TELLURIAN INC. /DE/ - Annual Report: 2011 (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, 2011

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 $2.87 closing price on December 31, 2010 (the last business day of the most recently completed second quarter) was $120,355,442.

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, 52,552,852 shares outstanding as of September 1, 2011

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2011 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 (“AUD”, “AUS”, “A$”). The exchange rate at September 1, 2011 was approximately (AUD) $1.00 which equaled U.S. $1.07.

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PART I

Items 1 and 2: Business and Properties.

GENERAL OVERVIEW

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. MPC was incorporated in 1957 under the laws of Panama and was reorganized under the laws of Delaware in 1967. At June 30, 2011, MPC has three reporting segments: (1) our 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 28.3% working interest in the East Poplar Unit and Northwest Poplar Field (collectively, the “Poplar Field”) in Montana.

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), one retention license for the Dingo Field (34.3% working interest) and thirteen licenses in the United Kingdom, four of which are operated by MPAL. The Mereenie, Palm Valley, and Dingo 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 65.7% interest in the Dingo field and is the operator of the Mereenie and Dingo fields. MPAL is operator of the Palm Valley field.

On December 4, 2009, the Company announced the sale of all its interests in the Cooper and Maryborough Basins in Australia. The Company subsequently entered into sales agreements to affect the sale of those interests including for the sale of its Authority to Prospect (“ATP”) 613P, ATPA 674P, ATP 732P and ATPA 733P interests which we completed during the year end June 30, 2011. These assets were disposed of because they are non-core to our strategies. See Note 10 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 Poplar Unit and varied interests averaging 57% in the Northwest Poplar Field. MPC owns directly a 28.3% working interest in the Poplar Field. The Poplar Field is comprised of 23,000 combined licensed acres and has an estimated 700 to 800 million barrels of oil in place in the Charles Formation with 52 million barrels recovered to date. The Poplar Field is also being developed for Bakken shale as well as other shallow and deep oil and gas reservoirs. On a consolidated basis, MPC through Nautilus and directly owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011. See Note 13 for further discussion.

MPC ORGANIZATION CHARTS

As of June 30, 2011:

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OIL AND GAS PROPERTIES AND ACTIVITIES

The following map is a summary of oil and gas properties in which the Company has an interest. 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, 2011, MPAL’s share of the Mereenie field proved developed oil reserves was zero. Under the revised rules of the U.S. Securities and Exchange Commission (“SEC”), proved reserves of natural gas cannot be booked for Mereenie until a natural gas sales agreement is completed. Probable developed oil and gas reserves have been booked at Mereenie.

During fiscal 2011, MPAL’s share of oil and condensate sales was approximately 64 MBbls, which is subject to net overriding royalties aggregating 4.06% and the statutory government royalty of 10%.

Prior to June 2009, the oil was transported by means of a 167-mile eight-inch crude oil pipeline flowing eastbound from the field to Brewer Estate, southwest of 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. Beginning with June 2009, service on the pipeline was suspended and the line was idled pending future evaluation. Oil production began direct road transport from the field to the Port Bonython Export Terminal. The cost of transporting the oil to the terminal is borne by the Mereenie Producers. 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. After September 5, 2010, natural gas volumes continued to be produced, were processed for condensate and then cycled back for reinjection into the field. See “Gas Supply Contracts” below.

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On September 14, 2011, Magellan Petroleum (N.T.) Pty Ltd (“Magellan NT”), a wholly owned subsidiary of MPAL, entered into a Sale Agreement (“Santos SA”) with Santos QNT Pty Ltd (“Santos QNT”) and Santos Limited (“Santos Entities”). The Santos SA provides for the transfer of Magellan NT’s 35% interest in the Mereenie oil and gas field to the Santos Entities and the transfer of the Santos entities 47.977% interest in the Palm Valley gas field and the 65.6635% interest in the Dingo gas field to Magellan NT subject to the satisfaction of certain conditions.

The cash consideration payable to Magellan NT is A$25 million plus a bonus amount based on Mereenie future production levels.

Upon completion of the Santos SA, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the anticipated 17 year term of the GSPA.

Palm Valley Gas Field

As of June 30, 2011, 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. Pursuant to the same SEC rules noted for Mereenie above, basing proved developed bookings on gas sales agreement volumes, MPAL’s share of the Palm Valley proved developed reserves was .43 Bcf at June 30, 2011 and is based upon gas contract amounts. During fiscal 2011, MPAL’s share of gas sales was .86 Bcf which is subject to a 10% statutory government royalty and net overriding royalties aggregating 7.31%. Under the current gas sales agreement, 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.

Magellan NT has entered into the Santos SA to receive all of the Santos Entities’ interest in the Palm Valley and Dingo fields with effect July 1, 2011, as described above. Upon completion of the Santos Agreement MPAL will own 100% of the Palm Valley and Dingo gas fields and will have 25.65PJ of gas contracted under the GSPA with the Santos Entities. (See Note 20)

Dingo Gas Field

MPAL has a 34.34% interest in the Dingo gas field which is held under Retention License No. 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.

Magellan NT has entered into the Santos SA to receive all of the Santos Entities’ interest in the Palm Valley and Dingo fields with effect July 1, 2011, as described above. Upon completion of the Santos Agreement MPAL will own 100% of the Palm Valley and Dingo gas fields and will have 25.65PJ of gas contracted under the GSPA with the Santos Entities. (See Note 20)

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 gas contract was adjusted quarterly to reflect changes in the Australian Consumer Price Index. The gas was delivered into the 922-mile Amadeus Basin gas pipeline which was built by an Australian consortium in 1987. Since 1985, there were 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

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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, and September 2010. 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.

Upon completion of the Santos SA, as described above, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the 17 year term of the GSPA.

The term of the GSPA shall commence on the later of Completion under the Sale Agreement, the first delivery of gas under a Concession GSPA or January 16, 2012 (when the existing gas sales agreement for the Palm Valley Gas Field expires) and will expire if the total contract quantity is reached before the expiry of 17 years.

As MPAL was not able to sell its uncontracted gas reserves for the fiscal year 2011, its revenues have declined in 2011. Palm Valley gas sales were approximately $1.8 million (net of royalties) or 100% of total gas sales for the year ended June 30, 2011, $2.1 million (net of royalties) or 15% of total gas sales for the year ended June 30, 2010, and $2.2 million (net of royalties) or 15% of total gas sales for the year ended June 30, 2009. There were no gas sales from Mereenie for the year ended June 30, 2011. There were $11.6 million of gas sales from Mereenie (net of royalties) or 85% of total sales for the year ended June 30, 2010, and $12.4 million (net of royalties) or 85% of total gas sales for the year ended June 30, 2009.

At June 30, 2011, MPAL’s commitment to supply gas under the Palm Valley contract was as follows:

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, in the Bonaparte Basin, offshore Northern Australia. The field was discovered in 1988 and lies in a range of water depths from very shallow to more than 300 feet.

MPAL entered into an agreement with Santos on March 25, 2010 (“Asset Sales Deed”), to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48) (“Evans Shoal Transaction”). Under the Asset Sales Deed, the Company agreed to pay Santos a time-staged cash consideration equal to (AUD) $100 million for its interest in the Evans Shoal field which included a (AUD) $15 million deposit. The Company also agreed to pay additional contingent payments to Santos of (AUD) $50 million upon a favorable partner vote on any final investment decision to develop the Evans Shoal field and a further (AUD) $50 million upon first stabilized gas production from the field. Closing and completion of the purchase was subject to regulatory and other approvals. The Australian Foreign Investment Review Board indicated it had ‘no objection’ to the acquisition of Santos’ interest by MPAL.

The Asset Sales Deed was amended by the January 31, 2011 Deed of Variation (“Amended Asset Sales Deed”) which extended the closing date of the Evans Shoal Transaction through to May 31, 2011 in exchange for (1) MPAL’s release to Santos of the initial (AUD) $15 million escrow deposit payment made towards the closing

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price (“First Escrow Amount”) and (2) an additional (AUD) $10 million escrow account deposit towards the closing price (“Second Escrow Amount”). While the Amended Asset Sales Deed provided that the payment of the Second Escrow Amount would be made in accordance with the terms of the Amended Asset Sales Deed which provided certain defined circumstances under which MPAL was entitled to reimbursement of the deposit, the Amended Asset Sales Deed re-classified the First Escrow Amount as non-refundable.

On July 21, 2011, Santos and MPAL executed a Release Agreement to (1) terminate the Amended Asset Sales Deed and (2) resolve all outstanding issues relating to the Amended Asset Sales Deed. Under the Release Agreement, MPAL received back the Second Escrow Deposit, plus all interest accrued on that deposit from the date of deposit to the date of release and the parties agreed to mutually release each other from all claims arising out of the Asset Sales Deed and the Evans Shoal Transaction. As a result, the A$15 million deposit was written off.

In connection with the unwinding of the Evans Shoal Transaction, the Company and Santos executed agreements to transfer their interests in the Amadeus licenses with a resulting ownership interest by the Company of 100% of the Palm Valley and Dingo gas fields. (See Note 20)

LICENSES AND PERMITS

MPAL has interests directly and indirectly in the following permits. Permit holders are generally required to carry out agreed work and expenditure programs. (See Note 16)

Petroleum permits issued by the Northern Territory of Australia 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.

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Bonaparte Basin

The Commonwealth – Northern Territory Offshore Petroleum Joint Authority granted Exploration Permit for Petroleum NT/P82 to the Company (100% interest) over Area NT09-1. 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.

Magellan undertook the reprocessing of 2,061 miles of existing 2D seismic data during the first year of the permit and planning has commenced to undertake the acquisition of 62 miles of 2D and 46 square miles of 3D seismic data during the second permit year. Acquisition of the seismic surveys is planned for the first quarter of 2012. At June 30, 2011, MPAL’s share of the work obligations committed for the NT/P82 permit was $1,798,000.

Maryborough Basin

MPAL held a 100% interest in exploration permit ATP 613P in the Maryborough Basin in Queensland, Australia. MPAL (100%) also has applications pending for permits ATP 674P and ATP 733P which are adjacent to ATP 613P. The Company was granted the previously excluded areas of ATP 613P in September 2010 and is waiting on the grant of ATP 674P and ATP 733P by the Queensland Government.

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 coal seam gas exploration wells in 2007 which intersected multiple thin coal seams. 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, ATP 733P and ATP 674P. The transaction with Adelaide Energy closed on November 30, 2010 following the grant of the ATP 613P excluded areas. ATP 674P and ATP 733P will be transferred to Adelaide Energy following their grant.

UNITED KINGDOM

PEDL 125 & PEDL 126 (Markwells-1)

Effective July 1, 2003, MPAL acquired two Petroleum Exploration and Development Licenses (“PEDL”), 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 terms of both PEDL’s were extended by the Government; PEDL 126 will expire in June 2015 and PEDL 125 in June 2012. A PEDL will be extended past the end of its 11-year exploration term for a further 20-year production term if a development plan for production is approved by the Government.

The South Downs National Park was established by the Government in April 2011 over a 636 square mile area in southern England including parts of PEDL 125 and PEDL 126. Any petroleum development with the South Downs Nation Park must comply with the park’s Planning Policy. The Department of Energy supports the exploration and production of onshore oil and gas in line with its stated aim to maximize the economic recovery of UK’s oil and gas reserves, taking full account of environmental, social and economic objectives.

The Company participated in the Markwells Wood-1 exploration well in PEDL 126, which spudded in November 2010. Northern Petroleum is operator of the PEDL 126 joint venture. Markwells Wood-1 well

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targeted the eastward extension of the Horndean oil field which is currently producing from the Great Oolite Formation. Assessment of the well logs confirmed that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil-bearing above the Horndean field oil-water contact of 4,446 ft sub-sea level.

The presence of mobile (‘live’) oil was observed in 30 feet of core in the upper section of the Great Oolite. Analysis of the logs indicate the well, which was deviated at an inclination of approximately 56 degrees through the Great Oolite, penetrated a gross hydrocarbon bearing interval of 275 ft with a calculated net reservoir of 192 ft with an average porosity of 13-14%; a typical porosity value for this reservoir in the nearby fields in the same formation. Northern Petroleum started operations for an extended well test of the Markwells Wood oil discovery in West Sussex, with the arrival of a workover rig on September 6, 2011. The test will enable the joint venture partners to evaluate the potential and scheme for future development of the Markwells Wood oil accumulation.

At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 125 and PEDL 126 licenses totaled $1,805,000.

PEDL 153, PEDL 154, PEDL 155 & PEDL 256

Effective October 1, 2004, MPAL acquired three licenses, 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 under consideration. The initial exploration term of PEDL 155 was extended for a further four years and will expire on September 30, 2015. PEDL 153 and PEDL 154 terminated on September 30, 2010. The U.K. Company, Egdon Resources, 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. 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 venture partners 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, 2011, MPAL’s share of the work obligations committed for the PEDL 155 & PEDL 256 licenses was $1,429,000.

PEDL 231, PEDL 232, PEDL 234 & PEDL 243

Effective July 1, 2008, MPAL (50%) and its joint venture partner, Celtique Energie, 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. Celtique Energie, operator of the four joint ventures, will acquire 109 miles of 2D seismic data in PEDL 231, PEDL 234 and PEDL 243 during the fall of 2011 to more closely define drilling prospects identified from the existing seismic data, which will fulfill the firm work obligations under the licenses. At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 231, PEDL 232, PEDL 234 & PEDL 243 licenses was $1,456,000.

PEDL 135, PEDL 137, PEDL 242 & PEDL 246

Effective October 1, 2004, MPAL was granted 100% interest in PEDL 135, 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 licenses; each with a six year initial term. The initial exploration term of each of PEDL 135 and PEDL 137 has been extended to September 30, 2012. PEDL 136

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expired on September 30, 2010. Each license 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. At June 30, 2011, MPAL’s share of the work obligations committed for the PEDL 135, PEDL 137, PEDL 242 and PEDL 246 licenses was $149,000.

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, 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 was surrendered in May 2011 towards the end of its 11-year term. Effective July 1, 2008, MPAL and its joint venture partners were granted PEDL 240 (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, 2011, MPAL’s share of the work obligations committed for the PEDL was $38,000.

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 a majority interest in and operates the Poplar Field in Roosevelt County, Montana. The controlling interest in Nautilus was purchased from White Bear, LLC and ECP Fund, SICAV-FIS (formerly, YEP I, SICAV- FIS) entities affiliated with Nikolay Bogachev and J. Thomas Wilson, two directors of the Company.

MPC also completed a consolidation of interests in the Poplar Field by purchasing a 25.05% average working interest from Hunter Energy, LLC and a 3.25% average working interest from Nautilus Technical Group, LLC in March 2010. On a consolidated basis, MPC, through Nautilus and directly, owned an average 85.7% working interest in the Poplar Fields in Montana as of June 30, 2011.

The Poplar Field was discovered and developed in 1954 by Murphy Oil Company. The Field, with 23,000 combined licensed acres, has an estimated 700-800 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) has embarked on an active development program utilizing both 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.

For the year end June 30, 2011, the Poplar Field produced approximately 86 MBbls with approximately 35 active wells producing from the Charles Formation. During June 30, 2011, MPC’s share of oil sales was approximately 68 MBbls, which is net of royalties and overriding royalties averaging 21%. At June 30, 2011, MPC’s share of the Poplar Field proved oil reserves was approximately 9,190 MBbls.

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.

On September 2, 2011, the Company signed and closed a Purchase and Sale Agreement with the owners of Nautilus Technical Group LLC, (“Nautilus Technical”), and Eastern Rider LLC, (“Eastern Rider”), (collectively

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the “Sellers”), resulting in the Company owning 100% of Nautilus Poplar and, directly or indirectly through Nautilus, a 100% working interest in the Poplar Field, aside from certain working interest owners in the Northwest Poplar fields. (See Note 20)

On September 7, 2011 the Company and VAALCO Energy (USA) Inc. (“VAALCO”) signed a definitive Lease Purchase and Sale Agreement (the “VAALCO LPSA”). VAALCO also agreed to drill three wells, at its sole expense as operator, to the Bakken formation and to formations below the Bakken (the “Deep Intervals”) in Poplar Field. Upon completion of three (3) new wells in the Deep Intervals of the Poplar Field, VAALCO will earn a 65% working interest in the Deep Intervals within the Poplar Field. One well will be spud on or before June 1, 2012 and the second and third will be spud on or before December 31, 2012. One well will be drilled horizontally to test the Bakken Formation, one well will be drilled vertically to test the Red River Formation, and a third will be targeted at VAALCO’s discretion.

The Company will retain a 35% working interest in the Deep Intervals and will continue to hold its current interest in all formations above the Bakken formation, including the currently producing Charles and Tyler formations where all Poplar proved and probable reserves are located.

The Company has initiated a program in late summer 2011 to undertake seven recompletions along with the completion of the East Poplar Unit (“EPU”) 119 drilled last fall into the Charles Formation. Magellan also plans to drill one shallow natural gas well in fall of 2011 to evaluate significant reservoir pressure differentials seen in the shallow gas horizon during the drilling of the EPU119 well.

A second drilling program, including up to three new infill wells in the Charles Formation, is planned for the fall of 2011. Drilling will be based upon the results from the recompletion program with the objective of increased production resulting in increased cash generation amid high oil price netbacks.

Given the complexity of the Poplar reservoir, the Company has completed the first steps of a reservoir engineering study for the Charles Formation. Further work is being conducted to manage and monitor water influx, determine new high potential drilling sites, and to determine the merit of an infill program.

RESERVES

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 19.

A summary of our estimated proved, probable and possible reserves as of June 30, 2011 are set forth in the table below. The table shows reserves on an Mboe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio.

Summary of Oil and Gas Reserves as of June 30, 2011 Fiscal Year End

Based on Average Fiscal-Year Prices

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Information regarding changes in estimated reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 19.

Proved Undeveloped Reserves

MPC first recorded these Proved Undeveloped reserves related to the Poplar Field at June 30, 2010.

In the United States, Magellan commenced a drilling and development program in the Poplar Field with the EPU 119 that reached a depth of 7,137 feet on October 18, 2010. Well results to-date, while under further evaluation, yielded a broad stack of hydrocarbon-bearing formations from 692 feet all the way to total vertical depth of 7,137 feet. A Charles Formation core (the current producing formation) was completed and is currently under analysis. A Bakken and Three Forks core was also successfully obtained and analyzed, where it was found that the Bakken is over pressured and mature, with oil and gas saturation, and substantial fracturing and fair to good porosity. The EPU119 well was targeting possible reserve volumes in the Nisku Formation and failed to produce commercially viable quantities of oil. However, EPU 119 did encounter hydrocarbons up hole of the Nisku Formation in the Charles Formation as seen on the well logs and in the core. Completion work is currently planned for EPU 119 in the fall of 2011. Other than the EPU 119, the Company did not drill any new wells at the Poplar Field during this reporting period. The Company has a drilling program planned for the fall of 2011 to drill up to three new wells in the Charles Formation targeting proven undeveloped reserves. Since the program is relatively new to the Company, there is no recent experience of converting proved undeveloped reserves to proved developed reserves.

In Australia, the Company has no recent experience of converting possible reserves to probable reserves and probable reserves to proved reserves. In Australia, our possible and probable oil reserves relate to the Mereenie Field in Northern Territory, where there has not been any drilling since 2004.

Preparation of Oil and Gas Reserve Information

Proved reserves. Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Probable reserves. Estimates of probable developed and undeveloped reserves are inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate that is as likely as not to be achieved. Estimates of probable reserves are also continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible reserves. Estimates of possible developed and undeveloped reserves are also inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. Possible reserves may be assigned to areas

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of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geo-science and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geo-science and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

PRODUCTION VOLUMES, PRICES AND COSTS

MPC’s production volumes, net of royalties, average sales prices and average production costs for oil and gas during the three years ended June 30, 2011, 2010, 2009 are as follows (data for Canada has not been included since MPC is in a carried interest position and the data is not material):

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PRODUCTIVE WELLS

Productive wells at June 30, 2011 were as follows:

ACREAGE

The following table summarizes gross and net developed and undeveloped acreage by geographic area at June 30, 2011. Net acreage is our percentage ownership of gross acreage. Acreage in which our interest is limited to royalty or overriding royalty is excluded.

Of the total undeveloped acreage (2.3 million gross, 1.9 million net), as of June 30, 2011, the portion of our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 4% in 2012, 0% in 2013 and 11% in 2014.

DRILLING ACTIVITY

There were two wells in process at June 30, 2011.

The Company has a 40% interest in the Markwells Wood-1 exploration well in PEDL 126, which spudded in November 2010. Northern Petroleum is operator of the PEDL 126 joint venture. Markwells Wood-1 well targeted the eastward extension of the Horndean oil field which is currently producing from the Great Oolite Formation. Assessment of the well logs confirmed that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil-bearing above the Horndean field oil-water contact of 4,446 ft sub-sea level. Northern Petroleum started operations for an extended well test of the Markwells Wood oil discovery, with the arrival of a workover rig on September 6, 2011. The test will enable the joint venture partners to evaluate the potential and scheme for future development of the Markwells Wood oil accumulation.

Magellan commenced a drilling and development program in the Poplar Field, with the EPU 119 that reached a depth of 7,137 feet on October 18, 2010. Well results to-date, while under further evaluation, yielded a broad stack of hydrocarbon-bearing formations from 692 feet all the way to current depth. The deepest target, the Nisku Formation, proved to be non-commercial and the well will be recompleted up hole in the Charles. Completion work is currently planned for EPU 119 in the fall of 2011.

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

MARKETING ACTIVITIES AND CUSTOMERS

Customers

Although MPAL’s producing oil and gas properties are located in a remote area in central Australia, 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. The last Mereenie gas sales contract terminated in September, 2010. As MPAL was not able to sell its uncontracted gas, its revenues have declined in 2011.

However, upon completion of the Santos SA, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”) with the Santos Entities on September 14, 2011, that provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65PJ over the anticipated 17 year term of the GSPA.

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. Oil sales during fiscal 2011 were 66.6% to the Santos group of companies, 20.2% to the Beach Petroleum group of companies and 13.2% to Origin Energy Resources.

Nautilus — Presently all of the oil production from the Poplar Field is being trucked to a terminal in Reserve, MT and sold to Plains Marketing, LP.

CURRENT MARKET CONDITIONS AND COMPETITION

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 and the availability of equipment. The success of exploitation is also the ability to avoid or minimize the effect 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.

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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.

SEGMENT INFORMATION

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, MPAL, and its 83.5% controlling member interest in Nautilus, as of June  30, 2011. See Note 15.

EMPLOYEES

Number of Persons Employed by Company.

As of fiscal year ended June 30, 2011 the Company had 42 total employees. MPC had 8 employees and Nautilus had 12 employees in the United States. At that date, MPAL had 22 employees in Australia.

REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS

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, natural gas liquids, 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, natural gas liquids, 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 fiscal year ended June 30, 2011, the Company had accrued approximately $11.4 million for asset retirement obligations for the Mereenie, Palm Valley, Dingo and Poplar Field (See Note 5).

Financial Information Relating to Foreign and Domestic Operations.

See Note 15 and Note 19.

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

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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.

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, Corporate Secretary, 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 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 field and Nautilus’ Poplar Field 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 cash flows 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.

MPAL’s production history depended upon long-term gas supply contracts, one of which was not renewed, and MPAL’s business has been adversely impacted.

MPAL’s financial performance and cash flows have historically been dependent upon its Palm Valley and Mereenie 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

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September 2009, is to supply the gas from its Blacktip field offshore of the Northern Territory. 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. The last Mereenie gas sales contract terminated in September, 2010. As MPAL was not able to sell its uncontracted gas, its revenues have declined in 2011.

In fiscal year 2010, we 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, in October 2009, we acquired a controlling interest in Nautilus. 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.

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

During fiscal year 2012, the Markwells Wood-1 well, in the Weald Basin United Kingdom in which we hold interests, is currently being production tested to recover oil and gas in commercially viable quantities. On October 18, 2010, Magellan commenced a drilling and development program in Poplar Field, with the EPU 119. Completion work is currently planned in the fall of 2011. 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 U.S. 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.

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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 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.

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 incentive plan and our outstanding warrants and shareholders may be adversely affected by the issuance of those shares.

As of June 30, 2011, there were 4,347,826 warrants outstanding and 5,200,000 stock options outstanding of which 3,258,332 are fully vested and exercisable. As of that date, there were also 1,270,000 options available for future grants under our 1998 Stock Incentive Plan as amended in December of 2010 (“Plan”). If all of these options and warrants, which total 10,817,826 in the aggregate, are awarded and exercised, shares received would represent approximately 21% 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

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regain compliance with the rule. On September 1, 2011 the Company’s shares closed at $1.55 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 42 total employees as of June 30, 2011. Despite our increase in employment relative to prior years, 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 create 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.

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

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caused by a recession would likely reduce worldwide demand for energy and result in lower oil and natural gas prices. Oil prices declined from previous years’ record levels to below $70 per barrel in August 2009, then up slightly to $76 per barrel in September 2010 and $82 per barrel in August 2011, 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 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. 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.

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 gas companies. Many of our 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.

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We depend on one purchaser for a substantial portion of our revenue in the United States. 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 Plains Marketing, LP. as the sole customer for its oil produced in Montana. If Nautilus’ sole customer reduces or discontinues its business with us, or if we are not able to successfully negotiate a replacement contract with our sole customer after the expiration of such contract, or if the replacement contract is on less favorable terms, the effect on us could be adverse if we were not able to locate new customers to purchase the oil produced at the Poplar Field. In addition, if Nautilus’ sole customer was to experience financial difficulties or any deterioration in its ability to satisfy its obligations to us, our cash flow from the Poplar Field could be adversely affected.

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 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.

Reserves as of June 30, 2011 have been reported under SEC rules. The estimates provided in accordance with the 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, 2011 as prepared consistent with our independent reserve engineers’ interpretations of the SEC rules relating to disclosures of estimated natural gas and oil reserves. These rules require SEC reporting companies to prepare their reserve estimates using

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reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. While the estimates of our proved reserves at June 30, 2011 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the 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 SEC rules.

Another impact of the 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.

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:

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

The Company follows 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. 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, 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 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. 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, future undiscounted cash flows were based upon the quantities of gas currently committed to the current contract and estimated sales subsequent to the contract. If such new contracts are affected, the proved developed reserves will be increased to the lesser of the current risk adjusted probable and possible reserves or the newly contracted quantities. At June 30, 2011, 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. 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

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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. economy, 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.

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 British pound, have changed in recent periods and may fluctuate substantially in the future. We expect that a majority of our revenue will be generated in the U.S. dollar in the future. However, at June 30, 2011, the U.S. dollar has weakened 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, 2011 was $9.2 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 British pounds. Accordingly, any material appreciation of the British pound against the Australian dollar could have a negative impact on our business, operating results and financial condition.

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None

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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:

(b) Approximate Number of Holders of Common Stock at September 1, 2011

(c) Frequency and Amount of Dividends

MPC has never paid a cash dividend on its common stock. The Company does not intend to pay cash dividends in the foreseeable future.

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(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 Composite Index, a broad equity market index, and Morningstar Oil and Gas E&P Industry Index Morningstar Industry Index (“Morningstar Industry Index”), an industry group index.

The chart displayed below is presented in accordance with SEC requirements. The graph assumes a $100 investment made on July 1, 2006 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.

The Hemscott Oil & Gas Index, the industry group index formally used in the MPET graph is no longer available due to Morningstar’s acquisition of Hemscott, and it has been replaced in the performance graph with Morningstar’s Oil and Gas E&P Industry index, an index deemed to be the closest fit by composition and construction.

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Recent Sales of Unregistered Securities

As previously disclosed in the Company’s 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 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 as well as, 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 are not registered under the Securities Act of 1933, as amended (“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. In the Purchase Agreement, YEP represents 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 will acquire 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 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 acquired from the Sellers an 83.5% controlling ownership interest in Nautilus, a Montana limited liability company. The Company paid gross $10.9 million for the controlling interest in Nautilus, comprised of a cash payment totaling approximately $7.3 million and the issuance of 1.7 million new shares of 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. All shares of Common Stock sold pursuant to the Nautilus Purchase Agreement were registered in the name of the YEP I Fund. The shares sold to YEP I Fund in the private placement 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 SEC or an available exemption from the applicable federal and state registration requirements. In the Nautilus Purchase Agreement, YEP I Fund represents 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 will acquire the shares for its own account for investment purposes only and not with a view to or for distributing or reselling the shares 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. The Company relied 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 another Securities Purchase Agreement (the “Second Purchase Agreement”) with YEP, under which the Company agrees to sell, and YEP agrees that YEP and/or one or more of its affiliates (collectively, the “Investor”) will purchase 5,200,000 shares of Common Stock at a purchase price of $3.00 per share, for an aggregate purchase price of $15.6 million (such transaction referred to below as the “Investment Transaction”). Pursuant to the terms of the Second Purchase Agreement, the Company shall use the proceeds from the Investment Transactions to facilitate the closing of the Evans Shoal Transaction. The shares to be issued to the Investor in connection with the Investment Transaction have not been registered under the Securities Act, and may not be offered or sold in the United States in the absence of an effective registration statement or exemption from the registration requirements of the Securities Act. In the Second

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Purchase Agreement, the Investor 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 will acquire the shares for its own account for investment purposes only and not with a view to or for distributing or reselling the shares 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.

On February 11, 2011, the Company and YEP executed a First Amendment to Securities Purchase Agreement (“First Amendment”). The First Amendment provides for a final closing of the Investment Transaction on or before June 15, 2011 to the extent that: (i) the Evans Shoal Transaction does not close as contemplated by the Asset Sales Deed; and (ii) the failure to close the Evans Shoal Transaction results in the failure of the Company to recover an additional $10 million deposit made towards the purchase price set forth of the Asset Sales Deed (the “Deposit Back Stop”). On February 17, 2011, the Company and YEP executed a Second Amendment to Securities Purchase Agreement (“Second Amendment”) to clarify that the Deposit Back Stop set forth in the First Amendment and states that the funding contemplated by the First Amendment would not be withheld to the extent that the Company fails to satisfy any condition precedent set forth in the Second Purchase Agreement if such non-satisfaction is reasonably attributable to the failure to close the Evans Shoal Transaction. Since the Asset Sales Agreement has been terminated and MPAL did receive the $10 million deposit back in July 2011, the Investment Transaction has not closed. The Company and YEP are in the process of terminating the Securities Purchase Agreement as amended by the First and Second Amendments.

Please refer to Note 20 for details of all subsequent events.

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, 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.