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, 2013,    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 001-5507
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) 484-2400
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.:
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 $0.922 closing price per share of the registrant's common stock as reported by the NASDAQ Capital Market, as of December 31, 2012 (the last business day of the most recently completed second fiscal quarter) was $33,470,909. 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, 45,359,647 shares outstanding as of September 12, 2013.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement related to the 2013 annual meeting of stockholders to be filed within 120 days after June 30, 2013, are incorporated by reference in Part III of this Form 10-K to the extent stated herein.




TABLE OF CONTENTS
ITEM
 
PAGE
 
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 

2



 
 
 
 
PART III
 
 
 
 
 
PART IV
 


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PART I

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 three wholly owned subsidiaries: Nautilus Poplar LLC ("NP"), which owns and operates an oil field covering Poplar Dome ("Poplar") located in the Williston Basin in eastern Montana; Magellan Petroleum Australia Pty Ltd ("MPA"), which owns and operates onshore gas fields in Australia, and owns an offshore exploration license in Australia; and Magellan Petroleum (UK) Limited ("MPUK"), which owns a large acreage position in the Weald and Wessex Basins in southern England prospective for conventional and unconventional oil and gas production.
Magellan was founded in 1957 and incorporated in Delaware in 1967. The Company's common stock has been trading on the NASDAQ since 1972 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) 484-2400.

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 significant engineering and management resources. We are committed to investing in these projects to establish their technical and economic viability. In turn, we are focused on determining the most efficient way to create greatest value and highest returns for our shareholders.

SIGNIFICANT DEVELOPMENTS IN FISCAL YEAR 2013
During fiscal year 2013, the Company took important steps in its strategy of creating value from our existing assets. Administratively, we completed the two-year turn-around of the Magellan platform through a number of achievements, including: hiring new engineering and geologic personnel, completing the overhaul of our accounting function, voluntarily delisting from the Australian Securities Exchange ("ASX"), repurchasing 17% of our common shares plus warrants that had been pledged by an entity affiliated with a former director, and raising $23.5 million through the issue of convertible preferred equity on attractive terms. As a result, we believe we now have an organized and effective platform poised to achieve growth and the successful development of our assets.
Operationally, we made steady progress on each of our key projects such that we can continue to achieve key developmental and operational milestones in fiscal year 2014. At Poplar, our work on the CO2-enhanced oil recovery ("CO2-EOR") pilot project during fiscal year 2013 resulted in obtaining a CO2 supply contract and receiving the permits to start the drilling of our pilot wells in July and August 2013, respectively. With the drilling of CO2-EOR pilot wells now underway, we expect to be able to deliver results by the end of calendar year 2014. In parallel, we initiated a water shut-off program to increase oil production from the existing wells at Poplar and reduce our operating costs. This program has started to yield positive results, and we will continue to roll it out across the field as we gather results from each treatment. Onshore Australia, we spent most of fiscal year 2013 in discussions and contract negotiations with potential customers of gas from our properties in the Dingo field, resulting in the signing of a long term gas supply and purchase agreement (the "Dingo GSPA") with Northern Territory Power and Water Corporation ("PWC") for the sale over a 20-year period of the majority of our current estimated probable reserves at Dingo. Gas sales are expected to commence in early calendar year 2015 once surface facilities and a tie-in pipeline are constructed at Dingo. With gas sales contracts in place at both Palm Valley and Dingo, and considering the cost of Dingo's surface facilities and pipeline tie-in, we expect our Amadeus Basin assets to provide Magellan with reasonably predictable cash flows. Offshore Australia, we conducted 2-D and 3-D seismic surveys over portions of NT/P82, our 100% owned exploration license in the Bonaparte Basin. Based on the preliminary interpretation of the seismic data we acquired, we believe we can successfully execute a farmout transaction in fiscal year 2014 whereby a new partner will drill the large gas prospects that lie within our block. In the UK, together with our partner Celtique Energie Holdings Ltd ("Celtique"), we completed an extensive geological analysis of the potential prospects underlying our Weald Basin acreage. In addition, we prepared and filed applications for permits to drill exploratory wells on our acreage, which will allow us to drill and further assess the potential for conventional and unconventional oil and gas production in fiscal year 2014.

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As a result of the achievements and improvements realized in fiscal year 2013, in fiscal year 2014 we expect to progress various operational initiatives to points that will permit us to demonstrate the potential value of our assets and develop an asset rationalization strategy to maximize Magellan's net asset value per share.

Financial Performance
Our 2013 fiscal year financial results were significantly affected by the full-year impact of events in Australia that occurred during fiscal year 2012, namely the termination of the 25-year gas sales contract between Palm Valley and PWC (the "PWC Palm Valley Contract") in January 2012 and completion of the asset swap with Santos QNT Pty Ltd ("Santos QNT") and Santos Limited (collectively "Santos") in May 2012 (the "Santos SA"). These events together resulted in a significant decline in revenue and net income. Adjusted EBITDAX, however, improved slightly as reduced expenditures offset the loss of revenue.
We expect fiscal year 2013 to be a "trough" year in terms of revenues and earnings, with greater hydrocarbon production expected from our operating assets in fiscal years 2014 and 2015. At Poplar, the results of ongoing work-overs and water shut-off treatments, as well as production from the CO2-EOR pilot project, are expected to increase production from Poplar over the next twelve months. Gas reserves at Palm Valley are currently contracted to Santos through the Palm Valley GSPA (as defined below), and gas sales volumes are expected to increase under this contract to an annualized rate of 1.3 Bcf by the end of fiscal year 2014 and 1.5 Bcf by the end of fiscal year 2015. In addition, in September 2013, the Company signed the Dingo GSPA, a long term, inflation-indexed contract with PWC, for the sale of Dingo gas reserves, under which gas sales are expected to commence in early calendar year 2015.
Revenues. For the fiscal year ended June 30, 2013, revenues totaled $7.1 million compared to $13.7 million in the prior year, a decrease of 48%. This decrease was primarily the result of the termination of the PWC Palm Valley Contract in January 2012 and the sale of Magellan's interests in the Mereenie oil and gas field to Santos in May 2012 as part of the Santos SA.
Under Palm Valley's current gas supply and purchase agreement with Santos (the "Palm Valley GSPA"), gas sales volumes and revenues are currently expected to increase materially in the second half of fiscal year 2014. Under the terms of the Dingo GSPA signed in September 2013, new gas sales volumes and revenues from Dingo are expected to commence in early calendar year 2015.
Net Income and Earnings per Share. For the fiscal year ended June 30, 2013, net loss was $19.8 million ($(0.41)/basic share), compared to net income of $26.5 million ($0.49/basic share) for the prior fiscal year. The decrease in net income was primarily the result of non-recurring gains on sales of assets of $40.4 million recorded in fiscal year 2012 related to the Santos SA in May 2012, and the farmout of an interest in Poplar to VAALCO in September 2011 (the "VAALCO Farmout").
Adjusted EBITDAX. For the fiscal year ended June 30, 2013, Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation under Part I, Items 1 and 2: Business and Properties) was negative $10.9 million, compared to negative $11.2 million in the prior fiscal year, a positive change of 2%. The slight improvement in Adjusted EBITDAX resulted from a decrease in revenues offset by a corresponding decrease in lease operating expense, both primarily due to the sale of the Company's interest in Mereenie in May 2012 as part of the Santos SA and a decrease in general and administrative expense.
Cash. As of June 30, 2013, Magellan had $32.5 million in cash and cash equivalents as compared to $41.2 million at the end of the prior fiscal year. The decrease of $8.7 million was primarily the result of investment in work-overs and water shut-off treatments at Poplar, the cost of the 2-D and 3-D seismic surveys over NT/P82 (as defined below), our offshore block in Australia, and the repurchase of shares and warrants from Sopak AG (as defined below) in January 2013. These cash outflows were partially offset by $23.0 million in net proceeds from the issuance of convertible preferred stock in May 2013. We believe that our cash balance will permit us to determine the most efficient way to enhance shareholder value through assessing the potential value of our existing assets.

Operational Progress on Our Key Projects
In fiscal year 2013, management diligently pursued its strategy of proving up the value of the Company's existing assets as the most economic way of increasing shareholder value. Towards that end, management made steady progress on the development of all our key projects and has laid the groundwork for the achievement of key milestones in fiscal year 2014.
CO2-EOR at Poplar. On the basis of reservoir modeling and lab testing performed in the prior year, in fiscal year 2013, management focused heavily on furthering plans for a CO2-EOR program in the Charles formation at Poplar. In particular, the Company prepared for a five-well CO2-EOR pilot project planned for fiscal year 2014. Specifically, the Company worked to fulfill the various regulatory requirements necessary to obtain permits to drill the pilot wells. These permits were obtained in August 2013. In addition, the Company held extensive discussions with various CO2 suppliers. These efforts led to a two-year CO2 supply contract with Air Liquide Industrial U.S. LP ("Air Liquide") in July 2013. Air Liquide is the world leader in gases

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for industry, health, and the environment. The Company also began dialogues with large-scale CO2 producers regarding the long term supply of CO2 for a full field CO2-EOR program at Poplar, which would follow the completion of the CO2-EOR pilot project if it proves successful.
NT/P82. During fiscal year 2013, Magellan focused on conducting a seismic survey over portions of its NT/P82 Exploration Permit ("NT/P82") in the Bonaparte Basin, offshore Northern Territory, Australia. In December 2012, the Company successfully conducted, via a third-party contractor, a 2-D and 3-D seismic survey over portions of the block. The seismic recording vessel Voyager Explorer, operated by Seabird Exploration FZ-LLC, acquired a total of 76 square miles of 3-D full fold data and 65 miles of 2-D full fold data. Between January and August 2013, the seismic data was undergoing processing and interpretation, the results of which were received in August 2013. We believe that the results of the seismic survey will allow the Company to begin a farmout process during the second quarter of fiscal year 2014. Through this process, the Company expects to identify a partner to drill exploratory wells over the large gas prospects that lie in our permit area in exchange for an ownership interest in and operatorship of the license.
Dingo. In fiscal year 2013, the Company undertook marketing efforts to identify and attract long term customers for Dingo's gas resources. These efforts resulted in the signing of the Dingo GSPA with PWC in September 2013 for the supply of up to 31 petajoules ("PJ") (30 billion cubic feet ("Bcf")) of gas over a 20-year period at a fixed price escalating with Australian CPI. In parallel to the marketing efforts, during the fiscal year Magellan completed a pre-front-end engineering and design ("pre-FEED") study to evaluate the cost and logistics of installing gas treatment facilities and laying a pipeline to tie the Dingo field into the existing pipeline infrastructure at Brewer Estate, south of Alice Springs, where PWC will take delivery of the gas. This study will serve as the basis for bringing Dingo to operational capability at the beginning of calendar year 2015.
United Kingdom. In fiscal year 2013, Magellan focused primarily on carrying out extensive geological analysis and planning for the exploration of three of the Production Exploration and Development Licenses ("PEDLs") it co-owns 50% with its partner Celtique (PEDLs 231, 234, and 243) in the Weald Basin in southern England. These licenses are prospective for unconventional oil production from the Kimmeridge Clay and Liassic formations. The Company, in conjunction with Celtique, which operates the licenses, worked toward permitting well site locations and evaluating the prospects for drilling exploratory wells, the first of which the Company expects to spud in the third quarter of fiscal year 2014.
Also in fiscal year 2013, it appears that the macro environment in the UK underwent favorable developments that positively impact the outlook on the development of unconventional resources. In December 2012, the UK government announced that exploratory hydraulic fracturing activities could resume in the UK following a moratorium on the practice. In February 2013, the government also announced plans to better exploit its unconventional hydrocarbon resources. Tax incentives and other favorable changes in UK laws and regulations with respect to onshore drilling in the UK are expected to be introduced in the coming months.

Realignment of Shareholder Base and Preferred Equity Issuance
During fiscal year 2013, the Company effected two major changes in its shareholder base. In January 2013, it repurchased 17% of its common stock and related warrants representing up to an incremental 7% dilution overhang from Sopak AG, a Swiss subsidiary of Glencore International plc ("Sopak"), which aquired the stock and warrants through a pledge by an entity affiliated with a former director. Later in the fiscal year, the Company issued convertible preferred stock to a new single investor, thereby replenishing its cash balances and gaining a new long term strategic and financial partner.
Series A Convertible Preferred Stock Financing Agreement with One Stone. On May 10, 2013, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the "Series A Purchase Agreement") with an affiliate of One Stone Energy Partners, L.P., a New York based private equity firm focused on investments in the oil and gas industry (both the private equity firm and its affiliate are hereinafter referred to collectively as "One Stone"). Pursuant to the terms of the Series A Purchase Agreement, on the closing date of May 17, 2013, the Company issued and sold to One Stone 19,239,734 shares of Series A Convertible Preferred Stock, par value $0.01 per share (the "Series A Preferred Stock"), at a purchase price of $1.22149381 per share, for aggregate net proceeds of approximately $23.0 million. Each share of Series A Preferred Stock will be entitled to a dividend equivalent to 7.0% per annum. Subject to certain conditions, each share of Series A Preferred Stock and any related unpaid accumulated dividends will be convertible into one share of the Company's common stock at an initial conversion price of $1.22149381 per share.
Management believes that this Series A Preferred Stock financing was a critical milestone in the path to delivering value to shareholders because the proceeds of this transaction, together with the proceeds from potential asset sales or farmout arrangements, in addition to the Company's existing cash resources, will provide the Company with sufficient liquid capital resources to fund (i) the CO2-EOR pilot project at Poplar, including the purchase of necessary CO2 volumes; (ii) the current negative cash flow from operations, which is expected to be partially mitigated by the planned ramp up of gas sales from our onshore Australian assets in calendar year 2014; and (iii) the Company's efforts to further establish the value of our UK acreage

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through the participation in one or more exploratory wells in calendar year 2014.
In pursuing this financing, the Company considered a number of alternatives, including equity issuances via a PIPE or secondary offering to the institutional investor markets, conventional bank debt, and mezzanine loans from a bank and alternative investment markets. The Company also considered the sale of non-core assets, but determined that this alternative would have been premature at the time, as the UK acreage remained highly prospective, 3-D seismic data over NT/P82 was still undergoing processing and interpretation, and the onshore Australian assets were not yet fully contracted.
Ultimately, the Company determined this Series A Preferred Stock financing to be the most attractive financing option available. Through this financing, the Company (i) gained a long term strategic and financial partner in One Stone; (ii) received approximately $23.0 million in net proceeds convertible at a 20% premium to the common share price prior to the transaction, without issuing any warrants; and (iii) maintained certain protections in the form of forced conversion and redemption rights. Management believes that, in spite of potential ownership dilution to existing shareholders, this transaction represented the most timely and efficient path to increasing net asset value per share.
The Series A Purchase Agreement and the related Certificate of Designations of the Series A Preferred Stock and Registration Rights Agreement have been previously filed as exhibits to the Company's US Securities and Exchange Commission ("SEC") reports, and are incorporated by reference in the exhibits under Part IV, Item 15 of this report. For a more detailed summary of the key terms of the Series A Purchase Agreement, please see Note 8 to the consolidated financial statements included in Item 8: Financial Statements and Supplementary Data of this report.
Sopak, YEP, and Nikolay V. Bogachev; Share and Warrant Repurchases. On January 14, 2013, the Company entered into a Collateral Purchase Agreement with Sopak. Under the terms of this agreement, Magellan paid $10.0 million to Sopak for 9,264,637 shares of Magellan common stock, a warrant granting Sopak the right to purchase an additional 4,347,826 shares of Magellan common stock at an exercise price of $1.15 per share, and a registration rights agreement related to the repurchased shares and warrant. In addition, the Company obtained from both Nikolay V. Bogachev, who served as a director of the Company until his resignation effective January 16, 2013, and Young Energy Prize S.A. ("YEP"), a Luxembourg entity affiliated with Mr. Bogachev, a release from all claims by those parties against Magellan or its assets. Sopak originally obtained its shares and warrant in September 2012 by exercising its rights under a pledge and security agreement between Sopak and YEP.
As a result of this transaction, the Company repurchased 17% of its outstanding common stock and eliminated the significant potential dilutive impact of the related warrant at a price and at a time that the Company believes was attractive.
For further details on this transaction, see Note 9 to the consolidated financial statements included in Item 8: Financial Statements and Supplementary Data of this report.

OUTLOOK FOR FISCAL YEAR 2014
During fiscal year 2014, 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 the Company's cash resources comprised of cash on hand and proceeds from asset sales or farmout arrangements, which include the proceeds from the Series A Preferred Stock issuance in May 2013:
implementing a CO2-EOR pilot project at Poplar;
drilling one and possibly two wells in the UK to evaluate the potential of the various formations in our licenses in the UK;
contracting most of Dingo's gas reserves under a long term agreement, which was achieved in September 2013 through the Dingo GSPA and conducting the engineering, design, and construction of the pipeline and surface facilities to make Dingo ready for gas production in fiscal year 2015;
completing the processing and interpretation of seismic data for NT/P82 and identifying a farm-in partner to drill one or more exploration wells on the exploration permit in Australia in fiscal year 2015.
Management believes that each of these projects has significant potential that, if realized, could materially impact the Company's reserves and the underlying net asset value per share and eventually allow the Company to generate positive cash flow from operations. Specific steps and milestones for each of these key areas are discussed below. By pursuing these courses of action in parallel, management expects that, over the next 12 to 15 months, the Company will be able to validate the value potential of these assets and will be able to determine the most appropriate course of action with respect to each asset to achieve the best value for its shareholders.


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CO2-EOR Pilot Project
In fiscal year 2014, the Company intends to implement a CO2-EOR pilot project in the Charles formation at Poplar to validate the reserves potential of this tertiary recovery technique on a full-field basis. In July 2013, the Company signed an approximately two-year COsupply contract with Air Liquide for the CO2 necessary to complete the CO2-EOR pilot project. In August 2013, the Company obtained permits from the US Bureau of Land Management to drill the five wells necessary for the pilot project. Drilling began in August 2013 and is expected to continue through November of this year. Currently we plan for the five pilot wells to be arranged in a "five-spot" pattern, with a single CO2 injection well in the center surrounded by four producing wells. CO2 injection is expected to commence in October 2013. From the time of first injection, it will take between 12 and 15 months to evaluate the effectiveness of the CO2-EOR technique and announce results from the pilot project. The cash cost of the pilot project, including capital and certain operating expenditures including the cost of the supply of CO2 over two years, will total approximately $20.0 million, with most of these expenditures incurred by March 2014.
With the results of the CO2-EOR pilot project expected to be received by the end of calendar year 2014, the Company hopes to demonstrate that the implementation of a full-field CO2-EOR program at Poplar could result in the recovery of approximately an additional 50 million barrels of oil. Based on our own work, the production history of the field to date, and reference to analogous CO2-EOR projects in the Williston Basin, management believes that the Charles formation at Poplar has 500 to 600 million barrels of oil in place and the recovery of an incremental 10% of this amount is an achievable objective.

United Kingdom Exploration Wells
In fiscal year 2014, the Company will focus on evaluating the potential of its conventional and unconventional prospects in the Weald Basin in southern England, which are primarily contained within the license areas of PEDLs 231, 234, and 243, which the Company co-owns 50% with Celtique. These licenses are prospective for unconventional oil production. The PEDLs are due to expire at the end of June 2014 and are subject to customary "drill or drop" work commitment and a 50% relinquishment rule. These PEDLs will be extended for an additional 5-year period if work commitments are met. We and our partner, Celtique, are planning to drill the first exploration well in PEDL 234, the location of which may meet our work commitments for both PEDLs 234 and 243. We expect to spud this well in the third quarter of fiscal year 2014. In addition, we are in the process of permitting a well in PEDL 231 to fulfill our commitments for this lease area, and will apply for a 12-month extension to our current PEDL to allow additional time to receive planning approval. In PEDL 234, we are also awaiting final planning approval to drill a well in the center of the Basin, which may spud in the fourth quarter of fiscal year 2014. The purpose of these wells is to test and evaluate the Kimmeridge Clay and Liassic formations in order to substantiate the unconventional oil and gas production potential of our acreage and to test and evaluate the conventional prospects in the Triassic formation. Under the terms of our joint operating agreement with Celtique, we are required to participate in these commitment wells to maintain our working interest in the PEDLs. We intend to participate in the drilling of these wells and expect to fund our share of the costs through either our cash reserves, the farmout of a portion of our interests, or the proceeds from other asset sales.
With regards to PEDL 137, of which the Company owns 100%, we expect to finalize the terms of a farmout agreement with a partner to drill the Horse Hill prospect, which targets Jurassic and Triassic formations with oil and gas potential, respectively. With regards to the various PEDLs (PEDLs 126, 155, 240, 256, and P1916) the Company owns along with Northern Petroleum Plc ("Northern"), we do not anticipate any significant activity in fiscal year 2014.

Dingo Development
In September 2013, the Company signed the Dingo GSPA with PWC for the sale of up to 31 PJ (30 Bcf) of gas over a 20-year period to PWC, commencing early in calendar year 2015. With a long term contract now in place, the Company will use the intervening time period to design, construct, and commission the surface facilities and tie-in pipeline necessary for the production and delivery of Dingo's gas. Gas volumes are expected to be produced from three wells drilled at Dingo in the 1980s and 1990s, of which two wells have since been temporarily shut-in but are expected to be capable of producing gas volumes sufficient to meet the initial delivery requirements under the Dingo GSPA. Currently, the Company is undertaking the front-end engineering and design ("FEED") of the facilities and pipeline, which is a continuation of work performed during the pre-FEED stage in fiscal year 2013, and which is expected to take approximately six months to complete. Based on engineering and design work already done, the Company is planning to run Dingo as a remote operation, with only wellheads and gathering lines to be located at the field itself. Production from the wells will flow through a pipeline approximately 30 miles in length to a processing facility to be located at Brewer Estate, an industrial facility located just south of Alice Springs, where the gas will be processed and where PWC will take delivery of the gas.
Concurrently with the FEED work, the Company will be applying for various regulatory permits and licenses to allow for the commercial production and sale of gas from Dingo, including (i) the grant of a production license over the area of the

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current Dingo retention license, (ii) the grant of a pipeline license over the approximately 30-mile pipeline route connecting the Dingo field to Brewer Estate, and (iii) the grant of planning approval for the use of land at Brewer Estate for the installation and operation of a gas processing facilities. The Company expects that it will take approximately twelve months to receive all required permits and licenses to be able to start the construction phase of the surface facilities and pipeline necessary to commission the production of gas from Dingo. We began preliminary permitting work in July 2013 and expect the construction phase of the project to commence in early fiscal year 2015.
The Company currently intends to fund the development of Dingo primarily through the issuance of new project finance debt facilities, which it will service with cash flow generated by the Dingo GSPA once production commences. The Company also expects to supplement the project financing from its own cash resources. If project finance debt is not available under satisfactory terms, Magellan may seek to find a third party to build and own the pipeline, which third party would in turn charge the Company a tariff for the use of the pipeline over the life of the Dingo GSPA. Finally, the Company also intends to review strategic alternatives for its Amadeus Basin assets, Palm Valley and Dingo, over the course of the upcoming year.

NT/P82, Offshore Australia
In the first quarter of fiscal year 2014, the Company expects it will complete the processing and interpretation of 3-D and 2-D seismic surveys that the Company shot over part of NT/P82 in the Bonaparte Basin in December 2012. From preliminary results of the 2-D and 3-D seismic interpretation the Company expects to engage in a farmout process to identify a partner experienced in offshore drilling. In completing a farmout, the Company expects to relinquish a portion of its working interest in, and operatorship of NT/P82, in exchange for a commitment from the partner to drill exploration wells over the large gas prospects identified in the block by fiscal year 2015. Given the high level of offshore drilling activity in the Bonaparte Basin, the network of installed gas infrastructure in the relative vicinity of our block, and the relatively shallow depths of water in the license, the Company believes it is well positioned to successfully complete a farmout.

OPERATIONS
Magellan operates in the single industry segment of oil and gas exploration and production. We have three reportable geographic segments, NP, MPA, and MPUK, corresponding to our operations in the United States, Australia, and the UK, respectively. NP's oil and gas assets consist of its interests in Poplar in the Williston Basin. MPA'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; and NT/P82, an exploration block in the Bonaparte Basin, offshore Australia. MPUK's oil and gas assets consist of various exploration licenses in the Weald and Wessex Basins located onshore and offshore southern England. 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 11 to the consolidated financial statements included in Item 8: Financial Statements and Supplementary Data of this report.


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Magellan's Areas of Operations

United States - Poplar
In the US, 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 with multiple stacked 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, as the Company defines it, is composed of a 100% working interest in the oil and gas leases within the East Poplar Unit ("EPU"), a federal exploratory unit in Roosevelt County, Montana, totaling approximately 18,000 net acres, and the working interests in various oil and gas leases that are adjacent to or near EPU ("Northwest Poplar" or "NWP") totaling approximately 4,000 net acres.
Our interests within EPU (also referred to herein as "Poplar") include a 100% operated working interest in the interval from the surface to the top of the Bakken/Three Forks formation (the "Shallow Intervals") and an operated working interest below those intervals ranging from 50% to 65%, which include the Bakken/Three Forks, Nisku, and Red River formations (the "Deep Intervals"). VAALCO Energy (USA), Inc. ("VAALCO") owns the remaining working interest in the Deep Intervals. Our interests within NWP are all operated and are the same as within EPU, except in certain leases in which the Company and VAALCO collectively own less than 100% of the working interest.
Shallow Intervals. Magellan's primary objective in the Shallow Intervals is to establish the technical and economic 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. Secondarily, the Company intends to explore other formations within the Shallow Intervals prospectively for oil and gas production, including the Tyler and Amsden formations, as well as the Piper and Judith River formations.
Deep Intervals. Pursuant to the terms of the VAALCO Farmout entered into in September 2011, VAALCO drilled and completed three wells in the Deep Intervals in fiscal year 2012 and 2013 to ultimately earn a 50% non-operated working interest in the Deep Intervals. The original agreement with VAALCO granted a 65% working interest upon the drilling of three wells and was re-negotiated in March 2013 to grant VAALCO a 50% working interest in the Deep Intervals, subject to other

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terms and conditions further discussed in Part II, Item 7 : Management's Discussion and Analysis of Financial Condition and Results of Operations of this report. Through this process, the Company was able to start evaluating the potential of various formations, including the Bakken/Three Forks, Nisku, and Red River. Although commercial quantities of oil and gas were not encountered with these three wells, the results of cores and logs are encouraging, and the Company may engage in further exploration of these formations at a later date.

Australia - Amadeus Basin
In the Amadeus Basin, located near Alice Springs in central Australia, Magellan owns 100% operated working interests in two gas fields, Palm Valley and Dingo.
Palm Valley. Palm Valley was discovered in 1965 and has been reliably producing natural gas since 1983. As of June 2013, 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 2011, Magellan entered into the Palm Valley GSPA 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 a 17-year period which began on May 25, 2012 to Santos, which onsells to third party customers. To date Santos has future sale commitments estimated at 11 Bcf of this gas. The deliverability of gas from existing wells and the firm sale commitments are crucial elements in determining the reserves that can be booked as proved reserves.
Dingo. Dingo is a gas field discovered in 1981. Four appraisal wells drilled between 1981 and 1991 established the field's resource and production potential. Magellan maintains its interest in Dingo through Retention License No. 2, which expires in February 2014, and is subject to renewal for a further five years. The Company has initiated the application process for an operating license that will allows us to maintain production for a 20-year period once received. Until recently, Northern Territory gas market dynamics have prevented the development of Dingo as a producing field. However, Magellan has entered into the Dingo GSPA with PWC for the sale of up to 31 PJ of gas (30 Bcf) over a 20-year period. Sales under the Dingo GSPA are expected to commence early in calendar year 2015. In the intervening time, Magellan will be focused on obtaining permits and licenses to commission Dingo for commercial production, completing the design, engineering, and construction of the surface facilities and the 30 mile tie-in to existing pipeline infrastructure. As of the date of this report, the Company has initiated the various permitting processes and expects the construction phase of the project to commence at the beginning of fiscal year 2015.

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. The Company conducted 3-D and 2-D seismic surveys over portions of the license area in December 2012 and is currently in the final stages of interpreting this data. Under the terms of the permit, which is due to expire in May 2016, the Company is required to drill one exploratory well by May 2015. The Company currently intends to meet its work commitment through a farmout to another company.

United Kingdom
In the Weald and Wessex Basins, Magellan has interests in 10 PEDLs and one Seaward Production License (P1916), representing a total of approximately 200,000 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 licenses: (i) four PEDLs co-owned 50% with, and operated by, Celtique; (ii) five licenses (four PEDLs and P1916) with varying ownership operated by Northern; and (iii) two licenses wholly owned and operated by Magellan. To date in the UK, 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.
The PEDL licensing regime in the UK, which is administered by the Department of Energy and Climate Change ("DECC"), allows for a 6-year initial exploration phase, which can be extended by an additional five years so long as pre-agreed work commitments have been met, for a maximum of an 11-year exploration phase from the original award date of a PEDL. Following the exploration phase, a PEDL will either convert into a production license with a term of approximately 20 years or transfer to the government and be made available for a new round of licensing. The licensing regime also requires that

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50% of the acreage of a PEDL be relinquished at the end of the first six-year exploration period. This 50% relinquishment is expected to occur for most of Magellan's licenses in June 2014.

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, 2013.
 
Oil
(Mbbls)
 
Gas
(Bcf)
 
Total
(Mboe)(1)
Proved developed producing (PDP):
 
 
 
 
 
United States
1,081

 

 
1,081

Australia

 
6

 
1,000

Total
1,081

 
6

 
2,081

 
 
 
 
 
 
Proved developed not producing (PDNP):
 
 
 
 
 
United States
500

 

 
500

Australia

 
5

 
833

Total
500

 
5

 
1,333

 
 
 
 
 
 
Proved undeveloped (PUD):
 
 
 
 
 
United States
5,787

 

 
5,787

Total
5,787

 

 
5,787

 
 
 
 
 
 
Total proved reserves
7,368

 
11

 
9,201

 
 
 
 
 
 
PDP%
15
%
 
55
%
 
23
%
PDNP%
7
%
 
45
%
 
14
%
PUD%
78
%
 
%
 
63
%
 
 
 
 
 
 
Probable:
 
 
 
 
 
Developed

 
13

 
2,167

Undeveloped
1,950

 
29

 
6,783

Total
1,950

 
42

 
8,950

 
 
 
 
 
 
Total proved and probable reserves
9,318

 
53

 
18,151

 
 
 
 
 
 
Proved %
79
%
 
21
%
 
51
%
Probable %
21
%
 
79
%
 
49
%
(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, 2013, our consolidated total proved reserves amounted to 9,201 Mboe, comprised of 7,368 Mbbls (79%) of proved oil reserves and 11 Bcf (21%) of proved gas reserves. All of our proved and probable oil reserves relate to our interest in Poplar, Montana. Of the 7,368 Mbbls of proved oil reserves, approximately 7,328 Mbbls (99%), 35 Mbbls (0%), and 5 Mbbls (0%) were derived from the Charles, Tyler, and Amsden formations, respectively. All of the probable oil reserves were derived from the Tyler formation.
The Company's proved undeveloped reserves in the US consist of twenty infill drilling locations within EPU at Poplar targeting the Charles formation. These proved undeveloped reserves were identified and recorded in fiscal year 2010. In light of the Company's focus on CO2-EOR and the fact that none of these infill locations have been drilled to date, the Company decided to reduce this drilling program from 20 locations to 16 locations over the next two fiscal years. In their place, the Company will be drilling four producing wells as part of the CO2-EOR pilot project. To be conservative and due to the lack of

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technical data available, we have decided not to include these wells in the Company's reserves estimates. The Company expects to conduct a similar review of its drilling program and impact on proved undeveloped reserves at the end of fiscal year 2014.
As of June 30, 2013, all of our proved gas reserves and 13 Bcf (45%) of our probable gas reserves related to our interest in Palm Valley in Australia. Under the terms of the Palm Valley GSPA, we are entitled to sell up to approximately 23 Bcf of gas from Palm Valley to Santos, who on-sells the gas to third-party customers. As of June 30, 2013, proved gas reserves totaled 11 Bcf, corresponding to gas sales volumes committed to third-party customers under the Palm Valley GSPA. The 42 Bcf of probable gas reserves correspond to the remaining volumes to be sold under the Palm Valley GSPA plus additional volumes of gas estimated to be economically recoverable from Dingo.
As of June 30, 2013, 29 Bcf (55%) of our probable gas reserves related to our interest in Dingo in Australia. In September 2013, Magellan entered into the Dingo GSPA with PWC for the sale of 31 PJ (30 Bcf) of gas over a 20-year period. Sales under the Dingo GSPA are expected to commence early in calendar year 2015. As a result of this contract, we believe that some of the probable reserves related to Dingo could be converted from probable to proved reserves as of June 30, 2014.

Proved Undeveloped Reserves
As of June 30, 2013, we had 5,787 Mboe of proved undeveloped reserves, representing a decrease of 1,471 Mboe, or 20%, over the prior year figure. During the fiscal year, we did not convert any proved undeveloped reserves to proved developed reserves.
As of June 30, 2013, we had no proved undeveloped reserves that had been on our books in excess of five years, and we had 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 estimating the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate that more likely than not will not 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 lower 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 SEC. The Company relies upon a combination of internal technical staff and third party consulting arrangements for reserve estimation and review.
In the US, the responsibility for reserves estimation is delegated to Blaine Spies, Magellan's Operations Manager since December 2011. Mr. Spies has over 20 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 and Gulf Coast regions. 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, and management review and approval.

Third Party Reserve Audit
In the US, 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-

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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 16) 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, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
72

 

 
72

 
$
84.91

 
$

 
$
84.91

 
$
67.17

Australia

 
191

 
32

 
$

 
$
4.93

 
$
29.56

 
$
68.86

Total
72

 
191

 
104

 
$
84.91

 
$
4.93

 
$
68.01

 
$
67.62

 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fiscal year ended June 30, 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

(*) 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.
(3) Production cost excludes severance taxes.
Total production declined from 196 Mboe in fiscal year 2012 to 104 Mboe in fiscal year 2013, primarily as a result of the termination of the PWC Palm Valley Contract in January 2012 and the impact of the Santos SA completed in May 2012. Production cost on a $/boe basis increased in Australia from $65.13/boe to $68.86/boe primarily due to decreased production, and decreased in the US from $70.06/boe to $67.17/boe primarily due to a fewer amount of work-overs in fiscal year 2013. These factors combined to increase production costs from $66.47/boe to $67.62/boe in the US and Australia, collectively.


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PRODUCTIVE WELLS
Productive wells include producing wells and wells mechanically capable of production. In the US, all wells were located at Poplar and, 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, 2013.
 
Oil Wells
 
Gas Wells
 
Total Wells
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
United States
42.0

 
40.4

 

 

 
42.0

 
40.4

Australia

 

 
4.0

 
4.0

 
4.0

 
4.0

Total
42.0

 
40.4

 
4.0

 
4.0

 
46.0

 
44.4

(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,
 
2013
 
2012
 
2011
 
Productive (2)
 
Dry (3)
 
Productive (2)
 
Dry (3)
 
Productive (2)
 
Dry (3)
Development wells, net (1):
 
 
 
 
 
 
 
 
 
 
 
United States

 

 
4.0

 
1.0

 
1.0

 

Total

 

 
4.0

 
1.0

 
1.0

 

 
 
 
 
 
 
 
 
 
 
 
 
Exploratory wells, net (1):
 
 
 
 
 
 
 
 
 
 
 
United States

 

 
1.0

 

 

 

Total

 

 
1.0

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
Total net wells

 

 
5.0

 
1.0

 
1.0

 

(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.
The following table summarizes the results, as of September 16, 2013, of our wells that were still in progress as of June 30, 2013.
 
Still in Progress
 
Gross (1)
 
Net (2)
United States (3)
4.0

 
3.4

Total
4.0

 
3.4

(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.
(3) The four work in progress wells consist of the three wells drilled by VAALCO in the Deep Intervals, EPU 120, EPU 133-H, EPU 125, and the EPU 119, which remains under evaluation following a water shut-off treatment in January 2013.


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ACREAGE
The following table summarizes gross and net developed and undeveloped acreage by geographic area at June 30, 2013.
 
Developed (1)
 
Undeveloped (4)
 
Total
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
United States:
 
 
 
 
 
 
 
 
 
 
 
Poplar
22,913

 
21,997

 

 

 
22,913

 
21,997

 
 
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
 
 
 
 
United Kingdom
80

 
32

 
373,137

 
195,203

 
373,217

 
195,235

Total
64,637

 
63,673

 
2,172,211

 
1,994,277

 
2,236,848

 
2,057,950

(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 (79%) form a federal exploratory unit which is held by economic production from any one well within the unit. Currently, Poplar contains 42 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 US, 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 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, 2013.
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
 
2/3/2014
 
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 by registrant in gross acres.

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United Kingdom
In the UK, Petroleum Exploration and Development Licenses ("PEDLs") and Seaward Production Licenses (denoted by a "P") issued by the government are subject to the Petroleum Act. A licensee has the exclusive right to produce, explore, and develop petroleum from the land subject to the payment of a rental payments to the UK government's Department of Energy and Climate Change ("DECC"). 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 UK as of June 30, 2013.
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 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%
 
98,800

 
49,400

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

P 1916
 
Wessex
 
1/31/2016
 
Northern
 
23%
 
11,535

 
2,653

Total
 
 
 
 
 
 
 
 
 
373,217

 
195,235

(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 by registrant in gross acres.
The PEDL 137 license, representing 24,525 gross and net acres, is due to expire in September 2013, however, pending our application to the UK Government is likely to be renewed for an additional 12 month period. The expiration of PEDL 137 would reduce our gross and net acres in the UK to 348,692 and 170,710 acres, respectively.

MARKETING ACTIVITIES AND CUSTOMERS
Customers
United States. In the US, the Company has a sole customer who accounted for 87% and 45%, of the consolidated revenues during the fiscal years ended June 30, 2013, and 2012, respectively.
Australia. In Australia, revenue from one customer accounted for approximately 13% and 0%, revenue from a second customer accounted for approximately 0%, and 45% of consolidated oil and gas production revenue for the years ended June 30, 2013, and 2012, 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. In May 2012, Magellan commenced the Palm Valley GSPA with Santos, the terms of which provide for the sale by Magellan to Santos of a total contract gas quantity of 25.65 Petajoules over the 17 year term of the agreement, subject to certain limitations regarding deliverability into the Amadeus Pipeline. We are not obliged to deliver fixed quantities of gas under the Palm Valley GSPA 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.


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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 the price of oil during those times. Increased demand for heating during the winter and air conditioning during the summer months can positively impact the price of natural gas. 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, as such, 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, 2013, the Company had a total of 39 full-time 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
Our business is extensively regulated by numerous foreign, US federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our results of operations. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Regulations Applicable to Foreign Operations
Several of the properties in which we have interests are located outside of the US, and are subject to foreign laws, regulations, and related risks involved in the ownership, development, and operation of 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. Foreign laws and regulations may also limit our ability to transfer funds or proceeds from operations. 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 legal and regulatory risks in addition to those risks inherent in US 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 approval 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 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

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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.
Oil and gas exploration and production operations in the UK are subject to numerous UK and European Union ("EU") laws and regulations relating to environmental matters, health, and safety. Environmental matters are addressed before oil and gas production activities commence and during the exploration and production activities. Before a UK licensing round begins, the DECC will consult with various public bodies that have responsibility for the environment. Applicants for production licenses are required to submit a summary of their management systems and how those systems will be applied to the proposed work program. In addition, the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 require the Secretary of State to exercise the Secretary's licensing powers under the UK Petroleum Act in such a way as to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects. Further, depending on the scale of operations, production facilities may be subject to compliance obligations under the EU emissions trading system. Compliance with the above regulations may cause us to incur additional costs with respect to UK operations.

Energy Regulations
States in which we operate have adopted laws and regulations governing the exploration for, and production of, oil and gas, including laws and regulations that require (i) permits for the drilling of wells; (ii) impose bonding requirements in order to drill or operate wells; and (iii) govern the timing of drilling and 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. Many of our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration 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, that are subject to change. In addition to permits required from other regulatory agencies, lessees, such as Magellan, must obtain a permit from the BLM before drilling and must 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 may suspend or terminate our operations on federal or Indian leases.
In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM.
Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission ("FERC") has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. FERC's current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the US Congress may not continue indefinitely.


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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 our ability to produce oil or gas a rate of oil and natural gas production that is lower than the rate that is otherwise 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 the 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 the 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.
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 US and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, US 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.
The Oil Pollution Act of 1990 ("OPA") addresses prevention, containment and cleanup, and liability associated with oil pollution. The OPA applies to vessels, offshore platforms, and onshore facilities, and subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of oil spills into

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jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.
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 crude oil and natural 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 on 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 achieve timely 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.
OSHA and other laws and regulations. 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 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, particularly natural gas, from tight formations, including shales. While we have not routinely utilized hydraulic fracturing techniques in our drilling and completion programs in the past, that may change in the future in view of our potential shale play with Celtique in southern England, or if we expand our Bakken/Three Forks play of 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, and in the UK a new Office of Unconventional Gas and Oil has recently been established to coordinate the related activities of various regulatory authorities. 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, all of which could adversely affect our financial position, results of

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operations, and cash flows. For example, the UK government imposed a temporary moratorium on hydraulic fracturing in the UK that was lifted in December 2012. 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. However 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. 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 (minus): (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 (gain) on sale of assets, (vii) net interest expense (income), (viii) other expense (income), (ix) income tax provision (benefit), and (x) net loss (gain) 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 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.

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The following table provides a reconciliation of net (loss) income to Adjusted EBITDAX for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
NET (LOSS) INCOME APPLICABLE TO MAGELLAN PETROLEUM CORPORATION
$
(19,767
)
 
$
26,498

Depletion, depreciation, amortization, and accretion expense
1,534

 
1,744

Exploration expense
8,267

 
6,291

Stock based compensation expense
848

 
1,560

Foreign transaction loss (gain)
18

 
(475
)
Impairment expense
890

 
328

Gain on sale of assets

 
(40,413
)
Net interest income
(624
)
 
(749
)
Other income
(830
)
 
(9
)
Income tax benefit
(1,266
)
 
(5,951
)
Net loss attributable to non-controlling interest in subsidiaries

 
(15
)
Adjusted EBITDAX
$
(10,930
)
 
$
(11,191
)
For clarification purposes, the below tables provides an alternative method for calculating Adjusted EBITDAX, which can also be calculated as revenue less (i) lease operating expense and (ii) general and administrative expense; plus (i) stock based compensation expense and (ii) foreign transaction (gain) loss.
The following table provides the alternative method for calculating Adjusted EBITDAX for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Total revenues
$
7,070

 
$
13,712

Less:
 
 
 
Lease operating
(7,037
)
 
(12,897
)
General and administrative
(11,829
)
 
(13,091
)
Plus:
 
 
 
Stock based compensation expense
848

 
1,560

Foreign transaction loss (gain)
18

 
(475
)
Adjusted EBITDAX
$
(10,930
)
 
$
(11,191
)


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 or performance to differ materially from any future results or performance 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 is not necessarily indicative of future performance.


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RISKS RELATING TO OUR BUSINESS
Our CO2-EOR project at Poplar may not be successful.
In August 2013, we initiated a five-well CO2-EOR pilot program for the Charles formation at the Poplar field to enhance oil recovery through the injection of CO2 into the formation, and we currently estimate that the total cost of the pilot program, including capital and certain operating expenditures over a two-year period, will be approximately $20.0 million. While laboratory analysis and other preliminary tests indicate that a CO2-EOR project at Poplar could be technically and economically viable on a full-field basis, the additional production and reserves that may result from CO2-EOR methods are inherently difficult to predict. If the results of the pilot program do not support the continued use of CO2-EOR methods at Poplar or if CO2-EOR methods ultimately do not allow for the extraction of additional 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. Although we currently have a two-year CO2 supply agreement for the pilot program, if we become 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.

Substantially all of our currently producing properties are located in the Poplar field and the Palm Valley gas field, making us vulnerable to risks associated with having revenue-producing operations concentrated in a limited number of geographic areas.
Because our current revenue-producing operations are geographically concentrated in the Poplar field in the Montana portion of the Williston Basin and the Palm Valley gas field in the Australian Amadeus Basin, the success and profitability of our operations are disproportionally exposed to risks associated with regional factors. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region, other regional supply and demand factors, including gathering, pipeline, and rail transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor, and infrastructure capacity, and the effects of regional or local governmental regulations. In addition, our operations at Poplar may be adversely affected by seasonal weather and wildlife protection measures, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in these regions also increases exposure to unexpected events that may occur in these regions such as natural disasters or labor difficulties. Any one of these events has the potential to cause a relatively significant number of our producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, and prevent development within originally anticipated time frames. Any of the risks described above could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our Palm Valley production revenues and cash flows are concentrated with one long-term gas sales agreement and a limited number of ultimate customers.
Sales of our Palm Valley natural gas production are concentrated with a long-term gas supply agreement to sell up to a total of approximately 23 Bcf from Palm Valley over a 17-year period, which began on May 25, 2012, to Santos, who on-sells the gas to third party customers. As of June 30, 2013, there were two Santos customers receiving gas from Palm Valley. In the event this agreement becomes uneconomic or is unexpectedly breached or terminated, or designated volumes are decreased as permitted under the agreement, or currently anticipated ramp-ups in customer off-take volumes do not occur, our revenues and cash flows could be adversely impacted.

Our current niche strategy of marketing Amadeus Basin gas to the mining industry in central Australia may not be successful.
Our current strategy is dependent on the continued expansion of the mining industry in central Australia, and the mining industry's need for gas. If the mining industry slows or finds alternative fuel sources to gas from Palm Valley, our potential operating results could be adversely impacted.

Our Poplar production revenues and cash flows are concentrated with one purchaser, and that purchaser may reduce or discontinue purchases or become unable to meet its payment obligations to us.
Sales of our Poplar oil production are currently concentrated with an agreement with Plains Marketing, LP, who is the sole purchaser of our oil production at Poplar. If this purchaser reduces or discontinues purchases from us, or if we are unable to successfully negotiate a replacement agreement with this purchaser, who can terminate the agreement after a 90-day notice

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period, or if the replacement agreement has 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 payment obligations to us, our revenues and cash flows from Poplar could be adversely affected.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our Australian NT/P82 prospect and other exploration and development activities.
We have incurred significant expenditures to acquire extensive 2-D and 3-D seismic data with respect to our NT/P82 Exploration Permit area in the Bonaparte Basin, offshore Northern Territory, Australia, and we use 2-D and 3-D seismic data in our other exploration and development activities. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Regulations related to hydraulic fracturing could result in increased costs and operating restrictions or delays that could affect the value of our potential unconventional play in the United Kingdom.
We along with Celtique Energie have a 50%-50% working interest in a potential unconventional play in southern England that is operated by Celtique. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including unconventional gas resources. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Although the UK government lifted a temporary moratorium on hydraulic fracturing in December 2012 and a new Office of Unconventional Gas and Oil has recently been established in the UK to coordinate the related activities of various regulatory authorities, hydraulic fracturing remains a publicly controversial topic, with media and local community concerns regarding the use of fracturing fluids, impacts on drinking water supplies, and the potential for impacts to surface water, groundwater, and the environment generally. If hydraulic fracturing is significantly restricted or delayed at our potential unconventional play in the UK, or made more costly, the volumes of natural gas that can be economically recovered could be reduced, which would adversely affect the value of the play.

Our acquisitions of or 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 or investments, we typically perform a customary review of the 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 or otherwise invest 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 or investments could include our stock or require that we incur additional debt and contingent liabilities. As a result, future acquisitions or investments could cause dilution of existing equity interests

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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;
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 the properties we have or may acquire.
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 us, 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 stock could decline.


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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 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 MPA's exploration and development operations and to MPA's payment of dividends to Magellan.
The properties in which we have interests that are located outside the US 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, US taxes on the repatriation of funds to the US, 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 MPA, 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 39 total employees as of June 30, 2013. 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 may be materially adversely affected.

Oil and natural 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 heavily on the prices we receive for the crude oil and natural 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 markets for crude oil and natural gas have historically 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 the level of consumer 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 US and Australian domestic oil and gas production and the consumption and importation of such fuels and substitute fuels in US, 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;
the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas;
weather conditions, including effects of weather conditions on prices and supplies in worldwide energy markets;
technological advances affecting energy consumption and conservation;

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the ability of the members of the Organization of Petroleum Exporting Countries and other 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 US dollar relative to other currencies; and
the effect of governmental regulations 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, but in general we expect oil and gas prices to continue to fluctuate significantly.
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 Australian Consumer Price Index. Future gas sales not governed by existing contracts would generate lower revenue if natural gas prices in Australia were to decline. Prices for sales of our oil production are primarily affected by global oil prices, and the volatility of those prices will affect future oil revenues.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technical, and other resources than we do.
We face intense competition from major oil and gas companies and independent oil and gas exploration and production companies who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to explore, develop, and operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring, exploring, and developing profitable properties in the face of this competition.
We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry.

Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.
US federal, state, tribal, and local authorities, and corresponding Australian and UK 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, and oil and gas operations. 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.

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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.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil and natural gas.
Due to concerns about the risks of global warming and climate change, a number of various national and regional legislative and regulatory initiatives to limit greenhouse gas emissions are currently in various stages of discussion or implementation. For example, the US Environmental Protection Agency has been adopting and implementing various rules regulating greenhouse gas emissions under the US Clean Air Act, the US Congress has from time to time considered other legislative initiatives 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.
Legislative and regulatory programs to reduce emissions of greenhouse gases could require us to incur substantially increased capital, operating, maintenance, and compliance costs, such as costs to purchase and operate emissions control systems, costs to acquire emissions allowances, and costs to comply with new regulatory or reporting requirements. Any such legislative or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislative 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, there has been public discussion that climate change may be associated with more extreme weather conditions, such as increased frequency and severity of storms, droughts, and floods. Extreme weather conditions can interfere with our development and production activities, increase our costs of operations or reduce the efficiency of our operations, and potentially increase costs for insurance coverage in the aftermath of such conditions. 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 contains 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 will most likely vary from these estimates. Any significant variation of any nature could materially affect the estimated quantities and present value of our proved reserves, and the actual quantities and present value may be significantly less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from

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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, in accordance with SEC rules. 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 costs 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, including severance and excise taxes.
The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor required by the SEC to be used to calculate discounted future net cash flows for reporting purposes may not be the most appropriate discount factor in view of actual interest rates, costs of capital, and other risks to which our business or the oil and natural gas industry in general are subject.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional proved undeveloped reserves as we pursue drilling programs on our undeveloped properties. In addition, we may be required to write down our proved undeveloped reserves if we do not drill the scheduled wells within the required five-year timeframe.

Substantial capital is required for our business.
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 financings. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices for oil and natural gas, and our success in developing and producing new reserves. If revenues decrease as a result of lower oil or natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to explore and develop our properties and replace our reserves. If our cash flows from operations are not sufficient to fund our planned capital expenditures, we must reduce our capital expenditures unless we can raise additional capital through debt, equity, or other financings or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us.

If we are not able to replace reserves, we will 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 exploration, development, 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 write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated

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undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. 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. A significant decline in oil or natural gas prices from current levels, or other factors, could cause a future impairment write-down of capitalized costs and a non-cash charge against future earnings. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if oil or natural gas prices increase.

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;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigations and penalties; and
suspension of operations.
Our liability for environmental hazards may include 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, and in the future we may not be able to obtain insurance at premium levels that justify its purchase.

Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
US, Australian, and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of government intervention. Although some portions of the economy appear to have stabilized and begun to recover, the extent and timing of recovery, and whether it can be sustained, are uncertain. Continued weakness in the US, Australian, or other large economies could materially adversely affect our business, financial condition, results of operations, and cash flows. 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.
In addition, some of our oil and gas properties are operated by third parties that we depend on 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 natural gas production. If weak 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 or suspended.

We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies. As a result, we have limited ability to exercise influence over, and control the risks associated with, the development and operation of those properties. The timing and success of drilling and development activities on those properties depend on a number of factors outside of our control, including the operator's:
determination of the nature and timing of drilling and operational activities;
determination of the timing and amount of capital expenditures;
expertise and financial resources;
approval of other participants in drilling wells; and

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selection of suitable technology.
The failure of an operator of our properties to adequately perform development and operational activities, 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, and have a material adverse effect on our financial condition, results of operations, and cash flows.

Currency exchange rate fluctuations may negatively affect our operating results.
The exchange rates between the Australian dollar and the US dollar, as well as the exchange rates between the US dollar and the British pound, have changed in recent periods and may fluctuate substantially in the future. We expect that a majority of our revenues will be denominated in US dollars in the future. However, at June 30, 2013, the US 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 on a consolidated basis. The foreign exchange gain for the fiscal year ended June 30, 2013, was $18 thousand and is included under general and administrative expenses in the consolidated statements of operations. Any appreciation of the US dollar against the Australian dollar is likely to have a positive impact on our revenue, operating income, and net income. Because of our UK 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 US dollar could have a negative impact on our business, operating results, and financial condition.

Proposed changes to US tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.
The US President's Fiscal Year 2014 Budget Proposal includes provisions that would, if enacted, make significant changes to US 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 natural gas properties;
extending the amortization period for certain geological and geophysical expenditures; and
implementing certain international tax reforms.
These proposed changes in the US 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.

One Stone has significant influence on our major corporate decisions, including control over some matters, and could take actions that could be adverse to other stockholders. In addition, One Stone has rights as a holder of preferred stock that are senior to, and could disadvantage, holders of our common stock.
In May 2013, we issued 19.2 million shares of Series A convertible preferred stock to an affiliate of One Stone for approximately $23.5 million. The certificate of designations governing the Series A preferred stock provides One Stone, as the holder of such stock, with certain rights relating to our business and management, including the right to appoint a specified number of members of our board of directors (currently two); the right to vote on an as-converted basis with our common stockholders on matters submitted to a stockholder vote; the right to veto certain corporate actions, including some related party transactions and changes to our capital budget; and the right to receive a cash payment providing it with a specified rate of return in the event of certain change of control transactions. As a result of the foregoing, One Stone has significant influence over us, our management, our policies and matters requiring stockholder approval. The interests of One Stone may differ from the interests of our other stockholders in some circumstances, and the ability of One Stone to influence certain of our major corporate decisions may harm the market price of our common stock by delaying, deferring or preventing transactions that are or are perceived to be in the best interest of other stockholders or by discouraging third-party investors. In addition, the Series A preferred stock is senior to our common stock in terms of the right to receive dividends and payments in the event of a liquidation. These preferences could disadvantage the holders of our common stock, and may make it more difficult for us to raise equity capital in the future.

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Our interests in the United Kingdom are licenses issued by the Secretary of State and if certain drilling requirements are not met could be forfeited.
We own certain interests in the UK under licenses issued by the Secretary of State for Trade and Industry under the Petroleum Act 1988. In order to retain the interest granted by the license, MPC is required to meet certain drilling requirements. If these drilling requirements are not met or waived, the interests granted by the licenses would be forfeited.

RISKS RELATED TO OUR COMMON STOCK
The market price of our common stock may fluctuate significantly, which may result in losses for investors.
During the past several years, the stock markets in general and for oil and gas exploration and production companies in particular have experienced significant price and volume fluctuations that have often been unrelated or disproportionate to the operating results and asset values of the underlying companies. In addition, due to relatively low trading volumes for our common stock, the market price for our common stock may fluctuate significantly more than the markets as a whole. The market price of our common stock could fluctuate widely in response to a variety of factors, including factors beyond our control. These factors include:
changes in crude oil or natural gas commodity prices;
our quarterly or annual operating results;
investment recommendations by securities analysts following our business or our industry;
additions or departures of key personnel;
changes in the business, earnings estimates, or market perceptions of comparable companies;
changes in industry, general market, or regional or global economic conditions; and
announcements of legislative or regulatory changes affecting our business or our industry.
Fluctuations in the market price of our common stock may be significant, and may result in declines in the market price and losses for investors.

We may issue a significant number of shares of common stock under outstanding stock options, future equity awards under our 2012 Omnibus Incentive Compensation Plan, and our outstanding Series A convertible preferred stock, and common stockholders may be adversely affected by the issuance and sale of those shares.
As of June 30, 2013, we had 7,788,957 stock options outstanding, of which 7,788,957 were fully vested and exercisable, and 19,239,734 shares of Series A convertible preferred stock outstanding. In addition, on July 1, 2013, we granted a total of 450,000 and 266,664 restricted shares of common stock to executive officers and directors, respectively, under our 2012 Omnibus Incentive Compensation Plan. As of that date, there were 3,343,441 shares of common stock remaining available for future awards under that plan. If all of the outstanding stock options, which total 8,408,957 and have exercise prices ranging from $0.79 to $2.41 per share, are exercised, or the outstanding shares of Series A convertible preferred stock are converted, the shares of common stock issued would represent approximately 16% and 30%, respectively, of the outstanding common shares. Sales of those shares could adversely affect the market price of our common stock, even if our business is doing well.

If our common stock is delisted from the NASDAQ Capital Market, its 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 common stock must maintain a minimum bid price of $1.00 as set forth in NASDAQ Marketplace Rule 5550(a)(2). If the closing bid price of the common stock is below $1.00 for 30 consecutive trading days, as occurred in October-November 2012, then the closing bid price of the common stock must be $1.00 or more for 10 consecutive trading days during a 180-day grace period to regain compliance with the rule, as occurred in January 2013. On September 12, 2013, the closing market price of our common stock was $1.03 per share, but the common stock has closed at below $1.00 on certain trading days in 2013. If our common stock is delisted from trading on the NASDAQ Capital Market, it may be eligible for trading on the OTCQB, but the delisting of our common stock from NASDAQ could adversely impact the liquidity and value of our common stock.


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We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our common stockholders.
Subject to the satisfaction of the dividend rights of our Series A convertible preferred stock, which provide for a dividend equivalent of 7% per annum on the issue price plus any accumulated unpaid dividends, payable in the form of cash, in kind (in the form of additional shares of Series A preferred stock), or a combination thereof (at our option), we currently anticipate that we will retain future earnings, if any, to reduce our accumulated deficit and finance the growth and development of our business. The Series A preferred stock ranks senior to the common stock with respect to dividends and other rights, and we do not intend to pay cash dividends on our common stock in the foreseeable future. Any future determination as to the declaration and payment of cash dividends on our common stock will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects, and any other factors that our board determines to be relevant. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our common stockholders.

Our largest stockholder beneficially owns a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.
One Stone Holdings II LP owns 19,239,734 shares of our Series A convertible preferred stock, and thereby currently beneficially owns approximately 30% of our common stock, assuming full conversion of the Series A preferred stock. The Series A preferred stock is entitled to vote on an as-converted basis with the common stock. In addition, two individuals affiliated with One Stone serve on our eight-member board of directors. As a result, One Stone is able to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents, and significant corporate transactions. Further, for so long as One Stone owns at least 10% of the fully diluted common stock, assuming full conversion of the Series A preferred stock, One Stone will hold veto rights with respect to capital expenditures greater than $15.0 million that are not provided for in the then-current annual budget, changes in our principal line of business, an increase in the size of our board to more than 12 members, and certain other matters.
The concentration of ownership and voting power with One Stone makes it difficult for any other holder or group of holders of our common stock to be able to affect the way we are managed or the direction of our business. The interests of One Stone with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings, and other corporate opportunities, and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentration of ownership will make it difficult for another company to acquire us and for stockholders to receive any related takeover premium unless One Stone approves the acquisition.

Provisions in our charter documents and Delaware law make it more difficult to effect a change in control of our company, which could prevent stockholders from receiving a takeover premium on their investment.
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 attractive to our existing stockholders. In addition, our certificate of incorporation and by-laws 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 approval, with rights senior to those of the 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 of their common stock.


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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.


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ITEM 4: MINE SAFETY DISCLOSURES
Not applicable.


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PART II

ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
PRINCIPAL MARKET
Magellan's common stock is traded on the NASDAQ Capital Market under the symbol MPET. The below table presents the quarterly high and low intraday prices during the periods indicated.
Quarter ended
 
High
 
Low
June 30, 2013
 
$1.19
 
$0.97
March 30, 2013
 
$1.33
 
$0.86
December 31, 2012
 
$1.06
 
$0.74
September 30, 2012
 
$1.63
 
$0.91
 
 
 
 
 
June 30, 2012
 
$1.39
 
$1.01
March 30, 2012
 
$1.49
 
$0.87
December 31, 2011
 
$1.24
 
$0.89
September 30, 2011
 
$1.89
 
$1.12

HOLDERS
As of September 12, 2013, the number of record holders of Magellan's common stock was 4,980 and, based upon inquiry, the number of beneficial owners was approximately 6,300.

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 on its common stock in the foreseeable future.

37




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 value of shares that may yet be purchased under the program
April 1, 2013 - April 30 , 2013
 

 
$

 

 
$
1,863,022

May 1, 2013 - May 31, 2013
 

 
$

 

 
$
1,863,022

June 1, 2013 - June 30, 2013
 

 
$

 

 
$
1,863,022

Total
 

 
$

 

 
$
1,863,022

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 announced on December 8, 2000, 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.
During Fiscal year 2013, the Company repurchased 149,539 shares of its common stock under the approved stock repurchase program between November 2012 and February 2013, and 9,264,637 shares of common stock through a Collateral Agreement (see Note 9). During this period the Company's share price was below $1.00 per share. No further repurchases of the Company's common stock occurred since.


ITEM 6: SELECTED FINANCIAL DATA
The Company is a smaller reporting company, as defined by 17 CFR § 229.10(f)(1), and therefore is not required to provide the information otherwise required by this Item.


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 (until May 2012) represents our MPA 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 expressed or implied in the forward looking statements. See "Forward Looking Statements" at the end of this section. Factors that might cause such differences include, but are not limited to, those discussed in Item 1A: Risk Factors of this Form 10-K. 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 operations are conducted through three wholly owned subsidiaries: NP, which owns and operates an oilfield in Poplar; MPA, which owns and operates onshore gas fields in Australia, and owns an offshore exploration license in Australia; and MPUK, which owns a large acreage position in the Weald and Wessex Basins in southern England. Our strategy

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is to enhance shareholder value by maximizing the value of these 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.

SIGNIFICANT DEVELOPMENTS IN FISCAL YEAR 2013
During fiscal year 2013, the Company took important steps in its strategy of creating value from our existing assets. Administratively, we completed the two-year turn-around of the Magellan platform through a number of achievements, including: hiring new engineering and geologic personnel, completing the overhaul of our accounting function, delisting from the Australian Securities Exchange ("ASX"), repurchasing 17% of our common shares plus warrants from an unsupportive shareholder, and raising $23.5 million in convertible preferred equity on terms the Company believes were attractive. As a result, we believe we now have an organized and effective platform poised to achieve growth and the successful development of our assets.
Operationally, we made steady progress on each of our key projects such that we can continue to achieve key developmental and operational milestones in fiscal year 2014. At Poplar, our work on the CO2-EOR pilot during fiscal year 2013 resulted in obtaining a CO2 supply contract and receiving the permits to start the drilling of our pilot wells in July and August 2013, respectively. With the drilling of CO2-EOR pilot wells now underway, we expect to deliver results by the end of calendar year 2014. In parallel, we initiated a water shut-off program to increase oil production from the existing wells at Poplar and reduce our operating costs. This program has started to yield positive results, and we will continue to implement it across the field as we gather results from each treatment. Onshore Australia, we spent most of fiscal year 2013 in discussions and contract negotiations with potential customers of Dingo gas, resulting in the signing of a long term gas sales contract, the Dingo GSPA with PWC for the sale of the majority of Dingo's reserves. Gas sales are expected to commence in early calendar year 2015 once surface facilities and a tie-in pipeline are constructed at Dingo. With gas sales contracts in place at both Palm Valley and Dingo, and considering the cost of Dingo's surface facilities and pipeline tie-in, we expect our Amadeus Basin assets to provide Magellan with reasonably predictable cash flows. Offshore Australia, we conducted 2-D and 3-D seismic surveys over NT/P82, our 100% owned exploration license in the Bonaparte Basin. Based on the preliminary interpretation of the seismic data we acquired, we are optimistic about our ability to execute a successful farmout transaction in fiscal year 2014 whereby a new partner will drill the large gas prospects that lie within our block. In the UK, together with our partner Celtique, we completed an extensive geological analysis of the potential prospects underlying our Weald Basin acreage. In addition, we prepared and filed permit applications to drill exploratory wells on our acreage, which will allow us to drill and further assess the potential for conventional and unconventional oil production in fiscal year 2014.
As a result of the achievements and improvements realized in fiscal year 2013, in fiscal year 2014 we expect to receive the results of various operational initiatives that will allow us to demonstrate the potential value of our assets and develop an asset rationalization strategy to maximize Magellan's net asset value per share.

SUMMARY RESULTS OF OPERATIONS FOR THE YEAR ENDED JUNE 30, 2013
For the year ended June 30, 2013, revenues totaled $7.1 million compared to $13.7 million in the prior year, a decrease of 48%. Operating loss totaled $22.5 million compared to operating income of $19.8 million in the prior year. Net loss totaled $19.8 million ($0.41/basic share), compared to a net income of $26.5 million ($0.49/basic share) in the prior year, primarily due to the favorable impact of the Santos SA in fiscal year 2012. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation under Part 1, Items 1 and 2: Business and Properties) totaled negative $10.9 million, compared to negative $11.2 million in the prior year, a change of (2)%. For further detail, please refer to the discussion below in this section under Comparison of Financial Results and Trends Between Fiscal 2013 and 2012.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES
During fiscal year 2013, the Company took important steps in its strategy of creating value from our existing assets. We made steady progress on meeting developmental and operational milestones on each of our key projects. The below discussion should be read in conjunction with the discussion of Significant Developments in Fiscal Year 2013 under Part 1, Items 1 and 2: Business and Properties above and the section covering Comparison of Financial Results and Trends between Fiscal Years 2013 and 2012 below.

Poplar (Montana, United States)
Magellan 100% operated intervals. During the year ended June 30, 2013, Magellan sold 72 Mbbls of oil attributable to its net revenue interests in Poplar, compared to 75 Mbbls of oil sold during the same period in 2012. These results represent a 4% decrease in average daily sales for the year from 205 boepd to 198 boepd.
During this period, Magellan focused heavily on advancing its CO2-EOR pilot project in the Charles formation at Poplar. The Company worked with various governmental agencies, including the Bureau of Land Management and the Bureau of Indian Affairs, to gain permits for the drilling of five wells as part of a CO2-EOR pilot project. These permits were received and drilling on these wells began in August 2013. In parallel to the permitting process, Magellan evaluated various options for the supply and transportation of CO2 for its pilot project, resulting in the signing of an approximately two-year CO2-supply contract with Air Liquide in July 2013. The CO2 supplied by Air Liquide will be trucked and stored on the drilling site and is expected

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to satisfy the CO2 volume requirements to our CO2-EOR pilot project. However, the current arrangement with Air Liquide will not be sufficient for a full field CO2-EOR program.
Magellan also remained focused on increasing oil production at Poplar and reducing operating expenses by reducing associated water production. Since most of the wells at Poplar were drilled in the 1950s, we regularly have to perform various work-overs on the wells such as small acid stimulations, fixing parted rods, and tanks and flowline repairs. These work-overs, combined with the cost of handling relatively high water production, result in high fixed costs and, while oil production remains at current levels, in high LOE/bbls. In order to increase oil production and reduce operating costs, we have identified a possible solution in the form of water shut-off treatments, which seek to block off part of the water influx and allow increased oil production. We continue to monitor and evaluate the results of these treatments to determine where they are most effective and which existing wells are the most likely candidates for future treatments. On the EPU 104 well, Magellan successfully executed a water shut-off treatment in December 2012. Prior to the water shut-off treatment, this well produced approximately 5 bopd and 1,050 bwpd. Following the treatment, the EPU 104's initial production rate was approximately 80 bopd and now produces at an average rate of 28 bopd and 337 bowd. Since then, the Company has performed water shut-off treatments on the EPU 119, EPU 34-11H, and EPU 42 wells, the results of which are still under evaluation. In July 2013, we performed similar operations on EPU 55 with the greatest results to date: the EPU 55 well is currently producing approximately 134 bopd and 35% oil cut. We believe that since these results are very recent, we need more time to estimate the well production decline rate of this well. During fiscal year 2013, we have invested approximately $1.2 million in several water shut-off treatments, and we will continue to prudently manage the allocation of the Company's cash resources to such treatments.
Finally, production from the Amsden formation from the EPU 117, which was a new pool discovery in January 2012, has declined from early production of approximately 80 bopd to approximately 7 bopd. We continue to test various stimulation techniques on this well.
Deep Intervals. Under the terms of the VAALCO PSA signed in September 2011, VAALCO was obligated to drill and complete at their own expense three test wells in the deeper formations at Poplar in order to earn a 65% working interest in and operatorship of these formations. Following completion of the first test well, the EPU 120, in fiscal year 2012, VAALCO completed its second test well, the EPU 133-H, as a horizontal well targeting the Bakken/Three Forks formation in September 2012. In March 2013, VAALCO completed its third test well, the EPU 125, a vertical well targeting the Nisku formation. Although core and log analyses taken during drilling of these wells were indicative of the potential for commercial hydrocarbon production from the Deep Intervals, the three test wells, upon completion and production testing, were found to be water bearing. Based on these inconclusive results and Magellan's desire to use those well bores for further exploration and/or potential salt water disposal, Magellan renegotiated certain terms of the VAALCO PSA in December 2012. Under the revised terms, Magellan (i) became the operator; (ii) obtained a 100% working interest in and operatorship of the wellbores for the first two wells, the EPU 133-H and the EPU 120; and (iii) increased its working interest in the Deep Intervals at Poplar from 35% to 50%, except for the spacing unit associated with EPU 125, VAALCO's third test well, which Magellan will operate but in which Magellan's working interest will remain 35%.
During fiscal year 2014, Magellan may attempt to recomplete the EPU 125 well in the Nisku formation. The Nisku formation at Poplar has produced approximately 200 thousand barrels of oil from a single well between 1970 and 1990, and data collected from the EPU 120 and EPU 125 wells confirmed the potential for commercial oil production from this formation. The decision to recomplete the EPU 125 will be based on further ongoing geological analysis by the Company and available cash resources.

Australia
Palm Valley. Following the termination of the PWC Palm Valley Contract in January 2012, Magellan successfully re-contracted the remaining 23 Bcf of Palm Valley's gas reserves through the Palm Valley GSPA with Santos. The Palm Valley gas field, which is operated by MPA, produced a gross average of approximately 0.5 MMcf/d of natural gas for sale for the year ended June 30, 2013. For the same time period in the prior year, the Palm Valley gas field produced approximately 2.7 MMcf/d. Gas sales volumes at Palm Valley decreased due to the termination of the PWC Palm Valley Contract in January 2012. The average price of gas, net of royalties and prior year royalty adjustments, at Palm Valley was AUD $4.80/Mcf for the year ended June 30, 2013, compared to AUD $3.01/Mcf for the prior year.
Gas volumes during fiscal year 2013 were sold under the Palm Valley GSPA to Santos. Gas sales volumes under this contract are expected to ramp up based on currently scheduled contracts to approximately 3.3 MMcf/d by the third quarter of fiscal year 2014 and to 4.1 MMcf/d by the fourth quarter of fiscal year 2015, at which point the field will be selling at its full deliverability capacity and generating revenues of approximately AUD $8.0 million per year.
Dingo. During the fiscal year, the Company undertook marketing efforts to identify and attract long term customers for Dingo's gas resources. These efforts resulted in the signing of the Dingo GSPA with PWC in September 2013 for the supply of

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31 PJ (30 Bcf) of gas over a 20-year period. In parallel to the marketing efforts, during the fiscal year Magellan completed a pre-front-end engineering and design study to evaluate the cost and logistics of installing gas treatment facilities and tying the Dingo field into the existing pipeline infrastructure near Alice Springs. This study will serve as the basis for bringing Dingo to operational capability in fiscal year 2015.
NT/P82. During fiscal year 2013, Magellan focused on conducting a seismic survey over portions of its NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia. In December 2012, the Company successfully conducted, via a third-party contractor, a 2-D and 3-D seismic survey over portions of the block. The seismic recording vessel Voyager Explorer, operated by Seabird Exploration FZ-LLC, acquired a total of 76 square miles of 3-D full fold data and 65 miles of 2-D full fold data. Between January and August 2013, the seismic data was undergoing processing and interpretation, including additional processing to address the impact of fluvial channeling on the seabed. The results of the seismic surveys interpretation are expected to be received by the end of the first quarter of fiscal year 2014 and we hope will allow us to begin a farmout process during the second quarter of fiscal year 2014. Through this process, we expect to identify a partner to drill exploratory wells over the large gas prospects that may lie in the permit area in exchange for an ownership interest in and operatorship of the license. The overall cost of the seismic surveys and related processing and interpretation is estimated to total approximately AUD $3.7 million, which is under the originally estimated budget.

United Kingdom
Going forward, the Company's primary objectives in the UK are (i) to receive drilling approval for a number of different sites in order to demonstrate that, assuming the prospect for producing commercial quantities of hydrocarbons is geologically and technically viable, access to drill sites is achievable within the existing regulatory framework and current social and environmental realities; and (ii) to establish the potential of its unconventional prospects, most of which lie within the licenses co-owned with Celtique, by drilling exploratory wells and collecting cores and logs. As part of this effort, the Company plans to participate in up to three evaluation wells with Celtique, the first of which will be spud in or around the third quarter of fiscal year 2014.
Celtique Operated Licenses. PEDLs 231, 234, and 243 overlay the center portion of the Weald Basin prospect for unconventional hydrocarbon resources and are subject to "drill or drop" rules by the end of June 2014 and a 50% relinquishment requirement to the extent that drilling obligations have been met by the term of the PEDLs. During fiscal year 2013, Magellan, in conjunction with Celtique, completed extensive geological analysis of the Weald Basin and focused on securing and permitting various potential well site locations.
We and our partner, Celtique, believe that the drilling of one well located in PEDL 234 may qualify to meet our work commitments for both PEDLs 234 and 243. We expect this well will be spud in the third quarter of fiscal year 2014. In addition, we are in the process of permitting a well in PEDL 231 to fulfill our commitments for drilling in PEDL 231 and have applied for a 12-month extension to our current PEDL to allow additional time to receive planning approval. In PEDL 234, we are also awaiting final planning approval to drill a well in the center of the Weald Basin, which may spud in the fourth quarter of fiscal year 2014. The purpose of these wells is to test and evaluate the Kimmeridge Clay and Liassic formations in order to substantiate the unconventional oil production potential of our acreage and to test and evaluate the conventional potential of the Triassic formations. Under the terms of our joint operating agreement with Celtique, we are required to participate in these commitment wells to maintain our working interest in the PEDLs. We intend to participate in the drilling of these wells and expect to fund our share of the costs through either our cash reserves, the farmout of a portion of our interests, or the proceeds from other asset sales.
Northern Petroleum Operated Licenses. In the Weald and Wessex Basins, Magellan owns working interests of between 23% and 40% in five licenses operated by Northern Petroleum (PEDL 126, 155, 240, and 256 and P1916), which expire between June 2014 and January 2016. During fiscal year 2013, Magellan determined it had no further development plans with respect to the Markwells Wood-1 well (located in PEDL 126), which was drilled in fiscal year 2011, and wrote off its remaining investment in that well of approximately $2.2 million. During the same period, the Company continued to evaluate the exploration options for its most recently acquired license, P1916, which lies offshore, west of the Isle of Wight, and PEDL 240 which is onshore and contiguous to P1916 and could provide a potential drilling site for the offshore prospect. P1916 is prospective for a Wytch Farm extension play.
Magellan Operated Licenses. In the Weald Basin, Magellan owns a 100% interest in two licenses (PEDL 137 and 246), which expire in September 2013 and June 2014, respectively. During fiscal year 2013, the Company actively pursued a farm-in partner for the drilling of an exploration well on the Horse Hill prospect in PEDL 137, for which the Company has obtained planning approval from the Surrey County Council. The Horse Hill well would target conventional oil plays in the Portland Sandstone and Corrallian Limestone, which are productive in nearby oil fields and a new Triassic gas play identified on 2-D seismic data which was reprocessed by the Company. The planning approval does not allow the operator to use hydraulic fracturing technology in this well. We will evaluate the Kimmeridge Clay and Liassic formations to contribute to the appraisal

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of the potential of these formations in the Weald Basin. In addition, Magellan has applied to the UK Government for a 12 month renewal of the PEDL 137 license to allow time for a farmout well to be drilled.

OTHER ITEMS
Voluntary ASX Delisting
On March 28, 2013, Magellan completed the voluntary delisting of its shares from trading on the Australian Securities Exchange ("ASX"). The Company's shares had traded on the ASX in the form of CHESS Depository Interests since Magellan's 2006 acquisition of the 45% interest it did not already own in MPA. In addition, effective April 5, 2013, Magellan converted the legal status of MPA to a proprietary company, allowing Magellan to alter the MPA board structure and eliminate related compensation expense. As a result of both initiatives, Magellan expects to realize annual savings of approximately $0.3 million.

US Federal Tax Withholdings
In connection with the Company's non-payment of required US Federal tax withholdings in the course of its 2009 acquisition of an interest in NP from White Bear and YEP I, both affiliated entities with Mr. Bogachev, a former director of Magellan, the Company estimated that it had a potential total liability of approximately $2.0 million as of June 30, 2012. As of June 30, 2013, the Company believes that this matter has been fully addressed as a result of a disclosure process with the IRS. During fiscal years ending June 30, 2012, and 2013, the Company incurred total cash expenses of $0.5 million related to this matter. The effect of this transaction on the consolidated statements of operations for the year ended June 30, 2013, resulted in other income of $0.4 million representing the difference between the original estimate and the approximate final liability of $0.1 million (see Note 13).

Transfer of MPUK
In June 2013, the Company completed the transfer of MPUK from MPA to MPC. The estimated fair value of the transfer was approximately $10.9 million. This transfer is not expected to give rise to any cash tax expenditures for the Company and will provide greater flexibility to the operation and funding of the Company's assets in the UK. As a result, the Company will now report MPUK as a third reportable segment together with NP and MPA.

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 obligations pertaining to its leases and licenses, which allow for significant flexibility in the use of its capital resources. Based on its existing cash position, the Company believes it has sufficient financial resources to fund its ongoing operations and to finance its core project at Poplar, the CO2-EOR pilot project, which we believe will further establish the full value of its assets. Furthermore, offshore Australia and in the UK, the Company owns interests in large potential projects, which require significant additional capital to reduce their inherent operational risk and increase their potential value. A possible funding strategy for these assets is to seek farm-in partners that will bear most of the costs of the next operational milestones in exchange for working interests in these assets alongside Magellan. The Company may also seek to raise debt facilities to fund some of its projects, including the construction of surface facilities and a pipeline to tie the Dingo gas field to Brewer Estate in Northern Territory, Australia. Finally, Magellan intends to explore the potential sale of certain assets which are more mature by the nature of their long term contracts and redeploy these proceeds in the Company's core assets, such as Poplar, which offer the potential to further increase the Company's net asset value per share.

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 79% of the acreage has been unitized as a federal exploratory unit, which is held by production from any one well. Currently, Poplar contains 42 productive 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 the CO2-EOR pilot project and results of water shut-off treatments. In the first half of fiscal year 2014, 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 $20.0 million in capital costs on these wells. The four producing wells are designed to yield conventional oil production from the Charles formation in

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addition to enhanced production as a result of the CO2-EOR.
In the Deep Intervals, which are operated by the Company and in which the Company has a working interest ranging between 50% to 35%, the Company does not intend to incur material capital expenditures in fiscal year 2014. Based on its cash resources and other strategic considerations, the Company may invest in re-completing a well in the Nisku formation.
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 in order to meet delivery obligations under its gas sales contract with Santos 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 an additional 5 years). Following the signing of the Dingo GSPA in September 2013, the Company expects to incur capital expenditures of approximately $20.0 million over the next 24 months in order to install surface facilities for production and processing of gas and to build a 27 mile pipeline connecting Dingo to existing pipeline infrastructure at Brewer Estate, south of Alice Springs. The Company expects to fund these expenditures from a combination of its own cash resources and through project finance debt facilities to be secured by the Dingo and/or Palm Valley assets and future cash flows therefrom or similar debt facilities.
In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, the Company is required to drill one exploratory well on the license by the license expiration date of May 2015. Following the successful completion of seismic surveys over two prospects in the license area and the associated processing and interpretation in August 2013, the Company expects to commence a farmout process in order to identify a partner experienced in offshore exploratory drilling to drill the exploratory well on our behalf. The Company expects to incur no further capital or exploratory expenditures of its own on this license at least until the first exploration well has been drilled.
In the UK, the Company's interests are governed by various Petroleum Exploration and Development Licenses and one Seaward Production License. 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). In fiscal year 2014, the Company will focus on evaluating the potential of its unconventional prospects in the Weald Basin in southern England, which are contained within the license areas of PEDLs 231, 234, and 243, which the Company co-owns 50% with Celtique. The Company expects to fund its share of the cost for an evaluation well to be spud within the area of these licenses during the third quarter of fiscal year 2014, of which the cost is estimated to be approximately $4.0 million net to Magellan. Pending the results of this well, the Company may participate in a second such evaluation well within these PEDLs toward the end of fiscal year 2014 or early in fiscal year 2015. The Company may seek a farmout partner to partially fund these expenditures or use the proceeds from other asset sales.
The Company expects to incur minimal capital or exploratory expenditures on its other UK licenses in fiscal year 2014.
Contractual Obligations. The following table summarizes our obligations and commitments as of June 30, 2013, to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods as follows:
 
Total
 
Less than
1 year
 
1-3 years
 
3-5 years
 
More than 5 years
 
(In thousands)
Purchase obligations (1)
$
5,660

 
$
5,660

 
$

 
$

 
$

Asset retirement obligations
6,879

 
476

 
242

 

 
6,161

Contingent consideration payable (2)
3,940

 

 
3,940

 

 

Operating leases (3)
1,055

 
162

 
530

 
363

 

Long term debt, including interest (4)
403

 
403

 

 

 

Total
$
17,937

 
$
6,701

 
$
4,712

 
$
363

 
$
6,161

(1) Purchase obligations of $0.7 million and $5.0 million are attributable to certain exploration and capital expenditures related to MPA and MPUK, respectively.
(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 $13 thousand for the 6.25% note payable (see Note 3).

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Share Repurchase Program. On September 24, 2012, the Company announced that its Board of Directors had approved a stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its common stock. As of June 30, 2013, $1.9 million remained authorized for stock repurchases under this program. See Issuer Purchases of Equity Securities under Part II, Item 5 of this report for additional information.
Collateral Purchase Agreement. Following the completion of the Collateral Purchase Agreement with Sopak in January 2013, the Company's cash balances were reduced by $10.0 million.

Sources of Funds
Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $32.5 million of cash and cash equivalents at June 30, 2013, compared to $41.2 million as of June 30, 2012. As of June 30, 2013, $5.3 million of the Company's consolidated cash and cash equivalents were deposited in accounts held by MPA, all of which was held in several Australian banks in time deposit accounts that have terms of 90 days or less. During fiscal year 2013, the Company repatriated approximately $24.6 million in the form of dividends from MPA to MPC at a weighted average exchange rate of 1.04:1.00. These dividends are not expected to result in any cash tax expenditures.
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.
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 MPA to the US, the Company is potentially liable for incremental US Federal and State Income Tax, which may be reduced by the US Federal and State net operating loss and foreign tax credit carry forwards available to the Company at that time.
Existing Credit Facilities. The Company's outstanding borrowings are summarized below for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Outstanding borrowings:
 
 
 
Note Payable
$
390

 
$
870

Line of credit
51

 
50

Total
$
441

 
$
920

The Company, through its wholly owned subsidiary NP, maintains its only credit facility (the "Line of Credit") with Jonah Bank of Wyoming. As of June 30, 2013, $51 thousand of the $1.0 million Line of Credit was drawn, $25 thousand secured a Line of Credit in favor of the Bureau of Land Management, and $0.9 million remained available to borrow. As of June 30, 2013, NP was in compliance with its financial covenants as set forth in the term loan agreement. The credit facility is collateralized by a first mortgage and an assignment of production from Poplar and guaranteed by the Company up to $6.0 million but not to exceed the amount of the principal owed, which was $0.4 million as of June 30, 2013. The Note Payable with Jonah Bank of Wyoming will be fully amortized by June 30, 2014.
Other Sources of Financing. In addition to its existing liquid capital resources the Company has various alternatives to fund the development of its assets. These alternatives could potentially include conventional bank debt, a reserve-based loan facility, a project finance loan facility, mezzanine financing from a bank and the alternative investment markets, equity issuances via a PIPE or secondary offering, and a partial or complete divestiture or farmout of a portion of the development program of some of the Company's assets.


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Cash Flows
The following table presents the Company's cash flow information for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Cash (used in) provided by:
 
 
 
Operating activities
$
(18,030
)
 
$
(10,441
)
Investing activities
(2,925
)
 
35,629

Financing activities
12,357

 
(3,928
)
Effect of exchange rate changes on cash and cash equivalents
(148
)
 
(462
)
Net (decrease) increase in cash and cash equivalents
$
(8,746
)
 
$
20,798

Cash used in operating activities during the year ended June 30, 2013, was $18.0 million, compared to cash used of $10.4 million in 2012. The increase in cash used in operating activities primarily resulted from a combination of a decrease in revenues of $6.6 million over the prior year and increased operational spending related to exploration of $2.0 million. The decrease in operating assets and liabilities of approximately $5.8 million was driven primarily by reduced cash receipts from sales at MPA due to the impact of the Santos SA in fiscal year 2012, in addition to increased cash payments to MPC creditors at the end of fiscal year 2013. These factors were partially offset by a decrease in lease operating expenses of $5.9 million, and a reduction in general and administrative costs (excluding stock based compensation and foreign transaction loss) of $1.0 million.
Cash used in investing activities during the year ended June 30, 2013, was $2.9 million, compared to cash provided of $35.6 million in 2012. The increase in cash used in investing activities was the result of a series of proceeds in the prior year, including $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 $26.6 million in cash proceeds from the Santos SA (see Note 2). The decrease in investing activities are represented by these non-recurring prior year proceeds and by a $6.6 million reduction in capital expenditures on our projects between fiscal year 2012 and fiscal 2013.
Cash provided by financing activities during the year ended June 30, 2013, was $12.4 million, compared to cash used of $3.9 million in 2012. The increase in cash provided by financing activities primarily resulted from net proceeds from the issuance of preferred equity to One Stone in fiscal year 2013 of $23.0 million offset by the expenditure of $10.0 million on the repurchase of shares and a warrant from Sopak in January 2013.
During the year ended June 30, 2013, the effect of changes in foreign currency exchange rates negatively impacted the translation of our AUD denominated cash and cash equivalent balances into US dollars and resulted in a decrease of $0.1 million in cash and cash equivalents, compared to a decrease of $0.5 million in 2012.


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COMPARISON OF FINANCIAL RESULTS AND TRENDS BETWEEN FISCAL 2013 AND 2012
Oil and Gas Sales Volumes
The following table presents oil and gas sales volumes for the fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Net sales by field:
 
 
 
 
 
 
 
Poplar (Mbbls)
72

 
75

 
(3
)
 
(4
)%
 
 
 
 
 
 
 
 
Palm Valley gas (MMcf)
191

 
434

 
(243
)
 
(56
)%
Mereenie oil (Mbbls)

 
45

 
(45
)
 
(100
)%
Total Australia sales (Mboe)
32

 
119

 
(87
)
 
(73
)%
 
 
 
 
 
 
 
 
Net sales by product:
 
 
 
 
 
 
 
Oil (Mbbls)
72

 
122

 
(50
)
 
(41
)%
Gas (MMcf)
191

 
434

 
(243
)
 
(56
)%
 
 
 
 
 
 
 
 
Consolidated sales (Mboe)
104

 
194

 
(90
)
 
(46
)%
Consolidated sales (boepd)
285

 
531

 
(246
)
 
(46
)%
Sales volumes for the year ended June 30, 2013, totaled 104 Mboe (285 boepd), compared to 194 Mboe (531 boepd) sold in the prior year period, a decrease of 46%. This decline was primarily the result of the termination of the PWC Palm Valley Contract at Palm Valley in January 2012 and the sale of the Company's interest in Mereenie in May 2012. Sales volumes by product for the year ended June 30, 2013, were 69% oil and 31% gas, compared to 63% oil and 37% gas in the prior year, with the change due to the reduced contribution of gas sales from Palm Valley. At Poplar, volumes were negatively impacted by the temporary shut-in of various wells producing from the Charles formation in order to conduct water shut-off treatments and a decline in production from the EPU 117 well, which produces from the Amsden formation, offset by increased production from the Charles formation as the result of successful water-shut-off treatments on various wells. Gas sales volumes at Palm Valley decreased due to the termination of the PWC Palm Valley Contract in January 2012. Since May 2012, gas volumes produced at Palm Valley have been sold under the Palm Valley GSPA with Santos, under which 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 16 years. Based on current gas sales contracts, the Company expects that Palm Valley will be selling gas at a rate of approximately 1.3 Bcf per year by the end of fiscal year 2014 and 1.5 Bcf per year by the end of fiscal year 2015, at which point Palm Valley will be selling at its full productive capacity. 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 fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Average realized price (1):
 
 
 
 
 
 
 
Poplar (USD/bbl)
$84.91
 
$82.66
 
$2.25
 
3
 %
Palm Valley (AUD/Mcf)
$4.80
 
$3.01
 
$1.79
 
59
 %
Mereenie oil (AUD/bbl)
$0.00
 
$132.92
 
$(132.92)
 
(100
)%
Consolidated (USD/boe)
$68.01
 
$70.95
 
$(2.94)
 
(4
)%
(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, 2013, was $68.01/boe compared to $70.95/boe in the prior year period, a decrease of 4%. This decrease in price is primarily the result of the loss of contribution from sales of oil from

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Mereenie, which historically enjoyed favorable pricing relative to the US. 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 3% as a result of a decrease in its benchmark pricing (WTI) partially offset by an improved differential to the benchmark realized at the field. The average realized gas price from Palm Valley increased by 59%, which reflects the higher gas prices realized under the Palm Valley GSPA with Santos, which commenced in May 2012, compared to prices that were realized under the PWC Palm Valley Contract, which ended in January 2012.

Revenues
The following table presents revenues for the fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Net revenue by source:
 
 
 
 
 
 
 
Poplar (USD)
$
6,131

 
$
6,172

 
$
(41
)
 
(1
)%
Palm Valley (USD)
939

 
1,347

 
(408
)
 
(30
)%
Mereenie (USD)

 
6,232

 
(6,232
)
 
(100
)%
Other (USD)

 
(39
)
 
39

 
(100
)%
Total (USD)
$
7,070

 
$
13,712

 
$
(6,642
)
 
(48
)%
 
 
 
 
 
 
 
 
Palm Valley (AUD)
$
914

 
$
1,305

 
$
(391
)
 
(30
)%
Mereenie (AUD)
$

 
$
6,037

 
$
(6,037
)
 
(100
)%
 
 
 
 
 
 
 
 
Net revenues by type (USD):
 
 
 
 
 
 
 
Oil
$
6,131

 
$
12,405

 
$
(6,274
)
 
(51
)%
Gas
939

 
1,307

 
(368
)
 
(28
)%
Total
$
7,070

 
$
13,712

 
$
(6,642
)
 
(48
)%
Revenues for the year ended June 30, 2013, totaled $7.1 million, compared to $13.7 million in the prior year period, a decrease of 48%. The $6.6 million decrease in revenue was the result of the termination at Palm Valley of the 25-year PWC Palm Valley Contract in January 2012 and the Company's sale of its interest in Mereenie in May 2012.

Operating and Other Expenses
The following table presents selected operating expenses for the fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Selected operating expenses (USD):
 
 
 
 
 
 
 
Lease operating
$
7,037

 
$
12,897

 
$
(5,860
)
 
(45
)%
Depletion, depreciation, amortization, and accretion
$
1,534

 
$
1,744

 
$
(210
)
 
(12
)%
Exploration
$
8,267

 
$
6,291

 
$
1,976

 
31
 %
General and administrative
$
11,829

 
$
13,091

 
$
(1,262
)
 
(10
)%
 
 
 
 
 
 
 
 
Selected operating expenses (USD/boe):
 
 
 
 
 
 
 
Lease operating
$
68

 
$
66

 
$
2

 
3
 %
Depletion, depreciation, amortization, and accretion
$
15

 
$
9

 
$
6

 
67
 %
Exploration
$
79

 
$
32

 
$
47

 
147
 %
General and administrative
$
114

 
$
67

 
$
47

 
70
 %

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Lease Operating Expenses. Lease operating expenses decreased by $5.9 million to $7.0 million, or $68/boe, during the year ended June 30, 2013. Lease operating expenses at Poplar decreased by approximately $0.4 million primarily as the result of a lower average of actively producing wells and a more selective work-over program in fiscal year 2013 focused mainly on water shut-off treatments. Lease operating expenses in Australia decreased by $5.5 million primarily as a result of the Company's sale of its interest in Mereenie in May 2012, which contributed $6.0 million to lease operating expenses in the prior fiscal year.
Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Depreciation and amortization
$
285

 
$
433

 
$
(148
)
 
(34
)%
Depletion
816

 
743

 
73

 
10
 %
ARO accretion
433

 
568

 
(135
)
 
(24
)%
Total
$
1,534

 
$
1,744

 
$
(210
)
 
(12
)%
Depletion, depreciation, amortization, and accretion expenses decreased by $0.2 million to $1.5 million, or $15/boe, during the year ended June 30, 2013. Accretion expense decreased as a result of the Company's sale of its interest in Mereenie in May 2012, which consequently reduced AROs.
Exploration Expenses. Exploration expenses increased by $2.0 million to $8.3 million, or $79/boe, during the year ended June 30, 2013. The $2.0 million increase is the result of a $1.7 million increase at MPA and a $1.4 million increase at MPUK, offset by a $1.1 million decrease at NP. Of the $8.3 million of exploration expenses incurred during the current period, $2.3 million related to non-cash exploration write offs, which included $2.2 million related to the Markwells Wood-1 well in the UK. The remaining $6.0 million were incurred for general and seismic exploration costs, including $3.7 million incurred for seismic activities over NT/P82 in Australia and $1.5 million for general exploration in the UK, and $300 thousand related to analysis of the planned CO2-EOR pilot project at Poplar.
General and Administrative Expenses. The following table presents general and administrative expenses for the fiscal years ended:
 
June 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
General and administrative (excluding stock based compensation and foreign transaction loss)
$
10,963

 
$
12,006

 
$
(1,043
)
 
(9
)%
Stock based compensation
848

 
1,560

 
(712
)
 
(46
)%
Foreign transaction loss (gain)
18

 
(475
)
 
493

 
(104
)%
Total
$
11,829

 
$
13,091

 
$
(1,262
)
 
(10
)%
General and administrative expenses decreased by $1.3 million to $11.8 million, during the year ended June 30, 2013. General and administrative expenses, excluding stock based compensation and foreign transaction losses and gains, amounted to $11.0 million, a decrease of $1.0 million. This decrease primarily resulted from a $2.2 million reduction in the use of third party accounting and legal services. These decreases in expenditures were offset by a $1.0 million increase in salaries and benefits which was primarily due to a $0.8 million expense for severance costs, and a $0.2 million increase in office administrative costs. Stock based compensation decreased to $0.8 million, largely due certain stock options granted in prior years vesting fully during the year ended June 30, 2013. Following the completion of the Santos SA in May 2012, Foreign transaction loss (gain) is expected to be minimal in the future.

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 proved reserves have been discovered. 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 when initially incurred. 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.
Oil and Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and the assessment of impairment. As a result, adjustments to depletion and evaluation of 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 the Financial Accounting Standards Board (the "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

48

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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.
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 with a high level of precision 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 quarterly, 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 16) 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 costs to satisfy plugging and abandonment and other obligations, future advances in technology, timing of settlements, the credit-adjusted risk-free rate, 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 is used to value time based and performance based awards that do not contain performance or market conditions which impact the valuation of the award. This 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 over the performance period 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, 2013, there were no performance based options outstanding.


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Income Taxes