TELLURIAN INC. /DE/ - Annual Report: 2010 (Form 10-K)

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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, 2010

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

(207) 619-8500

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 $1.73 closing price on December 31, 2009 (the last business day of the most recently completed second quarter) was $72,951,630.

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, 52,335,977 shares outstanding as of September 24, 2010

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2010, 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 “(AUS) $00”. The exchange rate at September 1, 2010 was approximately (AUS) $1.00 equaled U.S. $0.89.

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PART I

Magellan Petroleum Corporation (the “Company” or “Magellan” or “MPC” or “we” or “us”) is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves. At June 30, 2010, MPCs has three reporting segments: (1) 100.00% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”); (2) an 83.5% controlling member interest in Nautilus Poplar, LLC (“Nautilus”), based in Denver, Colorado and (3) MPC the parent company that owns directly a 26.3% working interest in the Poplar Fields in Montana. Magellan is a development company, early in the business cycle, with reserves that need to be developed. We now have a larger asset base, increased probable reserves that need to be developed and are in a strong strategic position in a large natural gas basin which can be used in Chinese fuel, oxygenate, and olefins demand.

MPAL’s major assets are two petroleum production leases covering the Mereenie oil and gas field (35% working interest), one petroleum production lease covering the Palm Valley gas field (52% working interest) and seventeen 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. 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 is the operator of the Mereenie field. MPAL is operator of the Palm Valley field.

In March 2010, MPAL entered into an agreement with Santos to purchase Santos’ 40% interest in the Evans Shoal natural gas field, located in the Bonaparte Basin offshore Northern Australia. The field has a contingent gas resource in excess of 6.6 trillion cubic feet (Tcf), including carbon dioxide (CO₂) gas content. Under the agreement, Magellan is obligated to pay Santos time-staged cash consideration equal to (AUS) $100 million for its interest in Evans Shoal. Magellan would also pay additional contingent payments to Santos of (AUS) $50 million upon a favorable partner vote on any final investment decision to develop Evans Shoal and (AUS) $50 million upon first stabilized gas production from NT/P 48. Closing and completion of the purchase is subject to regulatory and other approvals and is expected to occur in the second half of calendar 2010. See Note 10 for further discussion.

On December 4, 2009, the Company announced the sale of all its interests in the Nockatunga oil fields, the Kiana and Aldinga oil fields, the Udacha gas field and its exploration acreage in the Cooper Basin of Queensland and South Australia. The Company subsequently entered into sales agreements to affect the sale of those licenses. The Company also entered into a sales agreement for the sale of its ATP 613P, ATPA 674P and ATPA 733P interests in the Maryborough Basin of Queensland. These assets were disposed of because they are non-core to our strategies. See Note 9 for further discussion.

MPC acquired its 83.5% controlling interest in Nautilus in October 2009. Nautilus, based in Denver, Colorado, operates and holds a 68.75% interest in the East Polar Unit and varied interests averaging 57% in the Northwest Poplar Fields. The two fields with 23,000 combined licensed acres have between 700 and 800 million barrels of oil in place with 52 million barrels recovered to date or approximately 79% reserves. See Note 11 for further discussion.

MPC owns interests of 83.7% in the East Poplar Unit and varied interests in the Northwest Poplar Fields through its controlling interest in Nautilus and through the purchase of interests from Hunter Energy LLC and Nautilus Technical Group, LLC which were completed in March 2010.

MPC has a direct 2.67% carried interest in the Kotaneelee gas field in the Yukon Territory of Canada.

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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 varied interests in the Weald-Wessec Basin, UK.

MPAL owns 34.3% of the Dingo Field, Australia

MPAL owns 52% of the Palm Valley Field, Australia.

MPAL owns 35% of the Mereenie Field, Australia.

SANTOS owns 65.7% of the Dingo Field, Australia

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

SANTOS owns 65% of the Mereenie Field, Australia.

MPC — NAUTILUS POPLAR RELATIONSHIPS CHART

Through the controlling member interest of Nautilus and a direct Interest in the fields, Magellan owns a 83.7% average working interest in the Poplar fields.

MPC owns 83.5% of Nautilus.

MPC owns 26.3% direct working interest in the East Poplar Unit and varied interests averaging 22.7% in the Northwest Poplar Fields

Nautilus owns 68.75% working interest in the East Poplar Unit and varied interests averaging 57% in the Northwest Poplar Fields

(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. At June 30, 2010, MPAL’s share of the Mereenie field proved developed oil reserves was zero. Under SEC revised rules, neither proved nor probable reserves of natural gas can be booked for Mereenie until a natural gas sales agreement is completed. Probable developed oil reserves have been booked at Mereenie. Additionally, MPAL does not yet have sufficient history to use cost structure reduction assumptions making gas re-injection into the Mereenie field economic at June 30, 2010. During fiscal 2010, MPAL’s share of oil and condensate sales was approximately 80,000 barrels and 2.3 Bcf of gas, which is subject to net overriding royalties aggregating 4.38% and the statutory government

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royalty of 10%. Prior to June 2009, the oil was transported by means of a 167-mile eight-inch oil pipeline east from the field to an industrial park near Alice Springs. The oil was then shipped south approximately 950 miles by road to the Port Bonython Export Terminal at Whyalla, South Australia for sale. Since 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 were contracted until September 5, 2010 to supply gas on a reasonable endeavors basis to the Power and Water Corporation (“PWC”) for use in the Northern Territory. 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. MPAL and Santos (“Palm Valley Producers”) provide Palm Valley gas to meet a supply contract with PWC. See “Gas Supply Contracts” below. MPAL’s share of the Palm Valley proved developed reserves (net of royalties) was 1.2 Bcf at June 30, 2010 and is based upon gas contract amounts. During fiscal 2010, MPAL’s share of gas sales was 1.2 Bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.31%. 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 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 delivered into the 922-mile Amadeus Basin gas pipeline which was built by an Australian consortium in 1987. Since 1985, there have been several additional contracts for the sale of Mereenie gas, the latest being the Mereenie Sales Agreement No. 4 in June 2006 for the supply of an additional 4.4 Bcf of gas to be supplied prior to December 31, 2008. The principal Mereenie contracts and supply obligations under the various agreements expired in January and June 2009. The Palm Valley gas contract expires in January 2012.

MPAL’s major customer, PWC, contracted with Eni Australia in 2006 for the supply of PWC’s Northern Territory gas demand requirement for twenty five years, commencing January 2009. Eni Australia expected to commence sales from its Blacktip field offshore of the Northern Territory in January 2009; however, the Blacktip development encountered significant delays and only commenced partial production in September 2009 with full production not achieved until February 2010. The Mereenie Producers continued to supply PWC’s gas requirements on a reasonable endeavors basis to supplement Blacktip gas sales until early February, 2010.

MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves at Mereenie and Palm Valley. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2011-2013 timeframe. There is strong competition within the market with Blacktip gas now available, 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. As MPAL has not been able to sell its uncontracted gas reserves, its revenues have declined in 2010. Mereenie gas

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sales were approximately $11.6 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2010 and $12.4 million (net of royalties) or 85% of total sales for the year ended June 30, 2009.

At June 30, 2010, MPAL’s commitment to supply gas under the Palm Valley and Mereenie agreements was as follows:

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 follow-on production schedule and timing is not yet available to us. The Mereenie Producers continued to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until September 5, 2010. 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. With Blacktip gas now available, there is 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 continue to be substantially reduced in 2010 and beyond. Mereenie gas sales were approximately $11.6 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2010 and $12.4 million (net of royalties) or 85% of total sales for the year ended June 30, 2009.

Evans Shoal Gas Field

Evans Shoal is a large, yet to be developed natural gas field with an estimated contingent gas resource in excess of 6.6 Tcf, including CO₂ gas content. The field was discovered in 1998 and lies in a range of water depths from very shallow to more than 300 feet. There have been three wells drilled in the NT/P48 permit area. A drill stem test on the Evans Shoal-2 well flowed gas at a stabilized rate of 25 million cubic feet per day (MMcf/D). The field has had a complete 3D seismic program covering 840 square miles within the permit. Seismic analysis has confirmed the field’s structural closure to be in excess of 125 square miles. The gas resource is dependent upon completion, submission, and approval of a development plan and upon further drilling which Magellan believes will support the field’s potential. Carbon dioxide is a significant feed component for the production of Methanol, but can add cost to LNG development.

MPAL entered into an agreement with Santos on March 25, 2010, to purchase Santos’ 40% interest in the Evans Shoal natural gas field (Exploration Permit for Petroleum NT/P48), located in the Bonaparte Basin, offshore Northern Australia. The Company will pay Santos a time-staged cash consideration equal to (AUS) $100 million for its interest in the Evans Shoal field. The Company would also pay additional contingent payments to Santos of (AUS) $50 million upon a favorable partner vote on any final investment decision to

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develop the Evans Shoal field and a further (AUS) $50 million upon first stabilized gas production from the field. Closing and completion of the purchase is subject to regulatory and other approvals and is expected to occur in the second half of 2010. The Australian Foreign Investment Review Board has indicated it has ‘no objection’ to the acquisition of Santos’ interest by Magellan.

Based on its available cash on hand, and the expected liquidity to be generated from the Company’s Australian and U.S. operations during the remainder of 2010, the Company will need to raise additional debt or equity financing from third parties to complete this acquisition. The Company is currently working towards new equity financing options to raise sufficient funds to complete the Evans Shoal acquisition and its other requirements for capital resources over the next 12 month period, which are estimated to be approximately (AUS) $85 million. In the event the Company is unable to make the required payment on or before December 25, 2010 or to extend the time, under certain circumstances the Company could lose its rights to the (Aus) $15 million deposit.

Nockatunga Oil Fields

MPAL purchased a 40.97% working interest (38.70% net revenue interest) in the Nockatunga oil fields in the Cooper Basin in southwest Queensland, effective July 1, 2003. Santos is operator of the fields and held the remaining interest. The Nockatunga oil fields 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.

On December 22, 2009, the Company entered into an asset sale agreement with Santos to sell all of its ownership interests in the five petroleum leases and ATP. The sale was completed in March 2010. Through the date of disposition, MPAL’s share of oil sales was approximately 32,000 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 3.00%.

Dingo Gas Field

MPAL has a 34.34% 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 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 4.81%. The license was renewed for a further five year term and expires in February 2014.

Bonaparte Basin

The Commonwealth – Northern Territory Offshore Petroleum Joint Authority granted Exploration Permit for Petroleum No. NT/P82 to the Company (100% interest) over Area NT09-1, offshore Northern Territory. Area NT09-1 was offered for competitive bid under the Australian Government 2009 Release of Offshore Petroleum Exploration Areas. The exploration permit was granted on May 13, 2010 for a six year term. The committed work program under the permit during the first three years of the term involves the reprocessing of existing seismic data, the acquisition of additional 2D and 3D seismic data and the interpretation of the combined seismic database. NT/P82 lies to the south and southeast of the Evans Shoal gas field within the Bonaparte Basin. At June 30, 2010, MPAL work obligations on the NT/P82 licenses totaled $24,460,000 of which $2,300,000 was committed.

Maryborough Basin

MPAL holds a 100% interest in exploration permit ATP 613P in the Maryborough Basin in Queensland, Australia. MPAL (100%) also has applications pending for permits ATP 674P and ATP 733P which are adjacent

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to ATP 613P. The grant of ATPA 674P and ATP 733P is subject to the agreement of the native title claimants to the area. The Company executed native title agreements with the native title claimants over the area of ATPA 733P and ATPA 674P in June 2010, and is now waiting on the grant of ATP 674P, ATP 733P and the excluded areas of ATP 613P by the Queensland Government. ATP 613P was renewed in March 2008 for a further 12-year term ending in March 2019.

In May 2006, MPAL entered into a farm-out agreement in relation to ATP 613P, ATPA 674P and ATPA 733P with Eureka Petroleum, under which that company funded the drilling of two exploration wells in 2007 which intersected multiple thin coal seams. Evaluation of the coal seam gas potential is continuing. Eureka Petroleum has agreed to undertake a staged evaluation of the area to earn a 75% interest in any petroleum lease granted. MPAL retained a 25% interest and is carried by Eureka Petroleum through any development to the grant of a petroleum lease.

On January 16, 2010, the Company entered into an asset sale agreement with Adelaide Energy to sell all of its ownership interests in the three petroleum exploration permits ATP 613P, ATPA 733P and ATPA 674P. The transaction with Adelaide Energy will close following the grant of the ATP 613P excluded areas and third party approvals and notices which are procedural only in nature. Closing and completion of the sale is subject to regulatory and other approvals and is expected to occur in fiscal 2011.

Cooper/Eromanga Basin

PEL 94, PEL 95 & PPL 210

On December 22, 2009, the Company entered into an asset sale agreement with Strike Energy to sell all of its ownership interests in PEL 94, PEL 95 and PPL 210. This sale was completed in the third quarter of fiscal 2010.

PEL 106, PEL 107 & PPL 212

On January 15, 2010, the MPAL entered into a share sale agreement with Drillsearch Energy to sell all of the shares in its wholly-owned subsidiary, Magellan Petroleum (Southern) Pty Ltd, which held MPAL’s interests in PEL 107, PPL 212 and the PEL 91-PEL 106 Udacha Block. The effective date of the sale of the licenses was November 1, 2009. The transaction was completed in the third quarter of fiscal 2010 for a price of approximately $468,000. During the date of disposition, MPAL’s share of oil production was approximately 700 barrels which is subject to a 10% statutory government royalty and net overriding royalties aggregating 4.0%.

PEL 110

On December 15, 2009, the Company entered into an asset sale agreement with Victoria Oil Exploration (1977) to sell all of its ownership interests in PEL 110. The transaction was completed in the second quarter of fiscal 2010 for a price of approximately $364,000.

UNITED KINGDOM

PEDL 098 & PEDL 240

During fiscal year 2001, MPAL acquired an interest in an exploration license in southern England in the Weald-Wessex Basins. The license, Petroleum Exploration and Development License (“PEDL”) 098 (22.5%) on the Isle of Wight was granted for a term of six years. The Sandhills-2 well, drilled in PEDL 098 during 2005, encountered a heavily biodegraded remnant oil column and was plugged and abandoned. PEDL 098 expires in September 2011. Effective July 1, 2008, MPAL and its joint venture partners were granted PEDL 240

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(22.5%) adjacent to PEDL 098 for an initial exploration term of six years. The license has a drill or drop obligation at the end of its initial exploration term. An exploration well has to be drilled within the first six years of the initial term in order for the license to be extended into the next five-year license term, as was the case for PEDL 098. At June 30, 2010, MPAL’s share of the work obligations of the PEDL 098 and PEDL 240 licenses totaled $1,484,000, of which $77,000 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 an initial exploration term of six years. The drilling plans for the Markwells Wood-1 well in PEDL 126 are well advanced. All necessary approvals have been received and the well site constructed ready for drilling. However, Northern Petroleum, operator of the PEDL 126 joint venture, announced in May 2010 that it was offering for sale all its production and exploration interests in the Weald Basin. The drilling of the well as a consequence has been delayed. Plans for drilling Hedge End-2 in PEDL 125 are in progress. The UK company Egdon Resources (the interest was formerly held by Encore Oil) 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. The terms of both PEDLs were extended by the Government; PEDL 126 will expire in June 2011 and PEDL 125 in June 2012. At June 30, 2010, MPAL’s share of the work obligations of the PEDL 125 and PEDL 126 licenses totaled $3,938,000 which was committed.

PEDL 135, PEDL 136, PEDL 137, PEDL 242 & PEDL 246

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. Effective July 1, 2008, MPAL was granted 100% interest in PEDL 242 and PEDL 246 located adjacent to the other licences; each with a six year initial term. Each licence has a drill or drop obligation at the end of its initial term. MPAL has undertaken a program of seismic data purchase, reprocessing and interpretation and has identified three drilling prospects. Drilling of a well in each of PEDL 135 and PEDL 137 is being planned and government drilling approvals sought. The initial exploration term of each of PEDL 135 and PEDL 137 have been extended by a further one year. PEDL 136 will expire on September 30, 2010. At June 30, 2010, MPAL’s work obligation for the PEDL 135, PEDL 136, PEDL 137, PEDL 242 and PEDL 246 licenses totaled $22,758,000, of which $147,000 was committed.

PEDL 152, PEDL 153, PEDL 154, PEDL 155 & PEDL 256

Effective October 1, 2004, MPAL acquired four licenses, PEDL 152 (22.5%), PEDL 153 (33.3%), PEDL 154 (50%) and PEDL 155 (40%), in the Weald-Wessex Basins in southern England, each granted for an initial exploration term of six years. Each license has a drill or drop obligation at the end of its initial exploration term. The drilling plans for the Havant-1 well in PEDL 155 are well advanced, and the well will be drilled immediately following the drilling of the Markwells Wood well in PEDL 126. All necessary approvals have been received and the well site is constructed ready for drilling. Because of access restrictions to the area of the prospect, the well will be drilled in the area of PEDL 256, adjacent to PEDL 155, but will be regarded by the Government as fulfilling the PEDL 155 work obligation. However, as noted above Northern Petroleum, operator of the PEDL 155 joint venture, announced in June 2010 that it was offering for sale all its production and exploration interests in the Weald Basin. The drilling of the well as a consequence has been delayed. The initial exploration term of PEDL 155 was extended for a further one year and will expire on September 30, 2011. PEDL 152 was surrendered on September 30, 2009 and PEDL 153 and PEDL 154 will expire on September 30, 2010. The U.K. company, Egdon Resources (the interest was formerly held by 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.

During fiscal year 2001, MPAL acquired an interest in exploration license PEDL 099 of the Portsdown area of Hampshire in southern England in the Weald Basin. The license (MPAL 40%) expired in September 2008.

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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 initial exploration term. PEDL 256 expires in April 2015.

At June 30, 2010, MPAL’s share of the work obligations of the PEDL 153, PEDL 154, PEDL 155 & PEDL 256 licenses totaled $3,901,000, of which $1,753,000 was committed.

PEDL 231, PEDL 232, PEDL 234 & PEDL 243

Effective July 1, 2008, MPAL (50%) and its joint venture partner were granted interests in PEDL 231, PEDL 232, PEDL 234 and PEDL 243 located in the central Weald Basin of southern England. Each license has a drill or drop obligation at the end of its initial exploration term and expires in June 2014. At June 30, 2010, MPAL’s share of the work obligations of the PEDL 231, PEDL 232, PEDL 234 & PEDL 243 licenses totaled $12,110,000 of which $340,000 was committed.

UNITED STATES

East Poplar Unit and Northwest Poplar Oil Fields

On October 15, 2009, MPC completed the purchase of an 83.5% controlling interest in Nautilus. Nautilus, based in Denver, Colorado, owns and operates oil development assets in Roosevelt County, Montana known as the East Poplar Unit and the Northwest Poplar Field. The controlling interest in Nautilus was purchased from White Bear LLC and YEP I, SICAV- FIS, entities affiliated with Nicolay Bogachev and Thomas Wilson, two directors of the Company.

MPC also completed a consolidation of interests in the fields by purchasing a 25.05% average working interest from Hunter Energy LLC and a 1.25% average working interest from Nautilus Technical Group LLC in March 2010. Magellan, itself now owns a 83.70% average working interest in the Poplar fields and through its subsidiaries controls a 95.05% average working interest there.

The Poplar assets were discovered and developed in 1954 by Murphy Oil Company. The two fields, with 23,000 combined licensed acres, have an estimated 800 million barrels of original oil in-place with 52 million barrels recovered to-date (largely from just the Charles formation) or approximately 7% of in-place reserves. Typical recovery factors in other fields with like characteristics are 20% to 30%. Magellan (through Nautilus) will embark on an active development program utilizing both secondary infill and tertiary enhanced oil recovery programs shown to be successful and productive in adjacent, similar fields in both the U.S. and in nearby Canada. Although certain contingencies must materialize, attractive upside potential is seen in the three producing oil horizons in the Mississippian Charles formation, up to 23,000 acres of Bakken shale, and both shallow and deep gas plays.

From the acquisition date, October 2009, to June 30, 2010, the Poplar assets produced a net average of 66,000 Bbls with approximately 35 active wells producing from the Charles Formation and 2 wells producing from the Tyler Formation. At June 30, 2010, MPC’s share of the Poplar fields proved developed oil reserves (net of royalties) was approximately 2,515 Bbls. during fiscal year 2010. At June 30, 2010, MPC’s share of the Poplar fields proved developed oil reserves (net of royalties) was approximately 2,515 thousand Bbls. During fiscal 2010, MPC’s share of oil sales was approximately 42,000 Bbls, which is subject to royalties and overriding royalties averaging 12%.

The oil is transported by truck to a lease automatic custody transfer (LACT) facility in Reserve, MT where it enters the Enbridge Oil Pipeline to Clearbrook, MN. The East Poplar Unit and Northwest Poplar Field leases are held by production.

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To increase production, MPC through Nautilus, plans to drill infill wells in fiscal year 2011, farmout, sell, or partner on the Bakken shale development, and complete well tracer operations to test residual oil saturation and determine potential CO₂ effectiveness for enhanced oil recovery operations. The Poplar assets are in close proximity (less than 90 miles) to several current and projected CO₂ sources that could be used for enhanced oil recovery through CO₂ injection.

(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 three operating segments; MPC, its 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”), and its 83.5% controlling member interest in Nautilus Poplar, LLC, See Note 11.

(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 the United States, 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. 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. MPC has an 83.5% controlling member interest in Nautilus Poplar LLC, and an average working interest of 26.3% in the Poplar Fields in Montana, USA. See Item 1(a).

(ii) Status of Product or Segment.

See Item 1(a) and (b) — Australia, Canada, U.S. — for a discussion of the current and future operations of the Mereenie and Palm Valley fields in Australia, MPC’s interest in the Kotaneelee field in Canada, and in the Poplar Fields in the United States.

(iii) Raw Materials.

Not applicable.

(iv) Patents, Licenses, Franchises and Concessions Held.

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MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs.

PEDL 136, 153 and 154 expired in September 2010 and will not be renewed.

Petroleum permits issued by the Northern Territory are subject to the Petroleum (Prospecting and Mining) Act and the Petroleum Act of the Northern Territory. 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 21 years, and leases may be renewed for successive terms of 21 years each. 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.

(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 weather.

(vi) Working Capital Items.

See Item 7 — Liquidity and Capital Resources for a discussion of this information.

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(vii) Customers.

Although MPAL’s producing oil and gas properties are located in a 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 customer, PWC, contracted with Eni Australia in 2006 for the supply of PWC’s Northern Territory gas demand requirement for twenty five years, commencing January 2009. Eni Australia expected to commence sales from its Blacktip field offshore of the Northern Territory in January 2009; however, the Blacktip development encountered significant delays and only commenced partial production in September 2009 with full production not achieved until February 2010. The Mereenie Producers continued to supply PWC’s gas requirements on a reasonable endeavors basis to supplement Blacktip gas sales until early February, 2010. MPAL is actively pursuing gas sales contracts for the remaining uncontracted reserves at Mereenie and Palm Valley. While gas marketing efforts to date have identified several potential customers, the majority have a gas requirement commencing in the 2011-2013 timeframe. There is strong competition within the market with Blacktip gas now available, 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. As MPAL has not been able to sell its uncontracted gas, its revenues have declined in 2010. 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 continue to be substantially reduced in 2011 and beyond, which will materially affect the Company’s liquidity and results of operations.

Mereenie gas sales were approximately $11.6 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2010 and $12.4 million (net of royalties) or 85% of total sales for the year ended June 30, 2009.

Oil Production

MPAL — 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. Prior to the sale of the MPAL’s Cooper Basin oil field, crude oil production from Kiana and Aldinga were generally shipped through the Moomba processing facility in northeastern South Australia and piped from there to the Port Bonython Export Terminal where it was sold. Nockatunga crude oil was shipped and sold through the IOR Energy refinery at Eromanga, Southwest Queensland. Oil sales during fiscal 2010 were 47.40% to the Santos group of companies, 14.70% to the Beach Petroleum group of companies, and 9.40% to Origin Energy Resources and 28.5% to IOR Energy.

Nautilus Poplar – Presently all of the oil production from the East Poplar Unit and the Northwest Poplar Oil Field is being trucked to a terminal in Reserve, MT and sold to Nexen, Inc.

(viii) Backlog.

Not applicable.

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

Not applicable.

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(x) Competitive Conditions in the Business.

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

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.

(xi) Research and Development.

Not applicable.

(xii) Environmental Regulation.

The Company is subject to the environmental laws and regulations of the jurisdictions in which it carries on its business, and existing or future laws and regulations could have a significant impact on the exploration for and development of natural resources by the Company. However, to date, the Company has not been required to spend any material amounts for environmental control facilities. The federal and state governments in Australia strictly monitor compliance with these laws but compliance therewith has not had any adverse impact on the Company’s operations or its financial resources. We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits and international environmental conventions, including those relating to the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; the storage, use and treatment of water; and the placement, operation and reclamation of wells. These requirements are a significant consideration for us as our operations involve the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, oil and other hazardous or regulated materials and the emission and discharge of such materials to the environment. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be fined or otherwise sanctioned, which sanctions could include the imposition of fines and penalties and orders enjoining future operations. Pursuant to such laws, regulations and permits, we have made and expect to continue to make capital and other compliance expenditures.

At June 30, 2010, the Company had accrued approximately $9.3 million for asset retirement obligations for the Mereenie, Palm Valley, Dingo and Poplar 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, 2010 the Company had 39 total employees. MPC had 7 employees and Nautilus had 10 employees in the United States. At that date, MPAL had 22 employees in Australia.

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

See Note 17 to the Consolidated Financial Statements.

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(3) Risks Attendant to Foreign Operations.

Many 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.

(e) Available Information

Information regarding the Company, including corporate governance policies, code of ethics and charters for the committees of the board of directors can be found on our Internet website at http://www.magellanpetroleum.com and copies of these documents are available to stockholders, without charge, upon request to Jeffrey Tounge, Investor Relations, Magellan Petroleum Corporation, 7 Custom House Street, 3rd Floor, Portland, Maine 04101 (tel: (207) 619-8500. The information contained in our website is not intended to be incorporated into this Form 10-K. In addition, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are made available free of charge on our Internet website on the same day that we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. These filings are also available to the public from commercial document retrieval services and at the Internet website maintained by the SEC at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

Set forth below and elsewhere in this Annual Report on Form 10-K are the risks and uncertainties that should be considered in evaluating the Company’s common stock and 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, MPC and Nautilus could stop producing oil and gas.

MPAL’s Palm Valley and Mereenie fields and / or Nautilus’s Poplar 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 properties of Magellan, any decline in production levels at these properties could cause Magellan’s revenues to decline. Any such adverse impact on the revenues and cashflows being received by Magellan could restrict our ability to explore and develop oil and gas properties in the future and cause our stock price to decline.

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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 have historically been dependent upon its Palm Valley and Mereenie existing supply contracts to sell gas produced at these fields to MPAL’s former 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, commenced sales in January 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. The Blacktip development has encountered delays but has already commenced partial production. The Mereenie Producers continued to supply PWC’s gas demand on a reasonable endeavors basis to supplement Blacktip gas sales as required until September 5, 2010. 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 2011-2013 timeframe. With Blacktip gas now available, there is 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 continue to decline in 2011. Mereenie gas sales were approximately $11.6 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2010 and $12.4 million (net of royalties) or 85% of total sales for the year ended June 30, 2009.

The Palm Valley Darwin contract expires in the year 2012. 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. Palm Valley gas sales were approximately $2.1 million (net of royalties) or 18% of total gas sales for the year ended June 30, 2010 and $2.2 million (net of royalties) or 17% of total sales for the year ended June 30, 2009.

We recently completed an acquisition of a 83.5% controlling member interest in Nautilus and may make acquisitions or investments in new oil and gas reserves, operating businesses or assets that involve additional risks, which could disrupt our business or harm our financial condition or results of operations.

As part of our business strategy, we have recently acquired a controlling interest in Nautilus Poplar LLC. We expect to continue to make acquisitions of companies that possess oil and gas reserves or other businesses or assets that are complementary to our growth strategy. Such acquisitions or investments involve a number of risks, including:

These factors could have a material adverse effect on our business, financial condition and operating results. Consideration paid for any future acquisitions could include our stock or require that we incur additional debt and contingent liabilities. As a result, future acquisitions could cause dilution of existing equity interests and earnings per share.

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We recently entered into an agreement with Santos to purchase Santos’ 40% interest in a large gas field offshore in Australia, under which we made an initial cash deposit of (AUS) $15 million as partial payment of the purchase price, that could be forfeited should we be unable to complete the purchase of the interest by the “completion date” specified under the agreement.

On March 25, 2010, our subsidiary MPAL entered into an agreement with Santos Limited (Santos) to purchase Santos’ 40% interest in Evans Shoal natural gas field (NT/P48), located in the Bonaparte Basin offshore Northern Australia. Under the agreement, we paid a cash deposit of (AUS) $15 million to be credited against the (AUS) $100 million initial purchase price for the Santos interest. If we are unable to complete the purchase of Santos’ interest by the completion date specified under the agreement (which will occur during December 2010) either because we are unable to raise additional funding by the sale of additional equity or debt securities in the near future, would likely forfeit our initial (AUS) $15 million deposit payment to Santos, which would adversely impact our financial condition and could cause our stock price to decline. For a more complete description of the Evans Shoal agreement and gas field, see Note 10 to the Consolidated Financial Statements included herein in Item 8.

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 2011, we expect that at least two new wells, Markwells Wood-1, Havant-1, 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 affected.

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 North America 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 adversely affect the trading price of our common shares. From time to time, there may be significant volatility in the market price of our common shares. 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 shares.

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, Nautilus, 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.

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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 MPC.

The properties in which Magellan has interests located outside the United States 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. 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, 2010, there were 4,347,826 warrants outstanding and 3,880,000 stock options outstanding of which 2,230,000 were fully vested and exercisable. As of that date, there were also 800,000 options available for future grants under our 1998 Stock Incentive Plan as amended in May of 2009. If all of these options and warrants, which total 9,027,826 in the aggregate, were awarded and exercised these shares would represent approximately 17.24% of our outstanding common shares 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 1, 2010 the Company’s shares closed at $1.63 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.

We have limited management and staff and will be dependent upon partnering arrangements.

The Company and its affiliates had approximately 39 total employees as of June 30, 2010. Despite this increase in employment, we expect that we will continue to require the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price will be materially adversely affected.

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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 and are back up to $76 per barrel as of September 2010, while natural gas prices have declined from over $13 per mcf to approximately $4 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 our revenues, 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 2.6% of our proved reserves at June 30, 2010 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. Gas sales, which represented approximately 50% of production revenues in 2010, are derived primarily from the Palm Valley and Mereenie fields in the Northern Territory of Australia and the gas prices are set according to 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 Magellan.

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 potential impacts of climate change may negatively impact our business and results of operations.

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

We depend on one purchaser for a substantial portion of our revenue in North America. The inability of the purchaser to meet their payment obligations to us may adversely affect our financial results.

Currently, Nautilus relies on its contract with Nexen, Inc. as the sole customer for its oil produced in Montana.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

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. Actual future production, oil and gas

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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.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on the average, first-day-of-the-month price during the 12-month period preceding the measurement date. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows for financial statement disclosure, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Our reserves as of June 30, 2010 have been reported under new SEC Rules. The estimates provided in accordance with the new SEC rules may change materially as a result of interpretive guidance that may be subsequently released by the SEC.

We have included in this report estimates of our proved reserves at June 30, 2010 as prepared consistent with our independent reserve engineers’ interpretations of the new SEC rules relating to disclosures of estimated natural gas and oil reserves. These new rules are effective for fiscal years ending on or after December 31, 2009. These newly adopted rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has not specifically reviewed our reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules. Accordingly, while the estimates of our proved reserves at June 30, 2010 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could ultimately differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

We may be limited in our ability to book additional proved undeveloped reserves under the new SEC rules.

Another impact of the new SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program on our undeveloped properties.

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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, 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 the Company’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, but at least annually, assessed for impairment in value with any required impairment charged to expense. The successful efforts method also imposes limitations on the carrying or book

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value of proved oil and gas properties. Oil and gas properties (including exploration rights), along with goodwill, are reviewed for impairment annually or whenever events or 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 for gas, except in the case of Palm Valley proved gas, which is based in contracted volumes. At June 30, 2010, Mereenie had no gas contracts, thus no gas reserves. The Mereenie discounted future net cash flows were negative due to the loss of the gas contract. According to the SEC definition of proved reserves, this results in zero proved oil reserves. For Palm Valley, reserves were based upon the quantities of gas committed to the contract. 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.

Continual volatility and disruption, since 2008, 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.

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We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an ownership interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and reserves. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

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, 2009, the U.S. dollar has slightly strengthened against the Australian dollar which has had, and may continue to have, a positive 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 gain for the year ended June 30, 2010 was $1.4 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 positive 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 the United States, MPC has an 83.5% controlling member interest in Nautilus. Nautilus, based in Denver, Colorado, owns and operates oil development assets in Roosevelt County, Montana known as the East Poplar Unit and the Northwest Poplar Field. MPC also owns a 26.3% average working interest in these Montana fields. In Canada, MPC has a direct interest in one lease. For additional information regarding the Company’s properties, see Item 1 — Business.

(b) (1) Detailed information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows and results of operations is disclosed in note 17 — Supplementary Oil & Gas Information under Item 8 — Financial Statements and Supplementary Data.

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A summary of our estimated proved, probable and possible reserves as of June 30, 2010 are set for the in the table below.

Oil reserves stated in 1,000 Bbls; natural gas reserves stated in Mmcf.

Oil and gas production for the twelve months ended June 30, 2010 was as follows:

AUSTRALIAN MAP WITH MPAL PROJECTS SHOWN

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

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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

UNITED KINGDOM PROPERTY INTERESTS MAP

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

Production

MPC’s production volumes, net of royalties, for gas and oil during the three years ended June 30, 2010, 2009 and 2008 are as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

The average sales price per unit of production for Australia and the United States for the following fiscal years ended June 30, 2010, 2009 and 2008 are as follows:

The average production cost per unit of production for Australia and the United States for the following fiscal years ended June 30, 2010, 2009 and 2008 are as follows:

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Productive Wells and Acreage

Productive wells and acreage at June 30, 2010

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, 2010

MPAL, MPC and Nautilus have interests in the following properties (before royalties).

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Drilling Activity

There were no wells in process at June 30, 2010.

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

Present Activities

See Item 1 — Cooper Basin and United Kingdom for a discussion of the present activities of MPAL and United States, for the present activities of MPC and Nautilus.

Delivery Commitments

See discussion under Item 1 concerning the Palm Valley and Mereenie fields.

None

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 15, 2010

(c) Frequency and Amount of Dividends

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

(e) Performance Graph

The graph below compares the cumulative total returns, including reinvestment of dividends, if applicable, on the Company’s Common Stock with the returns on companies in the NASDAQ Index and Industry Group Index (the Hemscott Index).

The chart displayed below is presented in accordance with SEC requirements. The graph assumes a $100 investment made on July 1, 2005 and the reinvestment of all dividends. Stockholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future performance.

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Recent Sales of Unregistered Securities

During the fiscal year ended June 30, 2010, other than as described below, 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 May 14, 2010, 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 was used for acquisitions, 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.

On October 14, 2009, the Company entered into a Purchase and Sale Agreement (the “Nautilus Purchase Agreement”), dated October 15, 2009, with White Bear LLC, a Montana limited liability company (“White Bear”) and YEP I, SICAV-FIS, a Luxembourg entity (“the YEP I Fund”, and collectively with White Bear, the “Sellers”) and simultaneously closed the transactions described therein. Under the Nautilus Purchase Agreement, the Company has acquired from the Sellers an 83.5% controlling ownership interest in Nautilus Poplar, LLC, a Montana limited liability company. The Company paid gross $10.9 million for the controlling interest in Nautilus Poplar, comprised of a cash payment totaling approximately $7.3 million and the issuance of 1.7 million new shares of Company’s common stock, par value $.01 per share (the “Common Stock”), valued by the parties at $2,380,000 (or $1.40 per share), with an adjustment for $1.2 million of net debt. The shares sold to the ECP Fund, SICAV-FIS in the private placement pursuant to the Nautilus Purchase Agreement were not been 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 SEC or an available exemption from the applicable federal and state registration requirements. The Company replied upon the exemption from the registration requirements of the Securities Act provided by Regulation S promulgated under the Securities Act.

On August 5, 2010, the Company entered into a second securities purchase agreement with YEP related to the planned sale of an additional 5,200,000 shares of the Company’s common stock. See Note 18 to the Consolidated Financial Statements in Item 8 — Financial Statements and Supplementary Data.

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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:

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 and book 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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Forward Looking Statements

Our disclosure and analysis in this report contains forward-looking information that involves risks and uncertainties. Our forward-looking statements express our current expectations or forecasts of possible future results or events, including projections of future performance, statements of management’s plans and objectives, future contracts, and forecasts of trends and other matters. Forward-looking statements speak only as of the date of this filing, and we undertake no obligation to update or revise such statements to reflect new circumstances or unanticipated events as they occur. You can identify these statements by the fact that they do not relate strictly to historic or current facts and often use words such as “anticipate”, “estimate”, “expect”, “believe”, “will likely result”, “outlook”, “project” and other words and expressions of similar meaning. No assurance can be given that the results in any forward-looking statements will be achieved and actual results could be affected by one or more factors, which could cause them to differ materially. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Among these risks and uncertainties are the ability of MPAL, with the assistance of the Company, to successfully and timely close the Evans Shoal acquisition, the likelihood and timing of the receipt of proceeds from the YEP private placement transaction due to conditions stipulated in the Securities Purchase Agreement, the ability of the Company to successfully develop a strategy for methanol development, pricing and production levels from the properties in which Magellan and MPAL have interests, the extent of the recoverable reserves at those properties, the profitable integration of acquired businesses, including Nautilus Poplar LLC, 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. Any forward-looking information provided in this report should be considered with these factors in mind. Magellan assumes no obligation to update any forward-looking statements contained in this report, whether as a result of new information, future events or otherwise.

Executive Summary

Overview

MPC is engaged in the sale of oil and gas resulting from the exploration for and development of oil and gas reserves. Magellan’s most significant assets are its 100% equity ownership interest in MPAL and its 83.7% interest, through its ownership of Nautilus and directly, Poplar LLC in all zones surface to deep at the Poplar Dome fields, Roosevelt Co., Montana. MPAL also has signed an agreement to acquire a 40% equity interest in the Evans Shoal gas field, offshore Northern Territory, Australia. Magellan and MPAL also hold various override and working interest holdings elsewhere in the United Kingdom and in Canada.

Mission and Strategy

Magellan’s mission is to provide substantial growth and long-term value to stockholders by acquiring, developing and producing oil and natural gas resources using the following strategies to achieve this mission:

The Company has assembled a management team with over 100 man years of large oil-company experience to accomplish this mission. In 2009, Magellan added two assets to its portfolio; Poplar Oil Fields in Montana with CO₂ tertiary recovery potential and a contract to purchase a 40% interest in the Evans Shoal Natural Gas Field in offshore Darwin, Australia that may ultimately be developed into a world class Methanol project. These “under exploited” assets will provide the foundation of the Company and lead earnings and create opportunities for future growth through acquisitions and development of neighboring fields.

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The success of these strategies are shaped by emerging trends in the global energy industry that will have long term effects on the value of Magellan’s business model:

The team at Magellan is dedicated to understanding these trends as well as capitalizing on its extensive experience, innovative approach to problem solving, and determination to successfully grow a unique oil and gas company moving in a new direction.

Overview of our FY 2010 Financial Results

Magellan realized a 44% decrease in gas sales volume this fiscal year due to the term end of the Mereenie Sales Agreement resulting in year end June 30, 2010 gas sales of $13.6 million (net of royalties) or 48% of total revenues for the year ended June 30, 2010 and was offset by a 43% increase in the average price per mcf.

Magellan also saw a 36% decrease in oil sales volume due to the sale of Cooper Basin assets and a 9% decrease in average price per barrel partially offset by the purchase of Nautilus Poplar and the Poplar Oil Fields resulting in $2.6 million of total $9.9 million in oil sales.

For the year, Magellan recorded a net loss of $1.4 million on total revenues of $28.5 million. The following items impacted our 2010 earnings and cash flow as compared to 2009:

The net loss in fiscal year 2010 income was largely the result of the term end of the Mereenie Sales Agreement. Moving forward, Magellan is looking to develop the Poplar Fields and, after MPAL completes its planned acquisition of a 40% interest, the Evans Shoal Gas Field to increase cash flows and provide significant growth opportunities to shareholders. Magellan will incur significant capital obligations for Poplar development and the remainder of the Evans Shoal acquisition and development. The Company intends to raise the capital requirements through equity financing in the near term, to include the Securities Purchase Agreement with its largest stockholder, Young Energy Prize S.A. (“YEP”), executed on August 5, 2010. The placement involves the issuance and sale of up to 5.2 million new shares of the Company’s common stock to YEP and/or one or more of its affiliates in return for $3.00 per new share issued and sold. YEP’s share price for this transaction is indicative of our largest stockholder’s confidence in the pending Evans Shoal acquisition and our other projects, as the Company continues to build substantial stockholder value.

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Operational Results

Australia

MPC’s Australia production volumes, net of royalties, were 2.9 BCF of gas and 97,000 Bbls of Oil for year ended June 30, 2010 or 56% of total gas production and 63% of total oil production for the year ended June 30, 2009.

Mereenie: Natural gas takes at Mereenie were significantly reduced in the third and fourth fiscal quarters. Under the provisions of the MSA4 Sales Agreement, given the low take levels, the Mereenie Producers advised PWC that pursuant to the terms of the Agreement, Mereenie Producer obligations to PWC under the current MSA4 Agreement ceased effective on September 5, 2010. Significant remaining gas reserves, not yet committed to market, are seen as a viable fuel gas option in the construction of a large, new Methanol complex in Darwin using Evans Shoal feed gas.

Palm Valley: The Palm Valley Darwin gas sales contract expires in the year 2012. The Palm Valley local sales contract expires in January 2012. The Company is making strong efforts to dedicate remaining natural gas to area buyers under “life of remaining reserves” agreement(s).

Evans Shoal (NT/P48): Magellan agreed to purchase a significant interest in an already discovered, Evans Shoal natural gas field, offshore Australia. On March 25, 2010, MPAL executed an agreement with Santos to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48), located in the Bonaparte Basin offshore Northern Australia. Under the agreement, Magellan paid a deposit of AU$15 million and is obligated to pay Santos time-staged cash consideration equal to AUS $100 million for its interest in Evans Shoal. Magellan is also required to pay additional contingent payments to Santos of AUS $50 million upon a favorable partner vote on any final investment decision to develop Evans Shoal and AUS $50 million upon first stabilized gas production from NT/P 48. Closing and completion of the purchase is expected to occur in December 2010.

NT09-1: In March, Magellan accepted an offer from the Commonwealth — Northern Territory Offshore Petroleum Joint Authority for the grant of an exploration permit for petroleum over Area NT09-1 offshore Northern Territory. The area is located 220 kilometers (137 miles) northwest of Darwin. The permit covers 6,305 square kilometers (2,434 square miles). It is seen as a good fit with Magellan’s stated gas development strategy. We believe an important structural closure exists within this license area and are anxious to initiate a technical work program to study the area’s potential. Commercially, any gas that can be found in NT09-1 will yield incremental economics for development through Evans Shoal and will offset our neighbors at Caldita to the north.

Montana

MPC’s Poplar Fields oil production for this fiscal year was 36,553 Bbls net to Magellan at an average price of $67.88/Bbl for year ended June 30, 2010.

Poplar Fields: On October 15, 2009, the Company acquired an 83.5% controlling interest in Nautilus. Nautilus, based in Denver, Colorado, owns and operates oil development assets in Roosevelt County, Montana known as the East Poplar Unit and the Northwest Poplar Field. On March 15, 2010, Magellan consolidated interests at the Poplar Fields by purchasing Hunter Energy’s 25.05% average working interests and an additional 1.25% of Nautilus Technical Group’s working interest. Magellan, itself and through its subsidiaries, now owns an 83.7% average working interest there.

Magellan has begun work with an intermediary to farm-out a share of our 23,000 acres Bakken position within the Poplar Fields.

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Magellan, through Nautilus, will drill at least two targeted development wells (in the fall of 2010) to test wettability development strategies for the Tyler and Nisku oil formations. The Company will gain benefit from these wells by testing all of the producing formations on the way to the deeper Nisku formation for reservoir quality, producing capacity given new drilling technology, and for other pertinent reservoir data.

We will also conclude Single Well Tracer tests for residual oil saturation within the Mississippian Charles formation(s). This will allow us to determine the applicability of tertiary oil recovery strategies — including, but not limited to, carbon dioxide flooding. Furthermore, we will initiate work on a shallow natural gas development program involving a large industrial buyer wishing to restart operations in Canada.

United Kingdom

After significant weather delays in the winter of 2010 and ongoing discussions with Northern Petroleum, the Operator of the Markwells Wood and Havant wells, onshore Weald Basin, UK, these wells are expected to spud in the fall of 2010. While site preparation had been completed, projected drilling costs were higher than anticipated. Active discussions and focused work by the Operator, Northern Petroleum, yielded a cost that all parties found acceptable and the wells are planned to proceed. Markwells Wood is a promising offset location to the adjacent producing Horndean oil field. While there remains reservoir risk with the project, we are optimistic that surface proceedings have been concluded to all interested parties satisfaction with the well spud to occur as soon as is practical. Although this drilling program is not core to the Company’s long-term strategy, it is important that these wells are finally drilled to the satisfaction of all parties involved.

Magellan has a gross 240,000 acre Weald Basin position in Southern England, U.K., is a newer, less mature shale play, where Magellan is a 50% partner with Celtique Energie. The Weald Basin shale play is unexplored and is based on the Lower Jurassic (Liassic) shale which lies in both the oil and gas window. There are currently no producing wells in the license area; however, with the recent developments in shale development technology, coupled with the Basin’s proximity to UK and NW European oil and gas markets and infrastructure, these licenses are an attractive opportunity for near term development. The Company’s goal is to establish near-term monetization and strategic drilling programs for UK shale acreage.

Critical Accounting Estimates

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 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

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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.

Historically, we have adjusted our depletion rates during the year when new reserve information is available. For the year ended June 30, 2010, we adopted the new SEC accounting and disclosure regulations for oil and gas companies effective June 30, 2010. The change in price encompassed in the new SEC rules is a change in accounting principle inseparable from a change in estimate for 2009 and will be accounted for prospectively. The price used under the new rules is a 12 month average price on the first day of the month for the 12 month reporting period. The price used in prior periods was the price on the last day of the reporting period. There was no measurable difference in the two prices and as such there was no material dollar impact caused by the change.

Nondepletable assets

At June 30, 2010 and 2009 oil and gas properties include $4.3 million and $6.6 million respectively, of capitalized costs that are currently not being depleted. Components of these costs are as follows:

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Goodwill

As of June 30, 2010, we have $4,695,206 of goodwill of which $674,500 is attributable to the October 15, 2009 acquisition of Nautilus. We have determined the annual impairment testing date to be October 1 for Nautilus.

$4,020,706 of our goodwill is related to the fiscal 2006 acquisition of the 44.87% of MPAL that we did not own at the time. 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 perform our annual impairment testing as of June 30 on this goodwill. 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. As of June 30, 2010, no impairment existed as the adjusted fair value exceeded the carrying value by 19%.

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.

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

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.

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Income Taxes

The Company follows the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered.

The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. There are no significant uncertain tax positions for fiscal 2010 and 2009.

Business combinations

The Company applies the acquisition method of recording business combinations. Under this method, the Company recognizes and measures the fair value of identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree. Any goodwill or gain is identified and recorded. We engaged an independent valuation consultant to assist us in determining the fair values of crude oil and natural gas properties acquired, and other third-party consultants as needed to assist us in assessing the fair value of other assets and liabilities assumed. This valuation requires management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

Liquidity and Capital Resources

At June 30, 2010, the Company on a consolidated basis had approximately $33.6 million of cash and cash equivalents. 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 $18.0 million as of June 30, 2010 and the remaining $15.6 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 48% of the cash and cash equivalent balance.

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 $2.1 million during the year ended June 30, 2010 compared to a $637,000 decrease in those balances during the year ended June 30, 2009.

The factors favorably impacting our liquidity and capital resources during the year ended June 30, 2010 included:

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Factors contributing to a decrease in our liquidity and capital resources during the year ended June 30, 2010 included:

Cash provided by operating activities for the year ended June 30, 2010 decreased $6.0 million from the year ended June 30, 2009 as discussed below:

Cash from revenues increased approximately $1.8 million over the prior year.

Australian oil and gas sales volume decreased resulting from the sale of Cooper Basin, natural declines and significantly reduced sales to PWC were bolstered by oil sales volumes from Nautilus Poplar. Gas sales benefited from a 43% net increase in price per mcf while oil sales were unfavorably affected by a 10% net decrease in price per barrel in Australia. In addition, accounts receivable decreased due to reduced billings at June 30, 2010 relating to the cessation of Mereenie gas sales to PWC in mid/late February, 2010 creating a net increase in collections over the prior year. Cash from revenues also benefited from an 18% increase in the average exchange rate.

Operating cash outflows increased approximately $7.2 million over the prior year due to the following:

Our cash position was unfavorably affected, when compared to the same period in the prior year by the decrease of exchange rate changes on cash and cash equivalents of $1.2 million resulting from a weakened Australian dollar and an approximately $460,000 foreign exchange transaction loss.

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The Company invested $2.8 million and $2.9 million in oil and gas exploration activities, which includes additions to property and equipment, during years ended June 30, 2010 and 2009, respectively.

Effect of exchange rate changes

The value of the Australian dollar relative to the U.S. dollar increased 7.5% to $0.86 at June 30, 2010 compared to a value of $0.80 at June 30, 2009.

As to MPC

On March 7, 2010, MPAL loaned $4 million to MPC. On June 17, 2009, MPAL loaned $2.4 million to MPC.

On February 18, 2010, MPC extended credit of $1 million to Nautilus. As of June 30, 2010, Nautilus has borrowed $475,000.

On July 9, 2009, MPC completed, pursuant to the terms of a definitive purchase agreement and related amendments, an equity investment in MPC by MPC’s strategic investor, YEP, 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 are being used for acquisitions, working capital and general corporate purposes.

At June 30, 2010 MPC, on an unconsolidated basis, had working capital of $10.5 million. Working capital is comprised of current assets less current liabilities. MPC’s current cash position and any future MPAL dividends will be adequate to meet MPC’s current obligations for the 2011 fiscal year, other than those obligations related to the Evans Shoal agreement, discussed below.

On October 15, 2009, MPC paid $7.3 million in cash for a controlling interest in Nautilus Poplar, LLC. See Note 11 to the consolidated financial statements.

In Montana, the Company has completed a consolidation of interest in the East Poplar Unit and Northwest Poplar Fields, in Roosevelt County Montana. On March 9, 2010, the Company entered into a purchase and sale agreement with Hunter Energy LLC, under which the Company purchased Hunters 25.05% average working interest in those Montana fields, for $3.9 million. In a separate transaction the Company also purchased a 1.25% interest in the same fields for from a different owner, for $240,000. See Note 11 to the consolidated financial statements.

As to MPAL

At June 30, 2010 MPAL had working capital of $25.0 million and has budgeted approximately (AUS) $7.8 million for specific exploration projects in fiscal year 2011 as compared to the (AUS) $1.8 million expended during the year ended June 30, 2010. 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 contract for the sale of Palm Valley gas will expire during fiscal year 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 September 5, 2010 under the provisions of the Mereenie sales Agreement No. 4 (MSA 4). These sales took place into mid/late February, 2010 at which point volumes from the Blacktip field, PWC’s other gas supplier, began to flow in earnest. PWC’s most recent advisory to the Mereenie Producers (Magellan and Santos) states that Mereenie gas was no longer required. Under the provisions of that same MSA4 Sales Agreement, the Mereenie Producers advised PWC that pursuant to the terms of the Agreement, Mereenie Producer obligations to PWC under the current MSA4 Agreement

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ceased effective on September 5, 2010. Unless MPAL is able to sell uncontracted gas, including reasonable endeavors gas not taken by PWC or are successful in its current exploration program, its revenues will continue to be substantially reduced, which will 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. Future oil revenues will be impacted by any volatility in the world price for crude oil. MPAL will strive to optimize operating expenses with any reductions in revenues.

As previously discussed, on March 25, 2010, MPAL executed an agreement with Santos Limited (Santos) to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48), located in the Bonaparte Basin offshore Northern Australia. Under the agreement, Magellan is obligated to pay Santos time-staged cash consideration equal to (AUS) $100 million ) for its interest in Evans Shoal on or before December 25, 2010. Magellan would also pay additional contingent payments to Santos of (AUS) $50 million upon a favorable partner vote on any final investment decision to develop Evans Shoal and (AUS) $50 million upon first stabilized gas production from NT/P 48. Closing and completion of the purchase is subject to regulatory and other approvals and is expected to occur in December 2010. Based on its available cash on hand, and the expected liquidity to be generated from the Company’s Australian and U.S. operations during the remainder of 2010, the Company will need to raise additional debt or equity financing from third parties. The Company is currently working towards new equity financing options to raise sufficient funds to complete the Evans Shoal acquisition and its other requirements for capital resources over the next 12 month period, which are estimated to be approximately (AUS) $85 million. In the event the Company is unable to make the required payment on or before December 25, 2010, under certain circumstances, the Company would forfeit its (AUS) $15 million deposit.

As in the past, MPAL expects to fund its exploration costs other than Evans Shoal 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.

As to Nautilus

On February 18, 2010, MPC extended credit of $1 million to Nautilus. As of June 30, 2010, Nautilus has borrowed $475,000.

At June 30, 2010, Nautilus had working capital of ($342,000). Working capital is comprised of current assets less current liabilities.

At June 30, 2010 Nautilus has debt comprising a note payable of $660,220 and short term borrowings of $470,000 on a letter of credit (LOC), both issued by a bank.

In addition to other projects, Nautilus will begin work with an intermediary to farm-out a share of its 23,000 acres Bakken position within the fields. There has been strong external interest in a farm-in program. This work is now ongoing and we expect to report results within three months.

The Company will also drill at least two targeted development wells (during the fall of 2010) to test wettability development strategies for the Tyler and Nisku oil formations. We will also gain benefit from these wells by testing all of the producing formations on the way to the deeper Nisku formation for reservoir quality, producing capacity given new drilling technology, and for other pertinent reservoir properties.

Funding for these projects will primarily come from bank financing.

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Off Balance Sheet Arrangements

None

Contractual Obligations

The following is a summary of our consolidated contractual obligations at June 30, 2010, in thousands: