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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended June 30, 2009

or

For the transition period from              to             

Commission file number 1-5507

Magellan Petroleum Corporation

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code

(860) 293-2006

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act

Title of Class

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at the $0.65 closing price on December 31, 2008 (the last business day of the most recently completed second quarter) was $26,803,787.

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, 50,210,977 shares outstanding as of September 1, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2009, are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

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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 1, 2009 was approximately A.$1.00 equaled U.S. $.84.

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PART I

Magellan Petroleum Corporation (the “Company” or “MPC” or “Magellan”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2009, MPC’s principal asset was a 100.00% 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), one petroleum production lease covering the Palm Valley gas field (52% working interest), five petroleum production leases covering the Nockatunga oil fields (41% working interest) and eighteen licenses in the United Kingdom, five of which are operated by MPAL. Both the Mereenie and Palm Valley fields are located in the Amadeus Basin in the Northern Territory of Australia. The Nockatunga fields are located in the Cooper Basin in South West Queensland, Australia. Santos Ltd. (“Santos”), a publicly owned Australian company, owns a 65% interest in the Mereenie field, a 48% interest in the Palm Valley field and a 59% interest in the Nockatunga fields. Santos is the operator of the Mereenie and Nockatunga fields.

MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. 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 100% 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 41% of the Nockatunga Fields, Australia.

SANTOS owns 48% of the Palm Valley Field, Australia.

SANTOS owns 65% of the Mereenie Field, Australia.

SANTOS owns 59% of the Nockatunga Fields, 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.

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 and gas reserves based upon contracted amounts (net of royalties) was approximately 685,000 barrels and 0.8 billion cubic feet (Bcf) of gas at June 30, 2009. During fiscal 2009, MPAL’s share of oil sales was 105,000 barrels and 4.6 Bcf of gas, which is subject to net overriding royalties aggregating 4.0625% and the statutory government royalty of 10%. Prior to early June 2009, the oil was transported by means of a 167-mile eight-inch oil pipeline from the field to an industrial park near Alice Springs.

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The oil was then shipped south approximately 950 miles by road to the Port Bonython Export Terminal at Whyalla, South Australia for sale. Since early June 2009, the oil is transported by road directly from the field to Port Bonython Export Terminal. The cost of transporting the oil to the terminal is borne by the Mereenie Producers. The oil pipeline has been placed in care and maintenance because of environmental concerns by the operator over its integrity. The petroleum leases covering the Mereenie field expire in November 2023.

The Mereenie Producers are contracted to provide Mereenie gas in the Northern Territory to the Power and Water Corporation (“PWC”) for use in Darwin and other Northern Territory centers. See “Gas Supply Contracts” below.

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 the Palm Valley field which provides gas to meet the Alice Springs and Darwin supply contracts with PWC. See “Gas Supply Contracts” below. MPAL’s share of the Palm Valley proved developed reserves (net of royalties) was 2.5 Bcf at June 30, 2009 and is based upon gas contract amounts. During fiscal 2009, MPAL’s share of gas sales was 1.4 Bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.3125%. The producers and PWC installed additional compression equipment in the field in 2006 that will assist field deliverability during the remaining Darwin gas contract period. PWC funds the cost of additions and modifications to the gas delivery system under the gas supply agreement. The petroleum lease covering the Palm Valley field expires in November 2024.

Gas Supply Contracts

In 1983, the MPAL and Santos (“Palm Valley Producers”) commenced the sale of gas to Alice Springs under a 1981 agreement. That agreement terminated in June 2008. In 1985, the Palm Valley Producers and Mereenie Producers signed agreements for the sale of gas to PWC, through its wholly-owned company Gasgo Pty. Ltd. (“Gasgo”), for use in PWC’s Darwin electricity generating station and at a number of other generating stations in the Northern Territory. 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 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 latest being in June 2006 for the supply of an additional 4.4 Bcf of gas to be supplied prior to December 31, 2008. The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expired in January and June 2009. Supply obligations under the Mereenie contracts ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended.

MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the higher-priced Mereenie Sales Agreement 4 (“Backstop Agreement”). MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. Unless MPAL is able to sell uncontracted gas, including reasonable

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endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

At June 30, 2009, MPAL’s commitment to supply gas under the above agreements was as follows:

Nockatunga Oil Fields

MPAL purchased its 40.936% working interest (38.703% net revenue interest) in the Nockatunga oil fields in the Cooper Basin in southwest Queensland effective from July 2003. Santos is operator of the fields and holds the remaining interest. The assets are comprised of eleven producing oil fields (Currambar, Kamel, Dilkera, Dilkera North, Koora, Maxwell, Maxwell South, Muthero, Nockatunga, Thungo and Winna) in Petroleum Leases 33, 50, 51, 244 and 245, together with exploration acreage in the adjacent Authority to Prospect for Petroleum (“ATP”) No. 267P. The fields are currently producing about 425 barrels of oil per day (MPAL’s share is approximately 165 barrels of oil per day). During fiscal 2009, MPAL’s share of oil sales was 70,000 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 (net of royalties) was approximately 92,000 barrels at June 30, 2009. Petroleum Lease 33 was renewed for a further 21 years and will expire in April 2028. Petroleum Leases 50 and 51 expire in June 2011. Petroleum Leases 244 and 245 were granted with effect on December 1, 2008 and will expire in November 2029. ATP 267P was renewed for a further four year term and will expire in November 2011. A 99 square mile 3D seismic survey was conducted over Petroleum Leases 51 and 245 and parts of ATP 267P in early 2009. No drilling was undertaken during fiscal 2009.

Dingo Gas Field

MPAL has a 34.3365% interest in the Dingo gas field which is held under Retention License 2 in the Amadeus Basin in the Northern Territory. No market has emerged for the gas volumes that have been discovered in the Dingo gas field. MPAL’s share of potential production from this permit area is subject to a 10% statutory government royalty and overriding royalties aggregating 4.8125%. The license was renewed for a further five year term and expires in February 2014.

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. In May 2006, MPAL entered into a farm-out agreement in relation to a portion of ATP 613P, ATPA 674P and ATPA 733P with Eureka Petroleum, under which that company funded the drilling of two exploration wells in 2007 to test the coal seam gas potential of the Burrum Coal Measures near the city of Maryborough. The Burrum-1 and Burrum-2 farm-out wells drilled in early 2007 intersected multiple thin coal seams and evaluation of the gas potential is continuing. The grant of ATPA 674P and ATP 733P is subject to agreement of the native title claimants to the area.

Eureka Petroleum has agreed to undertake a staged evaluation of the farm-out area to earn a 75% interest in any petroleum lease granted in the area. MPAL retains a 25% interest and is carried by Eureka Petroleum through any development to the grant of a petroleum lease. Eureka Petroleum operates the joint venture. At June 30,

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2009, the work obligations of the ATP 613P permit were fully committed by Eureka Petroleum under the farm-out arrangement. ATP 613P was renewed in March 2008 for a further 12-year term ending in March 2019.

Cooper/Eromanga Basin (See Executive Summary in Part II, Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operation for discussion of potential sale of Cooper Basin assets.)

PEL 94, PEL 95 & PPL 210

During fiscal year 1999, MPAL (50%) and its partner Beach Petroleum were successful in bidding for two exploration blocks, Petroleum Exploration License (“PEL”) 94 and PEL 95, in South Australia’s Cooper Basin. The Aldinga-1 exploration well was drilled and completed in September 2002 and began producing in May 2003 at about 80 barrels of oil per day. Petroleum Production License (“PPL”) 210 was granted over the Aldinga field in December 2004. By June 2009, production had declined to about 10 barrels of oil per day. No further development is planned for the field.

Black Rock Petroleum 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 subsequently assigned its interest in PEL 94 to Victoria Petroleum. At June 30, 2009, MPAL’s share of the work obligations of PEL 94 totaled $622,000 of which $28,000 was committed and in PEL 95 totaled $929,000 of which $81,000 was committed. PEL 94 expires in May 2012 and PEL 95 expires in October 2011.

PEL 106, PEL 107 & PPL 212

During fiscal year 2005, MPAL entered into a farm-in arrangement with Great Artesian Oil and Gas to drill explorations wells in petroleum exploration permits PEL 106 and PEL 107 in the Cooper Basin of South Australia. The Kiana-1 well was drilled in PEL 107 in 2005 and was completed for production as an oil producer. PPL 212 was granted over the Kiana field in January 2006. MPAL earned a 30% interest in PPL 212 by contributing to the drilling cost of the Kiana-1 well. During fiscal 2009, MPAL’s share of oil sales was approximately 1,900 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 4.0%. MPAL’s share of the Kiana field’s proved developed oil reserves was approximately 11,000 barrels at June 30, 2009. Beach Petroleum is operator of the joint venture.

MPAL exercised its option to participate in a further two wells in PEL 107 under the farm-in arrangement with Great Artesian Oil and Gas to earn a 30% interest in any discoveries and a 20% interest in the PEL 107 permit. The Keeley-1 and Cabbots-1 farm-in wells were drilled in late 2006. Both wells were dry holes. PEL 107 was renewed for a further five year term and expires in December 2013. At June 30, 2009, the work obligations of PEL 107 totaled $525,000, of which $40,000 was committed.

The Udacha-1 gas discovery well was drilled in February 2006 in the farm-in area with Great Artesian Oil and Gas, covering portion of PEL 106 and the adjacent PEL 91 permit. A production test was carried out in late 2006 which indicated that the discovery is potentially commercially viable. If the discovery is commercial, MPC will earn a 30% interest in any petroleum production license granted over the Udacha field. Beach Petroleum is operator of the joint venture and the participants are seeking a gas sales arrangement for the Udacha gas. The operator has recommenced applying for a retention license with the view to moving to a petroleum production license by the end of 2009. The intention is to commence gas production and sales in January 2010.

PEL 110

During fiscal year 2001, MPAL (50%) and its partner Beach Petroleum were successful in bidding for exploration block PEL 110 in the Cooper Basin. PEL 110 was granted in February 2003. During July 2005, Cooper Energy contributed to the cost of the Yanerbie-1 well to earn a 25% interest in PEL 110 which reduced MPAL’s interest in PEL 110 to 37.5%. PEL 110 was renewed for a further five year term and expires in

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November 2013. Beach Petroleum withdrew from the license and joint venture with effect at the end of the first five year term, and MPAL’s interest increased proportionally to 60%. At June 30, 2009, MPAL’s share of the work obligations of PEL 110 totaled $1,231,000, of which $68,000 was committed.

UNITED KINGDOM

PEDL 098, PEDL 099 & PEDL 256

During fiscal year 2001, MPAL acquired an interest in two exploration licenses in southern England in the Weald-Wessex basin. The two licenses, Petroleum Exploration and Development License (“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, drilled in the PEDL 098 permit during 2005, encountered a heavily biodegraded remnant oil column and was plugged and abandoned. At June 30, 2009, MPAL’s share of the work obligations of the PEDL 098 license totaled $55,000 of which $18,000 was committed. PEDL 098 expires in September 2011. PEDL 099 expired in September 2008.

The former PEDL 099 licensees made an out-of-round application for a license over the northeast portion of the former PEDL 099 area which is adjacent to the Havant Prospect in PEDL 155. PEDL 256 was granted to MPAL (40% interest) and its joint venturers for a period of six years with effect from May 2009 with a drill or drop obligation at the end of the term. PEDL 256 expires in May 2015. At June 30, 2009, MPAL’s share of the work obligations of the PEDL 256 license totaled $2,180,000, of which $40,000 was committed.

PEDL 125 & PEDL 126

Effective July 1, 2003, MPAL acquired two exploration licenses, PEDL 125 (40%) in Hampshire and PEDL 126 (40%) in West Sussex, in the Weald Basin of southern England; each granted for a period of six years. The drilling plans for the Markwells Wood-1 well in PEDL 126 are in progress and have received all necessary approvals. However, due to certain delays and the availability of suitable rigs to perform the drilling work, the spudding of this well is expected in the early part of the first quarter of 2010. Plans for drilling Hedge End-2 later in 2010 are in progress. The U.K, company Encore Oil (formerly known as Oil Quest Resources) will fund part of MPAL’s share of the cost of drilling the two wells to acquire a 10% interest in each of the licenses. Both PEDLs were extended by the Government for a further one year term and the licenses expire in June 2010. At June 30, 2009, MPAL’s share of the work obligations of the two licenses totaled $3,150,000 which 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 the Weald Basin in southern England for a term of six years. Each has a drill or drop obligation at the end of the term. MPAL has undertaken a program of seismic data purchase, reprocessing and interpretation and has identified three drilling prospects. Drilling of two wells is being planned and government drilling approvals sought. At June 30, 2009, MPAL’s work obligation for the three licenses totaled $13,930,000, of which $282,000 was committed.

PEDL 152, PEDL 153, PEDL 154 & PEDL 155

Effective October 1, 2004, MPAL acquired four licenses in the Weald Basin in southern England, each granted for a period of six years; PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%). Each license has a drill or drop obligation at the end of its term. The well has to be drilled within the first six years of the initial term in order for the license to extend into the next five-year license term. The drilling plans for the Havant-1 well in PEDL 155 are in progress and spudding of this well is expected in 2010. The U.K. company Encore Oil will fund part of MPAL’s share of the PEDL 155 drilling and exploration costs to acquire a 10% interest in the license. At June 30, 2009, MPAL’s work obligation for the four licenses totaled $5,500,000, of which $1,588,000 was committed.

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PEDL 231, PEDL 232, PEDL 234, PEDL 240, PEDL 242, PEDL 243 & PEDL 246

Effective July 1, 2008, MPAL and its joint venture partner were granted interests in PEDL 231 (MPAL 50%), PEDL 232 (50%), PEDL 234(50%), PEDL 240 (22.5%), PEDL 242 (100%), PEDL 243 (50%) & PEDL 246 (100%) located in the Weald and Wessex Basins of southern England. Two of these PEDLs are operated by MPAL. Each license has a drill or drop obligation at the end of its term and expires in July 2014. At June 30, 2009, MPAL’s share of the work obligations of: the PEDL 231, PEDL 232, PEDL 234 & PEDL 243 licenses totaled $7,500,000 of which $1,000,000 was committed; the PEDL 240 license was $1,328,000, of which $40,000 was committed; and the PEDL 242 & PEDL 246 licenses totaled $10,515,000, of which $56,000 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 recorded revenue of $164,000 from this field in fiscal 2009.

(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 wholly 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, production and sale of oil and gas reserves in Canada, and indirectly through its subsidiary MPAL in Australia and the United Kingdom.

(i) Principal Products.

MPAL has an interest in the Palm Valley gas field and in the Mereenie oil and gas field in the Amadeus Basin of the Northern Territory and in the Nockatunga, Kiana and Aldinga oil fields in the Cooper Basin of South Australia and Queensland. See Item 1(a) — Australia — for a discussion of the oil and gas production from these 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, Palm Valley, Nockatunga, Kiana and Aldinga fields in Australia and MPC’s interest in the Kotaneelee field in Canada.

(iii) Raw Materials.

Not applicable.

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(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.

Petroleum Leases issued by the Northern Territory and Queensland Governments are subject to the Petroleum (Prospecting and Mining) Act and the Petroleum Act of the Northern Territory and the Petroleum Act and the Petroleum and Gas (Production & Safety) Act of Queensland. Lessees have the exclusive right to produce petroleum from the land subject to 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

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21 years, and leases may be renewed for successive terms of 21 years each. Petroleum Production Licenses issued by the South Australian Government are subject to the Petroleum Act of South Australia. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental and a royalty at the rate of 10% of the wellhead value of the petroleum produced. Licenses terminate two years after production ceases. Petroleum Exploration and Development Licenses issued by the Government of the United Kingdom are subject to the Petroleum Act. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental. The term of the license is 31 years.

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 seasonal 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 major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

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 Kiana and Aldinga is

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generally shipped through the Moomba processing facility in northeastern South Australia and piped from there to the Port Bonython Export Terminal where it is sold. Nockatunga crude oil is shipped and sold through the IOR Energy refinery at Eromanga, Southwest Queensland. Oil sales during fiscal 2009 were 40.2% to the Santos group of companies, 13.1% to the Beach Petroleum group of companies, 8.0% to Origin Energy Resources and 39.2% to IOR Energy.

(viii) Backlog.

Not applicable.

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

Not applicable.

(x) Competitive Conditions in the Business.

The exploration for and production of oil and gas are highly competitive operations. The ability to exploit a discovery of oil or gas is dependent upon such considerations as the ability to finance development costs, the availability of equipment, and the possibility of engineering and construction delays and difficulties. The Company also must compete with major oil and gas companies which have substantially greater resources than the Company.

Furthermore, various forms of energy legislation which have been or may be proposed in the countries in which the Company holds interests may substantially affect competitive conditions. However, it is not possible to predict the nature of any such legislation which may ultimately be adopted or its effects upon the future operations of the Company.

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 separately its respective share of gas production from each field. MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

(xi) Research and Development.

Not applicable.

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(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, 2009, the Company had accrued approximately $9.8 million for asset retirement obligations for the Mereenie, Palm Valley, Nockatunga, Kiana, Aldinga and Dingo fields. See Note 4 of the Consolidated Financial Statements under Item 8. Financial Statements and Supplementary Data.

(xiii) Number of Persons Employed by Company.

At June 30, 2009, MPC had 5 employees in the United States and MPAL had 25 employees in Australia.

(d) (2) Financial Information Relating to Foreign and Domestic Operations.

See Note 10 to the Consolidated Financial Statements.

(3) Risks Attendant to Foreign Operations.

Most of the properties in which the Company has interests are located outside the United States and are subject to certain risks involved in the ownership and development of such foreign property interests. These risks include but are not limited to those of: nationalization; expropriation; confiscatory taxation; changes in foreign exchange controls; currency revaluations; price controls or excessive royalties; export sales restrictions; limitations on the transfer of interests in exploration licenses; and other laws and regulations which may adversely affect the Company’s properties, such as those providing for conservation, proration, curtailment, cessation, or other limitations of controls on the production of or exploration for hydrocarbons. Thus, an investment in the Company represents a speculation with risks in addition to those inherent in domestic petroleum exploratory ventures.

Since 1992, there has been an ongoing controversy regarding the Aborigines and the ownership of their traditional lands. There has been legislation aimed at resolving this controversy. The Company does not believe that this issue will have a material adverse impact on MPAL’s properties.

(4) Data Which are Not Indicative of Current or Future Operations.

None.

Set forth below and elsewhere in this Annual Report on Form 10-K are risks that should be considered in evaluating the Company’s common stock, as well as risks and uncertainties that could cause the actual future results of the Company to differ from those expressed or implied in the forward-looking statements contained in this Annual Report and in other public statements the Company makes. Additionally, because of the following risks and uncertainties, as well as other variables affecting the Company’s operating results, the Company’s past financial performance should not be considered an indicator of future performance.

The principal oil and gas properties owned by MPAL could stop producing oil and gas.

MPAL’s Palm Valley, Mereenie and Nockatunga fields could stop producing oil and gas or there could be a material decrease in production levels at the fields. Since these are the three principal revenue producing

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properties of MPAL, any decline in production levels at these properties could cause MPAL’s revenues to decline, thus reducing the amount of dividends paid by MPAL to MPC. Any such adverse impact on the revenues being received by Magellan from MPAL could restrict our ability to explore and develop oil and gas properties in the future.

If MPAL’s existing long-term gas supply contracts are terminated or not renewed, MPAL’s business could be adversely affected.

MPAL’s financial performance and cash flows are substantially dependent upon its Palm Valley and Mereenie existing supply contracts to sell gas produced at these fields to MPAL’s major customer, Gasgo, a subsidiary of PWC of the Northern Territory. Gasgo has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expired in January and June 2009. The expiration of these contracts, if not replaced, will have an adverse effect on MPAL’s revenues and business outlook and possibly its share price.

Our plans to drill for oil and gas on fields located in the U.K. may not result in successful discoveries of oil and gas.

During fiscal year 2010, we expect that at least three new wells, Markwells Wood-1, Havant-1 and Hedge End-2, in the Weald Basin in the United Kingdom in which we hold interests will be drilled in an attempt to recover oil and gas in commercially viable quantities. If these drilling projects are not successful, no revenues will be achieved from the drilling projects and our results of operations would be adversely effected.

We may not be successful in sharing the exploration and development costs of the fields and permits in which we hold interests.

Our plans for drilling in the U.K. and other areas depend, in certain cases, on our ability to enter into farm-in, joint venture or other cost sharing arrangements with other oil and gas companies. If we are not able to secure such farm-in or other arrangements in a timely manner, or on terms which are economically attractive to the Company, we may be forced to bear higher exploration and development costs with respect to our fields and interests. We may also be unable to fully develop and/or explore certain fields if the costs to do so would exceed our available exploration budget and capital resources. In either case, our results of operations could be adversely affected and the market price of our common shares could decline.

Fluctuations in our operating results and other factors may depress our stock price.

During the past few years, the equity trading markets in the United States have experienced price volatility that has often been unrelated to the operating performance of particular companies. These fluctuations may

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adversely affect the trading price of our common stock. From time to time, there may be significant volatility in the market price of our common stock. Investors could sell shares of our common stock at or after the time that it becomes apparent that the expectations of the market may not be realized, resulting in a decrease in the market price of our common stock.

The loss of key personnel could adversely affect our ability to operate.

We depend, and will continue to depend in the foreseeable future, on the services of the officers and key employees of MPC and MPAL. The ability to retain its officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. We maintain $2 million of key person life insurance on our Chief Executive Officer, William Hastings.

There are risks inherent in foreign operations such as adverse changes in currency values and foreign regulations relating to MPAL’s exploration and development operations and to MPAL’s payment of dividends to us.

The properties in which Magellan has interests are located outside the United States and are subject to certain risks related to the indirect ownership and development of foreign properties, including government expropriation, adverse changes in currency values and foreign exchange controls, foreign taxes, nationalization and other laws and regulations, any of which may adversely affect the Company’s properties. In addition, MPAL’s principal present customer for gas in Australia is the Northern Territory Government, which also has substantial regulatory authority over MPAL’s oil and gas operations. Although there are currently no exchange controls on the payment of dividends to the Company by MPAL, such payments could be restricted by Australian foreign exchange controls, if implemented.

Our dividend policy could depress our stock price.

We have never declared or paid dividends on our common stock and have no current intention to change this policy. We plan to retain any future earnings to reduce our accumulated deficit and finance growth. As a result, our dividend policy could depress the market price for our common stock and cause investors to lose some or all of their investment.

We may issue a substantial number of shares of our common stock under our stock option plans and shareholders may be adversely affected by the issuance of those shares.

As of June 30, 2009, there were 3,242,500 stock options outstanding of which 530,000 were fully vested and exercisable. There were also 1,787,500 options available for future grants under our 1998 Stock Incentive Plan. If all of these options, which total 5,030,00 in the aggregate, were awarded and exercised these shares would represent approximately 11% of our outstanding common stock and would, upon their exercise and the payment of the exercise prices, dilute the interests of other shareholders and could adversely affect the market price of our common stock.

If our shares are delisted from trading on the Nasdaq Capital Market, their liquidity and value could be reduced.

In order for us to maintain the listing of our shares of common stock on the Nasdaq Capital Market, the Company’s shares must maintain a minimum bid price of $1.00 as set forth in Marketplace Rule 5550(a)(2). If the bid price of the Company’s shares trade below $1.00 for 30 consecutive trading days, then the bid price of the Company’s shares must trade at $1.00 or more for 10 consecutive trading days during a 180-day grace period to regain compliance with the rule. On September 16, 2009, the Company’s shares closed at $1.40 per share. If the Company shares were to be delisted from trading on the Nasdaq Capital Market, then most likely the shares would be traded on the Electronic Bulletin Board, or OTC-BB. The delisting of the Company’s shares from NASDAQ could adversely impact the liquidity and value of the Company’s shares.

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RISKS RELATED TO THE OIL AND GAS INDUSTRY

Oil and gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The prices of oil, natural gas, methane gas and other fuels have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including the following:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Furthermore, the ongoing worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession would likely reduce worldwide demand for energy and result in lower oil and natural gas prices. Oil prices declined from record levels in early July 2008 of over $140 per barrel to below $70 per barrel in August 2009, while natural gas prices have declined from over $13 per mcf to approximately $3 per mcf over the same period.

Sustained declines in oil and gas prices (such as those experienced in the second half of 2008) would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Approximately 44% of our proved reserves at June 30, 2009 were natural gas reserves. Gas sales contracts in Australia are adjusted to the gas price movements related to the Australian Consumer Price Index. Future gas sales not governed by existing contracts would generate lower revenue if natural gas prices in Australia were to decline. Sales of our proved oil reserves are dependent on world oil prices. The volatility of these prices will affect future oil revenues. Based on 2009 sales volume and revenue, a 10% change in oil price would increase or decrease oil revenues by approximately $1.1 million. Gas sales, which represented approximately 56% of production revenues in 2009, 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.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production and face intense competition from both major and other independent oil and natural

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gas companies. Many of our Australian competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may not be able to compete with, or enter into cooperative relationships with, any such firms.

Our oil and gas exploration and production operations are subject to numerous environmental laws, compliance with which may be extremely costly.

Our operations are subject to environmental laws and regulations in the various countries in which they are conducted. Such laws and regulations frequently require completion of a costly environmental impact assessment and government review process prior to commencing exploratory and/or development activities. In addition, such environmental laws and regulations may restrict, prohibit, or impose significant liability in connection with spills, releases, or emissions of various substances produced in association with fuel exploration and development.

We can provide no assurance that we will be able to comply with applicable environmental laws and regulations or that those laws, regulations or administrative policies or practices will not be changed by the various governmental entities. The cost of compliance with current laws and regulations or changes in environmental laws and regulations could require significant expenditures. Moreover, if we breach any governing laws or regulations, we may be compelled to pay significant fines, penalties, or other payments. Costs associated with environmental compliance or noncompliance may have a material adverse impact on our cash flows, financial condition or results of operations in the future.

The actual quantities and present value of our proved reserves may prove to be lower than we have estimated.

This annual report and the documents incorporated by reference in this annual report contain estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

There are many uncertainties in estimating quantities of oil and gas reserves. In addition, the estimates of future net cash flows from our proved developed reserves and their present value are based upon assumptions about future production levels, prices and costs that may prove to be inaccurate. Our estimated reserves may be subject to upward or downward revision based upon our production, results of future exploration and development, prevailing oil and gas prices, operating and development costs and other factors.

We may not have funds sufficient to make the significant capital expenditures required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations,

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farming-in other companies or investors to MPAL’s exploration and development projects in which we have an interest and/or equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund MPAL’s capital expenditure budget, we may not be able to rely upon additional farm-in opportunities, debt or equity offerings or other methods of financing to meet these cash flow requirements.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. Recovery of any additional reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

Future price declines may result in a write-down of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, the costs of successful wells, development dry holes and productive leases are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. Magellan records its proportionate share in its working interest agreements in the respective classifications of assets, liabilities, revenues and expenses. Unproved properties with significant acquisition costs are periodically assessed for impairment in value, with any required 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 (including exploration rights), along with goodwill are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate 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

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circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. For Mereenie, proved developed natural gas reserves are limited to contracted quantities. For Palm Valley, reserves were based upon the quantities of gas committed to the contract and estimated sales subsequent to the contract date. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves and risk adjusted probable and possible reserves or the contracted quantities. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future write down of capitalized costs and a non-cash charge against future earnings.

Oil and gas drilling and producing operations are hazardous and expose us to environmental liabilities.

Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these risks occur, we could sustain substantial losses as a result of:

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.

Difficult conditions resulting from the ongoing U.S. and worldwide financial and credit crisis, and significant concerns over the continuing recessions in the U.S. and Australian economies, may materially adversely affect our business and results of operations and we do not expect these conditions to improve in the near future.

Since 2008, the United States and many other nations (including Australia) around the world have been experiencing a financial and credit crisis. Concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. and elsewhere have contributed to increased market volatility and disruptions and diminished expectations for the U.S. and world economies and markets going forward. These factors, combined with volatile oil and gas prices, declining business and consumer confidence and increased unemployment, have precipitated a worldwide economic slowdown.

In addition, the U.S. and worldwide capital and credit markets have been experiencing extreme volatility and disruption for more than twelve months. Initially, the concerns on the part of market participants were focused on the subprime segment of the mortgage-backed securities market. However, these concerns have since expanded to include a broad range of mortgage and asset-backed and other fixed income securities, including those rated investment grade, the U.S. and international credit and interbank money markets generally, and a wide range of financial institutions and markets, asset classes and sectors. Since September 2008, market volatility and disruptions have reached unprecedented levels, leading in many cases to unprecedented

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government legislation and other actions to stabilize world markets and financial institutions and promote consumer and investor confidence.

Continuing volatility and disruption in worldwide capital and credit markets and further deteriorating conditions in the U.S. and Australian economies could affect our revenues and earnings negatively and could have a material adverse effect on our business, results of operations and financial condition. For example, purchasers of our oil and gas production may reduce the amounts of oil and gas they purchase from us and/or delay or be unable to make timely payments to us.

Further, a number of our oil and gas properties are operated by third parties whom we depend upon for timely performance of drilling and other contractual obligations and, in some cases, for distribution to us of our proportionate share of revenues from sales of oil and gas we produce. If current economic conditions adversely impact our third party operators, we are exposed to the risk that drilling operations or revenue disbursements to us could be delayed. This “trickle down” effect could significantly harm our business, financial condition and results of operation.

Currency exchange rate fluctuations may negatively affect our operating results.

The exchange rates among the Australian dollar and the U.S. dollar, as well as the exchange rates between the Australian dollar and the U.K. pound sterling, have changed in recent periods and may fluctuate substantially in the future. We expect that a majority of our revenue will continue to be generated in the Australian dollar in the future. Since June 30, 2008, the U.S. dollar has strengthened materially against the Australian dollar which has had, and may continue to have, a materially negative impact on our revenues generated in the Australian dollar, as well as our operating income and net income, as considered on a consolidated basis. The foreign exchange loss for the year ended June 30, 2009 was $9.9 million and is included in accumulated other comprehensive income on the balance sheet. Any continued appreciation of the U.S. dollar against the Australian dollar is likely to have a negative impact on our revenue, operating income and net income. Because of our U.K. development program, a portion of our expenses, including exploration costs and capital and operating expenditures, will continue to be denominated in U.K. pound sterling. Accordingly, any material appreciation of the U.K. pound sterling against the Australian dollar could have a negative impact on our business, operating results and financial condition.

None

(a) MPC has interests in properties in Australia through its 100% equity interest in MPAL which holds interests in the Northern Territory, Queensland and South Australia. MPAL also has interests in 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

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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

Mereenie Oil Pipeline

The following graphic presentation has been omitted, but the following is a description of the omitted material:

CANADIAN PROPERTY INTERESTS MAP

The map indicates the location of the Kotaneelee Gas Field in the Yukon Territories of Canada. The map identifies the following items:

Kotaneelee Gas Field

Pointed Mountain Gas Field

Beaver River Gas Field

The following graphic presentation has been omitted, but the following is a description of the omitted material:

UNITED KINGDOM PROPERTY INTERESTS MAP

The map indicates the location of the MPAL property interests in the United Kingdom.

(2) Reserves Reported to Other Agencies.

None

(3) Production.

MPC’s production volumes, net of royalties, for gas and oil during the three years ended June 30, 2009 were as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

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

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

Amounts presented above are in Australian dollars to show a more meaningful trend of underlying operations. For the years ended June 30, 2009, 2008 and 2007 the average foreign exchange rates were .7471, .8965, and .7860, respectively.

(4) Productive Wells and Acreage.

Productive wells and acreage at June 30, 2009

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(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, 2009

MPAL has interests in the following properties (before royalties). MPC has an interest in these properties through its 100% interest in MPAL.

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(6) Drilling Activity.

Productive and dry net wells drilled during the following years (data concerning Canada is insignificant):

(7) Present Activities.

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.

None

(a) On May 27, 2009, the Company held its 2008 Annual General Meeting of Stockholders.

(b) The following director was elected as a director of the Company. The vote was as follows:

(c) Authorization to amend the Company’s Restated Certificate of Incorporation to repeal, effective December 31, 2009, the “per capita” voting requirements of Articles 12^th and 14^th thereof, which will have the effect of adopting one share, one vote for all matters for which shareholders are required to vote under the Delaware General Corporation Law. The vote was as follows:

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(d) Authorization to amend the Company’s Restated Certificate of Incorporation to repeal, effective December 31, 2009, Article 13^th, the “super majority” voting provision of the Restated Certificate. The vote was as follows:

(e) Approval of a $10 million equity investment in the Company through the issuance (A) 8,695,652 shares of the Company’s common stock and (B) warrants to acquire 4,347,826 shares of common stock to Young Energy Prize S.A. or its affiliate. The vote was as follows:

(f) Approval of an amendment and restatement of the Company’s 1998 Stock Option Plan to: (A) increase the authorized shares of common stock reserved for awards under the Plan to 5,205,000 shares; (B) authorize the Compensation Committee to award shares of restricted stock, make annual awards of stock to non-employee directors and make performance-based awards; and (C) rename the Plan the “1998 Stock Incentive Plan.” The vote was as follows:

(g) The firm of Deloitte & Touche LLP was appointed as the Company’s independent auditors for the year ending June 30, 2009. The vote was as follows:

PART II

(a) Principal Market

The principal market for MPC’s common stock is the NASDAQ Capital Market under the symbol MPET. The stock is also traded on the Australian Stock Exchange in the form of CHESS depository interests under the symbol MGN. The quarterly high and low prices on the most active market, NASDAQ, during the quarterly periods indicated were as follows:

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(b) Approximate Number of Holders of Common Stock at September 1, 2009

(c) Frequency and Amount of Dividends

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

Recent Sales of Unregistered Securities

During the fiscal year ended June 30, 2009, there were no equity securities of the Company sold that were not registered under the Securities Act of 1933, as amended (the “Securities Act”).

As previously disclosed in the Company’s current reports filed on February 10, 2009, April 8, 2009, June 2, 2009 and July 14, 2009, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”), dated February 9, 2009, with Young Energy Prize S.A. (“YEP”) under which the Company agreed to sell, and YEP agreed to purchase, 8,695,652 shares (the “Shares”) of the Company’s common stock, par value $0.01 per share (the “Common Stock”) at a purchase price of $1.15 per share, or an aggregate of $10,000,000. The Purchase Agreement was amended on April 3, 2009 and June 30, 2009. On July 9, 2009, the Company and YEP completed the issuance and sale of the Shares to YEP. The Company received gross proceeds of $10 million, which will be used for general corporate and working capital purposes. On July 9, 2009, the Company also executed and delivered to YEP a Warrant Agreement entitling YEP to purchase an additional 4,347,826 shares of the Company’s Common Stock (the “Warrant Shares”) at an exercise price of $1.20 per Warrant Share, subsequently reduced to $1.15 per share on July 30, 2009.

The shares sold to YEP in the private placement and the Warrant Shares were not registered under the Securities Act or state securities laws, and may not be resold in the United States in the absence of an effective registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) or an available exemption from the applicable federal and state registration requirements. In the Purchase Agreement, YEP represented to the Company that: (a) it is an accredited investor, as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act; (b) it acquired the Shares and the Warrant as principal for its own account for investment purposes only and not with a view to or for distributing or reselling the Shares and the Warrant or any part thereof, and (c) it is knowledgeable, sophisticated, and experienced in making, and qualified to make, decisions with respect to investments in securities representing an investment decision similar to that involved in the purchase of the Shares and the Warrant. The Company has relied on the exemption from the registration requirements of the Securities Act set forth in Regulation S promulgated thereunder for the purposes of the YEP transaction.

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:

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The following table sets forth selected data (in thousands except for exchange rates and per share data) and other operating information of the Company. The selected consolidated financial data in the table, except for the exchange rate and market value per share, 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.

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Restatement

As discussed in Note 12 to accompanying consolidated financial statements in Item 8 of this Annual Report on Form 10-K, we have restated the Consolidated Statement of Cash Flows for the years ended June 30, 2008 and 2007 that were presented in Item 8 of the Company’s Form 10-K. All affected amounts contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations have been adjusted to reflect the restatement.

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. The results reflect fully the consolidated financial statements of MPC. Among these risks and uncertainties are pricing and production levels from the properties in which Magellan and MPAL have interests, the extent of the recoverable reserves at those properties and the future outcome of the negotiations for gas sales contracts for the remaining uncontracted reserves at both the Mereenie and Palm Valley gas fields in the Amadeus Basin, including the likelihood of success of other potential suppliers of gas to the current customers of Mereenie and Palm Valley production. In addition, MPAL has a large number of exploration permits and faces the risk that any wells drilled may fail to encounter hydrocarbons in commercially recoverable quantities. Magellan assumes no obligation to update any forward-looking statements contained in this release, whether as a result of new information, future events, or otherwise.

Executive Summary

MPC is engaged in the exploration, development, production, and sale of natural gas and oil reserves. Magellan has maintained a conservative financial philosophy and is now well-positioned with cash and no debt to gain value through acquisition of distressed, debt-laden small-cap companies with substantive discovered reserves.

MPAL has begun refocusing its activities toward long-term development of and sale of reserves from the Amadeus Basin, gaining ownership/control of existing reserves offshore in the Bonaparte and Browse Basin, Australia and toward entry into major oil/gas basins in North America and Europe beginning with the Weald Basin, onshore southern United Kingdom. In addition, a number of other recent initiatives are active as described below:

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The Palm Valley Darwin contract expires in the year 2012 and the principal Mereenie contracts expired in January and June 2009. Supply obligations under the Mereenie contracts ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010. The Palm Valley local sales contract expires in January 2012 and the Mereenie contracts continue on a month-to-month basis into 2010 under an evergreen term. The Company is making strong efforts to dedicate remaining natural gas to area buyers under “life of remaining reserves” agreement(s).

MPAL’s major customer, PWC, has contracted with Eni Australia for the supply of PWC’s Northern Territory gas demand requirement for twenty five years. Eni Australia, initially expected to commence sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delay but is expected to commence partial production in the near term. The follow-on production schedule and timing is not yet available to us. The Mereenie Producers will continue to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until December 31, 2010, unless amended or extended. All prices for those sales now fall under the Backstop Agreement. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2010-2013 timeframe. When Blacktip gas becomes available, there will be strong competition within the market and MPAL may not be able to contract for the sale of the remaining uncontracted reserves in the short term, but may be able to do so in the longer term with increasing demand from new mining developments and industrial users in the Northern Territory and the adjacent areas of neighboring states. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. Mereenie gas sales were approximately $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009 and $15.5 million (net of royalties) or 85% of total sales for the year ended June 30, 2008.

MPC also has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada. The Company recorded revenue of $164,000 from this investment during fiscal year 2009.

On July 9, 2009, the Company completed, pursuant to the terms of a definitive purchase agreement and related amendments an equity investment in the Company by the Company’s strategic investor, Young Energy Prize S.A. (“YEP”), through the issuance to YEP of 8,695,652 shares of the Company’s common stock, $0.01 par value per share (the “Common Stock”) and warrants to acquire an additional 4,347,826 shares of Common Stock. The Company received gross proceeds of $10 million, which will be used for working capital and general corporate purposes.

On July 9, 2009, the Company entered into a Warrant Agreement which entitles YEP to purchase 4,347,826 shares of the Company’s Common Stock (the “Warrant Shares”) at an exercise price of $1.20 per Warrant Share.

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The Warrant has a term of five years and contains certain provisions which would reduce the exercise price. Furthermore The First Amendment to the Purchase Agreement provides that, if YEP completes the purchase of the ANS Shares from the ANS Parties under the ANS-YEP Purchase Agreement, (more fully described in Item 8.01 of the Company’s Form 8-K filed on April 8, 2009,) then the exercise price payable by YEP for the Warrant Shares shall be reduced from $1.20 to $1.15 per share. This transaction was completed on July 30, 2009 reducing the exercise price to $1.15 per share.

In connection with the YEP Purchase Agreement, at a Board meeting held on May 27, 2009, the Company’s Board adopted resolutions: (a) conditionally amending the Company’s Bylaws to expand the size of the Board; and (b) conditionally electing Messrs. Nikolay Bogachev and J. Thomas Wilson to the Board as Class II directors, each to serve a term of office expiring at the Company’s 2011 Annual Meeting of Shareholders. On July 9, 2009, upon completion of the YEP equity investment transaction, the elections to the Board of Messrs. Bogachev and Wilson became effective.

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. 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, proved developed natural gas reserves were limited to contracted quantities. For Palm Valley, reserves were based upon the quantities of gas committed to the contract and estimated sales subsequent to the contract date. If such contracts are extended, the proved developed reserves will be increased to the lesser of the actual proved developed reserves and risk adjusted probable and possible 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 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.

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Nondepletable assets

At June 30, 2009 and 2008, oil and gas properties include $6.6 million and $6.8 million, respectively, of capitalized costs that are currently not being depleted. Components of these costs are as follows:

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Goodwill

All of our goodwill is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time. In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, goodwill is not amortized and is tested for impairment annually or whenever events or changes in circumstances indicate that the carrying value may be impaired. We performed our annual impairment testing as of June 30, 2009 and determined that no impairment existed as of that date.

We employ the adjusted balance sheet method to estimate the fair value of MPAL. This method entails estimating the fair value of all of MPAL’s balance sheet items as of the valuation date. If the adjusted equity value, after considering the fair values of the assets and liabilities, is greater than the carrying value of MPAL, then no impairment is indicated. Management believes that this methodology is most meaningful since the highest and best use of these assets would be to continue to hold and exploit the assets over time.

The fair value of our oil and gas properties are estimated based on the discounted cash flows of our proved and risk adjusted probable and possible reserves.

The significant assumptions used in estimating the fair values of the oil and gas properties are oil and gas selling prices for non-contracted volumes, oil and gas sales volumes, discount rates, and production trends. The fair value of MPAL is most susceptible to changes in selling prices of oil and gas and changes in estimated sales volume. As an example, a 10% decrease in the selling price or sales volume of oil and gas for the non-contracted volumes would reduce the estimated fair value of MPAL by approximately $3.3 million.

The fair value of our nondepletable exploration permits and licenses is estimated separately using one of four methods – discounted cash flows, discounted cash flows adjusted for chances of success, recent farmin costs and premiums, and estimated costs of committed work programs. The majority of the permits and licenses are valued based on the estimated cost of agreed work program commitments, which is a methodology that is not dependent on significant assumptions.

Asset Retirement Obligations

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” 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.

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 our operating fields. The liability is a discounted liability using a credit-adjusted risk-free rate on the date such liabilities are determined. Revisions to the liability could occur due to changes in the estimates or timing 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 (net of royalties) from its interests in producing wells as oil and gas is produced and sold from those wells. Revenues from the purchase, sale and transportation of natural

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gas are recognized upon completion of the sale and when transported volumes are delivered. Other production related revenues are primarily MPAL’s share of gas pipeline tariff revenues which are recorded at the time of sale. The Company records pipeline tariff revenues on a gross basis with the revenue included in other production related revenues and the remittance of such tariffs are included in production costs. 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. Shipping and handling costs in connection with such deliveries are included in production costs except for Nockatunga crude oil transportation costs which are deducted from gross sales. 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 may lag the production month by one or more months.

Liquidity and Capital Resources

At June 30, 2009, the Company on a consolidated basis had approximately $34.7 million of cash and cash equivalents and $1.0 million in marketable securities. The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of change in interest rates. Cash balances were $13.3 million as of June 30, 2009 and the remaining $21.4 million was held in time deposit accounts in several Australian banks that have terms of 90 days or less. National Australia Bank, Ltd. (“NAB”) holds 55% of the cash and cash equivalent balance. Although the funds are uninsured, Standard and Poor’s credit rating of NAB is AA Stable long-term and A-1+ short-term.

Consolidated

When considering our liquidity and capital resources, we consider cash and cash equivalents and marketable securities together since all of these amounts are available to fund operating, exploration and development activities. The balance of cash and cash equivalents and marketable securities decreased $637,000 during the year ended June 30, 2009 compared to a $3.5 million increase in those balances during the year ended June 30, 2008. The factors favorably impacting our liquidity and capital resources during the year ended June 30, 2009 included a decrease in tax payments of $12.2 million offset by a net decrease in collections of $8.8 million. We also experienced a $1.4 million decrease in cash expenditures on exploration and development and a $1.8 million decrease in property and equipment expenditures offset by a $0.6 million investment in securities available for sale. Our cash position was also unfavorably affected by a $10.2 million decrease in foreign exchange transaction gains resulting from a weakened Australian dollar.

The decrease in cash from the sales of oil and gas was due to decreased sales of $12.7 million offset by a decrease in accounts receivable of $3.9 million. Sales decreases were mostly due to a 27% decrease in barrels sold, attributable essentially to a 48,000 barrel decrease in the Nockatunga project resulting from a downward production trend. The decrease in accounts receivable resulted from the collection in 2009 of 2008 revenues for which the due date had been extended.

The Company invested $2.9 million and $6.1 million in oil and gas exploration activities, which includes additions to property and equipment, during the fiscal years ended June 30, 2009 and 2008, respectively. The decrease was due to reduced drilling activities in 2009.

MPAL’s current contracts for the sale of Palm Valley gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC or be successful in its current exploration program, its revenues will begin to decline substantially

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in 2010 which would materially affect liquidity. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. For further information, see “Gas Supply Contracts” in Item 1-Business above. MPAL’s oil sales are dependent on world oil prices. The volatility of these prices will affect future oil revenues. The Company will align operating expenses with any reductions in revenues.

As to MPC (Unconsolidated)

In December, 2008, a dividend of $3.0 million was received from MPAL to fund operating costs. Also in June, 2009, MPAL loaned approximately $1.9 million to MPC.

On July 9, 2009, the Company completed, pursuant to the terms of a definitive purchase agreement and related amendments an equity investment in the Company by the Company’s strategic investor, Young Energy Prize S.A. through the issuance to YEP of 8,695,652 shares of the Company’s common stock, $0.01 par value per share and warrants to acquire an additional 4,347,826 shares of Common Stock. The Company received gross proceeds of $10 million, which will be used for working capital and general corporate purposes.

At June 30, 2009, MPC, on an unconsolidated basis, had working capital of $800,054. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and any future MPAL dividends should be adequate to meet MPC’s current and future cash requirements.

MPC has a stock repurchase plan to purchase up to one million shares of its common stock in the open market. Through June 30, 2009, MPC purchased 680,850 of its shares at a cost of approximately $686,000. There were no shares purchased during fiscal years 2009, 2008 or 2007.

As to MPAL

At June 30, 2009, MPAL had working capital of $36,360,451. MPAL had budgeted approximately (Aus) $6.0 million for specific exploration projects in fiscal year 2009 as compared to the (Aus) $4.7 million expensed during fiscal 2009. During the year, there was less money spent than budgeted in the United Kingdom. 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 oil and gas in Australia. MPAL’s current contracts for the sale of Palm Valley gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC or be successful in its current exploration program, its revenues will begin to decline substantially in 2010 which could materially affect liquidity. The price of gas under the Palm Valley and Mereenie gas contracts is adjusted quarterly to reflect changes in the Australian Consumer Price Index. For further information, see “Gas Supply Contracts” in Item 1-Business above. MPAL’s oil sales are dependent on world oil prices. The volatility of these prices will affect future oil revenues. The Company will align operating expenses with any reductions in revenues.

As in the past, 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.

Off Balance Sheet Arrangements

The Company does not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company is exposed to oil and gas market price volatility and uses fixed pricing contracts with inflation clauses to mitigate this exposure.

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Contractual Obligations

The following is a summary of our consolidated contractual obligations as of June 30, 2009, in thousands:

Recent Accounting Pronouncements

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for annual reports for fiscal years ending on or after December 15, 2009. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The SEC will also require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.

In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of FASB Statement No. 157, “Fair Value Measurements”, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), including asset retirement obligations and goodwill and other impairment analyses. This guidance is effective for the Company for the fiscal year ended June 30, 2010. The Company is currently evaluating the impact of adoption of this FSP.

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Results of Operations

2009 vs. 2008

REVENUES

Changes in revenues are as follows:

Significant changes are discussed below.

OIL SALES DECREASED due to a 27% decrease in production, an 11% decrease in average price per barrel and the 17% decrease in the average exchange rate discussed below. Oil unit sales (after deducting royalties) in barrels (bbls) and the average price per barrel sold during the periods indicated were as follows:

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 fiscal years ended June 30, 2009 and 2008, the average foreign exchange rates were .7471 and .8965 respectively.

GAS SALES DECREASED due to a 10% decrease in volume resulting from natural field decline and the 17% decrease in the average exchange rate discussed below partially offset by a 4% increase in the average price per mcf. The volumes in billion cubic feet (bcf) (after deducting royalties) and the average price of gas per thousand cubic feet (mcf) sold during the periods indicated were as follows:

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MPAL’s current contracts for the sale of Palm Valley gas will expire during fiscal years 2012. Mereenie contracts expired in January and June 2009. Supply obligations ceased in June 2009, however, there is a reasonable endeavor obligation to supply certain of PWC’s requirements through to December 31, 2010, unless amended or extended. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will begin to decline substantially in 2010. For further information, see “Gas Supply Contracts” in Item 1-Business and Item 7-Executive Summary above.

OTHER PRODUCTION RELATED REVENUES are primarily MPAL’s share of gas pipeline tariff revenues which decreased as a result of a decrease in volumes of gas sold at Mereenie and the 17% Australian foreign exchange rate decrease discussed below.

INTEREST INCOME DECREASED due to a decrease in market interest rates and the 17% decrease in the average exchange rate discussed below.

COSTS AND EXPENSES

Changes in costs and expenses are as follows: