10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended June 30, 2012,    or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from        to

Commission file number 1-5507

Magellan Petroleum Corporation

(Exact name of registrant as specified in its charter)

Delaware	06-0842255
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 1950, Denver, CO	80203
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (720) 424-2400

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

Title of Each Class	Name of each exchange on which registered
Common stock, par value $0.01 per share	NASDAQ Capital Market

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

Large accelerated filer o	Accelerated filer o	Non-accelerated filer o	Smaller reporting company þ
		(Do not check if a smaller reporting company)

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 common equity held by non-affiliates of the registrant, based on the $0.968 closing price per share of the registrant's common stock as reported by the NASDAQ Capital Market, as of December 30, 2011 (the last business day of the most recently completed second fiscal quarter) was $41,241,284. For the purpose of this calculation, shares of common stock held by each director and executive officer and by each person who owns ten percent or more of the outstanding shares of common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for any other purpose.

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 $0.01 per share, 53,885,594 shares outstanding as of September 17, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement related to the Annual Meeting of Stockholders for the fiscal year ended June 30, 2012, are incorporated by reference in Part III of this Form 10-K to the extent stated herein.

TABLE OF CONTENTS

ITEM		PAGE
	PART I
ITEMS 1 and 2	BUSINESS AND PROPERTIES	4
	General	4
	Strategy	4
	Significant developments in fiscal year 2012	4
	Outlook for fiscal year 2013	6
	Operations	7
	Reserves	9
	Volumes and realized prices	11
	Productive wells	12
	Drilling activity	12
	Acreage	13
	Titles to property, permits, and licenses	13
	Marketing activities and customers	14
	Current market conditions and competition	15
	Employees and office space	15
	Government regulations	15
	Available information	18
	Non-GAAP financial measures and reconciliation	18
ITEM 1A	RISK FACTORS	19
ITEM 1B	UNRESOLVED STAFF COMMENTS	28
ITEM 3	LEGAL PROCEEDINGS	28
ITEM 4	MINE SAFETY DISCLOSURES	28
	PART II
ITEM 5	MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	29
ITEM 6	SELECTED FINANCIAL DATA	30
ITEM 7	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
	Introduction	31
	Overview of the Company	31
	Summary results of operations for the year ended June 30, 2012	31
	Highlights of operational activities	32
	Acquisitions and divestitures	33
	Other items	34
	Consolidated liquidity and capital resources	34
	Comparison of financial results and trends between fiscal 2012 and 2011	37
	Comparison of financial results and trends between fiscal 2011 and 2010	40
	Off-balance sheet arrangements	43
	Critical accounting policies and estimates	43
	Forward looking statements	45
ITEM 7A	QUANTITATIVE AND QUALITATITVE DISCLOSURES ABOUT MARKET RISK	46
ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	47
ITEM 9	CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	82
ITEM 9A	CONTROLS AND PROCEDURES	82
ITEM 9B	OTHER INFORMATION	84

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	PART III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	84
ITEM 11	EXECUTIVE COMPENSATION	84
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	84
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	85
ITME 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	85
	PART IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	85

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PART 1

ITEMS 1 AND 2: BUSINESS AND PROPERTIES

GENERAL

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we" or "us") is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. The Company conducts its operations through two wholly owned subsidiaries: Nautilus Poplar LLC ("NP"), which owns Poplar, a highly attractive oil field in the Williston Basin; and Magellan Petroleum Australia Limited ("MPAL"), a successful independent oil and gas company in existence since 1964 active in Australia and the United Kingdom.

Magellan was founded in 1957 and incorporated in Delaware in 1967. The Company's common stock has been trading on the NASDAQ since 1972, and trades under the ticker symbol "MPET."

Our principal offices are located at 1775 Sherman Street, Suite 1950, Denver, Colorado, 80203, and our telephone number is (720) 424-2400.

STRATEGY

Our strategy is to enhance shareholder value by maximizing the value of our existing assets. Our portfolio of operations includes several early stage oil and gas exploration and development projects, the successful development of which requires significant capital, as well as engineering, and management resources. We are committed to investing in these projects to establish their technical and economic viability. In turn, we will determine the most efficient way to create value and returns for our shareholders.

SIGNIFICANT DEVELOPMENTS IN FISCAL YEAR 2012

Fiscal year 2012was a year of significant transition for Magellan. We made numerous changes to the structure and operations of our business that we believe have favorably impacted our future ability to generate value for our shareholders. During the year, we have strengthened our balance sheet with a significant cash position, gained full control and operatorship of our core assets, stabilized our operational and administrative platform, and initiated a number of cost saving measures. All of these actions will allow us to fund and execute our strategy to prove the value of our existing assets in an efficient manner.

Financial Performance

During the fiscal year, financial results were significantly negatively impacted by the planned termination of key revenue streams in Australia, namely the Palm Valley long term gas contract and the Amadeus Gas Trust. To address this sharp decline in performance, we have focused our efforts on replacing revenues and addressing our cost base. However, the effect of these initiatives has only marginally impacted the results of fiscal year 2012.

Revenues. For the fiscal year ended June 30, 2012, revenues totaled $13.7 million compared to $18.2 million in the prior year, a decrease of 25%. This decrease was primarily the result of the termination at Palm Valley of the 25-year gas sales contract with Northern Territory Power and Water Corporation ("PWC") (with the 25 year gas sales contract with PWC sometimes hereinafter referred to as the "PWC Contract") during January 2012, the termination of the Amadeus Gas Trust revenue stream during fiscal year 2011, and the sale of Magellan's interests in the Mereenie oil and gas field in May 2012. The termination of both the Amadeus Gas Trust revenue and the PWC Contract had been planned since 1983 and 2006, respectively.

During fiscal year 2012, our share of production at Poplar increased due to a combination of our workover program and the consolidation of our ownership in the leases of Poplar. Moreover, we have entered into a new gas sales contract at Palm Valley, which will ramp up to replace by 2015 the volumes previously sold under the PWC Contract at improved prices.

Net income and EPS. For the fiscal year ended June 30, 2012, net income totaled $26.5 million ($0.49/basic share), compared to a net loss of $32.4 million ($(0.62)/basic share) in the prior year. The increase in net income is primarily the result of closing the Santos SA transaction whereby Magellan sold its interests in Mereenie to Santos and Santos sold its interests in the Palm Valley and Dingo fields to the Company, resulting in a gain on sale of assets of $36.2 million and the tax effect of recording the Company's Australian Petroleum Resource Rent Tax ("PRRT") which was enacted during the fiscal year 2012 and effective from July 1, 2012.

Adjusted EBITDAX. For the fiscal year ended June 30, 2012, Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation under Part 1, Items 1 and 2: Business and Properties) totaled negative$9.7 million, compared to negative

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$4.8 million in the prior year, a change of 103%. This decrease was the result of decreased revenues and increased lease operating expenses, offset by savings of $3.2 million in general and administrative expenses (excluding stock based compensation and foreign transaction loss).

Cash. As of June 30, 2012, Magellan had $41.2 million in cash and cash equivalents as compared to $20.4 million at the end of the prior fiscal year. The increase of $20.8 million was primarily driven by the completion of the Santos SA (see Santos asset swap transaction below), which generated $26.6 million in net cash proceeds for the Company. Our cash balance allows us to pursue our strategy of deploying capital resources towards assessing the potential value of our existing assets and determining the most efficient way to enhance shareholder value.

Rationalization of Asset Portfolio

During the fiscal year, Magellan executed a series of corporate transactions aimed at streamlining our corporate structure and gaining control and operatorship of our core assets.

Consolidation of ownership in Poplar. In the United States, we restructured and fully consolidated our ownership in Poplar (defined below) in September 2011, increasing the Company's economic exposure to the potential upside value of this asset while simplifying processes and procedures relating to accounting, reporting, and capital funding.

Santos asset swap transaction. On May 25, 2012, Magellan Petroleum (N.T.) Pty Ltd ("MPNT"), a wholly owned subsidiary of MPAL, and Santos QNT Pty Ltd and Santos Limited (collectively the "Santos Entities") completed a Sale Agreement (the "Santos SA"), and became the sole owner of the Palm Valley Interests and of the Dingo Interests, while Santos became the sole owner of the Mereenie Interests (see Note 2). As a result, we can now pursue a niche strategy of marketing Amadeus Basin gas to the mining industry in central Australia while reducing both field operating and overhead costs.

Initiation of Strategy to Prove-Up the Value of our Assets

During this past fiscal year, management articulated a strategy to focus on proving up the value of the Company's existing assets as the most economic way of increasing shareholder value. Towards that end, management has begun a number of initiatives to evaluate and determine the potential of the Company's oil and gas properties.

CO₂-EOR at Poplar. In the shallower formations at Poplar, which Magellan 100% owns and operates, management believes that the Charles formation is a potential candidate for a CO₂-enhanced oil recovery project ("CO₂-EOR"). Over the past year, we laid the groundwork for a CO₂-EOR pilot. After completing a detailed 3-D reservoir model earlier in the fiscal year, we commissioned laboratory analyses of oil samples from the Charles formation, the results of which confirm the potential viability of CO₂-EOR in that formation at Poplar. In addition, we have used the EPU 119 well to conduct CO₂ injectivity tests at reservoir conditions, the results of which tests were also favorable.

Other shallow formations of Poplar. Geological and geophysical analyses have led management to believe that there are other shallow formations at Poplar besides the Charles formation that contain significant hydrocarbon resources. In January 2012, Magellan identified a new pool discovery in the Amsden formation with the completion of the EPU 117 well, which has since produced commercial quantities of oil. Management is currently evaluating whether it is more economical to re-complete existing wells at Poplar in the Amsden formation or to drill new wells.

VAALCO farmout. In the United States, we farmed out the deeper intervals at Poplar to VAALCO Energy (USA), Inc. ("VAALCO") in September 2011. Under this arrangement, VAALCO will earn a 65% working interest in those intervals upon completion of three test wells aimed at evaluating the production potential of certain deep formations, in particular the Bakken/Three Forks formation. Magellan is carried 100% for the drilling and completion costs of these three wells and will be entitled to 35% of the gross revenue from the well less its proportionate share of lease burdens and taxes.

Improvements to Operating Assets

Poplar shallow intervals. Much of Poplar's current production is conventional production from the Charles formation generated by wells drilled in the 1950s and 1970s. These wells require significant workovers and maintenance to maintain stable production. Magellan implemented a workover program during the past fiscal year to assess the effectiveness of certain production-enhancing technologies, including stimoil treatments, acid stimulations, and water shut-off treatments. These assessments are ongoing, and have contributed to the increase in lease operating expenses during fiscal year 2012. If they are successful, these production enhancing technologies will be deployed on a broader scale and are expected to improve the production and profitability of the existing wells at Poplar.

Palm Valley. On May 25, 2012, MPNT and the Santos Entities completed the Santos SA, and MPNT became the sole owner of the Palm Valley Interests and of the Dingo Interests, while Santos became the sole owner of the Mereenie Interests, see Note 2. In the Amadeus basin in Australia, in connection with the Santos SA, Magellan executed a long-term sales agreement with Santos to sell substantially all of the remaining gas reserves from Palm Valley. Under this agreement, Magellan now sells gas from Palm Valley to Santos, who on-sells the gas to third party customers. As of June 30, 2012, there were two

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customers receiving gas from Palm Valley. Sales volumes from Palm Valley are expected to increase to approximately 1.5 Bcf per year by fiscal 2015 and are expected to be sold at prices significantly higher than those realized under the former long-term contract with PWC. Magellan also began to implement operational efficiencies at Palm Valley that have allowed for the reduction of field staff from ten to five workers while maintaining good oil and gas field practice.

Implementation of Recurring Cost Savings

During this fiscal year, Magellan reduced its general and administrative expenses (excluding stock based compensation and foreign transaction loss) by $3.2 million, or 23% . This reduction in expenses was primarily due to a $3.0 million reduction in third party consulting expenses, which resulted from reduced transaction expenses and the recruitment of additional staff that allowed us to internalize functions previously outsourced. This investment in human resources will leave the Company better prepared to handle the development of our projects in compliance with applicable laws and regulations. In addition, we have undertaken a number of cost saving initiatives, the positive impact of which in fiscal year 2012 was partially offset by implementation costs. These initiatives will have a greater impact in fiscal year 2013. Among our efforts to reduce costs, we consolidated our Portland, Maine, and Denver, Colorado, offices into a new single headquarters in Denver, Colorado, and we have streamlined our investor relations processes. Through fiscal year 2013, we will continue to implement cost savings initiatives to bring our cost structure more in line with our peers.

Overhaul of Financial and Administrative Functions

Over the past twelve months, management addressed a number of deficiencies and inefficiencies in the financial and administrative functions of the Company. With these issues now resolved, management believes we are better prepared for, and can be fully focused on, implementing our operational plans.

Remediation of material weakness. When the Company published its fiscal year 2011 Form 10-K, management concluded that the Company did not maintain effective internal controls over financial reporting, in particular in the area of the consolidated statement of cash flows and the review of third party expert work for significant, complex, and/or non-routine accounting issues. Management took this finding extremely seriously, and took significant measures to remediate these weaknesses. Management believes that remediating these weaknesses has now been accomplished.

Over the past year, we have also overhauled our accounting systems by bolstering our accounting staff, initiated the implementation of new accounting and land software, improving internal control processes, and reshaping the way we present our consolidated financial statements, to be more in line with industry practice. These efforts are essential to effectively running a business and establishing investor trust in our accounts.

Investor relations. In recent months, we have renewed our investor relations efforts to help the market better understand the intrinsic value of, and to attract a larger institutional following to, our stock. We have changed how we report our consolidated financial statements to be more in line with industry practice, launched a new website with detailed information about our assets, and created a new investor presentation which lays out our projects and milestones.

Relocation of headquarters. Recently we completed the relocation of the Company's headquarters from Portland, Maine, to Denver, Colorado. Consolidating our offices will achieve operational and organizational efficiencies. Basing our Company in an oil and gas hub will allow us to access talented professionals and service providers experienced in oil and gas and increase our exposure to new oil and gas opportunities. Management expects this move will prove critical to our success in growing this business.

OUTLOOK FOR FISCAL YEAR 2013

During fiscal year 2013, Magellan intends to execute on its strategy of proving the potential of its existing assets. We are particularly focused on the four projects below, which we intend to fund through a combination of the Company's cash resources and the risk capital invested by our farmout and joint venture partners.

• Implementing a pilot CO₂-EOR project at Poplar;

• Shooting and processing 3-D seismic over NT/P82, our exploration block offshore Australia; and

• Determining an exploration program for the unconventional formations in our United Kingdom leases.

• Evaluating the potential of, and possibly participating in the development of, the deeper formations at Poplar with our partner, VAALCO;

Management believes that each of these projects has significant potential that, if realized, will change the reserves and underlying value of our stock. Specific steps and milestones for each of these key areas are discussed below. By pursuing these courses of action, management expects that, by the end of fiscal year 2013, the Company will be able to validate and articulate clearly the value potential of its assets and will be able to determine the most appropriate course of action with respect to each

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asset to achieve the best value for its shareholders.

Pilot CO₂-EOR Project

In fiscal year 2013, the Company intends to evaluate the potential of CO₂-EOR in the Charles formation at Poplar by drilling a pilot CO₂-EOR, which consists of five-wells, including one CO₂ injector well and four producing wells. Magellan expects to incur up to $10.0 million in capital costs on these wells. Timing of the drilling of these wells will depend on the permitting process and drilling rig availability. The four producing wells are designed to yield both conventional oil production from the Charles formation and enhanced production as a result of the CO₂-EOR. As such, these four wells will constitute a portion of the wells to be drilled in the projections of our proved undeveloped reserves.

Poplar Deeper Formations

Under the terms of our agreement with VAALCO, VAALCO is required to spud and complete three test wells in the deeper formations at Poplar by December 31, 2012. The second test well, EPU 133-H, was completed as a horizontal well in the Bakken/Three Forks formation in September 2012. VAALCO has announced its intention to drill and complete the third test well as another horizontal well in the Bakken/Three Forks formation. The first test well, the EPU 120, was a vertical well drilled to a depth of 9,251 feet to test certain formations below the Bakken/Three Forks. Following VAALCO's determination that this well had not encountered hydrocarbons in commercial quantities, VAALCO announced its intention to recomplete this well as another horizontal Bakken/Three Forks well in fiscal year 2013. As a result of these three wells, we expect that by the end of fiscal year 2013 we will better understand the value potential of our approximately 22,000 net acres at Poplar.

Despite VAALCO's determination regarding the EPU 120 with respect to formations deeper than the Bakken/Three Forks, the Company believes the log data and core samples taken during the drilling phase of this well yielded encouraging results for the Nisku, Red River, and Winnipeg formations that justify further exploration of these formations in the future.

NT/P82, Offshore Australia

In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in the NT/P82 Exploration Permit. Magellan acquired this permit in May 2010, when it was engaged in pursuing the Evans Shoal transaction. 2-D seismic previously shot over the block shows a potential "bright spot" suggestive of a large gas resource estimated within a range of one to three Tcf. In accordance with the terms of the permit, which is due to expire in May 2016, the Company is planning to shoot 3-D seismic over the permit area, subject to environmental and permitting approvals, at a cost of less than $5.0 million, including the costs of processing and analyzing the seismic. The processing and analysis is expected to be complete by the end of fiscal year 2013, after which Magellan will have a much better understanding of the nature and size of the potential hydrocarbon resources in the permit area. If the results of the 3-D seismic are favorable, Magellan will then seek to design and implement an exploration and development plan for the block, most likely with a partner experienced in offshore drilling.

United Kingdom Exploration Plan

In fiscal year 2013, the Company intends to determine a definite course of action for exploring the unconventional formations underlying its licenses, most of which are due to expire by June 2015. Our primary focus in the United Kingdom is on establishing the potential value of the unconventional play underlying the licenses we co-own with Celtique Energie. Following our completion in fiscal year 2012 of 2-D seismic shot over these licenses, we have now fulfilled all our requirements except the drilling of a well. One potential strategy involves attracting an appropriate farmout partner to drill the wells required by these licenses.

With regard to the three licenses Magellan owns 100%, one of these is due to expire in September 2012 and is unlikely to be renewed, thereby reducing our gross and net acres in the United Kingdom to 361,762 and 192,622, respectively. Following the exploration work conducted with Celtique, management does not consider this license to be core to our strategy due to its location and assessed potential.

With respect to the Markwells Wood-1 well, operated by Northern Petroleum, following a long-term production test during fiscal year 2012, the well has been suspended and is currently being assessed by Northern for further actions.

OPERATIONS

Magellan operates in the single industry segment of oil and gas exploration and production. We have two reportable geographic segments, NP and MPAL, corresponding to our operations in the United States, and in Australia and the United Kingdom, respectively. NP's oil and gas assets consist of its interests in Poplar in the Williston Basin. MPAL's oil and gas assets consist of interests in the Palm Valley, Dingo, and Mereenie (prior to May 25, 2012) fields in the Amadeus Basin, onshore Australia; NT/P82, an exploration block in the Bonaparte Basin, offshore Australia; and various exploration licenses in the Weald and Wessex Basins, onshore United Kingdom. The locations of the Company's key oil and gas properties are presented in the map below. For certain additional information about the Company's reportable segments, see Note 9 to the financial

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statements included in Item 8: Financial Statements and Supplementary Data of this report.

Magellan's Areas of Operations

United States - Poplar

In the United States, Magellan owns Poplar, an oil field located in Roosevelt County, Montana. Our acreage position covers substantially all of Poplar Dome, the largest geologic structure in the western Williston Basin, the "layer cake" structure of which provides multiple formations with hydrocarbon resource potential.

The field was discovered in the 1950s by Murphy Oil, who actively explored and developed the Charles formation for two decades. By the time Magellan acquired Poplar in 2009, technological advances in oil and gas exploration allowed us to reevaluate Poplar's known formations and to discover new ones.

Poplar is composed of a 100% working interest in the oil and gas leases within the East Poplar Unit ("EPU") in Roosevelt County, Montana, and the working interests in various oil and gas leases that are adjacent to or near EPU ("Northwest Poplar" or "NWP") with the working interests varying between 63% and 100% in such leases (the Company's combined working interests in EPU and NWP are herein referred to as “Poplar”).

Our interests at Poplar include a 100% operated working interest in the interval from the surface to the top of the Bakken/Three Forks formation and a 35% non-operated working interest below that interval, which includes the Bakken/Three Forks formations.

Magellan 100% operated intervals. Magellan's current objectives are to prove up the potential of Poplar's various formations and to establish the viability of a CO₂-EOR project in the Charles formation, in which the substantial volume of oil in place offers Magellan a chance to significantly increase its oil reserves.

VAALCO 65% operated intervals. In September 2011, we farmed out part of our interest in the Bakken/Three Forks and deeper formations to VAALCO in return for their commitment to drill three exploration wells. This arrangement allows us to focus on the shallower formations while VAALCO tests the deeper formations, including the Bakken/Three Forks, Nisku, and Red River, on our collective behalf.

Australia - Amadeus Basin

In the Amadeus Basin, located near Alice Springs in central Australia, Magellan wholly owns 100% of the working interests in and operates two gas fields, Palm Valley and Dingo.

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Palm Valley. Palm Valley was discovered in 1965 and has been reliably selling natural gas since 1983. As of June 2012, the field has produced a cumulative total of 158 Bcf of gas. Through its direct connection to the Amadeus-Darwin Gas Pipeline, Palm Valley is able to meet the needs of its potential customers in Darwin, Northern Territory, and the mining operations adjacent to this pipeline. In 2012, Magellan entered into a new long-term gas sales contract with Santos whereby the Company has the ability to sell up to approximately 23 Bcf of natural gas, representing the majority of what the Company believes are the field's remaining gas reserves, over the next 17 years. To date Santos has future sale commitments for 11.5 Bcf of this gas. The firm sale commitments are a crucial part in determining the reserves that can be booked regarding this field.

Dingo. Dingo is a gas field discovered in 1981. Four appraisal wells drilled between 1981 and 1990 established the field's resource and production potential. Until recently, Australian gas market dynamics have prevented the full development of Dingo as a producing field and the construction of the 33-mile tie-in to the Amadeus-Darwin Gas Pipeline. Magellan maintains its interest in Dingo through Retention License No. 2, which expires in February 2014 but is subject to renewal for a further five years. No mandatory capital expenditure is required until new gas sales contracts are secured.

Australia - NT/P82

In the Timor Sea, offshore Northern Territory, Australia, Magellan holds a 100% interest in the exploration permit NT/P82, which covers 2,500 square miles of the Bonaparte Basin in water ranging in depth from 30 to 500 feet. Under the terms of the permit, which is due to expire in May 2016, the Company is committed to shoot a minimum of 46 square miles of 3-D and 62 miles of 2-D seismic in 2012 and to drill a well by 2015.

United Kingdom

In the Weald and Wessex Basins, Magellan has interests in 11 Production Exploration and Development Licenses ("PEDLs"), representing a total of approximately 240,000 net acres onshore and offering both oil and gas prospects through conventional and unconventional development.

Magellan's acreage position is composed of three groups of PEDLs: (i) four licenses co-owned 50% with, and operated by, Celtique Energie, (ii) four licenses with varying ownership operated by Northern Petroleum, and (iii) three licenses wholly owned and operated by Magellan. To date in the United Kingdom, Magellan has participated in conventional wells, the most recent being the Markwells Wood-1, which was drilled and operated by Northern in PEDL 126. In addition, Magellan has contributed, along with its partners, to the exploration of its other licenses in accordance with the terms of each PEDL.

RESERVES

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

The below table presents a summary of our proved and probable reserves as of June 30, 2012.

	Oil (Mbbls)	Gas (MMcf)	Total (Mboe)(1)
Proved developed producing (PDP):
United States	1,136	—	1,136
Australia	—	6,514	1,086
Total	1,136	6,514	2,222
Proved developed not producing (PDNP):
United States	511	—	511
Australia	—	4,979	830
Total	511	4,979	1,341
Proved undeveloped (PUD):
United States	7,258	—	7,258
Australia	—	—	—
Total	7,258	—	7,258
Total proved reserves	8,905	11,493	10,821

⁽¹⁾ Gas volumes are converted to Mboe at a rate of 6 MMcf of gas per Mbbl of oil based upon the approximate relative energy content of each fuel.

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	Oil (Mbbls)		Gas (MMcf)		Total (Mboe)(1)
PDP%	13	%	57	%	21	%
PDNP%	6	%	43	%	12	%
PUD%	81	%	—	%	67	%
Probable:
Developed	—		3,759		627
Undeveloped	4,097		10,065		5,775
Total	4,097		13,824		6,402
Total proved and probable reserves	13,002		25,317		17,223
Proved %	68	%	45	%	63	%
Probable %	32	%	55	%	37	%

⁽¹⁾ Gas volumes are converted to Mboe at a rate of 6 MMcf of gas per Mbbl of oil based upon the approximate relative energy content of each fuel.

As of June 30, 2012, our consolidated total proved reserves amounted to 10,821 Mboe, comprised of 8,905 Mbbls (68%) of proved oil reserves and 11,493 MMcf (45%) of proved gas reserves. All of our proved and probable oil reserves relate to our interest in Poplar, Montana. Of the 8,905 Mbbls of proved oil reserves, approximately 8,681Mbbls (97%), 186Mbbls (2%), and 38 Mbbls (1%) were derived from the Charles, Amsden, and Tyler formations, respectively.

As of June 30, 2012, all of our proved and probable gas reserves related to our interest in Palm Valley in Australia. Under the terms of the gas sales contract with Santos, we are entitled to sell up to approximately 22,500 MMcf of gas from Palm Valley to Santos, who on-sells the gas to third-party customers. As of June 30, 2012, proved gas reserves totaled 11,493 MMcf, corresponding to gas sales volumes committed to third-party customers under the Santos gas contract. The 13,824 MMcf of probable gas reserves correspond to the remaining volumes to be sold under the Santos gas contract plus additional volumes of gas estimated to be economically recoverable from Palm Valley.

Proved Undeveloped Reserves

As of June 30, 2012, we had 7,258 Mboe of proved undeveloped reserves, representing an increase of 317 Mboe, or 5%, over the prior year figure. This increase is the result of 1,247 Mboe added through Magellan's consolidation of its ownership in Poplar in September 2011, partially offset by a 721 Mboe reduction due to quantity revisions. During the fiscal year, we did not convert any proved undeveloped reserves to proved developed reserves.

As of June 30, 2012, we had no proved undeveloped reserves that had been on our books in excess of five years, and we recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well.

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 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.

Internal Controls Over Reserve Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with regulations established by the U.S. Securities and Exchange Commission ("SEC"). The Company relies upon a combination of internal technical staff and third party consulting arrangements for reserve

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estimation and review.

In the United States, the responsibility for reserves estimation is delegated to Blaine Spies, Magellan's Operations Manager since December 2011. Mr. Spies has over 19 years of operation and technical engineering experience in the oil and gas industry. Prior to his appointment with Magellan, Mr. Spies was the Operations Manager at American Oil & Gas, responsible for drilling and completion operations in North Dakota. Mr. Spies also has experience in the Rocky Mountain region working for Halliburton. He received his Bachelors of Science in Petroleum Engineering from the Colorado School of Mines and his Masters in Business Administration from the Colorado Technical University.

In Australia, reserve estimates were prepared by the Ryder Scott Company ("RS"), an independent petroleum engineering firm, in accordance with the Company's internal control procedures, which include the verification of input data used by RS, as well as management review and approval.

Third Party Reserve Audit

In the United States, reserve estimates were audited by Allen & Crouch Petroleum Engineers ("A&C"), an independent petroleum engineering firm. A copy of the summary reserve report of A&C is provided as Exhibit 99.1 to this Annual Report on Form 10-K. A&C does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis. In addition, A&C served as the reserves auditor for Jonah Bank of Wyoming with respect to NP's loan currently outstanding with Jonah Bank of Wyoming.

In Australia, reserve estimates were prepared by RS, an independent petroleum engineering firm. A copy of the summary reserve report of RS is provided as Exhibit 99.2 to this Annual Report on Form 10-K. RS does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.

Detailed information regarding reserves, costs of oil and gas activities, capitalized costs, discounted future net cash flows, and results of operations is disclosed in the supplemental information, see Note 13, to the consolidated financial statements of this Form 10-K.

VOLUMES AND REALIZED PRICES

The following table summarizes volumes and prices realized from the sale of oil and gas from properties in which we owned an interest during the periods stated. The table also summarizes operational costs per barrel of oil equivalent.

	Volumes			Average realized price (2)						Production costs (3) (Per boe)(1)
	Oil (Mbbls)	Gas (MMcf)	Total (Mboe)(1)	Oil (Per bbl)		Gas (Per Mcf)		Total (Per boe)(1)
Fiscal year ended June 30,
2012
United States	75	—	75	$	82.66	$	—	$	82.66	$	70.06
Australia	45	434	119	$	137.21	$	3.11	$	64.40	$	65.13
All other areas	2	—	2	*		$	—	*		$	—
Total	122	434	196	$	101.64	$	3.11	$	70.95	$	66.47
2011
United States	68	—	68	$	77.96	$	—	$	77.96	$	43.85
Australia	55	712	174	$	98.60	$	2.26	$	47.27	$	36.10
Total	123	712	242	$	96.11	$	2.26	$	56.27	$	38.28
2010
United States	42	—	42	$	67.88	$	—	$	67.88	$	36.44
Australia	68	3,430	640	$	75.46	$	4.47	$	31.22	$	12.83
All other areas	29	—	29	*		$	—	*		$	—
Total	139	3,430	711	$	70.75	$	4.47	$	33.02	$	13.67

^(*) Not meaningful.

⁽¹⁾ Gas volumes are converted to Mboe at a rate of 6 MMcf of gas per Mbbl of oil based upon the approximate relative energy content of each fuel.

⁽²⁾ Prices per bbl or per Mcf are reported net of royalties. However, it should be noted that current period prices may be influenced by prior period royalty adjustments arising from annual royalty audits.

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⁽³⁾ Production cost excludes ad valorem and severance taxes.

Total production declined from 242 Mboe in fiscal year 2011 to 196 Mboe in fiscal year 2012, primarily as a result of the Palm Valley PWC contract termination in January 2012, which also contributed to the decline of gas production from 712 MMcf to 434 MMcf in fiscal year 2012. Production cost on a $/boe basis increased in Australia from $36.10/boe to $65.13/boe primarily due to decreased production, and increased in the United States from $43.85/boe to $70.06/boe primarily due to a material increase in workovers without a corresponding increase in production volumes. These factors combined to increase production costs from $38.28/boe to $66.47/boe in the United States and Australia.

PRODUCTIVE WELLS

Productive wells include producing wells and wells mechanically capable of production. In Australia, all gas wells were located at Palm Valley. The following table presents a summary of our productive wells by geography as of June 30, 2012.

	Oil Wells		Gas Wells		Total Wells
	Gross (1)	Net (2)	Gross (1)	Net (2)	Gross (1)	Net (2)
United States	39.0	37.4	—	—	39.0	37.4
Australia	—	—	1.0	1.0	1.0	1.0
Total	39.0	37.4	1.0	1.0	40.0	38.4

⁽¹⁾ A gross well is a well in which the Company owns a working interest. Wells with one or more completions in the same bore hole are considered to be one well.

⁽²⁾ The number of net wells is the sum of the fractional working interests owned in gross wells.

DRILLING ACTIVITY

The following table summarizes the results of our development and exploratory drilling during the years ended:

	June 30,
	2012		2011		2010
	Productive (2)	Dry (3)	Productive (2)	Dry (3)	Productive (2)	Dry (3)
Development wells, net (1):
United States	4.0	1.0	1.0	—	—	—
Australia	—	—	—	—	0.4	—
Total	4.0	1.0	1.0	—	0.4	—
Exploratory wells, net (1):
United States	1.0	—	—	—	—	—
Australia	—	—	—	—	—	0.9
Total	1.0	—	—	—	—	0.9
Total net wells	5.0	1.0	1.0	—	0.4	0.9

⁽¹⁾ The number of net wells is the sum of the fractional working interests owned in gross wells. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.

⁽²⁾ A productive well is an exploratory, development, or extension well that is not a dry well.

⁽³⁾ A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been plugged and abandoned.

Out of the five productive wells completed during the current fiscal year, the EPU 117 was classified as an exploratory well, and the remaining four wells were comprised of four recompletions of existing wells at Poplar. The dry well was an unsuccessful recompletion of a well at Poplar.

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The following table summarizes the results, as of September 24, 2012, of our wells that were still in progress as of June 30, 2012.

	Still in Progress
	Gross (1)	Net (2)
United States	1.0	1.0
All other areas	1.0	0.4
Total	2.0	1.4

⁽¹⁾ A gross well is a well in which the Company owns a working interest. Wells with one or more completions in the same bore hole are considered to be one well.

⁽²⁾ The number of net wells is the sum of the fractional working interests owned in gross wells.

The one well still in progress in the United States is the EPU 119, which is still being evaluated for CO₂ stimulation and possible conversion into an injection well.

ACREAGE

The following table summarizes gross and net developed and undeveloped acreage by geographic area at June 30, 2012.

	Developed (1)		Undeveloped (4)		Total
	Gross (2)	Net (3)	Gross (2)	Net (3)	Gross (2)	Net (3)
United States
Poplar	22,913	22,035	—	—	22,913	22,035
Australia
Palm Valley	41,644	41,644	116,288	116,288	157,932	157,932
Dingo	—	—	116,139	116,139	116,139	116,139
NT/P82	—	—	1,566,647	1,566,647	1,566,647	1,566,647
All other areas
United Kingdom	—	—	410,909	241,769	410,909	241,769
Total	64,557	63,679	2,209,983	2,040,843	2,274,540	2,104,522

⁽¹⁾ Developed acreage encompasses those leased acres assignable to productive wells. Our developed acreage that includes multiple formations may be considered undeveloped for certain formations but have been included as developed acreage in the presentation above.

⁽²⁾ A gross acre is an acre in which the registrant owns a working interest.

⁽³⁾ The number of net acres is the sum of the fractional working interests owned in gross acres.

⁽⁴⁾ Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

Of our 22,913 gross acres at Poplar, approximately 18,000 acres (78%) form a Federal Exploratory Unit which is held by production from any one well. Currently, Poplar contains 39 producing wells.

TITLES TO PROPERTY, PERMITS, AND LICENSES

Magellan maintains interests in its oil and gas properties through various contractual arrangements customary to the oil and gas industry and relevant to the local jurisdictions of its assets.

United States

In the United States, Magellan maintains its working interests in oil and gas properties pursuant to leases from third parties. We have either commissioned title opinions or conducted title reviews on substantially all of our properties and believe we have title to them. Magellan obtains title opinions to a drill site prior to commencing initial drilling operations. In accordance with industry practice, we perform only minimal title review work at the time of acquiring undeveloped properties.

Australia

In Australia, all of Magellan's onshore permits are issued by the Northern Territory and 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 petroleum lease is typically 21 years, and

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leases may be renewed for successive terms of 21 years each.

The below table summarizes the permits we maintain in Australia as of June 30, 2012.

Permit	Geologic basin	Expiration date	Operator	Ownership interest	Gross acres (1)	Net acres (2)
Petroleum Lease No. 3 (Palm Valley)	Amadeus	11/7/2024	Magellan	100%	157,932	157,932
Retention License No. 2 (Dingo)	Amadeus	2/16/2014	Magellan	100%	116,139	116,139
NT/P82 (Timor Sea)	Bonaparte	5/12/2016	Magellan	100%	1,566,647	1,566,647
Total					1,840,718	1,840,718

⁽¹⁾ A gross acre is an acre in which the registrant owns a working interest.

⁽²⁾ The number of net acres is the sum of the fractional working interests owned in gross acres.

United Kingdom

In the United Kingdom, Petroleum Exploration and Development Licenses issued by the government are subject to the Petroleum Act. Licensees have the exclusive right to produce petroleum from the land subject to payment of a rental. The maximum term of the license is 31 years. Licenses expire after the initial exploration term of 6 years if a well is not drilled and after 11 years if a well is drilled but no development program is approved by the Secretary of State for Energy and Climate Change.

The below table summarizes the permits we maintain in the United Kingdom as of June 30, 2012.

License	Geologic basin	Expiration date	Operator	Ownership interest	Gross acres (1)	Net acres (2)
PEDL 126	Weald	6/30/2014	Northern	40%	30,124	12,050
PEDL 135	Weald	9/30/2012	Magellan	100%	49,147	49,147
PEDL 137	Weald	9/30/2013	Magellan	100%	24,525	24,525
PEDL 155	Weald	9/30/2015	Northern	40%	13,029	5,212
PEDL 231	Weald	6/30/2014	Celtique	50%	98,880	49,440
PEDL 232	Weald	6/30/2014	Celtique	50%	23,342	11,671
PEDL 234	Weald	6/30/2014	Celtique	50%	74,100	37,050
PEDL 240	Wessex	6/30/2014	Northern	23%	1,778	409
PEDL 243	Weald	6/30/2014	Celtique	50%	74,100	37,050
PEDL 246	Weald	6/30/2014	Magellan	100%	10,769	10,769
PEDL 256	Weald	4/30/2015	Northern	40%	11,115	4,446
Total					410,909	241,769

⁽¹⁾ A gross acre is an acre in which the registrant owns a working interest.

⁽²⁾ The number of net acres is the sum of the fractional working interests owned in gross acres.

The PEDL 135 license, representing 49,147 gross and net acres, is due to expire in September 2012 and is unlikely to be renewed, thereby reducing our gross and net acres in the United Kingdom to 361,762 and 192,622 acres, respectively. Following the exploration work conducted with Celtique, management does not consider this license to be core to our strategy due to its location and assessed potential.

MARKETING ACTIVITIES AND CUSTOMERS

Customers

United States. In the United States, the Company has a sole customer who accounted for 45%, 30%, and 8% of the consolidated revenues during the fiscal years ended June 30, 2012, 2011, and 2010, respectively.

Australia. In Australia, revenue from one customer accounted for approximately 45%, 35% , and 25% of consolidated revenues for the years ended June 30, 2012, 2011, and 2010, respectively; revenue from another customer accounted for approximately 8%, 11%, and 10% of consolidated revenues in the same periods, respectively.

Delivery Commitments

Our production sales agreements contain customary terms and conditions with various parties that require us to deliver a fixed determinable quantity of product. During September 2011, Magellan entered into a Gas Supply and Purchase Agreement (the “Santos Gas Contract”) with the Santos Entities. The terms of the Santos Gas Contract commenced upon completion of the

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Santos SA and provide for the sale by Magellan to the Santos Entities of a total contract gas quantity of 25.65 Petajoules over the 17 year term of the Santos Gas Contract, subject to certain limitations regarding deliverability into the Amadeus Pipeline. We are not obliged to deliver fixed quantities of gas under the Santos Gas Contract other than that which we forecast for delivery over the ensuing 12 months. We can re-forecast quantities of gas every three months for the remainder of the contract year. If a shortfall in delivery of more than 10% occurs on any daily nomination by Santos, and confirmed for delivery by us, we incur a shortfall. If we shortfall on deliveries we can provide make-up gas in years 16 and 17 of the contract term. We will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have certain rights to arrange for third party gas to be delivered into the gathering lines and such volume will count towards our minimum commitment. We believe our production and reserves are adequate to meet these delivery commitments.

CURRENT MARKET CONDITIONS AND COMPETITION

Seasonality of Business

Demand and prices for oil and gas can be impacted by seasonal factors. Increased demand for heating oil in the winter and gasoline during the summer driving season can positively impact oil price during those times. Increased demand for heating and air conditioning can positively impact the price of natural gas during the winter and summer months, respectively. Unusual weather patterns can increase or dampen normal price levels. Our ability to carry out drilling activities can be adversely affected by weather conditions during winter months at Poplar. In general, the Company's working capital balances are not materially impacted by seasonal factors. In Australia, gas supply contracts are generally long term fixed price contracts and are unaffected by seasonality.

Competitive Conditions in the Business

The oil and gas industry is highly competitive. We face competition from numerous major and independent oil and gas companies, many of whom have greater technical, operational, and financial resources, or who have vertically integrated operations in areas such as pipelines and refining. Our ability to compete in this industry depends upon such factors as our ability to identify and economically acquire prospective oil and gas properties; the geological, geophysical, and engineering capabilities of management; the financial strength and resources of the Company; and our ability to secure drilling rigs and other oil field services in a timely and cost-effective manner. We believe our acreage positions, our management's technical and operational expertise, and the strength of our balance sheet allow us to effectively compete in the exploration and development of oil and gas projects.

The oil and gas industry itself faces competition from alternative fuel sources, which include other fossil fuels, such as coal and renewable energy sources.

EMPLOYEES AND OFFICE SPACE

As of June 30, 2012, the Company had 35 total employees. We maintain approximately 6,000 square feet of functional office space in Denver, Colorado, for our executive and administrative headquarters and 4,435 square feet of office space in Brisbane, Australia.

GOVERNMENT REGULATIONS

Regulations Applicable to Foreign Operations

Many of the properties in which we have interests are located outside of the United States, and are subject to foreign laws, regulations, and related risks involved in the ownership, development, and operation of those foreign property interests. Foreign laws and regulations may result in possible nationalization of assets, expropriation of assets, confiscatory taxation, changes in foreign exchange controls, currency revaluations, price controls or excessive royalties, export sales restrictions, and limitations on the transfer of interests in exploration licenses. In addition, foreign laws and regulations providing for conservation, proration, curtailment, cessation, or other limitations or controls on the production of or exploration for hydrocarbons may increase the costs or have other adverse effects on our foreign operations. As a result, an investment in us is subject to foreign regulatory risks in addition to those risks inherent in U.S. domestic oil and gas exploration and production company investments.

Our Australian operations are subject to stringent Australian laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations, which include the Environment Protection and Biodiversity Conservation Act 1999, require the acquisition of approvals before seismic acquisition or drilling commences, restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit seismic or drilling activities in protected

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areas, and impose substantial liabilities for pollution resulting from oil and gas operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in Australian environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition as well. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release of such materials or if our operations were standard in the industry at the time they were performed.

Energy Regulations

Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for, and production of, oil and gas, including laws and regulations requiring permits for the drilling of wells; imposing bonding requirements in order to drill or operate wells; and governing the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management ("BLM") and/or the Bureau of Indian Affairs ("BIA"). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM or the BIA can suspend or terminate our operations on federal or Indian leases.

Environmental, Health, and Safety Matters

General.Our operations are subject to stringent and complex federal, state, tribal, and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits before drilling commences;

• restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules, and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste handling, disposal, and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules, and regulations to which our business is subject:

Waste handling.The Resource Conservation and Recovery Act (the "RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the "EPA"), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

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Comprehensive Environmental Response, Compensation and Liability Act.The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers, or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Air emissions.The federal Clean Air Act ("CAA") and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Climate change.In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. See Item 1A,Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and gas. In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.

Endangered species.The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

National Environmental Policy Act.Oil and natural gas exploration and production activities on federal and Indian lands are subject to the National Environmental Policy Act (the "NEPA"). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal and Indian lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects.

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OSHA and other laws and regulation.We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA"), and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. While we do not routinely utilize hydraulic fracturing techniques in our drilling and completion programs, that may change in the future if we embark on a successful Bakken/Three Forks play in Poplar. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation's public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs, and delays which could adversely affect our financial position, results of operations, and cash flows. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. We believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We cannot give any assurance that we will not be adversely affected in the future.

AVAILABLE INFORMATION

Our internet website address is www.magellanpetroleum.com. We routinely post important information for investors on our website, including updates about us and our operations. Within our website's investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available within our website's corporate governance section the by-laws, code of conduct, and charters for the Audit Committee and the Compensation, Nominating and Governance Committee of the Board of Directors of Magellan Petroleum Corporation. Information on our website is not incorporated by reference into this report and should not be considered part of this document.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATION

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (i) depletion, depreciation, amortization, and accretion expense, (ii) exploration expense, (iii) stock based compensation expense, (iv) foreign transaction loss (gain), (v) impairment expense, (vi) loss on Evans Shoal, (vii) gain on sale of assets, (viii) warrant expense, (ix) net interest income, (x) other income, (xi) income tax benefit (provision), and net (loss) income attributable to non-controlling interest in subsidiaries. Adjusted EBITDAX is not a measure of net income or cash flow as determined by accounting principles generally accepted in the United States ("GAAP"), and excludes certain items that we believe affect the comparability of operating results.

Our Adjusted EBITDAX measure provides additional information which may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of

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our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of our assets and our company without regard to historical cost basis and items affecting the comparability of period to period operating results.

The following table provides a reconciliation of net income (loss) to Adjusted EBITDAX for the years ended:

	June 30,
	2012			2011			2010
	(In thousands)
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498		$	(32,432	)	$	(1,446	)
Depletion, depreciation, amortization, and accretion expense	1,744			2,890			5,428
Exploration expense	6,291			2,854			1,273
Stock based compensation expense	1,560			1,670			2,305
Foreign transaction loss	1,038			951			677
Impairment expense	328			173			2,050
Loss on Evans Shoal	—			15,893			—
Gain on sale of assets	(40,413		)	(969		)	(6,817		)
Warrant expense	—			—			4,276
Net interest income	(749		)	(923		)	(1,038		)
Other income	(9		)	—			(1,975		)
Income tax (benefit) provision	(5,951		)	5,141			2,646
Net (loss) income attributable to non-controlling interest in subsidiaries	(15		)	(5		)	(11		)
Adjusted EBITDAX	$	(9,678	)	$	(4,757	)	$	7,368

ITEM 1A: RISK FACTORS

In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us. These risk factors and other uncertainties may cause our actual future results to differ from those expressed or implied in the forward-looking statements contained in this report and in other public statements we make. In addition, because of these risks and uncertainties, as well as other variables affecting our operating results, our past financial performance should not be considered to be indicative of future performance.

RISKS RELATING TO OUR BUSINESS

Our principal producing oil and gas properties in the Poplar and Palm Valley fields may stop producing oil and gas.

Our principal producing properties are located in the Poplar field in Montana and the Palm Valley field in Australia, and are subject to risks associated with regional supply and demand factors and potential delays or interruptions of production from wells in these areas resulting from governmental regulations, processing or transportation capacity constraints, and the availability of equipment, facilities, personnel, or services. Due to the relatively concentrated nature of our portfolio of producing properties, a number of our properties could experience any of the same conditions at the same time, resulting in relatively greater impact on our results of operations and cash flows than they might have on other companies that have a more diversified portfolio of properties. As a result of these risks, our producing properties may stop producing oil and gas, or there could be a material decrease in production levels at these fields. Since these properties are currently our principal revenue producing properties, any decline in production levels at these properties could have a material adverse effect on our revenues, results of operations, and cash flows. Any such adverse impact on our revenues and cash flows may restrict our ability to explore and develop oil and gas properties in the future and cause our stock price to decline.

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Our Palm Valley production revenues and cash flows depend on a long-term gas sales agreement.

In 2012, we entered into a long-term sales agreement with Santos to sell up to approximately 23 Bcf of natural gas from our properties in the Palm Valley field over the next 17 years to Santos, who on-sells the gas to third party customers. As of June 30, 2012, there were two customers receiving gas from Palm Valley. In the event this agreement becomes uneconomic or is unexpectedly breached or terminated or designated quantities are decreased as permitted under the contract terms, our revenues and cash flows could be adversely impacted, and our current niche strategy of marketing Amadeus Basin gas to the mining industry in central Australia may not be successful.

Our Poplar production revenues and cash flows depend on one purchaser, and the inability of the purchaser to meet its payment obligations to us may adversely affect our financial results.

Currently, we rely on an agreement with Plains Marketing, LP as the sole purchaser of our oil production at Poplar. If this purchaser reduces or discontinues its business with us, or if we are unable to successfully negotiate a replacement agreement with this purchaser, who can terminate services with a 90 day notice period, or if the replacement agreement is on less favorable terms, the effect on us could be adverse if we are unable to obtain new purchasers for the oil produced at Poplar. In addition, if this purchaser were to experience financial difficulties or any deterioration in its ability to satisfy its obligations to us, our revenues and cash flows from Poplar could be adversely affected.

Our CO₂-EOR project at Poplar may not be successful.

We believe that the Charles formation in the Poplar field is a potential candidate for a CO₂-EOR project, whereby CO₂ is injected into a reservoir to enhance oil recovery. While laboratory analyses and preliminary tests indicate that a CO₂-EOR project at Poplar is potentially viable, the additional production and reserves that may result from CO₂-EOR methods are inherently difficult to predict. If the CO₂-EOR project does not allow for the extraction of oil in the manner or to the extent that we anticipate, our future results of operations, cash flows, and financial condition could be materially adversely affected. In addition, our ability to utilize CO₂ as an enhanced recovery technique is subject to our ability to obtain sufficient quantities of CO₂. If we are limited in the quantities of CO₂ available to us, we may not have sufficient CO₂ to produce oil in the manner or to the extent that we anticipate, and our future oil production volumes could be negatively impacted.

Our acquisitions of our investments in new oil and gas properties or other assets may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property or other acquisitions or investments require an assessment of a number of factors sometimes beyond our control. These factors include exploration potential, future crude oil and natural gas prices, operating costs, and potential environmental and other liabilities. These assessments are not precise, and their accuracy is inherently uncertain.

In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties.

In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.

Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions.

These factors could have a material adverse effect on our business, financial condition, results of operations, and cash flows. 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.

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

Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible crude oil or natural gas will be found. The cost of drilling and completing wells is often uncertain, and crude oil or natural gas drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

• unexpected drilling conditions;

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• title problems;

• disputes with owners or holders of surface interests on or near areas where we intend to drill;

• pressure or geologic irregularities in formations;

• engineering and construction delays;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

• shortages or delays in the availability of or increases in the cost of drilling rigs and crews, equipment, pipe, water, and other supplies.

The prevailing prices for crude oil and natural gas affect the cost of and demand for, drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas.

Another significant risk inherent in drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil or natural gas is present, or whether it can 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. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs.

Our future drilling activities may not be successful. Although we have identified potential drilling locations, we may not be able to economically produce oil or natural gas from them.

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

Our drilling plans 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.

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 our executive management team and other key personnel. 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. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

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 Magellan.

The properties in which we have interests located outside the United States are subject to certain risks related to the indirect ownership and development of foreign properties, including government expropriation and nationalization, adverse changes in currency values and foreign exchange controls, foreign taxes, U.S. taxes on the repatriation of funds to the United

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States, and other laws and regulations, any of which may have a material adverse effect on our properties, financial condition, results of operations, or cash flows. Although there are currently no exchange controls on the payment of dividends to Magellan by MPAL, such payments could be restricted by Australian foreign exchange controls, if implemented.

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

We had 35 total employees as of June 30, 2012. Due to our limited number of employees, 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 also plan to pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation, and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

• the possibility that such third parties may not be available to us as and when needed; and

• the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

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.

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

Our revenues, results of operations, 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 and natural gas have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including the following:

• worldwide and domestic supplies of oil and gas, and the productive capacity of the oil and gas industry as a whole;

• changes in the supply and demand for such fuels;

• overall global and domestic economic conditions;

• political conditions in oil, natural gas, and other fuel-producing and fuel-consuming areas;

• the extent of Australian domestic oil and gas production and importation of such fuels and substitute fuels in Australian and other relevant markets;

• the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil or natural gas;

• weather conditions, including effects of weather conditions on prices and supplies in worldwide energy markets;

• technological advances affecting energy consumption;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain crude oil prices and production controls;

• the competitive position of each such fuel as a source of energy as compared to other energy sources;

• strengthening and weakening of the United States dollar relative to other currencies; and

• the effect of governmental regulation and taxes on the production, transportation, and sale of oil, natural gas, and other fuels.

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 to below $70 per barrel in August 2009, and then have increased to $97 per barrel in August 2012, while natural gas prices have declined from over $13 per Mcf to approximately $3 per Mcf over the same period.

Sustained declines in oil and gas prices would not only reduce our revenues but also 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, cash flows, 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

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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 we do.

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration, and production, and face intense competition from both major and other independent oil and natural 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 operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.

U.S. federal, state, tribal, and local authorities, and corresponding Australian governmental authorities, extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil and natural gas production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of crude oil and natural gas, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Governmental authorities also may require any of our ongoing or planned operations on their leases or licenses to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a material adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between various regulatory agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several liability or strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs but also natural resources, real or personal property, and other compensatory damages and civil and criminal liability. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a material adverse effect on us.

The potential impacts of global warming and climate change may have an adverse effect on our operations and the demand for crude oil and natural gas.

Global warming and climate change have 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 may contribute to the warming of the earth's atmosphere and other climatic changes and pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain greenhouse gas emissions, 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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International agreements and national or regional legislation and regulatory measures to limit greenhouse gas emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies, and regulations may result in substantial capital, compliance, operating, and maintenance costs. For example, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, results of operations, and cash flows.

In addition, some scientists have predicted that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operations or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

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 report and the documents incorporated by reference in this report contain estimates of our proved and probable 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. Probable reserves are less certain to be recovered than proved reserves.

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:

• actual prices we receive for oil and natural gas;

• actual cost of development and production expenditures;

• the amount and timing of actual production;

• supply of and demand for oil and natural gas; and

• changes in governmental regulations or taxation.

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.

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Reserves as of June 30, 2012, 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, 2012, 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 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, 2012, 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 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 our 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 our 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 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.

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

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, the costs of successful wells, development dry holes, and productive leases are capitalized and amortized on a units-of-production basis over the life of the related reserves. Cost centers for amortization purposes are determined on a field-by-field basis. We record our 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 effected, the proved developed reserves will be increased to the lesser of the current risk adjusted probable and possible reserves or the newly 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:

• injury or loss of life;

• severe damage to, or destruction of, property, natural resources, and equipment;

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• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigations and penalties;

• suspension of operations;

• and compliance with, or changes in, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing, laws and regulations imposing conditions and restrictions on drilling and completion operations, and other laws and regulations, such as tax laws and regulations.

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. 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, results of operations, and cash flows.

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:

• nature and timing of drilling and operational activities;

• timing and amount of capital expenditures;

• expertise and financial resources;

• the approval of other participants in drilling wells; and

• selection of suitable technology.

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 denominated in U.S. dollars in the future. However, at June 30, 2012, the U.S. dollar has strengthened against the Australian dollar which has had, and may continue to have, a negative impact on our revenues generated in the Australian dollar, as well as our operating income and net income, as considered on a consolidated basis. The foreign exchange gain for the year ended June 30, 2012, was $1.0 million and is included in accumulated other comprehensive income on the balance sheet. Any 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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Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws applicable to oil and natural gas exploration and production companies. These proposed changes include, but are not limited to:

• eliminating the immediate deduction for intangible drilling and development costs;

• eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development;

• repealing the percentage depletion allowance for oil and gas properties;

• extending the amortization period for certain geological and geophysical expenditures; and

• implementing certain international tax reforms.

These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

RISKS RELATED TO OUR COMMON STOCK

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.

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, other equity grants, and our outstanding warrants, and shareholders may be adversely affected by the issuance of those shares.

As of June 30, 2012, there were 4,347,826 warrants outstanding and 6,753,125 stock options outstanding, of which 4,861,454 are fully vested and exercisable. As of that date, there were also 435,000 options available for future grants under our 1998 Stock Incentive Plan as amended in December of 2010. If all of these options and warrants, which total 11,100,951 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 regain compliance with the rule. On September 4, 2012, our shares closed at $1.17 per share, but our shares closed at below $1.00 on certain trading days in August 2012. If our shares were to be delisted from trading on the NASDAQ Capital Market, they may be eligible for trading on the OTCQB. The delisting of our shares from NASDAQ could adversely impact the liquidity and value of our shares.

Provisions in our charter documents and Delaware law may delay or prevent our acquisition by a third party.

We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various barriers to the ability of a third party to acquire control of us, even if a change of control would be beneficial to our existing stockholders. In addition, our certificate of incorporation and bylaws contain several provisions that may make it more difficult for a third party to acquire control of us without the approval of our board of directors. These provisions may make it more difficult or expensive for a third party to acquire a majority of our outstanding common stock. Among other things, these provisions:

• authorize us to issue preferred stock that can be created and issued by the board of directors without prior stockholder

27

approval, with rights senior to those of common stock;

• classify our board of directors so that only some of our directors are elected each year;

• prohibit stockholders from calling special meetings of stockholders; and

• establish advance notice requirements for submitting nominations for election to the board of directors and for proposing matters that can be acted upon by stockholders at a meeting.

These provisions also may delay, prevent, or deter a merger, acquisition, tender offer, proxy contest, or other transaction that might otherwise result in our stockholders receiving a premium over the market price for their common stock.

ITEM 1B: UNRESOLVED STAFF COMMENTS

None.

ITEM 3: LEGAL PROCEEDINGS

We may be involved from time to time in legal proceedings relating to disputes or claims arising out of our operations in the normal course of business. As of the filing date of this report, there are no pending legal proceedings that we believe could have a material adverse effect on our financial condition, results of operations, or cash flows.

ITEM 4: MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5: MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

PRINCIPAL MARKET

The principal market for Magellan's common stock is the NASDAQ Capital Market. We trade under the symbol MPET. Our stock is also traded on the Australian Stock Exchange in the form of CHESS Depository Interests ("CDIs") under the symbol MGN. The below table presents the quarterly high and low prices on our most active market, NASDAQ, during the periods indicated. Each CHESS is matched by one Magellan common stock share. As of June 30, 2012, there were approximately 1,000,000 CDIs outstanding.

Quarter ended	High	Low
June 30, 2012	$1.39	$1.01
March 31, 2012	$1.49	$0.87
December 31, 2011	$1.24	$0.89
September 30, 2011	$1.89	$1.12
June 30, 2011	$2.58	$1.38
March 31, 2011	$3.45	$2.27
December 31, 2010	$3.03	$1.78
September 30, 2010	$1.97	$1.49

HOLDERS

As of September 7, 2012, the number of record holders of Magellan's common stock was 5,338; and, based upon inquiry, the number of beneficial owners was approximately 6,300, including approximately 1,100 who held beneficial ownership of shares through CHESS Depository Interests.

FREQUENCY AND AMOUNT OF DIVIDENDS

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

PERFORMANCE GRAPH

The following performance graph compares the cumulative return on our common stock, for the period beginning June 30, 2007, and ending on June 30, 2012, with the cumulative total returns of the NASDAQ Composite Index, a broad equity market index, and the Morningstar Oil and Gas E&P Industry Index, an industry group index. The graph assumes a $100 investment made on July 1, 2007, and the reinvestment of all dividends.

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.

RECENT SALES OF UNREGISTERED SECURITIES

Unregistered Inducement Grants during the fiscal year ended June 30, 2012, that were outside of the 1998 Stock Incentive Plan, as amended, were reported in Form 8-Ks.

ISSUER PURCHASES OF EQUITY SECURITIES

The table below provides information about purchases of the Company's common stock by the Company during the periods indicated.

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program
April 1, 2012 - April 30 , 2012	—	$	—	—	319,150
May 1, 2012 - May 31, 2012	—	$	—	—	319,150
June 1, 2012 - June 30, 2012	—	$	—	—	319,150
Total	—	$	—	—	319,150

On December 8, 2008, the Company announced that its Board of Directors had approved a stock repurchase plan whereby the Company was authorized to purchase up to one million shares of its common stock in the open market. Through June 30, 2012, the Company had purchased 680,850 of its shares under this plan at an average price of $1.01 per share, or a total cost of approximately $0.7 million, all of which shares have been canceled. No shares were purchased during 2012, 2011, or 2010. On September 24, 2012, the Company announced that its Board of Directors had approved a new stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its common stock. This authorization supersedes the prior plan and will expire on August 21, 2014. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including compliance with securities laws. Stock repurchases may be funded with existing cash balances or internal cash flow. The stock repurchase program may be suspended or discontinued at any time.

ITEM 6: SELECTED FINANCIAL DATA

The following table sets forth selected supplemental financial and operating data for Magellan for the fiscal years ended as indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Part II, Item 7: Management's Discussion and Analysis of Financial

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Condition and Results of Operations of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this Form 10-K.

	June 30,
	2012		2011			2010			2009		2008
	(In thousands, except per share amounts)
Total revenues	$	13,712	$	18,176		$	28,525		$	28,191	$	40,895
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498	$	(32,432	)	$	(1,446	)	$	665	$	(8,892	)
Net income (loss) per basic share outstanding	$	0.49	$	(0.62	)	$	(0.03	)	$	0.02	$	(0.21	)
Net income (loss) per diluted share outstanding	$	0.49	$	(0.62	)	$	(0.03	)	$	0.02	$	(0.21	)
Total assets	$	92,574	$	71,574		$	90,706		$	71,704	$	85,295
Long-term debt	$	390	$	870		$	232		$	—	$	—
Total equity attributable to Magellan Petroleum Corporation	$	72,908	$	52,528		$	71,904		$	53,513	$	62,463
Non-controlling interest in subsidiaries	$	—	$	1,989		$	1,914		$	—	$	—

ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis presents management's perspective of our business, financial condition, and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition, and outlook for the future and should be read in conjunction with Item 8: Financial Statements and Supplementary Data of this Form 10-K. In the following tables, the combination of Palm Valley and Mereenie represents our MPAL reporting segment. Amounts expressed in Australian currency are indicated as "AUD."

Forward looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward looking statements. See "Forward Looking Statements" at the end of the section. Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled "Risk Factors" above, which are incorporated herein by reference. We assume no obligation to revise or update any forward looking statements for any reason, except as required by law.

OVERVIEW OF THE COMPANY

Magellan is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. Our strategy is to enhance shareholder value by maximizing the value of our existing assets. We accomplish this through the exploration and development of our assets as outlined in Items 1 and 2: Business and Properties of this report.

SUMMARY RESULTS OF OPERATIONS FOR THE YEAR ENDED JUNE 30, 2012

For the year ended June 30, 2012, revenues totaled $13.7 million compared to $18.2 million in the prior year, a decrease of 25%. Operating income totaled $19.8 million compared to $28.2 million operating loss in the prior year. Net income totaled $26.5 million ($0.49/basic share), compared to a net loss of $32.4 million ($(0.62)/basic share) in the prior year. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation under Part 1, Items 1 and 2: Business and Properties) totaled negative$9.7 million, compared to negative$4.8 million in the prior year, a change of 103%. For further detail, please refer to the discussion below in this section under Comparison of Financial Results and Trends Between Fiscal 2012and 2011.

During the quarter ended December 31, 2011, we have changed the presentation of our financial statements to conform them to industry-specific norms and to improve our reporting to shareholders and stakeholders. Specifically, we have modified the presentation of expenses in the consolidated statements of operations and the presentation of property and equipment in the consolidated balance sheets. As a result, certain reclassifications have been made to the prior period financial statements to align them with this revised presentation format. These reclassifications have no impact on previously reported results.

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HIGHLIGHTS OF OPERATIONAL ACTIVITIES

During the fiscal year ended June 30, 2012, management articulated a strategy to focus on proving up the value of its existing assets as the most economic way of increasing shareholder value. Towards that end, management has begun a number of initiatives to evaluate and determine the potential of its oil and gas properties. The below discussion should be read in conjunction with the discussion of Significant Developments in Fiscal Year 2012 under Part1, Items 1 and 2: Business and Properties above and the section covering Comparison of Results and Trends between Fiscal Years 2012 and 2011 below.

Poplar (Montana, United States)

Magellan 100% operated intervals. During the year ended June 30, 2012, Magellan sold 75 Mbbls of oil attributable to its net revenue interests in Poplar, compared to 68 Mbbls of oil sold during the same period in 2011. These results represent a 10%increase in average daily sales for the year from 186 boepd to 205 boepd. Approximately 5 Mbbls out of the 7 Mbbls increase were attributable to sales from the EPU 117 well, which produces out of the Amsden formation, a new pool discovery made in January 2012. This well currently produces at a stabilized production rate of 10 to 20 bopd. The remaining production increase of 2 Mbbls is primarily the result of workovers and Magellan's consolidation of its ownership in Poplar in September 2011.

Poplar was discovered in the 1950s by Murphy Oil Company, with much of the field's development occurring in the Charles formation between the 1950s and 1970s. Most of the field's current production is conventional production from the Charles formation generated by wells initially drilled in that era, and these wells require significant workovers and maintenance to maintain stable production.

To improve the production and profitability of Poplar, Magellan implemented a workover and exploration program during the past fiscal year aimed at increasing conventional production from its operated formations. The Company tested and evaluated several unexplored shallow formations which are prospective for hydrocarbons. The discovery of the Amsden formation was a result of this effort, and management is currently evaluating whether it is more economic to develop this formation through the recompletion of existing wells or through the drilling of new ones. In addition, Magellan assessed the effectiveness of certain production-enhancing technologies, such as stimoil treatments, acid stimulations, and water shut-off treatments, in certain intervals. These assessments are ongoing, and, if successful, Magellan will seek to deploy them on a full-field basis.

During the fiscal year, Magellan also focused heavily on evaluating the potential for a CO₂-EOR project in the Charles formation at Poplar. During the third and fourth fiscal quarters, the Company commissioned various laboratory analyses of oil samples taken from the Charles formation, including studies of minimum miscibility pressure, CO₂ solubility swelling, and viscosity reduction. Magellan received analysis results back between May and August 2012, all of which confirm the potential viability of CO₂-EOR at Poplar. In addition, Magellan has utilized the EPU 119 well, initially drilled in 2010, to conduct CO₂ injectivity tests into the Charles formation under actual reservoir conditions. Such tests have been completed, and the results will support the viability of a CO₂-EOR at Poplar. Magellan is now working diligently to implement a five-well CO₂-EOR pilot project to be conducted during the fiscal year ending June 30, 2013.

VAALCO 65% operated intervals. In September 2011, we farmed out part of our interest in the Bakken/Three Forks and deeper formations to VAALCO in return for their commitment to drill three exploration wells. This arrangement allows us to focus on the shallower formations while VAALCO tests the deeper formations, including the Bakken/Three Forks, Nisku, and Red River, on our collective behalf.

Australia

Palm Valley. The Palm Valley gas field, which is operated by MPAL, produced a gross average of approximately 1.2 MMcf/d of natural gas for sale for the year ended June 30, 2012. Gas sales volumes at Palm Valley decreased due to the termination of the PWC Contract during January 2012. Gas sales resumed in February 2012 under month to month arrangements with Santos and were continued with Santos under a long-term gas sales agreement in May 2012 following completion of the Santos SA. Under these arrangements, sale terms were equivalent to those included in the Santos Gas Contract. The Santos Gas Contract became effective upon Completion of the Santos SA on May 25, 2012. To date, gas volumes sold under both the arrangements were significantly lower than under the PWC Contract, although volumes are expected to increase by fiscal year 2015 to levels similar to, and at prices significantly higher than, those realized under the PWC Contract. The average price of gas, net of royalties and prior year royalty adjustments, at Palm Valley was AUD $3.01/Mcf for the year ended June 30, 2012, compared to AUD $2.28/Mcf for the prior year.

During the fiscal year, Magellan took steps to reduce costs and improve operational efficiency at Palm Valley, including reducing its field staff from ten to five employees, while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.

Mereenie. The Mereenie oil and gas field, which is operated by Santos, produced a gross average of approximately 473

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bbls of oil and condensate per day for sale during the period from July 1, 2011, to May 25, 2012, when the Santos SA was completed, compared to 493 bbls during the prior year. The average price of oil at Mereenie, net of royalties and prior year royalty adjustments, was AUD $132.92/bbl for the year ended June 30, 2012, compared to AUD $99.67/bbl for the prior year. There were no natural gas sales at Mereenie during fiscal years 2012 and 2011. Magellan sold its interests in Mereenie to Santos as part of the Santos SA (see Note 2) effective May 25, 2012, and the results of operations for fiscal year 2012 reflect a revenue contribution from Mereenie through that date.

United Kingdom

Celtique Energie Operated Licenses. In the Weald Basin, Magellan and Celtique Energie each own a 50% working interest in four licenses (PEDL 231, 232, 234, and 243) covering a gross total of approximately 270,000 acres, all expiring on June 30, 2014, unless extended. Celtique Energie continues to gather data to assess the prospect for unconventional and conventional hydrocarbon deposits in these licenses. In September 2011, Celtique completed the acquisition of approximately 200 km of 2-D seismic data. This seismic acquisition fulfilled our current work commitment under the licenses. These four licenses remain subject to contingent "drill-or-drop" requirements. This seismic data revealed several prospects, and an exploratory drilling program is under development.

Northern Petroleum Operated Licenses. In the Weald Basin of Southern England, the Company participated (40% interest) in the Markwells Wood-1 exploration well, which was drilled in PEDL 126 in December 2010. On November 21, 2011, this well was completed for production testing to establish pressures and flow rates in the existing wellbore. Further stimulation of the well was performed during December 2011 and February 2012, and production testing continued through April 2012 to establish a stabilized oil production rate. The well was then suspended, and is now being assessed by Northern for further actions. As operator of the well, Northern Petroleum will continue to publish periodic updates on the well status. Limited quantities of oil volumes have been produced from the Markwells Wood-1 well.

In January 2012, the United Kingdom Department of Energy, in the 26th Licensing Round, announced it will award an exploration license (an offshore license) to the Isle of Wight Joint Venture, which is composed of Northern Petroleum (63%), Magellan (23%), Egdon Resources (7%), Montrose Industries (5%), and Oil & Gas Investments (2%). The license is an exploration license for two part blocks located offshore in the Wessex Basin and contains a potential Wytch Farm type play. Northern Petroleum is the operator. Commitments to the license consist of a contingent “drill-or-drop” well with a decision on drilling to be made before the end of Permit Year 2.

ACQUISITIONS AND DIVESTITURES

During the fiscal year, Magellan executed a series of corporate transactions aimed at streamlining our corporate structure, gaining control and operatorship of our core assets, and allowing management to execute its strategy of proving the value of its assets.

Santos Transactions

On May 25, 2012, Magellan completed the Santos SA which consolidated our ownership in the Palm Valley and Dingo. The transaction had an effective date of July 1, 2011, and resulted in net cash proceeds of $26.6 million, including adjustments of $1.1 million (reflecting activity between the effective date and closing date), in addition to a gain on sale of assets in the amount of $36.2 million. The impact of this transaction is reflected in the consolidated financial statements included in this report (see Note 2).

Lease Purchase and Sale and Participation Agreement with VAALCO.

On September 6, 2011, the Company entered into a Lease Purchase and Sale and Participation Agreement with VAALCO, pursuant to which VAALCO will receive, subject to certain obligations, an undivided 65% of the Company's working interests at Poplar in formations including and below the Bakken/Three Forks. In exchange, Magellan received $5.0 million in cash proceeds and will be carried for 100% of the capital expenditures on the first three wells VAALCO will drill at Poplar in the deeper formations, all of which wells are due to be spud before December 31, 2012. The Company also recognized a gain on sale of assets in the amount of $4.0 million (see Note 2).

Acquisition of Non-Controlling Interest in Nautilus Poplar LLC and Acquisition of Additional Working Interests.

On September 2, 2011, effective from September 1, 2011, the Company entered into a Purchase and Sale Agreement (the "Nautilus PSA") between the Company and the non-controlling interest owners of its subsidiary, NP, (the "Nautilus Sellers"). The Nautilus PSA provided for the Company's purchase of all membership interests in NP and working interests in the leases of Poplar from the Nautilus Sellers in return for (i) $4.0 million in cash, (ii) $2.0 million less certain adjustments in privately issued shares of Magellan's common stock, and (iii) the potential for future production payments, collectively, of up to $5.0 million if certain increased average daily production milestones are achieved. The impact of this transaction is reflected in the consolidated financial statements included in this report (see Note 2).

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The Company and the Nautilus Sellers entered into a Registration Rights Agreement ("RRA"), pursuant to which the Company granted to the Nautilus Sellers certain registration rights with respect to the shares ("Registrable Securities") owned by each Nautilus Seller and issued under the Nautilus PSA. On October 14, 2011, the Company filed a registration statement on Form S-3 with the U.S. Securities Exchange Commission to register for public resale of 1,182,742 shares of the Company's common stock acquired in the Nautilus Restructuring by the Nautilus Sellers (the "Registration Statement"). On November 18, 2011, the Registration Statement on Form S-3 became effective. The Company agreed to pay all expenses associated with the registration of the Registrable Securities except the fees and disbursements of counsel to the Nautilus Sellers. The Company has no continuing obligation related to the RRA.

OTHER ITEMS

U.S. Federal Tax Withholdings

During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's failure to make the required U.S. Federal tax withholding in the course of its initial acquisition of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition"), from the two majority owners of NP, White Bear LLC ("White Bear") and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Mr. Bogachev, a Director of Magellan and a foreign national. Due to the status of YEP I as foreign entity and the members of White Bear being foreign nationals, Magellan was required to make U.S. Federal tax withholdings from the payments to or for the benefit of White Bear and YEP I. Of the $2.0 million liability, $1.3 million was estimated to relate to the interest sold by White Bear, $0.6 million to the interest sold by YEP I, and $0.1 million to Magellan's interest on late payment of the U.S. Federal tax withholdings.

Upon the filing of U.S. income tax returns in relation to the Poplar Acquisition and payment of corresponding income taxes by White Bear and YEP I, Magellan is deemed to be relieved of its liability for the U.S. Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the U.S. Federal tax withholdings. With regards to White Bear, Magellan has confirmed that as of the date of this filing, Mr. Bogachev has filed his U.S. income tax return and paid taxes due on the Poplar Acquisition, which were estimated at $0.3 million. Magellan has agreed to pay Mr. Bogachev $0.3 million in additional compensation. Had Mr. Bogachev not filed and paid his tax return, Magellan's liability in relation to its U.S. Federal tax withholdings requirements was estimated at $1.3 million as of June 30, 2012. With regards to YEP I, Magellan continues to seek from YEP I or, because YEP I is a now defunct entity, from its successor entities, the filing of its U.S. income tax return.

As of June 30, 2012, we have recorded a total liability of $1.0 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.3 million payment to Mr. Bogachev, $0.6 million in withholdings, penalties, and interest related to YEP I, and $0.1 million related to Magellan's interest on late payment of the U.S. Federal tax withholdings. The effect on the consolidated statements of operations for the year ended June 30, 2012, is an expense of $0.9 million recorded under general and administrative expense and an interest expense of $0.1 million (see Note 11).

Based upon an evaluation of all relevant quantitative and qualitative factors, and after considering SEC Staff Accounting Bulletins Nos. 99 and 108, management believes that any amounts attributable to the years ending June 30, 2010, and 2011, and the impact of correcting such amounts in the year ending June 20, 2012, is not material to any of the Company's consolidated financial statements presented herein.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES

Historically, we have funded our activities from cash from operations and our existing cash balance. The Company has limited capital expenditure for which we are obligated pertaining to its leases and licenses, which allow for significant flexibility in the use of its capital resources. Based on its existing cash position including, the additional proceeds resulting from the completion of the Santos SA, and the various alternative sources of funds generally available to the Company, the Company believes it has sufficient financial resources to fund its ongoing operations and to finance projects that will further establish the full value of its assets.

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Uses of Funds

Capital Expenditures Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Approximately 80% of the acreage has been unitized as a Federal Exploratory Unit which is held by production from any one well. Currently, Poplar contains 39 producing wells. In the shallow intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans over the next two years will be determined by the results of ongoing engineering and technical analysis. In fiscal year 2013, the Company intends to evaluate the potential of CO₂-EOR in the Charles formation at Poplar by drilling a five-well pilot, including one CO₂ injector well and four producing wells. Magellan expects to incur up to $10.0 million in capital costs on these wells. Timing of the drilling of these wells will depend on the permitting process and drilling rig availability. The four producing wells are designed to yield conventional oil production from the Charles formation in addition to enhanced production as a result of the CO₂-EOR. As such, these four wells will constitute a portion of the wells to be drilled in the projections of our proved undeveloped reserves.

In the deeper intervals, which are operated by VAALCO and in which the Company has a 35% working interest, capital expenditures will be determined by the results of the three test wells which VAALCO is required to have spud by the end of calendar year 2012, and for which VAALCO will bear 100% of the capital expenditures. If these test wells are deemed successful, the Company plans to fund its 35% share of the cost of the future drilling program in the deeper formations of Poplar.

At Palm Valley, the Company’s interest in the field is governed by Petroleum Lease No. 3, which expires in November 2024 (and is subject to automatic renewal for another 21 years). The Company is not obligated to undertake significant mandatory capital expenditures in order to maintain its position in the lease. The Company’s discretionary capital expenditure plans are primarily focused on maintaining gas production from the existing facilities to meet the Santos Gas Contract demand while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.

At Dingo, the Company’s interest in the field is governed by Retention License No. 2, which expires in February 2014 (and is subject to renewal for a further 5 years). No mandatory capital expenditure is required until new gas sales contracts are secured. Dingo contains two suspended wells which are capable of production. The Company is currently evaluating a number of options for the future development of this field and is in the process of identifying potential new gas customers.

In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in the NT/P82 Exploration Permit. Under the terms of the permit, which is due to expire in May 2016, the Company committed to a minimum 46 square mile 3-D seismic survey in 2012. Magellan currently plans to shoot 2-D and 3-D seismic over the permit in the second quarter of fiscal year 2013 at an estimated cost of less than $5.0 million, including the costs of processing and analyzing the seismic. Timing of the shoot is subject to finalization of our environment plans with local authorities and to the contract with the vessel and service provider.

In the United Kingdom, the Company’s interests are governed by various Petroleum Exploration and Development Licenses. The majority of these licenses expire in 2014, and all are subject to "drill-or-drop" obligations (for further detail, see Operations under Part 1, Items 1 and 2: Business and Properties). The Company has minimal remaining capital expenditure obligations with respect to its interest in the Markwells Wood-1 well operated by Northern Petroleum.

Contractual Obligations. The following table summarizes our obligations and commitments as of June 30, 2012, to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods:

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Purchase obligations (1)	$	5,385	$	5,385	$	—	$	—	$	—
Asset retirement obligations	7,784		329		1,321		—		6,134
Contingent consideration payable (2)	4,072		—		4,072		—		—
Operating leases (3)	1,152		97		424		541		90
Long term debt, including interest (4)	918		517		401		—		—
Total	$	19,311	$	6,328	$	6,218	$	541	$	6,224

⁽¹⁾ Purchase obligations are attributable to certain exploration and capital expenditures related to MPAL.

⁽²⁾ Assumptions for the timing of these payments are based on our reserve report and planned drilling activity.

⁽³⁾ Operating lease obligations are shown net of guaranteed sublease income.

⁽⁴⁾ Long term debt in this table includes the current portion and accrued interest of $48 thousand for the 6.25% note payable (see Note 3).

35

Sources of Funds

Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $41.2 million of cash and cash equivalents at June 30, 2012, compared to $20.4 million as of June 30, 2011.

The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. As of June 30, 2012, $39.7 million of the Company’s consolidated cash and cash equivalents were deposited in accounts held by MPAL, of which $38.6 million was held in several Australian banks in time deposit accounts that have terms of 90 days or less. As of September 24, 2012, the company has repatriated $20.0 million of these Australian held funds to the U.S. The Company does not anticipate that U.S. Federal Income Tax will be owed on this amount. The intended use for the repatriated monies is the funding of Magellan's U.S. based operations, including part of its drilling activity at Poplar.

Due to the international nature of its operations, the Company is exposed to certain legal and tax constraints in matching the capital needs of its assets and its cash resources. To the extent that the Company repatriates cash amounts from MPAL to the U.S., the Company is potentially liable for incremental U.S. Federal and State Income Tax, which may be reduced by the U.S. Federal and State net operating loss and foreign tax credit carry forwards available to the Company at that time.

Marketable Securities.The Company may from time to time invest in marketable securities consisting of investments in U.S. Treasury Bills with maturities usually not exceeding six months. As of June 30, 2012, and June 30, 2011, respectively, the Company had no marketable securities.

Existing Credit Facilities. The Company's outstanding borrowings are summarized below for the years ended:

	June 30,
	2012		2011
	(In thousands)
Outstanding borrowings:
Term loan	$	870	$	1,422
Line of credit	50		1
Total	$	920	$	1,423

The Company, through its wholly owned subsidiary NP, maintains its only credit facility with Jonah Bank of Wyoming. As of June 30, 2012, the Company’s borrowing capacity under these facilities totaled $2.3 million, consisting of a $1.3 million term loan and a $1.0 million line of credit. Of the $1.3 million term loan, $0.9 million was drawn as of June 30, 2012. Of the $1.0 million line of credit, $50 thousand was drawn, $25 thousand secured business credit cards used by NP, $25 thousand secured a line of credit in favor of the Bureau of Land Management, and $900 thousand remained available to borrow. As of June 30, 2012, NP was in compliance with its financial covenants as set forth in the term loan agreement. The credit facilities are collateralized by a first mortgage and an assignment of production from Poplar and are guaranteed by the Company up to $6.0 million but not to exceed the amount of the principal owed, which was $920 thousand as of June 30, 2012.

Other Sources of Financing. In addition to its cash and existing credit facilities, the Company has various alternatives to fund the development of its assets. These alternatives could potentially include entering into a corporate credit facility, a reserve-based loan facility, a farmout of a portion of the development program of some of the Company's assets, and an issuance of new shares to equity investors and monetization of non-core assets.

Cash Flows

The following table presents the Company's cash flow information for the years ended:

	June 30,
	2012			2011
	(In thousands)
Cash (used in) provided by:
Operating activities	$	(10,441	)	$	(4,495	)
Investing activities	35,629			(13,481		)
Financing activities	(3,928		)	561
Effect of exchange rate changes on cash and cash equivalents	(462		)	4,240
Net increase (decrease) in cash and cash equivalents	$	20,798		$	(13,175	)

Cash used in operating activities during the year ended June 30, 2012, was $10.4 million, compared to cash used of $4.5

36

million in 2011. The increase in cash used in operating activities primarily resulted from a combination of a decrease in revenues of $4.5 million over the prior year and increased operational spending related to exploration and lease operating expenses of $3.7 million and $3.4 million, respectively. These factors were partially offset by a reduction in general and administrative costs (excluding stock based compensation and foreign transaction loss) of $3.2 million.

Cash provided by investing activities during the year ended June 30, 2012, was $35.6 million, compared to cash used of $13.5 million in 2011. The increase in cash provided by investing activities resulted from $5.0 million in proceeds from the VAALCO PSA (see Note 2), the refund of a $10.9 million deposit related to the Evans Shoal Asset Sales Deed, and $29.6 million in cash proceeds from the Santos SA (see Note 2), offset by $0.8 million spent on the purchase of non-controlling interests in Poplar and $9.6 million in expenditures on the development of our assets. Of the $9.6 million, $2.4 million related to the recompletion of four wells and the repair of one of our salt water disposal wells at Poplar, $1.6 million related to exploration activities at Poplar, primarily for the EPU 117 well, $1.2 million related to the Markwells Wood-1 well in the United Kingdom, and $3.4 million represented the acquisition of the remaining interest in the Palm Valley and Dingo gas fields.

Cash used in financing activities during the year ended June 30, 2012, was $3.9 million, compared to cash provided of $0.6 million in 2011. The increase in cash used in financing activities related to the $3.5 million purchase of the non-controlling interest in Poplar (see Note 2) and the repayment of the Company's long term debt of $0.5 million.

During the year ended June 30, 2012, the effect of changes in foreign currency exchange rates negatively impacted the translation of our AUD denominated cash and cash equivalent balances into U.S. dollars and resulted in a decrease of $0.5 million in cash and cash equivalents, compared to an increase of $4.2 million in 2011.

The Company also expects the impact of non-cash foreign transaction gains and losses in the consolidated statements of cash flows to be reduced in future periods. The source of the impact was primarily generated by MPAL's cash balances in U.S. dollar denominated accounts held in relation to the Evans Shoal Asset Sales Deed. Cash balances held in these accounts have now been reduced to immaterial amounts.

COMPARISON OF FINANCIAL RESULTS AND TRENDS BETWEEN FISCAL 2012 AND 2011

Oil and Gas Sales Volumes

The following table presents oil and gas sales volumes for the years ended:

	June 30,
	2012	2011	Difference		Percent change
Net sales by field:
Poplar (Mbbls)	75	68	7		10	%
Palm Valley gas (MMcf)	434	712	(278	)	(39	)%
Mereenie oil (Mbbls)	45	55	(10	)	(18	)%
Total Australia sales (Mboe)	119	174	(55	)	(32	)%
Net sales by product:
Oil (Mbbls)	122	123	(1	)	(1	)%
Gas (MMcf)	434	712	(278	)	(39	)%
Consolidated sales (Mboe)	194	242	(48	)	(20	)%
Consolidated sales (boepd)	531	662	(131	)	(20	)%

Sales volumes for the year ended June 30, 2012, totaled 194 Mboe (531 boepd), compared to 242 Mboe (662 boepd) sold in the prior year period, a decrease of 20%.The primary driver of this decline is the end of the PWC Contract of Palm Valley which was partially offset by increased production at Poplar. Sales volumes by product for the year ended June 30, 2012, were 63% oil and 37% gas, compared to 51% oil and 49% gas in the prior year, with the change due to the reduced contribution of gas sales from Palm Valley. At Poplar, volumes were positively impacted by the EPU 117 well, which was completed in January 2012 in the Amsden formation, a new pool discovery at Poplar, by Magellan's consolidation of its interests in Poplar in September 2011 (see Note 2), and by the results of the continuing workover program. Gas sales volumes at Palm Valley decreased due to the termination of the 25 year PWC Contract during January 2012. Gas sales resumed in February 2012 under a month to month arrangement with Santos and were continued under a long-term gas sales agreement in May 2012 following completion of the Santos SA. The month to month arrangement was entered into with Santos while we were awaiting the

37

Completion of the Santos SA and represented sales to Santos that were subsequently sold on by Santos to third-party customers. Since February 2012, gas volumes sold under these arrangements were significantly lower relative to the prior year period, although volumes are expected to increase over time and reach approximately 1.5 Bcf per year by fiscal 2015. At Mereenie, oil sales volumes decreased primarily due to Magellan's sale of its interests in the field in May 2012.

Oil and Gas Prices

The following table presents the average realized oil and gas prices for the years ended:

	June 30,
	2012		2011		Difference		Percent change
Average realized price (1):
Poplar (USD/bbl)	$	82.66	$	77.96	$	4.70	6	%
Palm Valley (AUD/Mcf)	$	3.01	$	2.28	$	0.73	32	%
Mereenie oil (AUD/bbl)	$	132.92	$	99.67	$	33.25	33	%
Consolidated (USD/boe)	$	70.95	$	56.27	$	14.68	26	%

⁽¹⁾ Prices per bbl or per Mcf are reported net of royalties. Current period prices may be influenced by prior period royalty adjustments arising from annual royalty audits.

The average realized price for the year ended June 30, 2012, was $70.95/boe compared to $56.27/boe in the prior year period, an increase of 26%. This increase in price is primarily the result of an increase in the contribution of oil sales to total sales during the year ended June 30, 2012, as well as increased oil prices in the United States and Australia relative to the prior year. At present, the Company does not engage in any oil and gas hedging activities. Relative to the prior year period, the average realized price from oil sales at Poplar increased by 6% as a result of an increase in its benchmark pricing (WTI). The average realized gas price from Palm Valley increased by 32%, which reflects the higher gas prices realized under both monthly sales arrangements with Santos in place from February to May 2012 and the long-term gas sales contract in place with Santos from May 2012 compared to prices that were realized under the PWC Contract, which ended in January 2012. The gas price currently realized at Palm Valley is approximately AUD $4.7/Mcf, compared to AUD $2.3/Mcf under the terms of the prior long term gas sales contract. The average realized oil price from Mereenie increased by 33% as a result of an increase in its benchmark pricing (Tapis).

Revenues

The following table presents revenues for the years ended:

	June 30,
	2012			2011		Difference			Percent change
	(In thousands)
Net revenue by source:
Poplar (USD)	$	6,172		$	5,383	$	789		15	%
Palm Valley (USD)	1,347			1,778		(431		)	(24	)%
Mereenie (USD)	6,232			6,432		(200		)	(3	)%
Other (USD)	(39		)	4,583		(4,622		)	(101	)%
Total (USD)	$	13,712		$	18,176	$	(4,464	)	(25	)%
Palm Valley (AUD)	$	1,305		$	1,797	$	(492	)	(27	)%
Mereenie (AUD)	$	6,037		$	6,502	$	(465	)	(7	)%
Net revenues by type (USD):
Oil	$	12,405		$	11,815	$	590		5	%
Gas	1,353			1,796		(443		)	(25	)%
Other	(46		)	4,565		(4,611		)	(101	)%
Total	$	13,712		$	18,176	$	(4,464	)	(25	)%

Revenues for the year ended June 30, 2012, totaled $13.7 million, compared to $18.2 million in the prior year period, a decrease of 25%. The $4.5 milliondecrease in revenue was driven by the end of the Amadeus Gas Trust revenue stream on

38

June 16, 2011, which contributed $4.5 million to the Company’s revenues in the prior period. The decreases in revenues at Palm Valley and Mereenie was offset by an increase in revenues from Poplar.

Operating and Other Expenses

The following table presents selected operating expenses for the years ended:

	June 30,
	2012		2011		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	12,897	$	9,247	$	3,650		39	%
Depletion, depreciation, amortization, and accretion	$	1,744	$	2,890	$	(1,146	)	(40	)%
Exploration	$	6,291	$	2,854	$	3,437		120	%
General and administrative	$	13,091	$	16,307	$	(3,216	)	(20	)%
Selected operating expenses (USD/boe):
Lease operating	$	66	$	38	$	28		74	%
Depletion, depreciation, amortization, and accretion	$	9	$	12	$	(3	)	(25	)%
Exploration	$	32	$	12	$	20		167	%
General and administrative	$	67	$	67	$	—		—	%

Lease Operating Expenses. Lease operating expenses increased by $3.6 million to $12.9 million, or $66/boe, during the year ended June 30, 2012. Lease operating expenses at Poplar increased by approximately $2.2 million, of which $0.5 million related to increased workover activities and increased testing of production-enhancing technologies on certain wells. An additional $0.7 million was incurred during the current year compared to the prior year related to increased production taxes. Lease operating expenses in Australia increased by approximately $1.4 million, primarily as the result of higher costs at Palm Valley related to severance costs, following a reduction of field personnel and increased lease operating expenses at Mereenie. Mereenie contributed approximately $6.0 million to lease operating expenses incurred in the current year.

Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the years ended:

	June 30,
	2012		2011		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	433	$	441	$	(8	)	(2	)%
Depletion	743		1,885		(1,142		)	(61	)%
ARO accretion	568		564		4			1	%
Total	$	1,744	$	2,890	$	(1,146	)	(40	)%

Depletion, depreciation, amortization, and accretion expenses decreased by $1.1 million to $1.7 million, or $9/boe, during the year ended June 30, 2012. Depletion decreased in fiscal year 2012 relative to the same prior year period due to MPAL's Australian oil and gas assets being fully depleted as of September 30, 2010.

Exploration Expenses. Exploration expenses increased by $3.4 million to $6.3 million, or $32/boe, during the year ended June 30, 2012. The $3.4 million increase is the result of an increase of $1.0 million at NP and a $2.4 million increase at MPAL. Of the $6.3 million of exploration expenses incurred during the current period, $2.9 million related to non-cash exploration write offs, which included $1.2 million related to the EPU 119 well at Poplar and $1.5 million related to the Markwells Wood-1 well in the United Kingdom. The remaining $3.4 million were incurred towards general and seismic exploration costs, including $2.7 million incurred in the Weald Basin in the United Kingdom, $0.3 million related to analysis of the planned CO₂-EOR project at Poplar, and $0.4 million related to exploration costs incurred at Mereenie.

39

General and Administrative Expenses. The following table presents general and administrative expenses for the years ended:

	June 30,
	2012		2011		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation and foreign transaction loss)	$	10,493	$	13,686	$	(3,193	)	(23	)%
Stock based compensation	1,560		1,670		(110		)	(7	)%
Foreign transaction loss	1,038		951		87			9	%
Total	$	13,091	$	16,307	$	(3,216	)	(20	)%

General and administrative expenses decreased by $3.2 million to $13.1 million, during the year ended June 30, 2012. General and administrative expenses, excluding stock based compensation and foreign transaction losses and gains, amounted to $10.5 million, a decrease of $3.2 million, which was partially offset by the recording of a $0.9 million expense, which represents the Company's maximum liability with respect to a withholding tax issue that arose in connection with the Company's acquisition of Nautilus Poplar LLC in October 2009 (see Note 11). This decrease resulted from a significant reduction in the use of third party professional services of $3.0 million and a number of cost saving initiatives which were undertaken during the year but were partially offset by their respective implementation costs. In fiscal year 2012 relative to the prior year period, consulting fees decreased by $3.6 million, legal fees increased by $0.3 million, accounting related expenses decreased by $0.9 million, salary expenditures increased by $0.7 million in relation to the development and expansion of human resources in the Company and a bonus of $0.3 million was paid to employees.

COMPARISON OF FINANCIAL RESULTS AND TRENDS BETWEEN FISCAL 2011 AND 2010

Oil and Gas Sales Volumes

The following table presents oil and gas sales volumes for the years ended:

	June 30,
	2011	2010	Difference		Percent change
Net sales by field:
Poplar (Mbbls)	68	42	26		62	%
Palm Valley gas (MMcf)	712	1,166	(454	)	(39	)%
Mereenie gas (MMcf)	—	2,264	(2,264	)	(100	)%
Mereenie oil (Mbbls)	55	68	(13	)	(19	)%
Other MPAL oil sales (Mbbls)	—	29	(29	)	(100	)%
Total Australia sales (Mboe)	174	669	(495	)	(74	)%
Net sales by product:
Oil (Mbbls)	123	139	(16	)	(12	)%
Gas (MMcf)	712	3,430	(2,718	)	(79	)%
Consolidated sales (Mboe)	242	711	(469	)	(66	)%
Consolidated sales (boepd)	662	1,948	(1,286	)	(66	)%

Sales volumes for the year ended June 30, 2011, totaled 242 Mboe (662 boepd), compared to 711 Mboe (1,948 boepd) sold in the prior year, a decrease of 66%. Sales volumes by product for the year ended June 30, 2011, were 51% oil and 49% gas, compared to 20% oil and 80% gas in the prior year. At Poplar, volumes were positively impacted primarily by Magellan's purchases of additional working interests in the leases of Poplar. In Australia, oil volumes decreased primarily due to the sale of Cooper Basin and Nockatunga Assets in fiscal year 2010, while gas volumes were negatively impacted by the end of the Mereenie MSA4 gas sales contract in February 2010.

40

Oil and Gas Prices

The following table presents the average realized oil and gas prices for the years ended:

	June 30,
	2011		2010		Difference			Percent change
Average realized price (1):
Poplar (USD/bbl)	$	77.96	$	67.88	$	10.08		15	%
Palm Valley (AUD/Mcf)	$	2.28	$	2.25	$	0.03		1	%
Mereenie gas (AUD/Mcf)	$	—	$	6.53	$	(6.53	)	(100	)%
Mereenie oil (AUD/bbl)	$	99.67	$	85.50	$	14.17		17	%
Consolidated (USD/boe)	$	56.27	$	33.02	$	23.25		70	%

⁽¹⁾ Prices per bbl or per Mcf are reported net of royalties. Current period prices may be influenced by prior period royalty adjustments arising from annual royalty audits.

The average realized price for the year ended June 30, 2011, was $56.27/boe compared to $33.02/boe in the prior year period, an increase of 70%. This increase in price is primarily the result of increased oil prices in the United States and Australia, as well as an increase in the contribution of oil sales to total sales during the year ended June 30, 2011, relative to the prior year. At present, the Company does not engage in any oil and gas hedging activities. Relative to the prior year period, the average realized price from oil sales at Poplar increased by 15% as a result of increased benchmark pricing (WTI). The average realized gas price from Palm Valley increased by 1%, in line with the terms of its gas sales contract with the PWC Contract. The average realized oil price from Mereenie increased by 17% as a result of an increase in its benchmark pricing (Tapis).

Revenues

The following table presents revenues for the years ended:

	June 30,
	2011		2010		Difference			Percent change
	(In thousands)
Net revenue by source:
Poplar (USD)	$	5,383	$	2,594	$	2,789		108	%
Palm Valley (USD)	1,778		2,059		(281		)	(14	)%
Mereenie (USD)	6,432		18,826		(12,394		)	(66	)%
Other (USD)	4,583		5,046		(463		)	(9	)%
Total (USD)	$	18,176	$	28,525	$	(10,349	)	(36	)%
Palm Valley (AUD)	$	1,797	$	2,332	$	(535	)	(23	)%
Mereenie gas (AUD)	$	—	$	13,094	$	(13,094	)	(100	)%
Mereenie oil (AUD)	$	6,502	$	8,236	$	(1,734	)	(21	)%
Net revenues by type (USD):
Oil	$	11,815	$	9,887	$	1,928		20	%
Gas	1,796		13,616		(11,820		)	(87	)%
Other	4,565		5,022		(457		)	(9	)%
Total	$	18,176	$	28,525	$	(10,349	)	(36	)%

Revenues for the year ended June 30, 2011, totaled $18.2 million, compared to $28.5 million in the prior year period, a decrease of 36%. The $10.3 milliondecrease in revenue was primarily due to the end of the Mereenie MSA4 contract in February 2010, which was partially offset by an increase in revenues at Poplar.

41

Operating and Other Expenses

The following table presents selected operating expenses for the years ended:

	June 30,
	2011		2010		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	9,247	$	10,116	$	(869	)	(9	)%
Depletion, depreciation, amortization, and accretion	$	2,890	$	5,428	$	(2,538	)	(47	)%
Exploration	$	2,854	$	1,273	$	1,581		124	%
General and administrative	$	16,307	$	14,023	$	2,284		16	%
Selected operating expenses (USD/boe):
Lease operating	$	38	$	14	$	24		171	%
Depletion, depreciation, amortization, and accretion	$	12	$	8	$	4		50	%
Exploration	$	12	$	2	$	10		500	%
General and administrative	$	67	$	20	$	47		235	%

Lease Operating Expenses. Lease operating expenses decreased$0.9 million to $9.2 million, or $38/boe, during the year ended June 30, 2011. Lease operating expenses decreased due to the result of cost reduction efforts at Mereenie and Palm Valley, which included a new transportation contract at Mereenie, the elimination of prior year pipeline repair costs at Mereenie, and the elimination of production repair costs related to the Cooper Basin Assets sold in fiscal year 2010. These cost reductions were offset by increases in production costs related to Magellan's increased ownership of working interests in the leases of Poplar.

Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the years ended:

	June 30,
	2011		2010		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	441	$	436	$	5		1	%
Depletion	1,885		4,244		(2,359		)	(56	)%
ARO accretion	564		748		(184		)	(25	)%
Total	$	2,890	$	5,428	$	(2,538	)	(47	)%

Depletion, depreciation, amortization, and accretion expenses decreased$2.5 million to $2.9 million, or $12/boe, during the year ended June 30, 2011. Depletion decreased in fiscal 2011 relative to the prior year period due MPAL's SEC defined reserves for oil were non-economic as of June 30, 2010.

Exploration Expenses. Exploration expenses increased by $1.6 million to $2.9 million, or $12/boe, during the year ended June 30, 2011. The $1.6 million increase is the result of an increase of $0.5 million at NP and $1.1 million increase at MPAL. Of the $2.9 million, $0.4 million related to Poplar, $0.4 million related to the Bonaparte and Maryborough Basins, $0.5 million related to Mereenie, and $1.6 million related to general exploration in the Weald Basin.

42

General and Administrative Expenses. The following table presents general and administrative expenses for the years ended:

	June 30,
	2011		2010		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation and foreign transaction loss)	$	13,686	$	11,041	$	2,645		24	%
Stock based compensation	1,670		2,305		(635		)	(28	)%
Foreign transaction loss	951		677		274			40	%
Total	$	16,307	$	14,023	$	2,284		16	%

General and administrative expenses increased$2.3 million to $16.3 million, or $67/boe, during the year ended June 30, 2011. General and administrative expenses, excluding stock based compensation and foreign transaction losses and gains, increased by $2.6 million to $13.7 million, or $57/boe. This increase resulted from $2.0 million in increased consulting costs and $0.5 million in increased legal costs related to the Evans Shoal transaction and an increase in severance payments of $0.1 million due to the departure of a senior executive during the year ended June 30, 2011.

OFF-BALANCE SHEET ARRANGEMENTS

The Company does not use off-balance sheet arrangements, such as securitization of receivables, with any unconsolidated entities or other parties.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates, and judgments made by management in Note 1 to our consolidated financial statements. We have outlined below certain more significant estimates and assumptions used in preparation of our consolidated financial statements.

Oil and Gas Properties

Successful Efforts Accounting. We account for our oil and gas operations using the successful efforts method of accounting. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within the consolidated statement of cash flows and reported as capital expenditures under investing activities. The costs of development wells are capitalized whether those wells are successful or unsuccessful. The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which classification will ultimately determine the proper accounting treatment of the costs incurred. Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found.

Oil and Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and FASB. Our independent third party engineering firms adhere to the same guidelines when auditing our reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the reserves estimates. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas

43

eventually recovered.

Depreciation, Depletion, and Amortization. The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method and is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record depreciation, depletion and amortization ("DD&A") expense increases, which in turn, increases DD&A expense. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Impairment of Oil and Gas Properties. Oil and gas properties are assessed annually, or more frequently as economic events dictate, for potential impairment. Any impairment loss is the difference between the carrying value of the asset and its fair value. We estimate the fair value using expected future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the cost of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. Different pricing assumptions (see Note 13) or discount rates could result in a different calculated impairment.

Asset Retirement Obligation. Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and gas properties. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions, and judgments regarding such factors as amounts, future advances in technology, timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact operating results as accretion expense. The related capitalized cost, net of estimated salvage values, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Revenue Recognition

We record revenues from the sale of oil and gas in the month in which the delivery to the purchaser occurred and title transferred. We receive payment one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, any differences have been insignificant.

Stock Based Compensation

We recognize compensation expense for all share-based payment awards made to employees and directors. Stock based compensation expense is measured at the grant date based on the fair value of the award. Judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. The Black-Scholes-Merton pricing model uses assumptions regarding expected volatility of our common stock, the risk-free interest rates, expected term of the awards, and other valuation inputs, which are subject to change. Any such changes could result in different valuations and thus impact the amount of stock based compensation expense recognized.

Costs related to time based stock options are recognized as an expense on a straight-line basis over the requisite service period, which is generally the vesting period. Performance based options are recognized when the achievement of the performance conditions is considered probable. Management re-assesses whether satisfaction of performance conditions are probable at the end of each reporting period. As of June 30, 2012, management believes the achievement of the performance conditions related to the performance based stock options is probable.

We recorded non-cash stock based compensation expense for the years ended June 30, 2012, 2011, and 2010, of $1.6 million, $1.7 million, and $2.3 million, respectively.

Income Taxes and Uncertain Tax Positions

We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of our deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

44

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Previously recognized uncertain tax positions that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. We currently do not have any uncertain tax positions recorded as of June 30, 2012.

Foreign Currenciesand Foreign Currency Adjustment of Intercompany Loans

When intercompany foreign currency transactions between entities included in the consolidated financial statements are of a long-term investment nature (i.e., those for which settlement is not planned or anticipated in the foreseeable future) foreign currency translation adjustments resulting from those transactions are included in stockholders' equity as accumulated other comprehensive income (loss). However, when intercompany transactions are deemed to be of a short term nature, translation adjustments are required to be included in the consolidated statement of operations.

As a result of the Company's repatriation of Australian held funds to the U.S. during the first quarter of fiscal year 2013, we will need to assess whether all investments and intercompany transactions would continue to be considered long-term in nature. In the event certain transactions and/or investments are no longer considered long-term in nature, any subsequent foreign currency translation adjustments associated with such items would be required to be reflected in the Company's future statements of operations. Accordingly, if foreign currency translation adjustments are required to be reported in our future statements of operations, exchange rate volatility could have a significant effect on future period results of operations.

During fiscal 2012, all foreign currency translation adjustments were recorded as a separate component of stockholders' equity as accumulated other comprehensive income (loss).

Accounting for Business Combinations

The Company continues to pursue acquisitions as opportunities arise in order to grow our business. We have accounted for all of our business combinations to date in accordance with guidelines established by FASB, using the acquisition method of accounting, which involves the use of significant judgment.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market based weighted average cost of capital rate, adjusted for risk, determined to be appropriate at the time of the acquisition.

The fair value of contingent consideration is calculated using production projections and the estimated timing of production payouts. The Company also utilized a discount factor which is consistent with the rate used in valuing its asset retirement obligation and reflects the Company’s credit adjusted incremental borrowing rate.

Authoritative Accounting Matters

See "Recently Issued Accounting Standards" under Note 1 for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8: Financial Statements and Supplementary Data of this Form 10-K.

FORWARD LOOKING STATEMENTS

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

Among these risks and uncertainties are: (i) whether the Company can successfully achieve cost savings while delivering revenue growth; (ii) whether the workovers, recompletions, and other drilling at Poplar will result in increased production and cash generation and/or will otherwise successfully assist in the development of Poplar; and (iii) the production levels from the properties in which the Company, through its subsidiaries, have interests, the recoverable reserves at those properties, and the prices that will ultimately be applied to the sale of such reserves and other risks described under the caption "Risk Factors" in

45

this Annual Report on Form 10-K. The Company assumes no obligation to update any forward looking statements contained in this report, whether as a result of new information, future events, or otherwise, except as required by securities laws.

ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company's exposure to market risk relates to fluctuations in foreign currency and world prices for crude oil, as well as market risk related to investment in marketable securities. The exchange rates between the Australian dollar and the U.S. dollar, as well as the exchange rates between the U.S. dollar and the British pound, have changed in recent periods and may fluctuate substantially in the future. Any appreciation of the U.S. dollar against the Australian dollar is likely to have a negative impact on our revenue, operating income, and net income. Because of our U.K. development program, a portion of our expenses, including exploration costs and capital and operating expenditures will continue to be denominated in British pound. Accordingly, any material appreciation of the British pound against the Australian and U.S. dollars could have a negative impact on our business, operating results, and financial condition.

For the twelve months ended June 30, 2012, oil sales represented approximately 63% of total oil and gas revenues. Based on fiscal year 2012 sales volume and revenues, a 10% change in oil price would increase or decrease oil revenues by $1.2 million. Gas sales, which represented approximately 37% of total oil and gas revenues in the current twelve months, are derived primarily from the Palm Valley gas field in the Northern Territory of Australia and the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index for the twelve months ended June 30, 2012.

At June 30, 2012, the carrying value of cash and cash equivalents was approximately $41.2 million, which approximates the fair value.

46

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Magellan Petroleum Corporation

Denver, Colorado

We have audited the consolidated balance sheet of Magellan Petroleum Corporation and subsidiaries (the "Company") as of June 30, 2012, and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for the year ended June 30, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company as of June 30, 2011 and for the years ended June 30, 2011 and 2010, before the effects of retrospective adjustments applied for (1) for the adoption of Accounting Standards Update No. 2011-5, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, as amended ("ASU 2011-5") discussed in Note 1 to the consolidated financial statements, (2) to the disclosures for a change in the composition of reportable segments discussed in Notes 1 and 9 to the consolidated financial statements, and (3) for reclassifications to certain financial statement captions to conform the presentation of the consolidated financial statements to industry-specific norms discussed in Notes 1 and 16 to the consolidated financial statements, were audited by other auditors whose report, dated September 20, 2011, expressed an unqualified opinion on those consolidated financial statements.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements, present fairly, in all material respects, the financial position of Magellan Petroleum Corporation and subsidiaries as of June 30, 2012, and the results of their operations and their cash flows for the year ended June 30, 2012, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1 and 16 to the consolidated financial statements the Company made reclassifications to certain 2011 and 2010 financial statement captions to conform the presentation with the 2012 consolidated financial statement presentation which management believes better aligns with industry-specific norms.

Also as discussed in Note 1, the Company early adopted Accounting Standards No. 2011-5, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, as amended ("ASU 2011-5")

We have also audited the adjustments to the 2011 and 2010 consolidated financial statements to retrospectively apply the (1) adoption of Accounting Standards No. 2011-5, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, as amended ("ASU 2011-5") discussed in Note 1 to the consolidated financial statements, (2) to the disclosures for a change in the composition of reportable segments discussed in Notes 1 and 9 to the consolidated financial statements, and (3) for reclassifications to certain financial statement captions to conform the presentation of the consolidated financial statements to industry-specific norms discussed in Notes 1 and 16 to the consolidated financial statements. Our procedures included evaluating the comparability of the retrospective application to each of the items described above. In our opinion, such retrospective adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2011 or 2010 consolidated financial statements of the Company other than with respect to the retrospective adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2011 or 2010 consolidated financial statements taken as a whole.

/s/ Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado

September 24, 2012

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Magellan Petroleum Corporation

Portland, Maine

We have audited, before the effects of the retrospective adjustments (1) for the adoption of Accounting Standards Update No. 2011-5, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, as amended ("ASU 2011-5"), (2) to the disclosures for a change in the composition of reportable segments, and (3) for reclassifications to certain financial statement captions to conform the presentation of the financial statements to industry-specific norms discussed in Notes 1 and 16 to the consolidated financial statements, the consolidated balance sheet of Magellan Petroleum Corporation and subsidiaries (the "Company") as of June 30, 2011, and the related consolidated statements of operations, changes in equity and comprehensive loss, and cash flows for the years ended June 30, 2011 and June 30, 2010 (the 2011 and 2010 consolidated financial statements before the effects of the adjustments discussed in Note 1 to the consolidated financial statements are not presented herein). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such 2011 and 2010 consolidated financial statements, before the effects of the adjustments to retrospectively apply the reclassifications and the adoption of ASU 2011-5, both of which are discussed in Notes 1 and 16 to the consolidated financial statements, present fairly, in all material respects, the financial position of Magellan Petroleum Corporation and subsidiaries as of June 30, 2011, and the results of their operations and their cash flows for the years ended June 30, 2011 and 2010, in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to audit, review, or apply any procedures to the retrospective adjustments for the adoption of ASU 2011-5, to the disclosures for a change in the composition of reportable segments and for reclassifications to certain financial statement captions, discussed in Notes 1 and 16 to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.

/s/ Deloitte & Touche LLP

Hartford, Connecticut

September 24, 2012

48

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share amounts)

	June 30,
ASSETS	2012			2011
CURRENT ASSETS:
Cash and cash equivalents	$	41,215		$	20,417
Accounts receivable — trade (net of allowance for doubtful accounts of $0 and $66 as of June 30, 2012, and 2011, respectively)	1,152			4,357
Accounts receivable — working interest partners	231			454
Deposit on Evans Shoal	—			10,745
Inventories	499			732
Prepaid assets	498			517
Other assets	13			62
Total current assets	43,608			37,284
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Proved oil and gas properties	33,927			136,094
Less accumulated depletion, depreciation, and amortization	(5,740		)	(115,917		)
Unproved oil and gas properties	7,091			3,368
Wells in progress	3,744			4,315
Land, buildings and equipment (net of accumulated depreciation of $2,077 and $3,985 as of June 30, 2012, and 2011, respectively)	1,422			1,293
Net property and equipment	40,444			29,153
OTHER NON-CURRENT ASSETS
Securities available for sale	155			238
Goodwill	2,174			4,695
Deferred income taxes	5,951			—
Other long term assets	242			204
Total other non-current assets	8,522			5,137
Total assets	$	92,574		$	71,574
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Short term line of credit	$	50		$	1
Current portion of note payable	480			552
Current portion of asset retirement obligations	329			—
Accounts payable	3,672			3,861
Accrued and other liabilities	3,000			2,055
Total current liabilities	7,531			6,469
LONG TERM LIABILITIES:
Note payable	390			870
Asset retirement obligations	7,455			11,397
Contingent consideration payable	4,072			—
Other long term liabilities	218			310
Total long term liabilities	12,135			12,577

49

COMMITMENTS AND CONTINGENCIES (Note 10)
Equity:
Common stock (par value $.01 per share): Authorized 300,000,000 shares, outstanding, 53,835,594 and 52,455,977 as of June 30, 2012 and 2011, respectively	538			525
Capital in excess of par value	90,753			93,617
Preferred stock (par value $.01 per share): Authorized 50,000,000 and 0 shares, outstanding, 0 and 0 as of June 30, 2012 and 2011, respectively	—			—
Accumulated deficit	(29,590		)	(56,073		)
Accumulated other comprehensive income	11,207			12,470
Total equity attributable to Magellan Petroleum Corporation	72,908			50,539
NON-CONTROLLING INTEREST IN SUBSIDIARIES	—			1,989
Total equity	72,908			52,528
Total liabilities and equity	$	92,574		$	71,574

The accompanying notes are an integral part of these consolidated financial statements.

50

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	For the years ended June 30,
	2012			2011			2010
REVENUES:
Oil production	$	12,405		$	11,815		$	9,887
Gas production	1,353			1,796			13,616
Other	(46		)	4,565			5,022
Total revenues	13,712			18,176			28,525
OPERATING EXPENSES:
Lease operating	12,897			9,247			10,116
Depletion, depreciation, amortization, and accretion	1,744			2,890			5,428
Exploration	6,291			2,854			1,273
General and administrative	13,091			16,307			14,023
Impairment	328			173			2,050
Loss on Evans Shoal	—			15,893			—
Gain on sale of assets	(40,413		)	(969		)	(6,817		)
Total operating (income) expense	(6,062		)	46,395			26,073
Income (loss) from operations	19,774			(28,219		)	2,452
Other income (expense)
Warrant expense	—			—			(4,276		)
Net interest income	749			923			1,038
Other income	9			—			1,975
Total other income (expense)	758			923			(1,263		)
Income (loss) before income tax	20,532			(27,296		)	1,189
Income tax benefit (provision)	5,951			(5,141		)	(2,646		)
Net income (loss) after income tax	26,483			(32,437		)	(1,457		)
Net loss attributable to non-controlling interest in subsidiaries	15			5			11
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498		$	(32,432	)	$	(1,446	)
Earnings per common share (Note 8)
Weighted average number of basic shares outstanding	53,592,958			52,398,936			51,410,596
Weighted average number of diluted shares outstanding	54,041,227			52,398,936			51,410,596
Net income (loss) per basic share outstanding	$	0.49		$	(0.62	)	$	(0.03	)
Net income (loss) per diluted share outstanding	$	0.49		$	(0.62	)	$	(0.03	)

The accompanying notes are an integral part of these consolidated financial statements.

51

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	For the years ended June 30,
	2012			2011			2010
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498		$	(32,432	)	$	(1,446	)
Foreign currency translation adjustments	(1,180		)	9,308			1,358
Unrealized holding (losses) gains on securities available for sale, net of deferred tax of $0	(83		)	46			(222		)
Total comprehensive income (loss)	25,235			(23,078		)	(310		)
Net loss attributable to non-controlling interest in subsidiary	(15		)	(5		)	(11		)
Comprehensive income (loss) attributable to Magellan Petroleum Corporation	$	25,220		$	(23,083	)	$	(321	)

The accompanying notes are an integral part of these consolidated financial statements.

52

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands, except share and per share amounts)

	Common Stock			Capital in Excess of Par Value			Accumulated Deficit			Accumulated Other Comprehensive Income			Non-Controlling Interest			Total Stockholders' Equity
	Shares	Amount
Balance June 30, 2009	41,500,325	$	416	$	73,311		$	(22,195	)	$	1,980		$	—		$	53,512
Net loss	—	—		—			(1,446		)	—			(11		)	(1,457		)
Foreign currency translation adjustments	—	—		—			—			1,358			—			1,358
Unrealized holding loss on securities available for sale, net of taxes	—	—		—			—			(222		)	—			(222		)
Stock and stock based compensation	440,000	4		2,301			—			—			—			2,305
Equity investment by YEP	8,695,652	87		7,528			—			—			—			7,615
Warrants issued	—	—		6,402			—			—			—			6,402
Acquisition of controlling interest	1,700,000	17		2,363			—			—			1,925			4,305
Balance June 30, 2010	52,335,977	524		91,905			(23,641		)	3,116			1,914			73,818
Net loss	—	—		—			(32,432		)	—			(5		)	(32,437		)
Foreign currency translation adjustments	—	—		—			—			9,308			—			9,308
Unrealized holding gain on securities available for sale, net of taxes	—	—		—			—			46			—			46
Stock and stock based compensation	90,000	1		1,669			—			—			—			1,670
Stock options exercised	30,000	—		43			—			—			—			43
Capital contribution	—	—		—			—			—			80			80
Balance June 30, 2011	52,455,977	525		93,617			(56,073		)	12,470			1,989			52,528
Net income	—	—		—			26,498			—			(15		)	26,483
Foreign currency translation adjustments	—	—		—			—			(1,180		)	—			(1,180		)
Unrealized holding loss on securities available for sale, net of taxes	—	—		—			—			(83		)	—			(83		)
Stock and stock based compensation	175,000	2		1,558			—			—			—			1,560
Stock options exercised	21,875	—		35			—			—			—			35
Acquisition of non-controlling interest	927,352	9		(4,844		)	(15		)	—			(1,974		)	(6,824		)
Acquisition of working interest	255,390	2		387			—			—			—			389
Balance June 30, 2012	53,835,594	$	538	$	90,753		$	(29,590	)	$	11,207		$	—		$	72,908

The accompanying notes are an integral part of these consolidated financial statements.

53

MAGELLAN PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	For the years ended June 30,
	2012			2011			2010
OPERATING ACTIVITIES:
Net income (loss) after income tax	$	26,483		$	(32,437	)	$	(1,457	)
Adjustments to reconcile net loss to net cash used in operating activities
Foreign transaction (gain) loss	(1,038		)	499			732
Write off of the Evans Shoal deposit	—			15,893			—
Depletion, depreciation, and amortization	1,744			2,890			5,428
Interest earned on restricted deposits	(24		)	(150		)	—
Fair value increase of contingent consideration payable	(79		)	—			—
Deferred income taxes	(5,951		)	5,355			922
Gain on disposal of assets	(40,413		)	(969		)	(6,817		)
Gain on sale of investments	—			—			(1,975		)
Exploration costs previously capitalized	2,930			(124		)	—
Stock based compensation	1,560			1,670			6,582
Related party withholding tax (Note 11)	1,082			—			—
Impairment loss	328			239			2,050
Net changes in operating assets and liabilities:
Accounts receivable	3,021			625			2,733
Inventories	142			143			647
Prepayments and other current assets	(36		)	213			(106		)
Accounts payable and accrued liabilities	(138		)	613			(1,689		)
Other long term liabilities	(113		)	—			—
Income taxes payable	61			1,045			(3,098		)
Net cash (used in) provided by operating activities	(10,441		)	(4,495		)	3,952
INVESTING ACTIVITIES:
Additions to property and equipment	(9,577		)	(4,568		)	(2,843		)
Proceeds from sale of assets	35,089			1,481			7,280
Purchase of working interest in Poplar	(823		)	(380		)	(4,090		)
Cash acquired from controlling interest purchase - Nautilus Poplar LLC	—			—			315
Increase in restricted cash	—			—			(75		)
Refund (Payment) of Deposit for Purchase of Evans shoal (includes interest)	10,940			(10,014		)	(13,752		)
Proceeds from sale of securities	—			—			465
Securities matured or sold	5,687			7,000			16,809
Securities purchased	(5,687		)	(7,000		)	(13,456		)
Net cash provided by (used in) investing activities	35,629			(13,481		)	(9,347		)
FINANCING ACTIVITIES:
Proceeds from issuance of stock	35			43			10,000
Short term debt issuances	6,075			5,027			570
Short term debt repayments	(6,025		)	(4,589		)	(845		)
Purchase of non-controlling interest - Nautilus Poplar LLC	(3,461		)	—			(7,309		)
Non-controlling capital contribution - Nautilus Poplar LLC	—			80			—
Long term debt repayments	(552		)	—			—
Net cash (used in) provided by financing activities	(3,928		)	561			2,416

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Effect of exchange rate changes on cash and cash equivalents	(462		)	4,240			1,882
Net increase (decrease) in cash and cash equivalents	20,798			(13,175		)	(1,097		)
Cash and cash equivalents at beginning of period	20,417			33,592			34,689
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	41,215		$	20,417		$	33,592
Cash payments (receipts):
Income taxes	—			(1,259		)	4,822
Interest paid, net of amount capitalized	109			141			62
Supplemental schedule of non-cash investing and financing activities:
Unrealized holding gain (loss)	(83		)	46			—
Revision to estimate of asset retirement obligation	(603		)	(129		)	(2,232		)
Accounts payable related to property, plant, and equipment	155			8			48
Purchase of non-controlling interest for stock and contingent consideration	4,729			—			—
Purchase of 3% working interest for stock and contingent consideration	1,243			—			—

The accompanying notes are an integral part of these consolidated financial statements.

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MAGELLAN PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Basis of Presentation

Description of Operations

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we" or "us") is an independent energy company engaged in the acquisition, exploration, exploitation, development, production, and sale of crude oil and natural gas. As of June 30, 2012, Magellan had two reporting segments: (i) a 100% membership interest in Nautilus Poplar LLC ("NP"), based in Denver, Colorado, and (ii) a 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited ("MPAL"), headquartered in Brisbane, Australia, which includes our operations in the United Kingdom.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP and MPAL, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") and the instructions to Form 10-K and Regulation S-X. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation. The Company has evaluated events or transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.

All amounts presented are in United States dollars, unless otherwise noted. Amounts expressed in Australian currency are indicated as "AUD."

Reclassification

As of December 31, 2011, we have changed the presentation of our financial statements to conform them to industry-specific norms and to improve our reporting to shareholders and stakeholders. Specifically, we have modified the presentation of expenses in the consolidated statements of operations and the presentation of property and equipment in the consolidated balance sheets. As a result, certain reclassifications have been made to the prior period financial statements to align them with this revised presentation format, there was no impact on previously reported results (see Note 16).

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign Currency Translation

The functional currency of our foreign subsidiaries is their local currency. Assets and liabilities of foreign subsidiaries are translated to United States dollars at period-end exchange rates, and our consolidated statements of operations and cash flows are translated at average exchange rates during the period. Resulting translation adjustments are recorded as a separate component of stockholders' equity as accumulated other comprehensive income (loss).

Transactions denominated in currencies other than the local currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in foreign currency transaction gains and losses that are reflected in results of operations as unrealized (based on period end translation) or realized (upon settlement of the transactions) and reported under general and administrative expenses.

Cash and Cash Equivalents and Concentration of Credit Risk

The Company considers all highly liquid short term investments with original maturities of three months or less at the date of acquisition to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short term nature of these instruments.

The Company's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents. Large balances of cash and cash equivalents were held in several Australian banks in time deposit accounts that have terms of 90 days or less. The Company regularly assesses the level of credit risk we are exposed to and whether there are better ways of managing credit risk. The Company invests its cash and cash equivalents with reputable financial institutions. At times, balances deposited may exceed FDIC insured limits. The Company has not incurred any losses related to these deposits.

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Accounts Receivables and Allowance for Doubtful Accounts

Trade accounts receivable consist mainly of receivables from oil and gas purchasers. For receivables from working interest partners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and gas receivables are collected within two months. We continuously monitor collectability of accounts receivables and use our judgment in establishing a provision for allowance for doubtful accounts based upon our historical experience and any specific customer collection issues we identify.

Inventories

Our inventories consist of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials, and parts and production equipment for use in future drilling operations or repair operations. All inventories are carried at the lower of cost or net realizable value.

Oil and Gas Exploration and Production Activities

The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within the consolidated statement of cash flows and reported as capital expenditures under investing activities. The costs of development wells are capitalized whether those wells are successful or unsuccessful.

Geological and geophysical costs and the costs of carrying and retaining unproved properties are expensed as incurred to exploration expense. Depreciation, depletion, and amortization ("DD&A") of capitalized costs related to proved oil and gas properties is calculated on a property-by-property basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. The Company records its proportionate share in joint venture operations in the respective classifications of assets, liabilities, and expenses.

The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement, and no gain or loss is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. A gain or loss is recognized for all other sales of producing properties and is included in the accompanying consolidated statements of operations.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs, using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

Land, Buildings, and Equipment

Land, buildings, and equipment and field equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets which range from three to fifteen years.

Securities Available for Sale

Securities available for sale are comprised of investments in publicly traded securities and are carried at quoted market prices. Unrealized gains and losses are excluded from earnings and recorded as a component of accumulated other comprehensive income in shareholders' equity, net of deferred income taxes, until realized.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. We adopted the new guidance for our annual impairment test in 2012 as allowed by ASU 2011-08, and therefore performed an assessment of qualitative factors for our annual impairment test in 2012 resulting in the conclusion that there is no impairment of goodwill. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors,

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and overall financial performance.

The Company has determined that it has two reporting units, NP and MPAL. Historical goodwill in the amount of $0.7 million relates to the acquisition of a majority ownership stake in NP and $4.0 million relates to the acquisition of and additional ownership interest in MPAL. The decrease in goodwill during fiscal 2012 relates to the disposition of a portion of the MPAL reporting segment associated with the Santos SA (see Note 2). As of June 30, 2012, $1.5 million of recorded goodwill related to MPAL, and $0.7 million related to NP.

The change in the carrying amount of goodwill can be summarized as follows:

	June 30, 2012
	(In thousands)
Fiscal year ended June 30, 2011	$	4,695
Sale of Mereenie interests (see Note 2)	2,521
Fiscal year ended June 30, 2012	$	2,174

Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is acquired or the liability to plug is legally incurred. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs, net of estimated salvage values, and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties (see Note 4).

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil and gas. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. Other production related revenues correspond primarily to the Company's share of gas pipeline tariff revenues which are recorded on a gross basis at the time of sale. Transportation costs are included in production costs.

Major Customers

For our NP reporting segment, revenue from a single customer accounted for approximately 45%, 30%, and 8% of the Company's consolidated oil and gas production revenue for the years ended June 30, 2012, 2011, and 2010, respectively. For our MPAL reporting segment, revenue from one customer accounted for approximately 45%, 35% , and 25% of consolidated oil and gas production revenues for the years ended June 30, 2012, 2011, and 2010, respectively; revenue from another customer accounted for approximately 8%, 11%, and 10% of consolidated oil and gas production revenues in the same periods, respectively.

Preferred Stock

The Company has 50.0 million shares of preferred stock authorized, par value $0.01 per share, issuable from time to time in one or more series issuable at the discretion of the Company's Board of Directors. As of June 30, 2012, and 2011, no preferred stock was outstanding.

Stock Based Compensation

The Company records compensation expense for time based options on a straight-line basis over the vesting period. Performance based options are recognized when the achievement of the performance conditions is considered probable. We estimate the fair value of all performance and non-performance based stock options using the Black-Scholes-Merton pricing model. The fair value of the stock options is determined on the grant date and is affected by our stock price, and other assumptions regarding a number of complex and subjective variables. These variables include our expected stock price volatility over the term of the awards, risk free interest rates, expected dividends, and the expected option exercise term. The lack of historical data related to the exercise of options leads the Company to use the simplified method to estimate the expected term of options.

Accounting for Income Taxes

The Company follows the liability method in accounting for income taxes. Under this method, deferred tax assets and

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

GAAP prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the Company has taken or expects to take in its tax returns. Under GAAP, the Company recognizes tax positions when it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company has presumed that its positions will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The next step consists of measurement. A tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. A tax position is measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. An uncertain income tax position will not be recognized if it does not meet the more-likely-than-not threshold. To appropriately account for income tax matters, the Company is required to make significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. There are no significant uncertain tax positions for either fiscal year 2012 or 2011.

The Company has adopted an accounting policy to record all tax related interest under the interest expense and tax related penalties under general and administrative expense in the consolidated statement of operations.

Financial Instruments

The carrying value for cash and cash equivalents, accounts receivable, marketable securities, accounts payable, and debt approximates fair value based on the timing of the anticipated cash flows and current market conditions.

Business Combinations

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

The fair value of contingent considerations are calculated using production projections and the estimated timing of production payouts. The Company also utilized a discount which is consistent with the rate used in valuing its asset retirement obligation and reflective of the Company’s credit adjusted incremental borrowing rate.

Segment Information

Prior to September 30, 2011, our reportable segments included Magellan ("Corporate"), NP, and MPAL. During the quarter ended September 30, 2011, Magellan completed a restructuring of its North American assets (see Note 2) resulting in a change to its reportable segments. Certain prior period groupings for the fiscal years ended June 30, 2011, and 2010, have been reclassified to conform to the current year segment presentation.

As of June 30, 2012, the Company had two reportable segments, NP and MPAL, as well as a head office which is treated as a cost center. The Company’s chief operating decision maker is J. Thomas Wilson (President and CEO of the Company) who reviews the results of the Australian and North American businesses on a regular basis. Both segments engage in business activities from which each may earn revenues and incur expenses. MPAL and its subsidiaries, which include our operations in the United Kingdom, are considered one segment.

Earnings (Loss) per Share

Income and losses per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The reconciling items in the calculation of diluted earnings per share are the dilutive effect of stock options, warrants, and restricted non-vested shares. The potential dilutive impact of non-vested shares is determined using the treasury stock method. The dilutive impact of stock options and warrants is also determined using the treasury stock method.

For the years ended June 30, 2012, 2011, and 2010, the Company had 7,522,826, 9,297,826, and 8,127,826 options and warrants outstanding, respectively, that had an exercise price below the average stock price that would have resulted in 448,269, 3,460,331, and 1,634,797, incremental dilutive shares, respectively. The Company also had 100,000, 104,167, and 208,334 non-vested options for shares of Company stock that would have resulted in zero incremental dilutive shares for the

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years ended June 30, 2012, 2011, and 2010. There were no other potentially dilutive items for the years ended June 30, 2012, 2011, and 2010. There was no dilutive effect on earnings per share for years ended June 30, 2011, and 2010, as a result of net losses.

Accumulated Other Comprehensive Income (Loss)

Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders' equity instead of net income (loss).

Recently Issued Accounting Standards

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and IFRS ("ASU 2011-04"), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards. The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments did not have a significant impact on companies applying GAAP. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this standard did not have an impact on the Company’s consolidated financial statements other than additional disclosures (see Note 5).

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (amended further under ASU No. 2011-12 in December 2011). This guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. The guidance allows two presentation alternatives: present items in net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income; or present items in two separate, but consecutive, statements of net income and other comprehensive income. This guidance is is effective for interim and annual periods beginning after December 15, 2011. Full retrospective application is required under both sets of accounting standards. The adoption of this standard did not have an impact on the Company’s consolidated financial statements.

In September 2011, the FASB issued Accounting Standards Update No. 2011-08, Intangibles – Goodwill and Other: Testing Goodwill for Impairment ("ASU 2011-08"), which provides amendments to FASB ASC Topic 350, Intangibles – Goodwill and Other. The objective of ASU 2011-08 is to simplify how entities test goodwill for impairment. The amendment provides an entity with the option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. ASU 2011-08 is effective for interim and annual goodwill impairment tests performed for annual periods beginning after December 15, 2011. The adoption of this standard did not have an impact on the Company’s consolidated financial statements.

Note 2 - Acquisitions and Divestitures

Evans Shoal Agreement. During the year ended June 30, 2010,MPAL entered into an agreement with Santos Offshore Pty Ltd to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48). On July 22, 2011, this agreement was terminated, and MPAL received a deposit refund from Santos of AUD $10.0 million, plus interest, pursuant to the terms of the agreement.

Sale Agreement between Magellan Petroleum (N.T.) Pty Ltd and Santos QNT Pty Ltd and Santos Limited. On May 25, 2012, Magellan Petroleum (N.T.) Pty Ltd ("Magellan NT"), a wholly owned subsidiary of MPAL, and Santos QNT Pty Ltd ("Santos QNT") and Santos Limited (collectively the "Santos Entities") completed a Sale Agreement (the "Santos SA"), referred to herein as the "Santos Transaction" and became the sole owner of the Palm Valley Interests (as defined below) and of the Dingo Interests (as defined below), while Santos became the sole owner of the Mereenie Interests (as defined below). In accordance with the terms of the Santos SA, the Santos Transaction is deemed to be effective as of July 1, 2011. The Santos SA resulted in net cash proceeds of $26.6 million, including adjustments of $1.1 million, and a gain on sale of assets in the amount of $36.2 million. The Santos SA provided for the transfer of the following assets:

• Magellan NT's 35% interest in each of the Mereenie Operating Joint Venture and the Mereenie Pipeline Joint Venture (collectively, the "Mereenie Interests") to Santos QNT;

• The Santos Entities' combined interests of 48% in the Palm Valley Joint Venture ("Palm Valley Interests") and combined interests of 66% in the Dingo Joint Venture ("Dingo Interests") to Magellan NT.

Pursuant to the Santos SA, Magellan NT is also entitled to a series of contingent payments. The Company has not

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recognized a contingent asset related to the series of contingent payments, as such amounts are not reasonably assured. The Company accounted for the Santos SA using the relative fair value method of accounting, which allocates the fair value of the assets received in the asset transfer to the Palm Valley Interests and the Dingo Interests. No goodwill or other intangible assets were recorded as a result of the Santos SA. However, goodwill in the amount of $2.5 million was recorded as a component of the gain on sale of assets. The purchase price allocation was considered final as of June 30, 2012.

The following table summarizes the allocation of the consideration received for the assets transferred as a result of the Santos SA as of June 30, 2012.

	Total
	(In thousands)
Consideration received
Net purchase price per Santos SA	$	25,493
Purchase price adjustments	1,138
Total	$	26,631
Allocation of the consideration received to fair value of assets
Proved oil and gas properties (Palm Valley)	$	3,403
Unproved oil and gas properties (Dingo)	2,957
Land, buildings, and equipment (Palm Valley)	370
Total allocation of the fair value received	6,730
Mereenie liabilities given up, net	2,805
Gain on sale of assets	(36,166		)
Total	$	(26,631	)

The Santos SA is deemed to be effective as of July 1, 2011. The following unaudited pro forma financial information presents combined results of the Santos SA, and assumes a transaction date of July 1, 2010. The pro forma financial information is presented for informational purposes and is not indicative of the results of operations that would have been achieved if the acquisition had taken place at July 1, 2010. The unaudited pro forma results can be summarized as follows for the years ended:

	Magellan as Reported			Pro Forma
				Acquisition (a)			Disposition (b)			Combined
	(In thousands, except per share amounts)
June 30, 2012
Sales	$	13,712		$	1,025		$	(5,891	)	$	8,846
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498		$	(223	)	$	835		$	27,110
Net income per basic share outstanding	$	0.49								$	0.51
Net income per diluted share outstanding	$	0.49								$	0.50
June 30, 2011
Sales	$	18,176		$	4,492		$	(8,813	)	$	13,855
Net (loss) income attributable to Magellan Petroleum Corporation	$	(32,432	)	$	2,471		$	(1,144	)	$	(31,105	)
Net (loss) per basic share outstanding	$	(0.62	)							$	(0.59	)
Net (loss) per diluted share outstanding	$	(0.62	)							$	(0.59	)

^(a) Reflects the pro forma results from operations related to the Palm Valley Interests and the Dingo Interests.

^(b) Reflects the pro forma results from operations related to the Mereenie Interests.

Lease Purchase and Sale and Participation Agreement with VAALCO Energy (USA), Inc. ("VAALCO").On September 6, 2011, the Company entered into a Lease Purchase and Sale and Participation Agreement (the "VAALCO PSA") with VAALCO. Pursuant to the VAALCO PSA, the Company received $5.0 million in cash, and VAALCO received an undivided 65% of the Company’s working interest in formations below the top of the Bakken/Three Forks (the "Deep Intervals") in Poplar.

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The accounting for this transaction is set forth in the table below:

	Total
	(In thousands)
Cash consideration received	$	5,000
Net book value allocated to Deep Intervals	(829		)
Transaction costs	(162		)
Gain on sale recognized	$	4,009

Acquisition of Non-Controlling Interest in Nautilus Poplar LLC and Acquisition of Additional Working Interests. On September 2, 2011, the Company entered into a Purchase and Sale Agreement (the "Nautilus PSA") between the Company and the non-controlling interest owners of NP, being the Nautilus Technical Group, LLC ("NT") and Eastern Rider, LLC ("ER") (the "Nautilus Sellers"). The Nautilus Sellers included J. Thomas Wilson (a Magellan director and now its President and CEO), a second individual who has served as a consultant to NP, and a third individual who was an employee of NP at the time of the transaction, as well as certain other persons.

The Nautilus PSA provided for the Company’s purchase of all membership interests from the Nautilus Sellers in return for (i) $4.0 million in cash (the "Cash Consideration"), (ii) $2.0 million, less certain costs and certain debt owed to Magellan by the Nautilus Sellers, in unregistered shares of Magellan’s common stock, par value $0.01 (the "Net Share Consideration"), and (iii) the potential for future production payments ("Contingent Production Payments"), payable in cash to the Nautilus Sellers, collectively, of up to $5.0 million if certain increased average daily production milestones are achieved. The shares were sold pursuant to Section 4(2) of the Securities Act of 1933. The Cash Consideration was transferred on September 2, 2011. Consistent with the terms of the Nautilus PSA, 1,182,742 of shares in the Net Share Consideration were issued on September 23, 2011. J. Thomas Wilson’s interest in this transaction approximated 52% of the consideration paid to the Nautilus Sellers.

The discounted fair value of the future contingent consideration payable is calculated at the end of each fiscal quarter using consistent assumptions and methodology. As of June 30, 2012, the contingent consideration payable was valued at $4.07 million and is reported in the consolidated balance sheet as contingent consideration payable.

The acquisition of NT’s direct working interests was treated as a business combination for accounting purposes. The fair value of assets acquired and liabilities assumed were recorded at estimated fair value. This estimate was made based on significant unobservable (Level 3) inputs and based on the best information available at the time (see Note 5). A de minimis amount of revenues and earnings related to the working interests acquired is included in the accompanying consolidated statements of operations for the year ended June 30, 2012.

The table below summarizes the consideration paid to the Nautilus Sellers under the Nautilus PSA and the estimated fair value of the assets acquired and liabilities assumed for the working interests acquired from NT.

	NT non- controlling  interest in NP		NT working  interest in  Poplar		ER non- controlling  interest in NP		Total
	(In thousands)
Consideration paid to Sellers (1):
Cash consideration	$	1,920	$	823	$	1,257	$	4,000
Share consideration (2)	907		389		526		1,822
Fair value of contingent consideration payable	1,993		854		1,304		4,151
Total	$	4,820	$	2,066	$	3,087	$	9,973
							Total
							(In thousands)
Recognized amount of identifiable assets acquired and liabilities assumed for Business combination:
Oil and gas assets (proved)							$	1,462
Oil and gas assets - Deep Intervals (unproved)							679
ARO liability							(75		)
Total							$	2,066

⁽¹⁾ Excludes transaction costs.

⁽²⁾ Common stock valued at $1.54 per share closing price on the date of the transaction.

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Note 3 - Debt

Long term debt relates to a $1.7 million note payable re-issued in January 2011. This note will be fully amortized in June 2014, and the outstanding principal consisted of the following for the years ended:

	June 30,
	2012			2011
	(In thousands)
Note payable	$	870		$	1,422
Less current portion of note payable	(480		)	(552		)
Long term debt, excluding current portion	$	390		$	870

As of June 30, 2012, the minimum future principal maturities of long term debt were as follows:

	June 30, 2012
	(In thousands)
One year	$	480
Two years	390
Total	$	870

The variable rate of the note is based upon the Wall Street Journal Prime Rate (the "Index") plus 1.00%, subject to a floor rate of 6.25%. The Index was 3.25% at June 30, 2012, resulting in an interest rate of 6.25% per annum as of June 30, 2012. Under the note payable, NP is required to maintain certain customary financial and restrictive covenants. As of June 30, 2012, NP was in compliance with all financial and restrictive covenants.

In addition, the Company has a $1.0 million working capital line of credit classified as short term debt. The amount due on the line of credit was $0.1 million as of June 30, 2012. The line of credit bears interest at a variable rate, which was 6.25% as of June 30, 2012. The line of credit also secures both a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management and business credit cards in the amount of $25 thousand. As of June 30, 2012, $0.9 million was available under this line of credit.

The note payable, letters of credit, and business credit cards are collateralized by a first mortgage and an assignment of production for Poplar and are guaranteed by Magellan up to $6.0 million, not to exceed the amount of the principal owed.

The carrying amount of the Company’s long term debt approximates its fair value, due to its variable interest rate, which resets based on the market rates.

Note 4 - Asset Retirement Obligations

The estimated valuation of asset retirement obligations ("AROs") are based on management's historical experience and best estimate of plugging and abandonment costs by field. Assumptions and judgments by management include determination of the existence of a legal obligation for an ARO; estimated probabilities, amounts, and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the consolidated statement of operations.

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The following table summarizes the asset retirement obligation activity for the years ended:

	June 30,
	2012			2011
	(In thousands)
Balance at beginning of year	$	11,397		$	9,292
Liabilities assumed	3,035			—
Liabilities incurred	398			50
Accretion expense	568			564
Sale of assets	(6,773		)	—
Revision to estimate	(603		)	(129		)
Effect of exchange rate changes	(238		)	1,620
Balance at end of year	7,784			11,397
Less current asset retirement obligation	329			—
Long term asset retirement obligation	$	7,455		$	11,397

Note 5 - Fair Value Measurements

The Company follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

• Level 1: Quoted prices in active markets for identical assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3: Significant unobservable inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s policy is to recognize transfers in and/or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed for all periods presented.

Items required to be measured at fair value on a nonrecurring basis include the assets acquired and liabilities assumed related to the acquisition of an additional 3% working interest in Poplar, assets acquired as a result of the Santos SA (see Note 2), and liabilities related to AROs.

Items required to be measured at fair value on a recurring basis include securities available for sale, classified as Level 1, and the contingent consideration payable (see Note 2), classified as Level 3.

As of June 30, 2012, the Company had $41.2 million in cash and cash equivalents, with $2.7 million held in cash and $38.6 million classified as cash equivalents. The cash equivalents were held in time deposit accounts in several Australian banks with maturities of 90 days or less.

64

The following table presents the amounts of assets and liabilities carried at fair value by the level in which they are classified within the valuation hierarchy for the years ended:

	June 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	41,215	$	—	$	—	$	41,215
Securities available for sale	155		—		—		155
	$	41,370	$	—	$	—	$	41,370
Liabilities
Contingent consideration payable	$	—	$	—	$	4,072	$	4,072
	June 30, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	20,417	$	—	$	—	$	20,417
Securities available for sale	238		—		—		238
	$	20,655	$	—	$	—	$	20,655

During the years ended June 30, 2012, and 2011, there have been no transfers in and out of Level 1, Level 2, or Level 3.

The following table presents a roll forward of liabilities measured at fair value using significant unobservable inputs (Level 3) as of:

	June 30, 2012
	(In thousands)
Balance at beginning of year	$	—
Contingent consideration payable addition	4,072
Balance at end of year	$	4,072

Note 6 - Income Taxes

The domestic and foreign components of our income (loss) before income taxes are as follows for the years ended:

	June 30,
	2012			2011			2010
	(In thousands)
Domestic	$	(6,646	)	$	(6,780	)	$	(8,456	)
Foreign	27,178			(20,516		)	9,645
Net income (loss) after income tax	$	20,532		$	(27,296	)	$	1,189

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The following reconciles the Company's effective tax rate to the federal statutory tax rate for the years ended:

	June 30,
	2012			2011			2010
	(In thousands)
Tax provision computed per federal statutory rate	$	6,160		$	(8,088	)	$	356
State taxes, net of federal benefit	190			(201		)	244
Foreign rate differential	76			(271		)	(338		)
Non taxable Australian revenue	(8		)	(822		)	(953		)
Non deductible warrant and stock related compensation	—			—			2,203
Goodwill write off	756			—			—
Decreases related to lapse of applicable statute of limitations	1,571			—			—
Change in valuation allowance	9,352			17,135			(346		)
Australian petroleum resource rent tax	(5,951		)	—			—
Australian petroleum resource rent tax - income tax effect	1,785			—			—
Magellan capitalized facilitation costs	—			106			201
Taxable dividends from subsidiaries, net of foreign tax credits	(1,152		)	932			1,690
Foreign tax credit adjustment	649			(3,411		)	—
Capital loss adjustment	(3,006		)	—			—
Additional basis related to the Santos SA	(18,118		)	—			—
Impact of rate change	457			—			—
Foreign currency translation differential	1,375			—			—
Other	(87		)	(239		)	(411		)
Consolidated income tax (benefit) provision	$	(5,951	)	$	5,141		$	2,646

Components of our income tax provision can be summarized as follows:

	June 30,
	2012			2011			2010
	(In thousands)
Current income tax
United States
Federal tax	$	—		$	—		$	—
State tax (benefit) provision	—			(127		)	375
Foreign tax (benefit) provision	—			(87		)	1,349
Total current income tax (benefit) provision	—			(214		)	1,724
Deferred income tax
United States deferred tax (benefit) provision	—			(195		)	195
Foreign tax provision (benefit)	(5,951		)	5,550			727
Total deferred income tax (benefit) provision	(5,951		)	5,355			922
Consolidated income tax (benefit) provision	$	(5,951	)	$	5,141		$	2,646
Effective tax rate	(29		)%	(19		)%	223		%

The Company's effective tax rate was reduced to negative 29% primarily due to the recognition of the onshore Australian Petroleum Resource Rent Tax ("PRRT") deferred tax asset.

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Significant components of the Company's deferred tax assets and liabilities can be summarized as follows for the years ended:

	June 30,
	2012			2011
	(In thousands)
Deferred tax liabilities
Land, buildings and equipment	$	(2,767	)	$	—
Stepped up basis of oil and gas properties	(550		)	(690		)
Australian petroleum resource rent tax - income tax effect	(1,785		)	—
Other	(261		)	(901		)
Total deferred tax liabilities	(5,363		)	(1,591		)
Deferred tax assets
Acquisition and development costs	—			3,234
Asset retirement obligations	2,210			2,993
Net operating losses, capital losses, and foreign tax credit carry forwards	28,139			12,188
Australian petroleum resource rent tax	5,951			—
United Kingdom exploration costs and net operating losses	3,224			2,358
Stock option compensation	1,851			1,673
Interest	539			539
Australian capitalized legal costs	514			426
Other	579			521
Total deferred tax asset	43,007			23,932
Valuation allowance	(31,693		)	(22,341		)
Net long term deferred tax asset	$	5,951		$	—

For the fiscal year ended June 30, 2012, the valuation allowance increased by $9.4 million, primarily due to additional capital losses available for MPAL related to the Santos SA.

During the fiscal year ended June 30, 2011, the Company did not expect to remit undistributed earnings of our foreign subsidiaries to the U.S. in the foreseeable future. Federal and State Income Taxes were therefore not provided on accumulated but undistributed earnings of foreign subsidiaries, because such earnings were considered permanently reinvested in the business. During the fiscal year ended June 30, 2012, the Company changed its position with respect to permanently reinvesting its undistributed earnings. The Company determined that $20.0 million of undistributed earnings of its wholly-owned foreign subsidiary, MPAL, would be remitted to the U.S. in the foreseeable future. The Company does not anticipate any future Federal or State Income Tax effect as a result of this repatriation of foreign earnings due to the utilization of available foreign tax credit carry forwards.

The tax benefit recorded for fiscal year 2012 totals $6.0 million. In addition to corporate income tax, the income tax benefit includes the tax effect of the Company's obligation related to the Australian PRRT. The extension of PRRT to onshore projects was enacted during fiscal year 2012 and effective from July 1, 2012. As a consequence of the extension of the Australian PRRT regime to onshore petroleum products, a deferred tax benefit related to the Palm Valley gas field of $6.0 million in respect of the starting base of $16.6 million (which is net of AROs, and claimable against future PRRT liabilities) was recorded.

The United States gross deferred tax asset at June 30, 2012, consists primarily of foreign tax credits. The Australian gross deferred tax asset at June 30, 2012, consists primarily of acquisition and development costs, asset retirement obligations, net operating and capital loss carry forwards, and other assets which will result in tax deductions when paid. Australian net operating and capital losses carry forward indefinitely.

After reviewing all positive and negative evidence, a valuation allowance is still recorded against all the deferred tax assets, with exception of the $6.0 million deferred tax asset based on the Australian PRRT noted above.

67

As of June 30, 2012, the Company remains subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction	Tax Years Subject to Exam:
U.S. Federal	2011
Montana	2010 - 2011
Australia	2008 - 2011

Subsequent to June 30, 2012, the IRS completed an examination of the Company's 2009 and 2010 annual return forms which resulted in no additional tax due and a reduction in the Company's foreign tax credit carry forward of $0.5 million.

At June 30, 2012, the Company had net operating loss and foreign tax credit carry forwards for U.S. Federal and State Income Tax purposes, respectively, which are scheduled to expire periodically as follows:

	Net Operating Losses				Federal Foreign Tax Credit
	Paroo USA Federal		State
	(In thousands)
Expires
2013	$	230	$	—	$	—
2017	—		—		310
2018	—		1,271		—
2019	96		—		1,411
2020	—		—		144
2021	25		—		886
2022	74		—		4,494
2023	3		—		—
2024	2		—		—
2025	1		—		—
Total	$	431	$	1,271	$	7,245

The Company estimates that it has sufficient foreign tax credits to repatriate significant earnings and profits over and above the $20.0 million already repatriated from its foreign subsidiaries subsequent to the fiscal year ended June 30, 2012, without incurring additional U.S. income tax due to the utilization of available foreign tax credits.

During fiscal year 2012, the Company recorded a cumulative out of period adjustment in connection with U.S. Federal Tax Withholdings and related penalties and interest (see Note 11). The adjustment related to fiscal year 2010 and increased general and administrative expense in fiscal year 2012 by $0.9 million. Had this amount been reflected in fiscal year 2010, the period in which it arose, general and administrative expense, and accumulated deficit would have increased by $0.9 million. The impact on net loss per basic and diluted share attributable to Magellan Petroleum Corporation common shareholders would have been less than $0.02 had the amount been reflected in the period in which it arose. Based upon an evaluation of all relevant quantitative and qualitative factors, and after considering SEC Staff Accounting Bulletins Nos. 99 and 108, management believes that any amounts attributable to the years ended June 30, 2010, and 2011, and the impact of correcting such amounts in the year ended June 20, 2012, are not material to any of the Company's consolidated financial statements presented herein

There are no material uncertain tax positions for either fiscal 2012 or 2011.

Note 7 - Stock Based Compensation

The Stock Plan

On December 8, 2010, shareholders approved an amendment to the Company’s 1998 Stock Incentive Plan (the "Stock Plan") to increase the number of authorized common stock shares reserved for awards under the Stock Plan to a total of 7,205,000 shares. These authorized shares can take the form of non-qualified stock options, stock appreciation rights, restricted share awards, annual awards of stock to directors, and performance based awards ("PBOs").

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Stock Option Grants

Stock option grants contain both time based and performance based vesting provisions. The time based options are expensed on a straight-line basis over the vesting period. Performance based options are recognized when the achievement of the performance conditions is considered probable. Management re-assesses whether satisfaction of performance conditions are probable at the end of each reporting period. If changes in the estimated outcome of the performance conditions affect the quantity of the awards expected to vest, the cumulative effect of the change is recognized in the period of change. As of June 30, 2012, management believes the achievement of the performance conditions related to the performance based stock options is probable. Accordingly, the Company has begun to recognize expense on these awards over the period of time the performance condition is expected to be achieved.

As of June 30, 2012, 435,000 shares were available for future issuance under the Stock Plan. Of the 1,675,000 options granted during the current fiscal year, 295,750 were issued as PBOs and 825,000 options were issued outside of the Stock Plan. Options outstanding have expiration dates ranging from November 28, 2015, through January 10, 2022.

The following table summarizes the stock option activity for the years ended:

	June 30,
	2012			2011			2010
	Number of Shares		WAEPS (1)	Number of Shares		WAEPS (1)	Number of Shares	WAEPS (1)
Balance at beginning of year	5,200,000		$1.49	3,880,000		$1.26	3,242,500	$1.25
Granted	1,675,000		$1.10	1,750,000		$2.08	637,500	$1.33
Exercised	(21,875	)	$1.60	(30,000	)	$1.45	—	$0.00
Forfeited	(100,000	)	$1.72	(400,000	)	$1.84	—	$0.00
Options outstanding at year end	6,753,125		$1.44	5,200,000		$1.49	3,880,000	$1.26
Weighted average remaining contractual term			6.8 years			7.6 years		8.1 years

⁽¹⁾ Weighted average exercise price per share

At June 30, 2012, there was a total of $0.7 million in unrecognized stock compensation expense related to stock options granted. This cost is expected to be recognized over a weighted-average period of 1.4 years. The amount of unrecognized compensation expense noted above does not necessarily represent the amount that will ultimately be realized by the Company in its consolidated statement of operations. During the fiscal year ending June 30, 2013, it is expected that an additional 1,100,002 stock options will vest.

Cash received from the exercise of stock options for the years ended June 30, 2012, and 2011, was less than $0.1 million. No stock options were exercised during 2010.

The following table summarizes options outstanding and exercisable as of June 30, 2012:

			Options outstanding and exercisable
Range of exercise prices			Number of shares			Weighted average remaining contractual life	Weighted average exercise price
$1.01	-	$1.16	549,999			8.7 years	$1.12
$1.20	-	$1.20	3,100,000			6.5 years	$1.20
$1.40	-	$1.60	528,125			4.5 years	$1.54
$1.72	-	$2.41	683,330			7.9 years	$2.18
			4,861,454
Aggregate intrinsic value			$	(1,851,313	)

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The fair value of shares issued under the Stock Plan was estimated using the following weighted-average assumptions for the years ended:

	June 30,
	2012					2011					2010
Number of options	1,675,000					1,750,000					637,500
Weighted-average grant date fair value per share	$0.66					$1.10					$0.85
Expected dividend	$0.00					$0.00					$0.00
Risk free interest rate	1.0	%	-	1.3	%	1.6	%	-	2.4	%	2.4	%	-	2.6	%
Expected life	5.3		-	6.0	years	5.0		-	6.0	years	5.8		-	5.8	years
Expected volatility (based on historical price)	61.2	%	-	62.8	%	55.2	%	-	61.5	%	6.2	%	-	62.5	%

Stock Compensation Expense

The Company recorded $1.6 million, $1.7 million, and $2.3 million of stock compensation expense for the years ended June 30, 2012, 2011, and 2010, respectively. Stock based compensation is included under general and administrative expense in the consolidated statements of operations.

The Company's compensation policy is designed to provide the Company's directors with a portion of their annual Board compensation in the form of equity. The number of shares for each director award is subject to an annual maximum of 15,000 shares. The Company issued 75,000 shares during 2012 pursuant to this policy.

Note 8 - Earnings Per Share

The following table summarizes the computation of basic and diluted earnings per share:

	June 30,
	2012		2011			2010
	(In thousands, except share and per share amounts)
Net income (loss) attributable to Magellan Petroleum Corporation	$	26,498	$	(32,432	)	$	(1,446	)
Basic weighted-average shares outstanding	53,592,958		52,398,936			51,410,596
Add: dilutive effects of stock options and unvested stock grants (1)	448,269		—			—
Diluted weighted-average common shares outstanding	$	54,041,227	$	52,398,936		$	51,410,596
Basic net loss per common share	$	0.49	$	(0.62	)	$	(0.03	)
Diluted net loss per common share	$	0.49	$	(0.62	)	$	(0.03	)

⁽¹⁾ There is no dilutive effect on earnings per share in periods with net losses.

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following:

	June 30,
	2012	2011	2010
Stock options	100,000	—	—
Non-vested restricted stock	—	104,167	208,334
Total potentially dilutive securities	100,000	104,167	208,334

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Note 9 - Segment and Geographic Data

The Company conducts its operations through two wholly owned subsidiaries, NP, which operates in the United States, and MPAL, which is primarily active in Australia. The following table presents segment and geographic data for years ended:

	June 30,
	2012			2011			2010
	(In thousands)
Revenues
NP	$	6,173		$	3,804		$	2,291
MPAL	7,533			12,775			25,908
Corporate	646			2,722			2,826
Inter-segment eliminations	(640		)	(1,125		)	(2,500		)
Consolidated revenues	$	13,712		$	18,176		$	28,525
Net income (loss)
NP	$	2,154		$	(23	)	$	(55	)
MPAL	24,192			(25,968		)	7,569
Corporate	(5,416		)	(6,429		)	(263		)
Inter-segment eliminations	5,568			(12		)	(8,697		)
Consolidated net (loss) income	$	26,498		$	(32,432	)	$	(1,446	)
Assets
NP	$	10,833		$	16,985		$	5,427
MPAL	67,748			49,291			63,131
Corporate	59,099			83,323			90,345
Inter-segment eliminations	(45,106		)	(78,025		)	(68,197		)
Consolidated assets	$	92,574		$	71,574		$	90,706
Expenditures for additions to long lived assets
NP	$	(4,857	)	$	(2,095	)	$	(328	)
MPAL	(4,575		)	(1,679		)	(2,209		)
Corporate	(145		)	(794		)	(306		)
Consolidated expenditures for long lived assets	$	(9,577	)	$	(4,568	)	$	(2,843	)

The following table summarizes other significant items for years ended:

	June 30,
	2012		2011		2010
	(In thousands)
Depletion, depreciation, amortization, and accretion
NP	$	819	$	919	$	448
MPAL	695		1,653		4,834
Corporate	230		318		146
Consolidated depletion, depreciation, amortization, and accretion	$	1,744	$	2,890	$	5,428
Lease operating
NP	$	5,232	$	2,227	$	1,373
MPAL	7,665		6,270		8,585
Corporate	—		750		158
Consolidated lease operating	$	12,897	$	9,247	$	10,116

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	June 30,
	2012		2011			2010
	(In thousands)
Exploration
NP	$	1,495	$	151		$	—
MPAL	4,796		2,378			1,273
Corporate	—		325			—
Consolidated exploration	$	6,291	$	2,854		$	1,273
Income tax benefit (expense)
MPAL	$	5,951	$	(5,463	)	$	(2,076	)
Corporate	—		322			(570		)
Consolidated income tax benefit (expense)	$	5,951	$	(5,141	)	$	(2,646	)

Note 10 - Commitments

Operating Leases. The following table summarizes the Company's future minimum rental commitments under non-cancelable operating leases, net of guaranteed sublease income, as of:

	June 30, 2012
	(In thousands)
Amounts payable in:
2013	$	97
2014	162
2015	262
2016	268
2017 and thereafter	363
Total	$	1,152

Rental expenses for each of the years ended June 30, 2012, 2011, and 2010, were $0.6 million, $0.5 million, and $0.4 million, respectively.

Purchase obligations. Although the Company is committed to certain exploration and capital expenditures related to MPAL, some of these expenses may be farmed out to third parties. Amounts payable under these firm commitments for fiscal year 2013 were $5.4 million as of June 30, 2012.

Note 11 - Related Party Transactions

Transactions with Young Energy Prize S.A. ("YEP") and Related Entities

First Private Investment in a Public Entity ("First PIPE"). The Company entered into a Securities Purchase Agreement (the "First Purchase Agreement") to finalize the terms of the First PIPE, dated February 9, 2009, with its largest stockholder, YEP, under which the Company agreed to sell, and YEP agreed to purchase, 8,695,652 shares (the "Shares") of the Company's common stock, par value $0.01 per share (the "Common Stock") at a purchase price of $1.15 per share, or an aggregate of AUD $10.0 million. YEP is a Luxembourg corporation. Mr. Nikolay Bogachev, a director of the Company since July 2009, is the President and CEO of YEP as well as an equity owner of YEP.

The First 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 in accordance with the First PIPE. The Company received gross proceeds of AUD $10.0 million, which was used for acquisitions, general corporate, and working capital purposes. On July 9, 2009, the Company also executed and delivered to YEP a Warrant Agreement entitling YEP to purchase an additional 4,347,826 shares of the Company's Common Stock (the "Warrant Shares") at an exercise price of $1.20 per Warrant Share, subsequently reduced to $1.15 per share on July 30, 2009. The shares sold to YEP in the First PIPE and the Warrant Shares were not registered under the Securities Act or state securities laws and may not be resold in the United States in the absence of an effective registration statement filed with the U.S. Securities and Exchange Commission ("SEC") or an available exemption

from the applicable federal and state registration requirements.

Initially, the Warrant Agreement contained anti-dilutive provisions that reduced the exercise price of the warrants based on certain trigger events such as the issuance of additional shares at a discount from the then current warrant exercise price. Since the provisions permitted the warrant holder to avoid bearing some of the risks and rewards normally associated with equity share ownership, the warrants were initially classified as liabilities and marked to market each reporting date with the change in value flowing through earnings. On March 11, 2010, YEP and the Company agreed to amend the Warrant Agreement to remove certain anti-dilution provisions. As a result, the Warrants were reclassified as equity and no revaluations were required subsequent to March 11, 2010. For the year ended June 30, 2010, non-cash charges of $4.3 million were recorded in the consolidated statement of income.

U.S. Federal Tax Withholdings. During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's failure to make the required U.S. Federal tax withholding in the course of its initial acquisition of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition"), from the two majority owners of NP, White Bear LLC ("White Bear") and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Mr. Bogachev, a Director of Magellan and a foreign national. Due to the status of YEP I as foreign entity and the members of White Bear being foreign nationals, Magellan was required to make U.S. Federal tax withholdings from the payments to or for the benefit of White Bear and YEP I. Of the $2.0 million liability, $1.3 million was estimated to relate to the interest sold by White Bear, $0.6 million to the interest sold by YEP I, and $0.1 million to Magellan's interest on late payment of the U.S. Federal tax withholdings.

Upon the filing of U.S. income tax returns in relation to the Poplar Acquisition and payment of corresponding income taxes by White Bear and YEP I, Magellan is deemed to be relieved of its liability for the U.S. Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the U.S. Federal tax withholdings. With regards to White Bear, Magellan has confirmed that as of the date of this filing, Mr. Bogachev has filed his U.S. income tax return and paid taxes due on the Poplar Acquisition, which were estimated at $0.3 million. Magellan has agreed to pay Mr. Bogachev $0.3 million in additional compensation. Had Mr. Bogachev not filed and paid his tax return, Magellan's liability in relation to its U.S. Federal tax withholdings requirements was estimated at $1.3 million as of June 30, 2012. With regards to YEP I, Magellan continues to seek from YEP I or, because YEP I is a now defunct entity, from its successor entities, the filing of its U.S. income tax return.

As of June 30, 2012, we have recorded a total liability of $1.0 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.3 million payment to Mr. Bogachev, $0.6 million in withholdings, penalties, and interest related to YEP I, and $0.1 million related to Magellan's interest on late payment of the U.S. Federal tax withholdings. The effect on the consolidated statements of operations for the year ended June 30, 2012, is an expense of $0.9 million recorded under general and administrative expense and an interest expense of $0.1 million.

Based upon an evaluation of all relevant quantitative and qualitative factors, and after considering SEC Staff Accounting Bulletins Nos. 99 and 108, management believes that any amounts attributable to the years ending June 30, 2010, and 2011, and the impact of correcting such amounts in the year ending June 20, 2012, is not material to any of the Company's consolidated financial statements presented herein.

Second Private Investment in a Public Entity ("Second PIPE"). On August 5, 2010, the Company executed a Securities Purchase Agreement (the "Second Purchase Agreement"), an Investor's Agreement, and a Memorandum of Agreement to finalize the terms of its Second PIPE with YEP.

The Purchase Agreement involves the issuance and sale of up to 5.2 million new Shares to YEP and/or one or more of its affiliates in return for $3.00 per new share issued and sold for an aggregate purchase price of $15.6 million ("Investment Transaction"). Pursuant to the terms of the Second Purchase Agreement, the Company is required to use the proceeds from the Investment Transaction to close the Evans Shoal Transaction. Since the Amended Asset Sales Agreement has been terminated and MPAL has received back the additional $10.0 million deposit, the Investment Transaction has not closed. The Company and YEP subsequently terminated the Second Purchase Agreement.

Investment Agreement and Related Amendment.On February 11, 2011, the Company and YEP executed an Investment Agreement to document the terms of additional financing to be provided by YEP to the Company in order to facilitate the closing of the Evans Shoal Transaction. On February 17, 2011, the Company and YEP executed an amendment to the Investment Agreement in the form of a side letter ("Side Letter"). Under the Investment Agreement, YEP shall provide funding to the Company required for the completion of the Evans Shoal Transaction in the amount of approximately AUD $85.5 million, which shall include the proceeds of the $15.6 million provided by the Investment Transaction. The Investment Agreement states that the funding of the AUD $85.5 million by YEP is contingent upon the requirements and conditions of the Evans Shoal Agreement being satisfied or waived. The Company and YEP has terminated the Investment Agreement, as amended by the Side Letter.

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Other Related Party Transactions

The Company leased its prior Denver office space from an entity owned, in part, by J. Thomas Wilson, President and CEO of the Company and a member of the Company's Board of Directors. The total lease expense paid under this arrangement was $72 thousand for the fiscal years ended June 30, 2012, and 2011, and $52 thousand for the fiscal year ended June 30, 2010. Following the relocation of the Company's headquarters to Denver, Colorado, a lease agreement for new office space was entered into with an unrelated party in August 2012. Consulting services of $59 thousand, $100 thousand, and $36 thousand for the fiscal years ended 2012, 2011, and 2010 was paid to Mr. Wilson.

J. Robinson West, the Chairman of the Board of Directors of the Company, is also Chairman, Founder, and CEO of PFC Energy ("PFC"). PFC has served as a consultant for the Company on various Australian projects. As of June 30, 2012, there were no consulting arrangements between the Company and PFC in place or planned. The total consulting fees paid to PFC during the fiscal year ended June 30, 2012, was $64 thousand for work performed primarily in fiscal year 2011. As of June 30, 2011, an amount of $49 thousand remained unpaid for consulting fees related to fiscal 2011, which has since been paid. PFC was paid $0.4 million in fiscal year 2011, of which $0.2 million was expensed in fiscal year 2010.

See Note 2 for information related to transactions the Company entered into with NT and ER, effective September 1, 2011.

Note 12 - Subsequent Events

As of June 30, 2012, $38.6 million of the Company's cash and cash equivalents was held in several Australian banks in time deposit accounts that have terms of 90 days or less. As of September 24, 2012, the Company has repatriated $20.0 million of these Australian held funds to the U.S. The Company does not anticipate that U.S. Federal Income Tax will be owed on this amount, due to the expected utilization of foreign tax credits carried forward from June 30, 2012, and foreign tax credits expected to be generated during the fiscal year ending June 30, 2013 (see Note 6). The intended use for the repatriated monies is the funding of Magellan's U.S. based operations, including part of its drilling activity at Poplar.

On July 16, 2012, William H. Hastings resigned from the Board of Directors of Magellan. Pursuant to the terms and conditions of the Employment Agreement between Mr. Hastings and the Company dated February 3, 2009, as amended by the addendum thereto dated September 27, 2011, the Company is required to pay Mr. Hastings two years' severance compensation as a result of the Company's decision to discontinue his employment with the Company and Mr. Hastings' decision to resign from the Board of Directors.

On August 28, 2012, Stratex Oil & Gas Holdings, Inc. ("Stratex") announced an unsolicited proposal for the acquisition of each outstanding share of the Company's common stock for $0.65 in cash and one share of Stratex common stock, the closing price for which as reported by the OTCQB on August 27, 2012 was $1.65 per share. On September 10, 2012, the Company announced that its Board of Directors, after carefully considering the unsolicited proposal and consulting with its financial and legal advisors, had determined not to pursue the Stratex proposal. On September 12, 2012, the Company received a subpoena from the U.S. Securities and Exchange Commission (the "SEC") for the production of documents in connection with these announcements. On September 14, 2012, the Company received a letter from the Financial Industry Regulatory Authority ("FINRA") indicating that FINRA is conducting a review of trading in the Company's common stock surrounding the August 28, 2012 announcement by Stratex, and requesting information and documents from the Company in connection therewith. The Company is cooperating fully with the SEC and FINRA in these matters.

On September 24, 2012, the Company announced that its Board of Directors had approved a new stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its common stock. This authorization supersedes the prior plan and will expire on August 21, 2014. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including compliance with securities laws. Stock repurchases may be funded with existing cash balances or internal cash flow. The stock repurchase program may be suspended or discontinued at any time.

Note 13 - Supplemental Oil and Gas Information (Unaudited)

Supplemental Oil and Gas Reserve Information

The Company relies upon a combination of internal technical staff and third party consulting arrangements for reserve estimation and review. The reserve information presented below is based on estimates of net proved reserves as of June 30, 2012, 2011, and 2010, and was prepared in accordance with guidelines established by the SEC.

In the United States, reserves estimates were prepared by the Company's Operations Manager, Blaine Spies, in 2012, and were audited by the Company's independent petroleum engineering firm, Allen & Crouch Petroleum Engineers ("A&C"), in

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2012, 2011, and 2010. A copy of the summary reserve audit report of A&C is provided as Exhibit 99.1 to this Annual Report on Form 10-K. A&C does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.

In Australia, reserve estimates were prepared by the Ryder Scott Company ("RS"), an independent petroleum engineering firm, in 2012, and 2011. In 2010, reserve estimates were prepared by the RISC Pty Ltd ("RISCS"), an independent petroleum engineering firm. Reserve estimates were prepared in accordance with the Company's internal control procedures, which include the verification of input data used by RS and RISC, as well as management review and approval. A copy of the summary reserve report of RS is provided as Exhibit 99.2 to this Annual Report on Form 10-K. RS does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.

Proved reserves are the estimated quantities of oil, gas, and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company's estimated proved reserves are located in North America and Australia.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Company's estimated proved oil and gas reserve quantities. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

	United States			Australia (1)				Total
	Oil (Mbbls)		Gas (MMcf)	Oil (Mbbls)		Gas (MMcf)		Oil (Mbbls)		Gas (MMcf)
Proved Reserves:
2009	—		—	996.0		3.3		996.0		3.3
Extensions and discoveries	6,963.0		—	—		—		6,963.0		—
Revision of previous estimates	(74.0	)	—	(694.0	)	1.6		(768.0	)	1.6
Purchase of minerals in place	2,631.0		—	—		—		2,631.0		—
Sales of minerals in place	—		—	(205.0	)	—		(205.0	)	—
Production	(42.0	)	—	(97.0	)	(3.4	)	(139.0	)	(3.4	)
2010	9,478.0		—	—		1.5		9,478.0		1.5
Extensions and discoveries	6.0		—	—		—		6.0		—
Revision of previous estimates	(404.0	)	—	64.0		(0.2	)	(340.0	)	(0.2	)
Purchase of minerals in place	178.0		—	—		—		178.0		—
Production	(68.0	)	—	(64.0	)	(0.9	)	(132.0	)	(0.9	)
2011	9,190.0		—	—		0.4		9,190.0		0.4
Extensions and discoveries	186.4		—	—		—		186.4		—
Revision of previous estimates	(1,643.8	)	—	—		6.0		(1,643.8	)	6.0
Purchase of minerals in place	1,246.8		—	—		5.5		1,246.8		5.5
Production	(74.2	)	—	—		(0.4	)	(74.2	)	(0.4	)
2012	8,905.2		—	—		11.5		8,905.2		11.5

⁽¹⁾ The amount of proved reserves applicable to Australia gas reflects the amount of gas committed to specific contracts and is net of royalties.

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	United States		Australia (1)		Total
	Oil (Mbbls)	Gas (MMcf)	Oil (Mbbls)	Gas (MMcf)	Oil (Mbbls)	Gas (MMcf)
Proved Developed Reserves:
June 30, 2010	2,515.0	—	—	1.5	2,515.0	1.5
June 30, 2011	2,249.0	—	—	0.4	2,249.0	0.4
June 30, 2012	1,646.7	—	—	11.5	1,646.7	11.5
Proved Undeveloped Reserves:
June 30, 2010	6,963.0	—	—	—	6,963.0	—
June 30, 2011	6,941.0	—	—	—	6,941.0	—
June 30, 2012	7,258.4	—	—	—	7,258.4	—

⁽¹⁾ The amount of proved reserves applicable to Australia gas reflects the amount of gas committed to specific contracts and is net of royalties.

Extensions and discoveries. Extensions and discoveries are additions to reserve amounts either by drilling a well to extend the limits of a known reservoir or by drilling a well in a reservoir that was not included in previous reserves estimates, respectively. During the year ended June 30, 2012, in the United States, there was one discovery well, EPU 117, drilled in the Amsden formation at Poplar, which added 186 Mbbls to our reserves total. During the year ended June 30, 2011, in the United States, there were minor extensions related to Poplar. During the year ended June 30, 2010, in the United States, there were 6,963 Mbbls of extensions recorded at Poplar as a result of petrophysical, geophysical, and petrographic data based on our current proved developed wells which identified certain locations as proved undeveloped reserves.

Revision of previous estimates. Revisions of estimates represent upward (downward) changes in previous estimates attributable to new information gained primarily from development activity, production history, and changes to the economic conditions present at the time of each estimate. During the year ended June 30, 2012, in the United States, there was a 1,644 Mbbls downward revision of estimates as a result of modifications to projected production profiles from new wells. During the same period in Australia, there was a 6.0 Bcf upward revision of gas estimates related to the signing of a new gas sales contract with Santos in May 2012. During the period ended June 30, 2011, in the United States, there was a 404 Mbbls downward revision of oil estimates. During the same period in Australia, there was a 64 Mbbls upward revision of oil estimates and a 0.2 Bcf downward revision of gas estimates. During the period ended June 30, 2010, in the United States, there was a 74 Mbbls downward revision of oil estimates. During the same period in Australia, there was a 694 Mbbls downward revision of oil estimates and a 1.6 Bcf upward revision of gas estimates.

Purchase of minerals in place. During the year ended June 30, 2012, in the United States, there were 1,247 Mbbls of purchases of minerals in place related to the Company's consolidation of its ownership in NP and Poplar in September 2011. During the same period in Australia, there were 5.5 Bcf of purchases of minerals in place related to the consolidation of Magellan's ownership in Palm Valley as part of the Santos SA in the Amadeus Basin completed in May 2012. These minerals in place have been recorded as proved reserves because they have been contracted for sale under the Santos Gas Contract. During the year ended June 30, 2011, there were 178 Mbbls of purchases of minerals in place related to the Company's acquisition of non-controlling working interests in the leases of Poplar. During the year ended June 30, 2010, there were 2,631 Mbbls of purchases of minerals in place related to the Company's majority acquisition of NP in October 2009 and the Company's acquisition of Hunter's working interests in the leases of Poplar in March 2010.

Sales of minerals in place. Sales of minerals in place during 2010 relate to the Cooper basin asset sales. There were no adjustments to reserves quantities relating to sales of minerals in place for the years ended June 30, 2012, and 2011.

Standardized Measure of Oil and Gas

The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

The "standardized measure" is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, and depreciation, depletion, and amortization or tax, and are discounted using an annual discount rate of 10% to reflect timing of future cash flows.

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The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices, or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Prices. All prices used in calculation of our reserves are based upon a twelve month unweighted arithmetic average of the first day of the month price for the period July 2011 through June 2012, unless prices were defined by contractual arrangements. Prices are adjusted for local differentials and gravity and, as required by the SEC, held constant for the life of the projects (i.e., no escalation). The resulting prices used for proved reserves for the year ended June 30, 2012 are:

	United States		Australia
Year ended June 30, 2012
Oil	$	84.94	NA
Gas	NA		$	4.64

Costs. Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Income taxes. Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

Discount. The present value of future net cash flows from the Company's proved reserves is calculated using a 10% annual discount rate. This rate is not necessarily the same as that used to calculate the current market value of our estimated oil and natural gas reserves.

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The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:

	United States			Australia			Total
	(In thousands)
Fiscal year ended June 30,
2012
Future cash inflows	$	756,405		$	53,296		$	809,701
Future production costs	(291,212		)	(34,729		)	(325,941		)
Future development costs	(34,416		)	(4,107		)	(38,523		)
Future income tax expense	(152,314		)	(3,667		)	(155,981		)
Future net cash flows	278,463			10,793			289,256
10% annual discount	(156,967		)	(2,214		)	(159,181		)
Standardized measures of discounted future net cash flows	$	121,496		$	8,579		$	130,075
2011
Future cash inflows	$	734,592		$	972		$	735,564
Future production costs	(303,005		)	(700		)	(303,705		)
Future development costs	(28,849		)	—			(28,849		)
Future income tax expense	(155,701		)	—			(155,701		)
Future net cash flows	247,037			272			247,309
10% annual discount	(137,021		)	(8		)	(137,029		)
Standardized measures of discounted future net cash flows	$	110,016		$	264		$	110,280
2010
Future cash inflows	$	627,842		$	3,031		$	630,873
Future production costs	(251,335		)	(1,870		)	(253,205		)
Future development costs	(27,293		)	(1,780		)	(29,073		)
Future income tax expense	(132,843		)	(297		)	(133,140		)
Future net cash flows	216,371			(916		)	215,455
10% annual discount	(131,163		)	1,062			(130,101		)
Standardized measures of discounted future net cash flows	$	85,208		$	146		$	85,354

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A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	United States			Australia			Total
	(In thousands)
Standardized measure of discounted future net cash flows for Fiscal year ended June 30,
2009	$	—		$	20,055		$	20,055
Extensions and discoveries	115,092			—			115,092
Acquisitions of reserves	29,656			—			29,656
Revisions of previous quantity estimates	(8,258		)	1,850			(6,408		)
Divestiture of reserves	—			(11,687		)	(11,687		)
Sales and transfers of oil and gas produced	(1,064		)	(12,299		)	(13,363		)
Accretion of discount	1,725			—			1,725
Net change in income taxes	(53,722		)	2,227			(51,495		)
Net change in timing and other	1,779			—			1,779
2010	85,208			146			85,354
Net change in prices and production costs	24,899			38			24,937
Extensions and discoveries	117			—			117
Acquisitions of reserves	3,486			—			3,486
Revisions of previous quantity estimates	(7,041		)	1,094			(5,947		)
Changes in estimated future development costs	(798		)	536			(262		)
Sales and transfers of oil and gas produced	(2,406		)	(1,940		)	(4,346		)
Accretion of discount	13,893			41			13,934
Net change in income taxes	(16,125		)	297			(15,828		)
Net change in timing and other	8,783			52			8,835
2011	110,016			264			110,280
Net change in prices and production costs	18,517			—			18,517
Extensions and discoveries	6,785			—			6,785
Acquisitions of reserves	26,584			4,872			31,456
Revisions of previous quantity estimates (1)	(37,846		)	6,144			(31,702		)
Changes in estimated future development costs	(2,275		)	(555		)	(2,830		)
Sales and transfers of oil and gas produced	(941		)	(264		)	(1,205		)
Previously estimated development cost incurred during the period	5,841			—			5,841
Accretion of discount (2)	—			—			—
Net change in income taxes	(1,657		)	(1,576		)	(3,233		)
Net change in timing and other	(3,528		)	(306		)	(3,834		)
2012	$	121,496		$	8,579		$	130,075

⁽¹⁾ The downward revision of previous quantity estimates of 1,644 Mbbls resulted from a reduced well count which was impacted by higher operating costs.

⁽²⁾ For the year ended June 30, 2012, Magellan assumed no benefit from the accretion of the beginning of year value of its proved oil reserves in the United States. Accretion, with respect to measuring the changes in the standardized measure of reserves values, represents the value benefit of being closer in time, relative to the prior year's standardized measure, to future cash flows in the reserves projections. During the year ended June 30, 2012, Magellan did not develop its United States proved oil reserves in accordance with its reserve plan as of June 30, 2011, and instead postponed its reserves development plan by one year. Therefore, the benefit of accretion of last year's reserves should not factor into the value of the current standardized measure.

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Note 14 - Oil and Gas Activities (Unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

	United States		Australia		United Kingdom		Total
	(In thousands)
Fiscal year ended June 30,
2012
Proved	$	1,606	$	5,634	$	—	$	7,240
Unproved	945		3,787		—		4,732
Exploration Costs	2,192		1		5		2,198
Development Costs	2,779		—		—		2,779
Total, including asset retirement obligation	$	7,522	$	9,422	$	5	$	16,949
2011
Proved	$	380	$	—	$	—	$	380
Unproved	150		—		—		150
Exploration Costs	762		976		3,023		4,761
Development Costs	1,971		4		—		1,975
Total, including asset retirement obligation	$	3,263	$	980	$	3,023	$	7,266
2010
Proved	$	13,456	$	—	$	—	$	13,456
Exploration Costs	—		714		1,127		1,841
Development Costs	314		1,428		—		1,742
Total, including asset retirement obligation	$	13,770	$	2,142	$	1,127	$	17,039

The net changes in capitalized costs that are currently not being depleted pending the determination of proved reserves can be summarized as follows:

	United States			Australia		United Kingdom			Total
	(In thousands)
Fiscal year ended June 30,
2012
Balance at beginning of year	$	2,411		$	415	$	5,259		$	8,085
Additions to capitalized costs	4,631			3,973		1,369			9,973
Assets sold or held for sale	(150		)	—		—			(150		)
Reclassified to producing properties	(3,772		)	—		—			(3,772		)
Charged to expense	(1,297		)	—		(2,106		)	(3,403		)
Exchange adjustment	—			—		102			102
Balance at end of year	$	1,823		$	4,388	$	4,624		$	10,835

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	United States			Australia			United Kingdom			Total
	(In thousands)
2011
Balance at beginning of year	$	314		$	415		$	3,576		$	4,305
Additions to capitalized costs	2,406			—			1,703			4,109
Assets sold or held for sale	—			—			—			—
Reclassified to producing properties	(277		)	—			—			(277		)
Charged to expense	(32		)	—			36			4
Exchange adjustment	—			—			(56		)	(56		)
Balance at end of year	$	2,411		$	415		$	5,259		$	8,085
2010
Balance at beginning of year	$	—		$	3,487		$	3,154		$	6,641
Additions to capitalized costs	314			—			608			922
Assets sold or held for sale	—			(3,072		)	—			(3,072		)
Reclassified to producing properties	—			—			—			—
Charged to expense	—			—			(232		)	(232		)
Exchange adjustment	—			—			46			46
Balance at end of year	$	314		$	415		$	3,576		$	4,305

At June 30, 2012, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.

Note 15 - Quarterly Financial Data (Unaudited)

The following table summarizes the unaudited quarterly financial data, including income before income taxes, net income, and net income per common share for the years ended 2012 and 2011.

	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			June 30, 2012
	(In thousands, except per share data)
Year ended June 30, 2012
Total operating revenues	$	3,735	$	3,202		$	4,805		$	1,970		$	13,712
Total operating expenses (income)	$	2,883	$	8,076		$	9,367		$	(26,388	)	$	(6,062	)
Income (loss) before income taxes	$	1,123	$	(4,755	)	$	(4,590	)	$	28,754		$	20,532
Net income (loss) attributable to Magellan Petroleum Corporation	$	940	$	(4,557	)	$	(4,590	)	$	34,705		$	26,498
Net income (loss) per basic common share outstanding	$	0.02	$	(0.08	)	$	(0.09	)	$	0.64		$	0.49
Net income (loss) per diluted common share outstanding	$	0.02	$	(0.08	)	$	(0.09	)	$	0.64		$	0.49

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	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			June 30, 2011
	(In thousands, except per share data)
Year ended June 30, 2011
Total operating revenues	$	3,699		$	4,461		$	4,867		$	5,149		$	18,176
Total operating expenses	$	7,658		$	8,158		$	4,947		$	25,632		$	46,395
(Loss) income before income taxes	$	(3,713	)	$	(3,476	)	$	111		$	(20,218	)	$	(27,296	)
Net loss attributable to Magellan Petroleum Corporation	$	(3,376	)	$	(2,099	)	$	(84	)	$	(26,873	)	$	(32,432	)
Net loss per basic common share outstanding	$	(0.06	)	$	(0.04	)	*			$	(0.51	)	$	(0.62	)
Net loss per diluted common share outstanding	$	(0.06	)	$	(0.04	)	*			$	(0.51	)	$	(0.62	)

^(*) Not meaningful

During the fourth quarter of fiscal year 2012, Magellan, through its wholly owned subsidiary MPAL, completed the Santos SA (see Note 2) and became the sole owner of the Palm Valley Interests and of the Dingo Interests, while Santos became the sole owner of the Mereenie Interests. The transaction resulted in a gain on sale of assets in the amount of $36.2 million.

Note 16 - Reclassification

Certain reclassifications have been made to the prior period consolidated financial statements to conform them to the current year format. Magellan believes this change improves presentation of our financial statements by conforming them to industry-specific norms. This reclassification had no effect on previously reported results.

The table below provides a summary of the reclassifications related to the consolidated balance sheet for the comparative period presented.

	June 30, 2011
	(In thousands)
CONSOLIDATED BALANCE SHEET
As reported previously:
Oil and gas properties (successful efforts method)	$	138,577
Land, buildings, and equipment	4,089
Field equipment	6,390
Less accumulated depletion, depreciation, and amortization	(119,903		)
Net property and equipment	$	29,153
As currently reported:
Proved oil and gas properties	$	136,094
Less accumulated depletion, depreciation, and amortization	(115,917		)
Unproved oil and gas properties	3,368
Wells in progress	4,315
Land, buildings, and equipment, net of accumulated depreciation	1,293
Net property and equipment	$	29,153

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The table below provides a summary of the reclassifications related to the consolidated statements of operations for the comparative periods presented.

	June 30,
	2011		2010
	(In thousands)
CONSOLIDATED STATEMENTS OF OPERATIONS
As reported previously:
Salaries and employee benefits	$	5,079	$	4,816
Depletion, depreciation, and amortization	2,326		4,680
Auditing, accounting, and legal services	2,595		1,948
Accretion expense	564		748
Shareholder communications	396		551
Other administrative expenses	7,286		6,031
Foreign transaction loss	951		677
Total	$	19,197	$	19,451
As currently reported:
Depletion, depreciation, amortization, and accretion	$	2,890	$	5,428
General and administrative	16,307		14,023
Total	$	19,197	$	19,451

ITEM 9: CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A: CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including resource constraints and judgments about the expected benefits of control alternatives relative to their costs, assumptions about the likelihood of future events, the possibility of human error, and the risk of fraud.  Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time.  Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective.

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MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company's internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that have a material effect on the financial statements.

Management assessed the effectiveness of the Company's internal control over financial reporting as of June 30, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework

Based on our assessment and these criteria, we believe that internal control over financial reporting is effective as of June 30, 2012.

This annual report does not include an attestation report of the company's registered public accounting firm regarding internal control over financial reporting. Our internal controls over financial reporting were not subject to attestation by the Company's registered public accounting firm pursuant to rules of the SEC that permit the Company to provide only management's report in this annual report.

Description of Material Weaknesses at June 30, 2011

The Company did not maintain effective internal controls over the preparation of the consolidated statement of cash flows and the review of third party expert work for significant complex and/or non-routine accounting issues:

1. An error in the Company's unaudited condensed consolidated statement of cash flows was identified as of March 31, 2011. Certain foreign currency exchange losses were improperly excluded from the reconciliation of our net loss to cash flows from operations. In addition, certain other errors were made in the preparation of the consolidated statement of cash flows for the period ended June 30, 2011. These errors, if taken individually, would not be considered material, however, on an aggregate basis were considered a material weakness.

2. The Company's internal control procedures over the review of the work provided by third party accounting experts were not effective.

Remediation Actions Relating to the Material Weaknesses

Beginning in the fiscal year 2012, the Company initiated a process to improve its internal control over financial reporting which included regular reports issued to the Audit Committee and Board of Directors as to the progress of the remediation.

1. The improvement of processes surrounding the statement of cash flows included the following steps:

• An improved process of consolidating the financial statements has been implemented, including a more efficient process to communicate, receive, and consolidate information from international locations.

• The Company has augmented its financial reporting and technical accounting resources to enable a more detailed and rigorous review of the cash flow statement in compliance with GAAP.

2. The improvement of the review process of work provided by third party accounting experts included the following steps:

• The Company has hired additional accounting and finance resources with increased technical abilities, reducing reliance on and use of third party accounting experts.

• An enhanced process to review complex accounting matters and the work provided by third party expert has been implemented among the senior accounting staff of the Company.

We believe the measures described above remediated the material weaknesses we identified in 2011 and have strengthened our internal controls over financial reporting. We identified no such material weakness that existed at June 30, 2012. We are committed to continually improving our internal control processes and will diligently and vigorously review our

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financial reporting controls and procedures. As we continue to evaluate and work to improve our internal controls over financial reporting, we may determine that additional measures are necessary to address control deficiencies. Moreover, we may decide to modify certain of the remediation measures described above.

CHANGE IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Other than described above, there have not been any other changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of the Company's fiscal year ended June 30, 2012, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 9B: OTHER INFORMATION

Not applicable.

PART III

Pursuant to General Instruction G(3), the information called for by Items 10, (except for information concerning the executive officers of the Company) 11, 12, 13, and 14 is hereby incorporated by reference to the Company’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012. Certain information concerning the executive officers of the Company is included under Item 10: Directors, Executive Officers, and Corporate Governance of this report.

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The following table sets forth the names, ages, and positions held by the Company’s executive officers. The ages of our executive officers are listed as of September 24, 2012.

Name	Age	Office Held	Length of Service as Officer
J. Thomas Wilson	60	President and Chief Executive Officer	Since September 2011
Antoine J. Lafargue	38	VP - Chief Financial Officer and Treasurer	Since July 2010
C. Mark Brannum	46	VP - General Counsel and Secretary	Since September 2012

For further information regarding the named executive officers, see the Company’s definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012.

ITEM 11: EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the information provided in the Company's definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012.

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the information provided in the Company's definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012.

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ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to the information provided in the Company's definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012.

ITEM 14: PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference to the information provided in the Company's definitive proxy statement for the 2012 annual meeting of stockholders to be filed within 120 days from June 30, 2012.

PART IV

ITEM 15: EXHIBITS AND FINCANCIAL STATEMENT SCHEDULES

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:

ITEM	PAGE
Report of Independent Registered Public Accounting Firm	47
Report of Independent Registered Public Accounting Firm	48
Consolidated Balance Sheets	49
Consolidated Statements of Operations	51
Consolidated Statements of Comprehensive Income (Loss)	52
Consolidated Statements of Stockholders’ Equity	53
Consolidated Statements of Cash Flows	54
Notes to Consolidated Financial Statements	56

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the consolidated financial statements and notes thereto.

(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:

EXHIBIT
NUMBER	DESCRIPTION
2.1	Lease Purchase and Sale and Participation Agreement among Magellan Petroleum Corporation, Nautilus Poplar LLC, and VAALCO Energy (USA), Inc., dated as of September 6, 2011 (filed as Exhibit 2.1 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
2.2	Purchase and Sale Agreement among Magellan Petroleum Corporation and the members of Nautilus Technical Group LLC and Eastern Rider LLC, dated as of September 2, 2011 (filed as Exhibit 2.2 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
2.3	Sale Agreement among Magellan Petroleum (NT) Pty Ltd, Santos QNT Pty Ltd, and Santos Limited, dated September 14, 2011 (filed as Exhibit 2.3 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
3.1	Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware, as amended by an Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware (filed as Exhibit 4.B. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference)
3.2	Certificate of Amendment of Restated Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware (filed as Exhibit 3(a) to the registrant's Quarterly Report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference)
3.3	Certificate of Amendment of Restated Certificate of Incorporation related to Articles Twelfth and Fourteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.3 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference)

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3.4	Certificate of Amendment to Restated Certificate of Incorporation related to Article Thirteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.4 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference)
3.5	Certificate of Amendment of Restated Certificate of Incorporation related to Article Fourth as filed on December 10, 2010 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference)
3.6	By-Laws, as amended on March 10, 2010 (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on March 15, 2010 and incorporated herein by reference)
10.1	Petroleum Lease No. 4 dated November 18, 1981 granted by the Northern Territory of Australia to United Canso Oil & Gas Co. (N.T.) Pty Ltd. (filed as Exhibit 10(a) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.2	Petroleum Lease No. 5 dated November 18, 1981 granted by the Northern Territory of Australia to Magellan Petroleum (N.T.) Pty. Ltd. (filed as Exhibit 10(b) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.3	Palm Valley Petroleum Lease (OL3) dated November 9, 1982 (filed as Exhibit 10(d) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.4	Palm Valley Operating Agreement dated April 2, 1985 among Magellan Petroleum (N.T.) Pty. Ltd., C.D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, I.E.D.C. Australia Pty. Ltd., Southern Alloys Ventures Pty. Limited, and Amadeus Oil N.L. (filed as Exhibit 10(f) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.5	Mereenie Operating Agreement dated April 27, 1984 among Magellan Petroleum (N.T.) Pty. Ltd., United Oil & Gas Co. (N.T.) Pty. Ltd., Canso Resources Limited, Oilmin (N.T.) Pty. Ltd., Krewliff Investments Pty. Ltd., Transoil (N.T.) Pty. Ltd., and Farmout Drillers NL, and Amendment thereto dated October 3, 1984 (filed as Exhibit 10(g) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.6	Palm Valley Gas Purchase Agreement dated June 28, 1985 among Magellan Petroleum (N.T.) Pty. Ltd., C.D. Resources Pty. Ltd., Farmout Drillers N.L., Canso Resources Limited, International Oil Proprietary, Pancontinental Petroleum Limited, IEDC Australia Pty Limited, Amadeus Oil N.L., Southern Alloy Venture Pty. Limited, and Gasgo Pty. Limited, including the Guarantee of the Northern Territory of Australia dated June 28, 1985 and the Certification Letter dated June 28, 1985 that the Guarantee is binding (filed as Exhibit 10(h) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.7	Agreements dated June 28, 1985 relating to the Amadeus Basin - Darwin Pipeline, including a Deed of Trust related to Amadeus Gas Trust, an Undertaking by the Northern Territory Electric Commission, and an Undertaking from the Northern Territory Gas Pty Ltd. (filed as Exhibit 10(j) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.8	Agreement among the Mereenie Producers and the Palm Valley Producers dated June 28, 1985 (filed as Exhibit 10(k) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 1999 and incorporated herein by reference)
10.9	Palm Valley Renewal of Petroleum Lease dated November 6, 2003 (filed as Exhibit 10(s) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 2004 and incorporated herein by reference)
10.10+	Form of Indemnification Agreement between Magellan Petroleum Corporation and directors and officers pursuant to Article Sixteenth of the Restated Certificate of Incorporation and the By-Laws (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on June 2, 2009 and incorporated herein by reference)
10.11+	1998 Stock Option Plan (filed as Exhibit 4.A. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference)
10.12+	First Amendment to the 1998 Stock Option Plan dated October 24, 2007 (filed as Exhibit 10(n) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 2008 and incorporated herein by reference)
10.13+	1998 Stock Incentive Plan, as amended and restated through September 28, 2010 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference)
10.14+	Form of Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and officers and directors (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on November 30, 2005 and incorporated herein by reference)
10.15+	Form of Amendment to Non-Qualified Stock Option Agreement between Magellan Petroleum Corporation and directors (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on December 15, 2008 and incorporated herein by reference)
10.16+	Employment Agreement between Magellan Petroleum Corporation and William H. Hastings, dated as of February 3, 2009 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on February 9, 2009 and incorporated herein by reference)
10.17+	Indemnification Agreement between Magellan Petroleum Corporation and William H. Hastings, dated as of February 3, 2009 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on February 9, 2009 and incorporated herein by reference)
10.18+	Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and William H. Hastings, dated as of February 3, 2009 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on February 9, 2009 and incorporated herein by reference)
10.19+	Non-Qualified Stock Option Performance Award Agreement between Magellan Petroleum Corporation and William H. Hastings, dated as of February 3, 2009 (filed as Exhibit 10.4 to the registrant's Current Report on Form 8-K filed on February 9, 2009 and incorporated herein by reference)

86

10.20+	Employment Agreement Addendum between Magellan Petroleum Corporation and William H. Hastings, dated as of September 27, 2011 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on October 3, 2011 and incorporated herein by reference)
10.21	Warrant Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated July 9, 2009 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 14, 2009 and incorporated herein by reference)
10.22	Amended and Restated Warrant Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated March 11, 2010 (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q filed on May 14, 2010 and incorporated herein by reference)
10.23	Registration Rights Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated July 9, 2009 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on July 14, 2009 and incorporated herein by reference)
10.24	First Amendment to Registration Rights Agreement among Magellan Petroleum Corporation, Young Energy Prize S.A., and YEP I, SICAV-FIS, dated as of October 14, 2009 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on October 19, 2009 and incorporated herein by reference)
10.25	Second Amendment to Registration Rights Agreement among Magellan Petroleum Corporation, Young Energy Prize S.A., and ECP Fund, SICAV-FIS, dated June 23, 2010 (filed as Exhibit 10(xx) to the registrant's Annual Report on Form 10-K for the fiscal year ended June 30, 2010 and incorporated herein by reference)
10.26+	Consulting Agreement between Magellan Petroleum Corporation and J. Thomas Wilson, dated July 9, 2009 (filed as Exhibit 10.4 to the registrant's Current Report on Form 8-K filed on July 14, 2009 and incorporated herein by reference)
10.27+	Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and J. Thomas Wilson, dated July 9, 2009 (filed as Exhibit 10.5 to the registrant's Current Report on Form 8-K filed on July 14, 2009 and incorporated herein by reference)
10.28+	Non-Qualified Stock Option Performance Award Agreement between Magellan Petroleum Corporation and J. Thomas Wilson, dated July 9, 2009 (filed as Exhibit 10.6 to the registrant's Current Report on Form 8-K filed on July 14, 2009 and incorporated herein by reference)
10.29+	Employment Agreement between Magellan Petroleum Corporation and J. Thomas Wilson dated November 2, 2011 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K/A filed on November 16, 2011 and incorporated herein by reference)
10.30+	Indemnification Agreement between Magellan Petroleum Corporation and J. Thomas Wilson dated November 2, 2011 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K/A filed on November 16, 2011 and incorporated herein by reference)
10.31+	Nonqualified Stock Option Award Agreement between Magellan Petroleum Corporation and J. Thomas Wilson dated November 16, 2011 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K/A filed on November 16, 2011 and incorporated herein by reference)
10.32+	Restricted Stock Award Agreement between Magellan Petroleum Corporation and J. Thomas Wilson dated November 16, 2011 (filed as Exhibit 10.4 to the registrant's Current Report on Form 8-K/A filed on November 16, 2011 and incorporated herein by reference)
10.33	First Amended and Restated Operating Agreement of Nautilus Poplar, LLC among Nautilus Technical Group, LLC, White Bear, LLC, YEP I, SICAV-FIS, and Eastern Rider, LLC dated as of October 14, 2009 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on October 19, 2009 and incorporated herein by reference)
10.34+	Employment Agreement between Magellan Petroleum Corporation and Susan M. Filipos, dated as of September 28, 2009 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on May 7, 2010 and incorporated herein by reference)
10.35+	Employment Agreement between Magellan Petroleum Corporation and Susan M. Filipos, dated as of September 28, 2009, as amended on August 16, 2011 (filed as Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
10.36+	Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and Susan M. Filipos, dated as of October 1, 2009 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on May 7, 2010 and incorporated herein by reference)
10.37+	Indemnification Agreement between Magellan Petroleum Corporation and Susan M. Filipos, dated as of May 3, 2010 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on May 7, 2010 and incorporated herein by reference)
10.38	Assets Sale Deed between Magellan Petroleum Australia Limited and Santos Offshore Pty Ltd., dated as of March 25, 2010 (filed as Exhibit 2.1 to the registrant's Quarterly Report on Form 10-Q filed on May 14, 2010 and incorporated herein by reference)
10.39+	Form of Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and non-employee directors, dated April 1, 2010 (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q filed on May 14, 2010 and incorporated herein by reference)
10.40+	Form of Restricted Stock Award Agreement between Magellan Petroleum Corporation and non-employee directors, dated April 1, 2010 (Version A) (filed as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q filed on May 14, 2010 and incorporated herein by reference)
10.41+	Form of Restricted Stock Award Agreement between Magellan Petroleum Corporation and non-employee directors, dated April 1, 2010 (Version B) (filed as Exhibit 10.4 to the registrant's Quarterly Report on Form 10-Q filed on May 14, 2010 and incorporated herein by reference)

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10.42+	Employment Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue, dated as of August 2, 2010 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on August 4, 2010 and incorporated herein by reference)
10.43+	Indemnification Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue, dated as of August 2, 2010 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on August 4, 2010 and incorporated herein by reference)
10.44+	Non-Qualified Stock Option Award Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue, dated as of August 2, 2010 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on August 4, 2010 and incorporated herein by reference)
10.45+	Non-Qualified Stock Option Performance Award Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue, dated as of August 2, 2010 (filed as Exhibit 10.4 to the registrant's Current Report on Form 8-K filed on August 4, 2010 and incorporated herein by reference)
10.46+	Nonqualified Stock Option Award Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue dated November 30, 2011 (filed as Exhibit 10.7 to the registrant's Quarterly Report on Form 10-Q filed on February 10, 2012 and incorporated herein by reference)
10.47+	Nonqualified Stock Option Performance Award Agreement between Magellan Petroleum Corporation and Antoine J. Lafargue dated November 30, 2011 (filed as Exhibit 10.8 to the registrant's Quarterly Report on Form 10-Q filed on February 10, 2012 and incorporated herein by reference)
10.48	Securities Purchase Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated August 5, 2010 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on August 11, 2010 and incorporated herein by reference)
10.49	Memorandum of Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated August 5, 2010 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on August 11, 2010 and incorporated herein by reference)
10.50	Investor Rights Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated August 5, 2010 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on August 11, 2010 and incorporated herein by reference)
10.51	Letter Deed dated December 23, 2010 between Magellan Petroleum Australia Limited and Santos Offshore Pty Ltd. (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on December 28, 2010 and incorporated herein by reference)
10.52	Deed of Variation between Magellan Petroleum Australia Limited and Santos Offshore Pty Ltd. dated as of January 31, 2011 (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q filed on May 16, 2011 and incorporated herein by reference)
10.53	Letter of Young Energy Prize S.A. to Magellan Petroleum Corporation dated January 13, 2011, effective as of December 23, 2010 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on January 18, 2011 and incorporated herein by reference)
10.54	First Amendment to Securities Purchase Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated February 11, 2011 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on February 18, 2011 and incorporated herein by reference)
10.55	Second Amendment to Securities Purchase Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated February 17, 2011 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on February 18, 2011 and incorporated herein by reference)
10.56	Investment Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated February 11, 2011 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on February 18, 2011 and incorporated herein by reference)
10.57	Amended Side Letter to Investment Agreement between Magellan Petroleum Corporation and Young Energy Prize S.A., dated February 17, 2011 (filed as Exhibit 10.4 to the registrant's Current Report on Form 8-K filed on February 18, 2011 and incorporated herein by reference)
10.58	Release Agreement between Santos Offshore Party Ltd and Magellan Petroleum Australia Limited, dated as of July 21, 2011 (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
10.59	Registration Rights Agreement among Magellan Petroleum Corporation and the members of Nautilus Technical Group LLC and Eastern Rider LLC, dated September 2, 2011 (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
10.60	Gas Supply and Purchase Agreement among Magellan Petroleum (N.T.) Pty. Ltd., Santos Limited, and Santos QNT Pty. Ltd., dated September 14, 2011 (filed as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
10.61+	Offer Letter to Milam Randolph Pharo dated November 16, 2011 and accepted on November 30, 2011 (filed as Exhibit 10.5 to the registrant's Quarterly Report on Form 10-Q filed on February 10, 2012 and incorporated herein by reference)
10.62+	Nonqualified Stock Option Award and Subscription Agreement between Magellan Petroleum Corporation and Milam Randolph Pharo dated November 30, 2011 (filed as Exhibit 10.6 to the registrant's Quarterly Report on Form 10-Q filed on February 10, 2012 and incorporated herein by reference)
10.63+	Nonqualified Stock Option Award and Subscription Agreement between Magellan Petroleum Corporation and Blaine K. Spies dated December 14, 2011 (filed as Exhibit 10.9 to the registrant's Quarterly Report on Form 10-Q filed on February 10, 2012 and incorporated herein by reference)
14.1*	Code of Conduct of Magellan Petroleum Corporation, as amended July 24, 2012

88

21.1*	Subsidiaries of the Registrant
23.1*	Consent of Ehrhardt Keefe Steiner & Hottman PC
23.2*	Consent of Deloitte & Touche LLP
23.3*	Consent of Allen & Crouch Petroleum Engineers Inc.
23.4*	Consent of Ryder Scott Company, L.P.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Summary reserves report of Allen & Crouch Petroleum Engineers, Inc.
99.2*	Summary reserves report of Ryder Scott Company, L.P.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Taxonomy Extension Schema Document
101.CAL***	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	XBRL Taxonomy Extension Presentation Linkbase Document
*	Filed herewith.
**	Furnished herewith.
***	To be furnished by amendment. Users of this data to be submitted electronically are advised pursuant to Rule 406T of Regulation S-T that this interactive data file will not be deemed filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, will not be deemed filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise will not be subject to liability under these sections.
+	Management contract or compensatory plan or arrangement.

89

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		MAGELLAN PETROLEUM CORPORATION
		(Registrant)
		By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)
		By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer
			(as Principal Financial and Accounting Officer)
Date:	September 24, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ J. Thomas Wilson	Date:	September 24, 2012
John Thomas Wilson, President and Chief Executive Officer, and Director
/s/ Antoine J. Lafargue	Date:	September 24, 2012
Antoine J. Lafargue, Vice President - Chief Financial Officer, and Treasurer
/s/ Donald V. Basso	Date:	September 24, 2012
Donald V. Basso, Director
/s/ Nikolay Bogachev	Date:	September 24, 2012
Nikolay Bogachev, Director
/s/ Walter McCann	Date:	September 24, 2012
Walter McCann, Director
/s/ Robert J. Mollah	Date:	September 24, 2012
Robert J. Mollah, Director
/s/ Ronald P. Pettirossi	Date:	September 24, 2012
Ronald P. Pettirossi, Director
/s/ J. Robinson West	Date:	September 24, 2012
J. Robinson West, Director

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INDEX TO EXHIBITS

EXHIBIT
NUMBER	DESCRIPTION
14.1*	Code of Conduct of Magellan Petroleum Corporation, as amended July 24, 2012
21.1*	Subsidiaries of the Registrant
23.1*	Consent of Ehrhardt Keefe Steiner & Hottman PC
23.2*	Consent of Deloitte & Touche LLP
23.3*	Consent of Allen & Crouch Petroleum Engineers Inc.
23.4*	Consent of Ryder Scott Company, L.P.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Summary reserves report of Allen & Crouch Petroleum Engineers, Inc.
99.2*	Summary reserves report of Ryder Scott Company, L.P.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Taxonomy Extension Schema Document
101.CAL***	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	XBRL Taxonomy Extension Presentation Linkbase Document
*	Filed herewith.
**	Furnished herewith.
***	To be furnished by amendment. Users of this data to be submitted electronically are advised pursuant to Rule 406T of Regulation S-T that this interactive data file will not be deemed filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, will not be deemed filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise will not be subject to liability under these sections.

91

EX-14.1

Exhibit 14.1

Code of Conduct

As amended by the Board of Directors on July 24, 2012

GENERAL PRINCIPLES

This Code of Conduct ("Code") for Magellan Petroleum Corporation (the "Company") is designed to provide employees, officers, and directors of the Company with guidelines for dealing with other employees, customers, vendors, shareholders, competitors, the communities where we work, conflicts of interest, and trading in the Company's securities. The Company also expects others who work on the Company's behalf, such as agents and consultants, to be guided by this Code in their work for the Company.

Business Ethics and Compliance

It is the policy of the Company that all employees, officers, directors, agents, and other representatives of the Company maintain the highest ethical standards and comply with all applicable laws, rules, and regulations when conducting business on behalf of the Company in the United States ("U.S.") and any other country.

Employees

We are committed to maintaining employment practices based on equal opportunity for all employees. We will respect each other's privacy and treat each other with dignity and respect. We are committed to providing a safe working environment and an atmosphere of open communication for all employees. Contract personnel temporarily employed by the Company to (i) address increases in workload in a given area and/or (ii) work on a particular project are not full time Company employees. However, unless otherwise indicated, for purposes of this Code, the term "employees" or "representatives" shall include both Company employees and contract personnel.

Shareholders

We are committed to continually striving to provide an excellent return on the investment of our shareholders in the Company and to protect and improve the long-term value of their investment through the prudent utilization of Company resources.

Competitors

We are committed to competing vigorously and honestly in the oil and gas exploration and production industry. Our efforts and results will be based on the merits of our competitive ability.

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Communities

We are committed to being a responsible corporate citizen of the communities in which we reside. We will abide by all national and local laws, and will endeavor to improve the well being of our communities.

STANDARDS OF CONDUCT

Introduction

Our Code of Conduct governs our business decisions and actions. The integrity, reputation, and profitability of the Company ultimately depend upon the individual actions of our employees, officers, directors, and other representatives. Each employee, officer, and director is personally responsible and accountable for compliance with this Code. In addition, any representative, consultant, or agent utilized by the Company shall be prohibited from acting on our behalf in any manner which is inconsistent with this Code. All of the foregoing persons are from time to time directly referred to in this Code as "you."

This Code serves to assist in defining our ethical principles, and are not all-encompassing. This Code must be interpreted within the framework of the laws, rules, regulations, and customs of the jurisdictions in which we operate, as well as in light of specific Company policies and common sense. Reasons such as "everyone does it," or "the competition is doing it," or "it's not illegal" are unacceptable as excuses for violating this Code. We must seek to avoid circumstances and actions that give the appearance of impropriety. This Code will be enforced equitably.

Business and Accounting Practices

Compliance with generally accepted accounting principles, rules, and standards, and established internal controls, is required at all times. The use of assets of the Company for any unlawful or improper purpose is strictly prohibited. Purchasers, vendors, royalty owners, joint interest owners, and other third party entities shall be honestly and fairly dealt with, and employees shall conduct business with such parties in a manner that will not impugn or jeopardize the Company's integrity or reputation. No payment on behalf of the Company shall be approved without adequate supporting documentation. Also, no payment shall be made with the intention or understanding that any part of such payment is to be used for any purpose other than that described by the documents supporting the payment.

Political Contributions

U.S. Federal, State, and Local Contributions

No funds or assets of the Company shall be used for U.S. federal political campaign contributions, even if permitted by applicable law. No such funds or assets shall be used for state or local political contributions, even where permitted by applicable state or local laws. These prohibitions cover not only direct contributions, but also indirect assistance or support of candidates or political parties through the purchase of tickets to special dinners or other fund raising events. Also prohibited is the furnishing of any goods, services, or equipment to political parties or committees.

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Foreign Contributions

No funds or assets of the Company shall be used, directly or indirectly, for political contributions outside of the U.S., even where permitted by local laws.

Anti-Bribery and Corrupt Practices Law Compliance

U.S. Foreign Corrupt Practices Act, Australian Anti-Bribery Laws, U.K. Bribery Act, and Other Similar Laws

We must comply with the U.S. Foreign Corrupt Practices Act (the "FCPA"), which prohibits payments and offers of payments of anything of value to foreign officials, political parties, or candidates for foreign political office, in order to get, keep, or direct business. Payments made indirectly through intermediaries, such as sales agents and consultants, when circumstances indicate that such payments are being passed along for prohibited purposes, are also illegal. In addition to prohibiting certain actions, the FCPA requires internal accounting controls and record keeping by the Company in connection with payments by it or its foreign subsidiaries.

The application of the FCPA can be complex. For example, the term "foreign official" includes employees of businesses owned by a foreign government. In addition, claiming not to know of a prohibited offer or payment may not serve as a defense if you are aware of circumstances that would reasonably cause suspicion. Further complexity results from certain exceptions in the FCPA, such as the exception for facilitation payments, which may not exist under other applicable anti-bribery and corrupt practices laws as discussed below. For these reasons, the assistance of legal counsel is essential for working through the complexities of the issues encountered in connection with complying with the FCPA and other applicable anti-bribery and corrupt practices laws.

Other countries have enacted or are enacting laws similar to the FCPA, such as the 2010 amendments to the Australian Criminal Code Act 1995 to provide for the imposition of significant penalties on individuals and corporations found guilty of bribing a foreign or Commonwealth of Australia public official. Many such laws apply a broad definition of "public official" or "corrupt practices" and state that local custom or practice, if questionable regarding corruption and bribes, must be disregarded. It is important to note that, like the FCPA, some of these laws, such as the U.K. Bribery Act 2010 (the "U.K. Bribery Act"), are extra-territorial. This means that they apply even if the transactions take place outside of the country imposing the law. For example, provisions under the U.K. Bribery Act related to an organization's failure to prevent bribery extend to organizations carrying on a business or part of a business in the United Kingdom ("U.K."), regardless of the place of incorporation or where the bribery was committed. Accordingly, because the Company has a business presence in the U.K., we could be subject to liability under the U.K. Bribery Act for bribes paid in a third country.

The U.K. Bribery Act contains two broad categories of primary offense - (1) the offering, promising, or giving of a financial or other advantage, and (2) the requesting, agreeing to receive, or accepting of a financial or other advantage - in business transactions involving either government officials or private parties, with the intention of inducing or rewarding a person to perform certain functions improperly. Under the U.K. Bribery Act, companies are required not only to refuse participation in bribes and other unethical practices for business preferences, but also to have adequate procedures in place to prevent corruption and bribery. Unlike the FCPA, the U.K. Bribery Act prohibits bribery in the private sector, and does not permit facilitation payments, which are sometimes requested to induce public officials in some countries to perform their functions, such as issuing permits or licenses, and which may be permissible under

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the FCPA. Due to these complexities and the broad extra-territorial applicability of the U.K. Bribery Act, Company employees and other associated parties must consult with the Company's legal counsel before offering or making any payment which could be construed as a bribe or facilitation payment to any person in any jurisdiction.

As indicated above, the Company could be found in violation of anti-bribery or corrupt practices laws for actions taken by third parties, or "associated parties," acting on our behalf. Associated parties include joint venture partners, agents, employees of outside service providers, consultants, or subcontractors who perform services on our behalf. It is important that Company employees remain alert for any suspicious behavior by associated parties or related events and promptly report them to their supervisor/manager.

To ensure compliance with anti-bribery and corrupt practices laws, no funds or assets of the Company shall be paid, loaned, given, or otherwise transferred, directly or indirectly, to any federal, state, local, or foreign government official or employee, or to any entity in which the government official or employee is known to have a material interest, or to a private party, except in accordance with the following practices and procedures.

Legitimate Business Transactions

The Company shall enter into no transaction with any government official, employee, or entity, or a private party, except for a legitimate business purpose and upon terms and conditions which are fair and reasonable under the circumstances and which comply with all applicable laws, rules, and regulations.

Retention as Attorneys or Consultants

No government official or employee shall be retained by the Company to perform legal, consulting, or other services related to a matter within the scope of his or her official duties or the duties and responsibilities of the governmental body of which he or she is an official or employee.

Social Amenities, Gifts, and Entertainment

Under no circumstance shall the Company's relations with government officials and employees be conducted in any manner which would subject the Company to embarrassment or reproach if publicly disclosed. Accordingly, when considering whether to offer or provide any gift or entertainment to any government official or employee, you must follow the applicable provisions under "Gift Giving and Receiving" in this Code below, and keep in mind that social amenities, reasonable entertainment, and other courtesies may be extended to government officials or employees only to the extent clearly appropriate under applicable customs and practices and not prohibited by any applicable law, rule, or regulation. Any expenses incurred by a Company employee in connection therewith shall be specifically designated as such on the employee's related expense account and specifically reviewed and approved by the employee's immediate supervisor/manager.

4

Foreign Transactions and Payments

Having due regard for and recognition of the responsibilities arising from and attendant to international operations, it is the Company's policy that all of its employees, officers, and agents shall comply with the ethical standards and applicable legal requirements of each foreign country in which Company business is conducted.

Foreign Deposits and Accounts

All accounts established and maintained abroad by the Company shall be clearly identified on the Company's books and records in the name of the Company. All cash payments received abroad by the Company shall be promptly recorded on the Company's books of account and deposited in an account maintained with a bank or other institution approved by the Company's Chief Financial Officer. No funds shall be maintained abroad by the Company in the form of negotiable currency except to the extent reasonably required for normal business operations.

Sales and Purchases of Goods or Services Abroad

All payments and billings for goods or services abroad shall be made in such a manner that public disclosure of the full details thereof will not impugn or jeopardize the Company's integrity or reputation. Foreign sales of goods or services by the Company shall be billed to the purchaser by written invoice setting forth, in reasonable detail, the goods or services involved and the correct amounts due the Company. Any amount billed subject to refund shall be separately identified on such invoice.

Each payment by the Company for goods or services purchased abroad shall be supported by documentation reflecting the purpose and nature of such payment. All payments of fees and commissions to attorneys, consultants, advisors, agents, dealers, and representatives shall be made by check, draft, or other documentary transfer drawn to the order of the party duly entitled thereto, and shall be made under written contract except where services are routine in nature and arise out of the Company's ordinary course of business.

No payment shall be made directly to an account maintained by a party in a country other than that in which such party resides or maintains a place of business or has rendered the services for which the payment is made, except under circumstances giving no reasonable grounds for belief that the Company would thereby violate any applicable income tax or exchange control laws.

EMPLOYEES

Equal Employment Opportunity

It is our policy to afford equal employment opportunities to all qualified individuals in all aspects of the employment relationship.

5

Employee Development

The Company is dedicated to promoting the development and enhancement of work-related skills of full time employees. The Company expects each full time employee to play an important role in assessing his or her training and development needs and, if there is a concern such needs are not currently being met, to discuss the same with his or her manager/supervisor.

Workplace Environment

The Company is committed to providing its employees with a safe employment environment, free from discrimination or harassment and conducive to productive work.

Sexual and Other Unlawful Harassment

It is the policy of the Company to treat all employees with respect and dignity. The Company prohibits any form of harassment, including harassment based on an employee's gender, race, national origin, religion, age, or disability. Harassment is verbal or physical conduct that denigrates or shows hostility or aversion toward an individual because of his/her race, color, religion, gender, national origin, age, or disability, or that of his/her relatives, friends, or associates, and that: (1) has the purpose or effect of creating an intimidating, hostile, or offensive working environment; (2) has the purpose or effect of unreasonably interfering with an individual's work performance; or (3) otherwise adversely affects an individual's employment opportunities. Unwelcome sexual advances and/or requests for sexual favors constitute sexual harassment when submission to such conduct is made either explicitly or implicitly a term or condition of an individual's employment, or submission to, or rejection of, such conduct by an individual is used as a basis for employment decisions affecting such individual. Other sexually harassing conduct includes: (1) unwelcome sexual flirtations, advances, or propositions; (2) verbal or written abuse of a sexual nature; (3) graphic, verbal, or written comments about an individual's body; (4) sexually degrading words used to describe an individual; and (5) the display, in our workplace, of sexually suggestive objects or pictures.

Any person who believes he or she has been or is being subjected to harassment based on his or her gender, race, national origin, religion, age, or disability, should bring the matter to the attention of his or her supervisor/manager, or, if that supervisor/manager is involved in the harassment, the President or the General Counsel of the Company. Any person who believes that unlawful harassment has occurred or is occurring should promptly report such conduct to one of the above persons regardless of the position of the offending person. Reports should be made as soon as possible (usually within 24 hours) to enable the Company to facilitate prompt and thorough investigations and enable the Company to eradicate harassment. Employees should not wait for a situation to become worse or unbearable before making a report. All reports and complaints will be promptly investigated. It is intended that the privacy of the persons involved will be protected, except to the extent necessary to comply with applicable laws and regulations and to conduct a fair, thorough, and effective investigation.

If the investigation substantiates that the report or complaint is valid, immediate corrective action designed to stop the harassment and prevent its reoccurrence will be taken. Such corrective action may, in appropriate instances, include discipline (up to and including discharge) of the offending person. Any person who believes she or he has been or is being subjected to harassment, or who believes she or he has observed harassment, and who reports the matter

6

pursuant to this policy, shall not be retaliated against or adversely treated, with respect to terms and conditions of employment, because of the making of the report. All supervisors and managers have the responsibility to eliminate all harassing behavior. This responsibility includes communicating the Company's anti-harassment policy, educating all employees under their supervision about the policy and how to use it, and enforcing the policy.

Drug and Alcohol Abuse

Drug abuse in the workplace is strictly prohibited. Furthermore, employees are required to report to work free from the presence of illegal or prohibited drugs or alcohol in their body systems. Alcohol use by employees on the job is also prohibited, except that reasonable alcohol use in connection with appropriate business dinners or entertainment is permitted, subject to all applicable laws regarding alcohol consumption.

Communication

The Company is committed to providing communication channels that encourage self-expression and open dialog relative to good faith opinions, questions, and concerns regarding this Code of Conduct. The Company is also committed to follow-up on those expressions and to ensure proper management response. Each employee is encouraged and expected to direct his or her questions or concerns regarding this Code of Conduct and their application to the affairs of the Company to his or her supervisor/manager or to the Chief Financial Officer or General Counsel of the Company.

Conflicts of Interest

The term "conflict of interest" describes any circumstance that could cast doubt on our ability to act with total objectivity with regard to the Company's interests. You must deal with vendors, customers, and others doing business with the Company in a manner that avoids even the appearance of a conflict between personal interests and those of the Company. Although it is impossible to list all potential conflict of interest situations, the following examples represent a few situations where a conflict of interest could arise:

• A significant direct or indirect financial interest in any company that is a Company vendor, competitor, or customer, where the interest could appear to influence decisions with respect to our business or relationship with such company or otherwise influence judgment on our matters.

• Serving on the Board of Directors or employment in any capacity with any vendor, competitor, or customer of the Company.

• Use of any Company asset for personal advantage. Examples of such assets include not only equipment, tools, and supplies, but also valuable ideas, technical data, and other confidential information.

7

Relationships, including business, financial, personal, and those with relatives may give rise to situations causing conflicts of interest or the appearance of a conflict. You must carefully evaluate your relationships as they relate to Company business to ensure that such conflicts do not exist or arise. To avoid conflicts of interest:

• You must not have undisclosed financial interests in any businesses that compete or deal with the Company.

• You must not perform services in competition with the Company.

• While you are encouraged to participate in philanthropic, professional, and community organizations, you must ensure that the manner of your participation in a particular organization does not imply the Company's endorsement or sponsorship.

• A full time employee shall obtain the approval of his or her supervisor/manager before serving as a trustee, regent, director, or officer of a philanthropic, professional, national, regional, or community organization or educational institution. This policy applies where significant time spent in support of these functions may interfere with time that should be devoted to the Company's business.

• You must not sell or lease equipment, materials, or property to the Company without appropriate corporate authorization.

• Purchases of equipment, materials, property, and services shall be only on terms available to the general public.

• You must not use other Company employees to perform non-Company work.

The Company recognizes that the exercise of judgment is required in determining the applicability of the conflicts of interest policy to any given situation. Primary responsibility for conduct within the letter and spirit of this policy must rest with you.

Antitrust/Competition Law Compliance

The Company is committed to abiding by the antitrust laws, as they are referred to in the U.S., or competition laws, as they are often referred to internationally, of every jurisdiction in which the Company does business. These laws and related rules and regulations are designed to help make sure the free market system works properly and that competition among companies is fair, by prohibiting such things as anti-competitive agreements among competitors and providing for the regulatory monitoring of potential situations where a business may have or obtain market power. For example, the joint marketing of natural gas by industry participants in a project in Australia can be subject to review by the Australian Competition and Consumer Commission. Everyone with the Company is responsible for compliance with applicable antitrust/competition laws. You should seek legal advice from the Company's legal counsel whenever any question arises as to the possible application of the antitrust/competition laws, and be guided by the advice received.

8

Consultants, Representatives, Agents, Contractors, and Subcontractors

Consultants, representatives, agents, and subcontractors of the Company must not act on the Company's behalf in any manner which is inconsistent with our Code of Conduct.

Vendors

It is our policy to purchase all equipment and services on the basis of competitive pricing and/or merit. Company vendors will be treated with integrity and without discrimination.

Gift Giving and Receiving

You must not accept gifts, gratuities, or entertainment in any form from existing or potential vendors or customers, or anyone else in business with or seeking to do business with the Company, if acceptance of such item violates any applicable law or regulation, or could be perceived as having influence over decisions regarding Company business. Any gift valued in excess of $100 shall be the property of the Company and shall be reported to your supervisor/manager. You should not give or offer to give gifts, favors, or entertainment to anyone on the Company's behalf unless such item (1) is in accordance with accepted business practice; (2) is of nominal value; (3) could not be construed as a kickback, bribe, or other payment in violation of any applicable law or regulation; (4) was not solicited or offered in return for something else; and (5) is approved in advance by your supervisor/manager. If you have any questions about gifts or entertainment, you should consult with your supervisor/manager or the Chief Financial Officer or General Counsel.

SHAREHOLDERS

Return on Investment

The Company's main objectives are to earn a profit, in an ethical manner, and to provide a consistent return on shareholder investment, given the standards and general conditions of the oil and gas industry in the Company's areas of operation.

Protection of Assets - Confidentiality

You are responsible for the proper use, conservation, and protection of the Company's assets. Employees, officers, and directors frequently have access to the intellectual property of the Company, such as business, geological, geophysical, and other technical information, including computer programs and oil and gas production data. You must not misuse or improperly disclose "confidential information" pertaining to the business affairs of the Company. Confidential information is private information about the Company and its business partners or other entities that are subject to a confidentiality agreement with the Company. Examples include:

• Information pertaining to drilling programs or wells drilled by the Company.

• Information about acquisitions, mergers, or other purchases or sales of oil and gas properties or technology.

• Financial information, including historical, current, and projected financial results, unless publicly announced.

• Information about future plans or changes in the Company's operations.

• Information about liquidity, borrowings, securities offerings, or changes in previously disclosed financial information.

9

• Changes in management.

• Information about significant litigation.

You should assume that any of the types of information listed above that is received from an outside company or individual has been provided on the condition that it is to be kept confidential, whether or not there exists a written confidentiality agreement. You should not disclose confidential information to anyone except those within the Company or authorized representatives who have a "need to know." Precautions should be taken to avoid inadvertent disclosure. Examples of precautions which should be taken to avoid inadvertent disclosure, include:

• Avoiding discussion of confidential information in public places.

• Keeping sensitive documents in secure areas, in envelopes or folders marked "confidential" where appropriate.

• Ensuring that documents are not left in non-secure locations such as the photocopy room or at the facsimile machine.

If you receive information about a company as a result of the Company's relationship or business with that company, you may not trade in the securities of that company until you are certain that this information is available to the public.

Accuracy of Company Records

Company supervisors/managers are responsible for maintaining an effective system of administrative and accounting controls in their areas of responsibility. Internal controls provide the Company with a system of "checks and balances" to help ensure that administrative and accounting policies are complied with throughout the organization. In addition to being necessary and good business practice, this policy promotes compliance with the applicable securities laws. Administrative controls promote organizational effectiveness and help establish a uniform direction for employee efforts by ensuring adherence to Company policies. Accounting controls safeguard Company assets and ensure the reliability of Company records. In administering the system of internal control, supervisors are expected to communicate to their subordinates all Company policies that apply to their job, show leadership in adhering to the policies and enforcing them, and establish reasonable procedures for carrying out Company policies and preventing deviations. In carrying out their responsibility for administering accounting controls, supervisors must ensure that:

• Business transactions of all kinds are executed by employees authorized to do so.

• Access to assets of all kinds (e.g., cash, inventory, property, etc.) is permitted only with authorization by appropriate management levels.

• Business transactions are reported and recorded as necessary to (a) permit preparation of accurate financial statements and other records in conformity with generally accepted accounting principles and (b) clearly reflect and maintain the responsibility and accountability for assets.

• Records identifying the responsibility and accountability for assets are compared with actual assets at reasonable intervals, and appropriate action is taken if there are discrepancies.

Supervisors must ensure that records are kept on a timely basis and accurately and fairly represent all business transactions. This means that:

• All assets and transactions must be recorded in normal books and records.

• No unrecorded funds shall be established or maintained for any purpose.

10

• Records shall not be falsified in any manner.

Oral and written descriptions of transactions, whether completed or contemplated, must be full and accurate. Special care must be exercised in describing transactions to those responsible for the preparation or verification of financial records to avoid any misunderstandings. The retention or disposal of Company records shall be in accordance with established policies and/or legal requirements. Anyone with questions or concerns about possible inaccurate or false records should promptly report them to the Chief Financial Officer.

Insider Trading

You must adhere to the Company's "INSIDER TRADING POLICY" and all applicable laws and regulations with respect to insider trading in securities.

Public Reporting

The Company's principal executive, financial, and accounting officers are responsible for the full, fair, accurate, timely, and understandable disclosure of all information required by applicable laws or regulations to be so disclosed in reports and documents filed with, or submitted to, the U.S. Securities and Exchange Commission (the "SEC") and other regulators, and all information in other public communications made by the Company. All such reports and documents shall be filed or submitted in a timely, accurate, and complete manner in compliance with applicable laws and regulations.

Shareholder Communications

Our shareholders are the owners of the Company. All shareholder inquiries pertaining to the Company shall receive prompt response from the Company through appropriate Company personnel. Subject to applicable securities laws and regulations, including the SEC's Regulation FD (Fair Disclosure), and the confidentiality requirements of our business, shareholders shall be informed on a fair basis of all significant and material Company events in a timely and appropriate manner. In order to ensure that material information is provided to shareholders on a fair basis, employees, officers, and directors of the Company must not discuss material nonpublic information about the Company with shareholders, members of the investment community (including securities analysts or representatives of broker/dealers, investment advisors or managers, investment companies, hedge funds, or private equity funds), or the media, except as authorized by the Company's senior management and in accordance with the Company's procedures for external disclosure of information regarding the Company (e.g., in SEC filings or press releases).

COMMUNITIES

Health, Safety, and Environmental Matters

The Company will conduct its operations in a manner that safeguards the environment. The Company believes the promotion of health, safety, and sound environmental practice to be of fundamental importance to the welfare of the Company, its shareholders, and employees. In this regard, the Company has established policies, procedures, and plans for the conduct of its operations in compliance with applicable environmental and occupational health and safety laws and regulations, which must be complied with by all employees. Communication from employees on health, safety, and environmental matters is invited by management and is seen as being a key factor in achieving the Company's goals.

11

COMPLIANCE PROCEDURES

Reporting any Illegal or Unethical Behavior

You should promptly report to your supervisor/manager or to the Chief Financial Officer or General Counsel any observed illegal or unethical behavior or violation of this Code. You should also promptly talk to your supervisor/manager or to the Chief Financial Officer about any questions or concerns regarding compliance by you or others with this Code, or when in doubt about the best course of action in a particular situation. It is the policy of the Company not to allow retaliation for reports of misconduct by others made in good faith. You are expected to cooperate in any internal investigations of misconduct.

The Audit Committee of the Company's Board of Directors has established procedures for the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, auditing, or other matters, and the confidential, anonymous submission by employees of concerns regarding questionable accounting, auditing, or other matters. If you have any concerns regarding accounting, internal accounting controls, auditing, or other similar matters, you are encouraged to follow those procedures.

Compliance Procedures

We must all work to ensure prompt and consistent action to foster compliance with this Code. However, in some situations it is difficult to know the appropriate course of action. Since we cannot anticipate every situation that may arise, it is important that we have a way to approach a new question or problem. These are the steps to keep in mind:

• Make sure you have all the facts. In order to reach the right solutions, we must be as fully informed as possible.

• Ask yourself: What specifically am I being asked to do? Does it seem unethical or improper? This will enable you to focus on the specific question you are faced with, and the alternatives you may have. Use your judgment and common sense. If something seems unethical or improper, it probably is.

• Understand each person's individual responsibility and role. In most situations, there is shared responsibility. Are your colleagues informed? It may help to get others involved and discuss the problem.

• Discuss the problem with your supervisor/manager or the Chief Financial Officer or General Counsel. This is the basic guidance for all situations. In many cases, your supervisor/manager or the Chief Financial Officer or General Counsel will be more knowledgeable about the question and will appreciate being brought into the decision-making process.

• Seek help from other Company resources. In the rare case where it may not be appropriate to discuss an issue with your supervisor/manager or the Chief Financial Officer or General Counsel, or where you do not feel comfortable approaching your supervisor/manager or the Chief Financial Officer or General Counsel with your question, you should discuss it with the Chairman of the Audit Committee. If that also is not appropriate, call the Chairman of the Board of Directors at (720) 570-3858 and, if appropriate, you will be put in direct contact with the appropriate assistance. If you prefer to write, address your concerns to: Chairman of the Board of Directors, c/o Magellan Petroleum Corporation, 700 East Ninth Avenue, Suite 200, Denver, CO 80203.

• You may report ethical violations in confidence and without fear of retaliation. If your situation requires that your identity be kept secret, your anonymity will be protected to the fullest extent practicable, consistent with applicable laws, regulations, and the requirements necessary to conduct a fair, thorough, and effective investigation

12

of the conduct or matter. The Company will not permit retaliation of any kind against any person for a report made in good faith and pursuant to the provisions of this Code of a matter or conduct that the reporting person reasonably believes may constitute a violation of this Code or applicable laws, rules, or regulations (except that appropriate disciplinary action may be taken against the reporting person if such person was involved in the violation).

• Always ask first, act later: If you are unsure of what to do in any situation, seek guidance and ask questions before you act.

Investigation of Violations

If, through compliance monitoring, internal or independent audit procedures, reports under this Code, or otherwise, the Company becomes aware of a potential violation of this Code, an executive officer, or if the matter involves an executive officer or director, the Board of Directors, shall, as appropriate:

• evaluate the underlying information as to gravity and credibility;

• promptly initiate an informal inquiry or a formal investigation;

• prepare a report of the results of such inquiry or investigation, including recommendations as to the disposition of the matter; and

• determine and implement the appropriate disciplinary action.

Anyone accused of wrongdoing shall be allowed to review the underlying information and make corrections in the event of a factual error. All documents and reports with respect to potential violations of this Code and the resolution and any action taken with respect thereto shall be retained in accordance with applicable laws, rules, and regulations.

Disciplinary Action

The matters covered in this Code are of the utmost importance to the Company and its employees, officers, directors, shareholders, and business partners. Compliance with this Code is essential to the Company's ability to conduct its business in accordance with its stated values. We expect all employees, officers, and directors to adhere to this Code in carrying out their duties for the Company.

The Company will take prompt, consistent, and appropriate action against any employee, officer, or director whose actions are found to violate these policies or any other policies of the Company. Disciplinary actions may include reprimands, probations or suspensions without pay, demotions, reductions in salary or other compensation, and/or immediate terminations of employment or other relationship at the Company's sole discretion. Where the Company has suffered a loss, it may pursue its remedies against the individuals or entities responsible. Where laws have been violated, the Company will cooperate fully with the appropriate authorities.

Persons subject to disciplinary action shall include, in addition to the principal violator, others involved in the violation such as persons who fail to use reasonable care to detect a violation, persons who if requested to provide information withhold material information about a violation, and supervisors/managers who approved or condoned the violation or attempted to retaliate against a person who reported the violation or the violators.

13

Waivers of this Code

Any waiver of this Code for officers, directors, or employees may be made only by the Board of Directors. Any waiver granted, along with the reasons for the waiver, will promptly be publicly disclosed as required by applicable laws, regulations, or stock exchange rules.

14

MAGELLAN PETROLEUM CORPORATION

CODE OF CONDUCT

Certificate of Compliance

ISSUED TO:__________________________________________________ (name)

DATE:_______________________________________________________

ACKNOWLEDGMENT:

My signature below indicates that I have read, understood, accept, and agree to comply with the Code of Conduct for the Company. I understand that my failure to comply in any respect with the Code of Conduct may be a basis for termination of my employment or other relationship with Magellan Petroleum Corporation.

Full Name:__________________________________________________

Signature:___________________________________________________

Date:_______________________________________________________

15

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE REGISTRANT

Magellan Petroleum Corporation owns the following subsidiaries directly:

SUBSIDIARY	STATE OR JURISDICTION OF INCORPORATION OR ORGANIZATION	OWNERSHIP
Nautilus Poplar LLC	Montana, U.S.A	100.00	%
Magellan Petroleum Australia Limited	Queensland, Australia	100.00	%

Magellan Petroleum Australia Limited owns the following subsidiaries directly or indirectly:

SUBSIDIARY	STATE OR JURISDICTION OF INCORPORATION OR ORGANIZATION	OWNERSHIP
Magellan Petroleum (N.T.) Pty. Ltd.	Queensland, Australia	100.00	%
Paroo Petroleum Pty. Ltd.	Queensland, Australia	100.00	%
Paroo Petroleum (Holdings), Inc.	Delaware, U.S.A.	100.00	%
Paroo Petroleum (USA), Inc.	Delaware, U.S.A.	100.00	%
Magellan Petroleum (W.A.) Pty. Ltd.	Queensland, Australia	100.00	%
Magellan Petroleum (U.K.) Limited	United Kingdom	100.00	%
Magellan Petroleum (Eastern) Pty. Ltd.	Queensland, Australia	100.00	%
United Oil & Gas Co. (N.T.) Pty. Ltd.	Queensland, Australia	100.00	%
Magellan Petroleum (Qld.) Pty. Ltd.	Queensland, Australia	80.00	%
Magellan Petroleum (Offshore) Pty. Ltd.	Queensland, Australia	100.00	%
Jarl Pty. Ltd.	Queensland, Australia	100.00	%

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-70567, 333-162668, and 333-171149 on Form S-8, and Registration Statement No. 333-177331 on Form S-3 of our report dated September 24, 2012, relating to the consolidated financial statements of Magellan Petroleum Corporation and subsidiaries, appearing in this Annual Report on Form 10-K of Magellan Petroleum Corporation for the fiscal year ended June 30, 2012.

/s/ Ehrhardt Keefe Steiner & Hottman PC

Denver, Colorado

September 24, 2012

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-70567, 333-162668, and 333-171149 on Form S-8 and 333-177331 on Form S-3 of our report dated September 20, 2011, relating to the consolidated financial statements (before retrospective adjustments to the financial statements and financial statement disclosures) of Magellan Petroleum Corporation and subsidiaries (not presented herein) (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the retrospective adjustments for the adoption of ASU 2011-5, to the disclosures for a change in the composition of reportable segments and for reclassifications to certain financial statement captions, discussed in Notes 1 and 16 to the consolidated financial statements), appearing in this Annual Report on Form 10-K of Magellan Petroleum Corporation for the year ended June 30, 2012.

/s/ Deloitte & Touche LLP

Hartford, Connecticut

September 24, 2012

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

The undersigned firm of Independent Petroleum Engineers, of Casper, Wyoming, United States, knows that it is named as having prepared an audit of a constant dollar reserves evaluation prepared by Nautilus Poplar LLC dated July 18, 2012, of the Montana interests of Magellan Petroleum Corporation, and hereby gives its consent to the use of its name and to the use of the said estimates in the form and context in which they appear in the Annual Report on Form 10-K of Magellan Petroleum Corporation for the fiscal year ended June 30, 2012. We hereby further consent to the use of the information contained in our audit letter dated July 18, 2012 relating to said estimates. We further consent to the incorporation by reference thereof in Magellan Petroleum Corporation's Registration Statement Nos. 333-70567, 333-162668, and 333-171149 on Form S-8, and Registration Statement No. 333-177331 on Form S-3.

		ALLEN & CROUCH PETROLEUM ENGINEERS, INC
		By:	/s/ Richard L. Vine, P.E.
			Richard L. Vine, P.E.
Date:	September 24, 2012

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

The undersigned firm of Independent Petroleum Engineers, of Denver, Colorado, United States, knows that it is named as having prepared a constant dollar evaluation dated July 6, 2012, of the Australian interests of Magellan Petroleum Corporation, and hereby gives its consent to the use of its name and to the use of the said estimates in the form and context in which they appear in the Annual Report on Form 10-K of Magellan Petroleum Corporation for the fiscal year ended June 30, 2012. We hereby further consent to the use of the information contained in our letter dated July 6, 2012 relating to said estimates. We further consent to the incorporation by reference thereof in Magellan Petroleum Corporation's Registration Statement Nos. 333-70567, 333-162668, and 333-171149 on Form S-8, and Registration Statement No. 333-177331 on Form S-3.

		RYDER SCOTT COMPANY, L.P.
		By:	/s/ Ryder Scott Company, L.P.
Date:	September 24, 2012

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, J. Thomas Wilson, certify that:

1. I have reviewed this annual report on Form 10-K of Magellan Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

		By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)
Date:	September 24, 2012

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Antoine J. Lafargue, certify that:

1. I have reviewed this annual report on Form 10-K of Magellan Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

		By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer
			(as Principal Financial and Accounting Officer)
Date:	September 24, 2012

EX-32.1

Exhibit 32.1

SECTION 1350 CERTIFICATIONS

In connection with the Annual Report of Magellan Petroleum Corporation (the “Company”) on Form 10-K for the fiscal year ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, J. Thomas Wilson, President and Chief Executive Officer of the Company, do hereby certify, pursuant to and solely for the purpose of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and believe, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

		By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)
Date:	September 24, 2012

EX-32.2

Exhibit 32.2

SECTION 1350 CERTIFICATIONS

In connection with the Annual Report of Magellan Petroleum Corporation (the “Company”) on Form 10-K for the fiscal year ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer of the Company, do hereby certify, pursuant to and solely for the purpose of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and believe, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

		By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer
			(as Principal Financial and Accounting Officer)
Date:	September 24, 2012

EX-99.1

EX-99.2

MAGELLAN PETROLEUM CORP. ESTIMATED FUTURE RESERVES AND INCOME ATTRIBUTABLE TO CERTAIN LEASEHOLD INTERESTS SEC PARAMETERS As of JUNE 30, 2012

FAX (303) 623-4258 621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147 July 6, 2012 Magellan Petroleum Corp. 700 East 9th Avenue Denver, CO 80203 Gentlemen: At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved and probable reserves, future production, and income attributable to certain leasehold interests of Magellan Petroleum Corporation as of June 30, 2012. The subject properties are located in the country of Australia. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on July 6, 2012 and presented herein, was prepared for public disclosure by Magellan Petroleum Corp. in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved and probable gas reserves of Magellan Petroleum Australia Limited, a wholly owned subsidiary of Magellan Petroleum Corp as of June 30, 2012. The estimated reserves and future net income amounts presented in this report, as of June 30, 2012 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on prices defined by contractual arrangements. Following the term of the defined contractual arrangements the hydrocarbon prices used are based on average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below. SEC PARAMETERS Estimated Net Reserves and Income Data Certain Leasehold Interests of Magellan Petroleum Corp. As of June 30, 2012 Proved Developed Total Producing Non-Producing Proved Net Remaining Reserves Gas – MMCF 6,514 4,979 11,493 Income Data Future Gross Revenue $25,448,114 $19,297,392 $44,745,506 Deductions 17,312,159 12,972,887 30,285,046 Future Net Income (FNI) $8,135,955 $6,324,505 $14,460,460 Discounted FNI @ 10% $5,954,825 $4,200,627 $10,155,452

Magellan Petroleum Corp. July 6, 2012 Page 2 Probable Developed Total Producing Non-Producing Probable Net Remaining Reserves Gas – MMCF 3,759 10,065 13,824 Income Data Future Gross Revenue $10,621,882 $32,074,902 $42,696,784 Deductions 8,563,038 18,996,450 27,559,488 Future Net Income (FNI) $2,058,844 $13,078,452 $15,137,296 Discounted FNI @ 10% $337,469 $4,113,384 $4,450,853 All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material. The future gross revenue is after the deduction of royalties, which are treated as a production tax since they are based on the well head value of the royalty and the royalty owners have no right to take the royalty in-kind. The deductions incorporate the normal direct costs of operating the wells and recompletion costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for 100 percent of total future gross revenue from proved reserves and probable reserves. The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows. Discounted Future Net Income As of June 30, 2012 Discount Rate Total Total Percent Proved Probable 5 $12,663,586 $7,878,065 8 $11,130,675 $5,544,554 12 $9,255,790 $3,609,599 15 $8,064,987 $2,680,986 The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Magellan Petroleum Corp. July 6, 2012 Page 3 Reserves Included in This Report The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category and the probable developed non-producing reserves included herein consist of the behind-pipe and shut-in categories. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes included herein do not attribute gas consumed in operations as reserves. Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable or possible reserves to denote progressively increasing uncertainty in their recoverability. At Magellan Petroleum Corp.’s request, this report addresses the proved and probable reserves attributable to the properties evaluated herein. Proved gas reserves are those quantities of gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The reserves included herein were estimated using deterministic methods. Under the deterministic approach, discrete quantities of reserves are estimated and assigned separately as proved or probable based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable. Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved and probable reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Magellan Petroleum Corp. July 6, 2012 Page 4 The proved reserves reported herein are limited to the period prior to expiration of current gas sales contracts. Probable reserves reported herein consist of two reworks to return currently non- productive zones to production during the contract period. Additional probable reserves were assigned to the continuation of all production past the current contract period. Based on current activity, it is reasonably certain that these volumes will be contracted in the future. This report includes certain volumes of proved and probable reserves attributable to royalties owed to the host government that are treated as taxes to be paid in cash. Magellan Petroleum Australia Limited’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ from the estimated quantities. The estimates of reserves presented herein were based upon a detailed study of the properties in which Magellan Petroleum Corp. owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Estimates of Reserves The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved and/or probable that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are

Magellan Petroleum Corp. July 6, 2012 Page 5 those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved and probable reserves for the properties included herein were estimated by performance methods. Approximately 100 percent of the proved and 100 percent of the probable producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance method utilized was decline curve analysis which utilized extrapolations of historical production data available through April, 2012. The data utilized in this analysis were furnished to Ryder Scott by Magellan Petroleum Australia Limited and were considered sufficient for the purpose thereof. Approximately 100 percent of the probable developed non-producing reserves included herein were also estimated by the performance method. To estimate economically recoverable proved and probable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved and probable reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Magellan Petroleum Australia Limited has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by Magellan Petroleum Australia Limited with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, recompletion costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Magellan Petroleum Australia Limited. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC

Magellan Petroleum Corp. July 6, 2012 Page 6 Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. Future Production Rates For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of contract volumes where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Magellan Petroleum Australia Limited or on the dates required to provide capacity to meet contract quantities. Wells that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. Magellan Petroleum Australia Limited furnished us with the above mentioned average prices in effect on June 30, 2012. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. For the probable gas reserves the gas price utilized was the volume weighted annual price based on the contract prices contained in the latest available term sheets. The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or

Magellan Petroleum Corp. July 6, 2012 Page 7 distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were estimated by us based on information furnished by Magellan Petroleum Australia Limited. In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before any deductions and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report. Geographic Area Product Price Reference Avg Benchmark Prices Avg Proved Realized Prices Avg Probable Realized Prices Australia Gas Contract Prices $4.64/MCF $3.68/MCF The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations. Costs Operating costs for the leases and wells in this report are based on the operating expense reports of Magellan Petroleum Australia Limited and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs used in the preparation of this report were estimated by us based on information furnished by Magellan Petroleum Australia Limited. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. Development costs were furnished to us by Magellan Petroleum Australia Limited and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. Magellan Petroleum Australia Limited provided abandonment costs net of salvage. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Magellan Petroleum Australia Limited’s estimate. The probable developed non-producing reserves in this report have been incorporated herein in accordance with Magellan Petroleum Australia Limited’s plans to develop these reserves as of June 30, 2012. The implementation of Magellan Petroleum Australia Limited’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Magellan Petroleum Australia Limited’s management. As the result of our inquiries during the course of preparing this report, Magellan Petroleum Australia Limited has informed us that the development activities included herein have been subjected to and received the internal approvals required by Magellan Petroleum Australia Limited’s management at the appropriate local, regional and/or corporate level. Since Magellan Petroleum Australia Limited has a 100% working interest in all properties contained in this report, no external approval is required. Additionally, Magellan Petroleum Australia Limited has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Magellan Petroleum Corp. July 6, 2012 Page 8 Current costs used by Magellan Petroleum Australia Limited were held constant throughout the life of the properties. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee- owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision- making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. We are independent petroleum engineers with respect to Magellan Petroleum Corp. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Magellan Petroleum Corp.. We have provided Magellan Petroleum Corp. with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Magellan Petroleum Corp. and the original signed report letter, the original signed report letter shall control and supersede the digital version.

Magellan Petroleum Corp. July 6, 2012 Page 9 The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 Larry T. Nelms, P.E. Approved: James L. Baird, P.E. Managing Senior Vice President

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Professional Qualifications of Primary Technical Person The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Thomas Nelms is the primary technical person responsible for the estimate of the reserves, future production and income. Nelms, a former employee of Ryder Scott Company L.P. (Ryder Scott) from 1983 through 2011, was a Managing Senior Vice President and also served as a member of the Board of Directors, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Nelms served in a number of engineering positions with Dome Petroleum, Mizel Petro Resources and Exxon. For more information regarding Mr. Nelms’ geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees. Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a registered Professional Engineer in the State of Colorado. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman of the Denver Section and also served for three years on the board of directors. As part of his 2009 continuing education hours, Nelms attended an internally presented 16 hours of formalized training as well as the day long 2009 RSC Reserves Conference forum, and a presentation at the Denver Section of SPEE by Dr. John Lee relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Nelms serves as the instructor of the PetroSkills course entitled “Oil & Gas Reserve Evaluation” for a period of four years. Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Nelms has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein). Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

PETROLEUM RESERVES DEFINITIONS Page 2 Reserves do not include quantities of petroleum being held in inventory. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

PETROLEUM RESERVES DEFINITIONS Page 3 PROVED RESERVES (SEC DEFINITIONS) CONTINUED (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. PROBABLE RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows: Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) 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. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) 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. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

RESERVES STATUS DEFINITIONS AND GUIDELINES Page 2 Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate, but which have not started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.