Officer of the Company, effective as of July 1, 2004, at a salary of $175,000 per annum, and an annual contribution of 15% of the salary to a SEP/ IRA pension plan for Mr. Samela’s benefit. The employment agreement may be terminated for cause (as defined in the agreement), on written notice by the Company without cause, by Mr. Samela’s resignation or upon a change in control of the Company (as defined in the agreement). Upon a termination without cause, Mr. Samela will be entitled to payment of the balance of salary and average bonus payments due for the term of the agreement. If, during the two-year period following a change in control, Mr. Samela terminates his employment for good reason (as defined in the agreement) or the Company terminates his employment other than for cause of disability (as defined in the agreement), then Mr. Samela will be paid an amount equal to three times his annual base salary and three-year average bonus payment, plus any previously deferred compensation, accrued vacation pay, and three years of reimbursements for medical coverage and insurance benefits. In addition, any then-unvested options will be accelerated so as to become fully exercisable. If, at any time after the two-year period following a change in control, Mr. Samela terminates his employment for good reason or the Company terminates his employment other than for cause of disability, then he will be paid an amount equal to his then current annual salary and a three-year average bonus payment. In addition, any then-unvested options will be accelerated so as to become fully exercisable.

Compensation of Directors

      Messrs. Donald V. Basso, Timothy L. Largay, and Ronald P. Pettirossi were each paid director’s fees of $40,000 during fiscal year 2005. Mr. Walter McCann was paid $65,000 as Chairman of the Board. In addition, Mr. Pettirossi was paid $7,500 as Chairman of the Audit Committee.

      Under the Company’s medical reimbursement plan for all outside directors, the Company reimburses certain directors the cost of their medical premiums, up to $500 per month. During fiscal 2005, the cost of this plan was approximately $18,000.

Compensation Committee Interlocks and Insider Participation

      The only officers or employees of the Company or any of its subsidiaries, or former officers or employees of the Company or any of its subsidiaries, who participated in the deliberations of the Board concerning executive officer compensation during the fiscal year ended June 30, 2005 were Messrs. Daniel T. Samela and Timothy L. Largay. At the time of such deliberations, Mr. Largay was a director of the Company. Because he does not serve on the Board, Mr. Samela did not participate in any discussions or deliberations regarding his own compensation. Mr. Largay does not receive any compensation for his services as Assistant Secretary.

55

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

      The following table sets forth information as to the number of shares of the Company’s Common Stock owned beneficially as of September 22, 2005 (except as otherwise indicated) by each director (or nominee director) and each Named Executive Officer listed in the Summary Compensation Table and by all directors and executive officers of the Company as a group:

	Amount and Nature of
	Beneficial Ownership*
					Percent of
Name of Individual or Group	Shares		Options		Class
Donald Basso		11,000		—		**
T. Gwynn Davies		—		—		**
Timothy L. Largay		6,000		—		**
Walter McCann		59,368		—		**
Ronald P. Pettirossi		6,500		—		**
Daniel J. Samela		—		10,000		**
Directors and Executive Officers as a Group (a total of 6)		109,453		10,000		**

*  Unless otherwise indicated, each person listed has the sole power to vote and dispose of the shares listed.

**  The percent of class owned is less than 1%.

Amount and Nature of Beneficial Ownership

Name of Individual or Group	Percent of Class
Sagasco Amadeus Pty. Limited 1,300,000		5.05%*

*  As reported in Schedule 13G filed with the SEC on July 22, 2003. On July 10, 2003, a subsidiary of Origin Energy Limited Sagasco Amadeus Pty. Limited, agreed to exchange 1,200,000 shares of MPAL for 1,300,000 shares of the company’s common stock, which is 5.05% of the Company’s outstanding shares. The exchange was completed on September 2, 2003. The Company believes that as of April 21, 2004, Origin Energy has resold all shares of the Company held by it.

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, 2005.

					Number of Securities
	Number of Securities				Remaining Available for
	to be Issued Upon		Weighted Average		Issuance Under Equity
	Exercise of Outstanding		Exercise Price of		Compensation Plans
	Options, Warrants		Outstanding Options,		(Excluding Securities
	and Rights		Warrants and Rights		Reflected in Column (a))
Plan Category	(a) (#)		(b) ($)		(c) (#)
Equity compensation plans approved by security holders		30,000	$	1.45		795,000

Item 13 — Certain Business Relationships and Transactions

      During the year ended June 30, 2005, the Company paid G&O’D INC. $65,700 for providing accounting and administrative services, a firm owned by Mr. James R. Joyce, who served as the Company’s President and Chief Financial Officer until June 30, 2004. In addition, the Company purchased $12,000 of office equipment from G&O’D INC.

56

Item 14 —Principal Accountant Fees and Services

      During the fiscal years ended June 30, 2004 and June 30, 2005, the Company retained its current principal auditor, Deloitte & Touche LLP, to provide services in the following categories and amounts.

Audit Fees

      The aggregate fees paid or to be paid to Deloitte & Touche LLP for the fiscal years ended June 30, 2004 and June 30, 2005, for the review of the financial statements included in the Company’s Quarterly Reports on Form 10-Q and the audit of financial statements included in the Annual Report on Form 10-K for the fiscal years ended June 30, 2004 and June 30, 2005, respectively, were $208,432 and $195,702.

Audit-Related Fees $0

Tax Fees $0

All Other Fees $0

Pre-Approval Policies

      Under the terms of its Charter, the Audit Committee is required to pre-approve all the services provided by, and fees and compensation paid to, the independent auditors for both audit and permitted non-audit services. When it is proposed that the independent auditors provide additional services for which advance approval is required, the Audit Committee may form and delegate authority to a subcommittee consisting of one or more members, when appropriate, with the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are to be presented to the Committee at its next scheduled meeting.

57

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		26
Consolidated balance sheets as of June 30, 2005 and 2004		28
Consolidated statements of income for each of the three years in the period ended June 30, 2005		29
Consolidated statements of changes in stockholders’ equity for each of the three years in the period ended June 30, 2005		30
Consolidated statements of cash flows for each of the three years in the period ended June 30, 2005		31
Notes to consolidated financial statements		32
Supplementary oil and gas information (unaudited)		47

      (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) 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) By-Laws, as amended on July 22, 2004, is filed as Exhibit 3(b) to Annual Report on Form 10-K for the year ended June 30, 2004 (File No-001-5507) are incorporated by reference.

      4. Instruments defining the rights of security holders, including indentures.

      None.

      9. Voting Trust Agreement.

      None.

58

      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 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.

59

      (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 as Exhibit 10 (s) to Annual Report on Form 10K for the year ended June 30, 2005, is incorporated herein by reference.

      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.

60

      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. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, is filed herein.

      (d) Financial Statement Schedules.

      None.

61

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: September 26, 2005

      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 Daniel J. Samela	President, Chief Executive Officer, Chief Financial and Accounting Officer	Dated: September 26, 2005
/s/Donald V. Basso Donald V. Basso	Director	Dated: September 26, 2005
/s/Timothy L. Largay Timothy L. Largay	Director	Dated: September 26, 2005
/s/Walter McCann Walter McCann	Director	Dated: September 26, 2005
/s/Ronald P. Pettirossi Ronald P. Pettirossi	Director	Dated: September 26, 2005

62

INDEX TO EXHIBITS

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.