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 seasonal,drill any new wells at the demandPoplar 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

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 especially 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):

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 seasonal fluctuationsexpiration 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 weather.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.

(vi) Working Capital Items.

See Item 7 — LiquidityMagellan commenced a drilling and Capital Resourcesdevelopment 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 a discussionEPU 119 in the fall of this information.2011.

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

(vii) MARKETING ACTIVITIES AND CUSTOMERS

Customers.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 pursuingThe last Mereenie 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 commencingcontract terminated 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.September, 2010. As MPAL haswas 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 in2011.

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, 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 salesthat 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 ended June 30, 2010 and $12.4 million (netterm of royalties) or 85% of total sales for the year ended June 30, 2009.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. 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 20102011 were 47.40%66.6% to the Santos group of companies, 14.70%20.2% to the Beach Petroleum group of companies and 9.40%13.2% to Origin Energy Resources and 28.5% to IOR Energy.Resources.

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.Plains Marketing, LP.

(viii) Backlog.CURRENT MARKET CONDITIONS AND COMPETITION

Not applicable.

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

Not applicable.

(x) Competitive Conditions in the Business.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, andequipment. The success of exploitation is also the possibilityability 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.

(xi) Research and Development.Seasonality of Business

Not applicable.Although the Company’s business is not seasonal, the demand for oil and especially gas is subject to seasonal fluctuations in the weather.

(xii) 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, NGLs,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, NGLs,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, 2010,2011, the Company had accrued approximately $9.3$11.4 million for asset retirement obligations for the Mereenie, Palm Valley, Dingo and Poplar fields. SeeField (See Note 4 of the Consolidated Financial Statements under Item 8 — Financial Statements and Supplementary Data.5).

(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.

(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 InformationAVAILABLE 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 athttp://www.magellanpetroleum.com and copies of these documents are available to stockholders, without charge, upon request to Jeffrey Tounge, Investor Relations,Corporate Secretary, Magellan Petroleum Corporation, 7 Custom House Street, 3rd Floor, Portland, Maine 04101 (tel: (207) 619-8500.619-8500). 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”).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 athttp://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 Mereenie fields and / or Nautilus’sNautilus’ Poplar fieldsField 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 cashflowscash 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.

If MPAL’s existingproduction history depended upon long-term gas supply contracts, are terminated orone of which was not renewed, and MPAL’s business could behas been adversely affected.impacted.

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

September 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 pursuingThe last Mereenie 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 commencingcontract terminated in the 2011-2013 timeframe. With Blacktip gas now available, there is strong competition within the market andSeptember, 2010. As MPAL maywas 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 its uncontracted gas, including reasonable endeavors gas not taken by PWC, its revenues will continue to declinehave declined in 2011. Mereenie gas sales were approximately $11.6 million (net of royalties) or 85% of total gas sales for the

In fiscal 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 recentlywe 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 have recently acquired a controlling interest in Nautilus Poplar LLC.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.

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 onat fields located in the U.S. and U.K. may not result in successful discoveries of oil and gas.

During fiscal year 2011, we expect that at least two new wells,2012, the Markwells Wood-1 Havant-1,well, in the Weald Basin in the United Kingdom in which we hold interests, will be drilled in an attemptis 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 North AmericaU.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.

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.

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

As of June 30, 2010,2011, there were 4,347,826 warrants outstanding and 3,880,0005,200,000 stock options outstanding of which 2,230,000 were3,258,332 are fully vested and exercisable. As of that date, there were also 800,0001,270,000 options available for future grants under our 1998 Stock Incentive Plan as amended in MayDecember of 2009.2010 (“Plan”). If all of these options and warrants, which total 9,027,82610,817,826 in the aggregate, wereare awarded and exercised, these shares received would represent approximately 17.24%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

regain compliance with the rule. On September 1, 20102011 the Company’s shares closed at $1.63$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 3942 total employees as of June 30, 2010.2011. Despite thisour 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 createscreate 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

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 in early July 2008 of over $140 per barrel to below $70 per barrel in August 2009, and are backthen up slightly to $76 per barrel as ofin 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 (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

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 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 Nexen, Inc.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.

Our reservesReserves as of June 30, 20102011 have been reported under new SEC Rules.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, 20102011 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, whileWhile the estimates of our proved reserves at June 30, 20102011 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.

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 followThe 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. MagellanThe Company records its proportionate share in its working interest agreementsjoint venture operations 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

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 circumstances where it is probable that additional resources will be developed and contribute to cash flows in the case offuture. 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 gas, which is based indeveloped reserves will be increased to the lesser of the current risk adjusted probable and possible reserves or the newly contracted volumes.quantities. At June 30, 2010,2011, 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. 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,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 U.K.British 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 AustralianU.S. dollar in the future. SinceHowever, at June 30, 2009,2011, the U.S. dollar has slightly strengthenedweakened 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, 20102011 was $1.4$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 U.K. pound sterling.British pounds. Accordingly, any material appreciation of the U.K.British 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.

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