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EX-99.2 - EXHIBIT 99.2 - TELLURIAN INC. /DE/e99-2risktellurian_16.htm
EX-32.1 - EXHIBIT 32.1 - TELLURIAN INC. /DE/e32-1sec906ceo_16.htm
EX-31.1 - EXHIBIT 31.1 - TELLURIAN INC. /DE/e31-1sec302ceo_16.htm
EX-23.2 - EXHIBIT 23.2 - TELLURIAN INC. /DE/e23-2consentac_16.htm
EX-23.1 - EXHIBIT 23.1 - TELLURIAN INC. /DE/e23-1consenteksh_16.htm
EX-21.1 - EXHIBIT 21.1 - TELLURIAN INC. /DE/e21-1subsidiaries_16.htm


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, 2016,
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
mpetblue-2016a01.jpg
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, Colorado
 
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 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 $0.55 closing price per share of the registrant's common stock as reported by the NASDAQ Capital Market, as of December 31, 2015 (the last business day of the most recently completed second fiscal quarter) was $2,857,981. 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.
As of September 9, 2016, the registrant had 5,879,610 shares of common stock outstanding, which is net of 1,209,389 treasury shares held by the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement related to the 2016 annual meeting of stockholders to be filed within 120 days after June 30, 2016, 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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PART I

ITEMS 1 AND 2: BUSINESS AND PROPERTIES


OVERVIEW OF THE COMPANY
Magellan Petroleum Corporation (the "Company" or "Magellan" or "MPC" or "we") is an independent oil and gas exploration and production company. Subject to the closing of the announced merger with Tellurian Investments Inc. (“Tellurian”), Magellan will become a company focused on the development of liquefied natural gas (“LNG”) projects along the United States Gulf Coast. Historically active internationally, Magellan also owns interests in the Horse Hill-1 well and related licenses in the Weald Basin, onshore UK, and an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia.
The Company conducts its operations through two wholly owned subsidiaries corresponding to the geographical areas in which the Company operates: Magellan Petroleum (UK) Limited ("MPUK"), and Magellan Petroleum Australia Pty Ltd ("MPA"). Following the closing of the merger with Tellurian, which is expected in the fourth quarter of calendar year 2016, the combined company will operate its LNG business in the US through its new wholly owned subsidiary, Tellurian.
On July 10, 2015, the Company completed a one share-for-eight shares reverse stock split with respect to the Company's common stock. All amounts of shares of common stock, per share prices with respect to common stock, amounts of stock options to purchase common stock, respective exercise prices of each such option, and amounts of shares convertible upon conversion of the Series A convertible preferred stock for periods both prior and subsequent to the split have been adjusted in this report to reflect the reverse stock split.
As of June 30, 2016, our cash balance amounted to $1.7 million and the Company continues to experience liquidity constraints. We believe there is substantial doubt about the Company's ability to continue as a going concern. Because Tellurian's assets do not currently generate revenues, the combined company is also likely to experience liquidity constraints. However, we believe that upon the closing of the merger with Tellurian, the combined company will be better positioned to raise capital to fund the combined company's operations due to the attributes of Tellurian's business plan and management. Therefore, we believe that Magellan's ability to continue as a going concern in the short-term is subject to the closing of the merger with Tellurian. However, following the closing of the merger with Tellurian, the combined company may not be able to raise sufficient capital in a timely manner to fund the operations of the combined company. Should the merger with Tellurian not close, the Company will need to pursue other alternatives in order to continue as a going concern.
We were 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
We believe that Magellan’s sources of value are embedded in the Company’s portfolio of assets. Magellan’s strategy is therefore focused on recovering shareholder value by realizing the value of its existing assets.

STRATEGIC REPOSITIONING OF THE COMPANY
Over the past few years, Magellan was focused on the potential development of the Poplar field ("Poplar") in Montana using CO2-enhanced oil recovery ("CO2-EOR") as a technique to potentially recover significant volumes of hydrocarbons from the field. Over the second and third quarter of calendar year 2015, the Company reached the conclusion that using CO2-EOR at Poplar was a technical success but that it would be economically challenging to develop the project in the current commodity price environment, which was increasingly weakening over this period. As a result of these considerations, in June 2015, the Company formed a special committee of independent members of the Board of Directors of the Company (the "Special Committee") with the primary objective of reviewing the strategic alternatives potentially available to the Company. During the twelve month period ended June 30, 2016, and the third quarter of calendar year 2016, the strategic alternatives review process resulted in: (i) the disposal of the Company's Nautilus Poplar segment ("NP"), consisting of interests in Poplar and an option on CO2 produced from Farnham Dome, Utah, through the Exchange Agreement signed in March 2016 with One Stone Holdings II

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LP (“One Stone”); (ii) the sale of the Mereenie bonus (the "Mereenie Bonus") in May 2016; and (iii) the sale of the Weald Basin assets signed in June 2016. The strategic alternatives review process reached a conclusion with the announced merger transaction with Tellurian in August 2016.
Although the Company was able to extrapolate from the CO2-EOR pilot project that significant hydrocarbons may be recovered from Poplar using the CO2-EOR technique, we determined that the economic development of such project would require materially higher oil prices. Therefore, in light of the Company’s constrained liquidity position and continuing lower commodity price environment, we determined that Magellan was unlikely to have sufficient liquidity to finance this project and its other activities in the medium term until such time that commodity prices would recover to a level that would enable the necessary capital raising for the development of the project. The strategic alternatives review process also considered the possibility of focusing the Company’s business and strategy on certain of the Company’s other international assets. We estimated that although the prospects identified through the seismic surveys conducted in 2012 and 2013 over the NT/P82 block in the Bonaparte Basin, offshore Australia, were promising, these prospects remained at an early stage of the exploration process and required significant capital to be further assessed, which capital may become available through potential farmout or other transactions. Therefore, the Company’s interests in NT/P82 could not form the core business of the Company at this stage. With respect to the Company’s interests in the United Kingdom, the Company considered the following factors: i) the term of the main licenses in the central Weald Basin expiring in June 2016, ii) the pending litigation with Celtique Energie Weald Ltd (“Celtique”), which hampered our ability to strategically progress the potential play in the Weald, and iii) the challenging political and social environment in the United Kingdom, particularly evidenced by the rejection of the planning application of Cuadrilla Resources Limited’s proposed wells in Lancashire. Although the Horse Hill-1 well presents interesting prospects, these remained uncertain at the time of the review, and Magellan merely holds a 35% interest and is not the operator of the well, which combined with the prior factors undermined the potential to focus the Company’s business plan on its UK assets.
The Company then estimated that, in order to unlock the potential value of its assets and public platform and to preserve and maximize value for the Company's shareholders, the Company needed to (i) dispose of Poplar, which was incurring operating losses and further undermining the Company’s liquidity position, and (ii) to address its financial obligations primarily related to the term loan with West Texas State Bank (“WTSB”) and the Series A convertible preferred stock (the "Series A Preferred Stock") issued to One Stone. The Company engaged Petrie Partners, LLC ("Petrie") to support its strategic alternatives review process and conducted a thorough process which eventually resulted in the signing of the Exchange Agreement with One Stone on March 31, 2016. The Company closed the transactions contemplated by the Exchange Agreement on August 1, 2016, after the Company’s shareholders approved the transactions on July 13, 2016. Based on the findings of the marketing process of Poplar, the analysis prepared by our financial advisor and the implied valuation at which we disposed our interests in Poplar, which implied valuation was based on the disposal value of the preferred shares and the assumption of the WTSB term loan and Poplar’s outstanding accounts payables, we believe that the terms of this transaction were attractive to the Company’s shareholders. As a result of the closing of the One Stone exchange, the Company essentially became debt-free, since the term loan with WTSB was assumed by One Stone as part of the transaction, and the Company redeemed and canceled all the outstanding preferred shares which had been previously issued.
The Company then executed in May 2016, the sale to Macquarie Bank of certain bonus rights related to the Mereenie field in Australia, which rights were contingent on certain gas sales volumes from the Mereenie field, the proceeds of which sale provided the Company with the necessary funding required to complete its strategic alternatives review process, which concluded with the signing of the merger agreement with Tellurian. Also critical to the ability to attract potential merger candidates was the ability to resolve the pending litigation with Celtique, in order to create a vehicle with some cash, no debt, no litigation, and certain assets. In June 2016, the Company entered into several contemporaneous agreements, resulting in the sale of the combined interests of Celtique and Magellan in the Weald Basin to UK Oil and Gas Investments PLC (“UKOG”) in primarily Petroleum Exploration and Development License ("PEDL") 234, where the potential Broadford Bridge well is located, and the settlement of the litigation with Celtique. Following these transactions, the Company continues to own i) its 35% interests in the Horse Hill-1 well and related licenses, which interests are fully carried by Horse Hill Development Limited through the completion of its flow tests, ii) its 100% interest in the NT/P82 permit, the term of which permit was extended until November 2017, and iii) its shares of Central Petroleum Limited (“Central”).
The execution of these various transactions enabled the Company to conduct an efficient marketing process to seek a potential business combination partner, which process was particularly active in the second quarter of calendar year 2016, following the announcement of the Exchange Agreement with One Stone. The Company engaged in discussions with several quality potential partners and eventually agreed to the terms of a merger with Tellurian on August 2, 2016, which merger remains subject to certain customary conditions and the approval of the Company’s shareholders. Based on the thorough process it conducted, its analysis of the terms of the merger with its financial advisor and other factors, the Company believes i) the ownership by Magellan’s shareholders of the combined company reflects appropriately the value of the Company’s remaining assets and of its public vehicle and ii) provides the Company’s shareholders a unique opportunity to participate in a business model of large scale under the leadership of a seasoned management team, which has a proven track record of

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delivering significant shareholder value. Upon the closing of the merger with Tellurian, which is expected in the fourth quarter of calendar year 2016, Magellan will enter a new chapter of its long history as a public company.


SIGNIFICANT DEVELOPMENTS IN FISCAL YEAR 2016
During fiscal year 2016, the Company was very active in the execution of various transactions related to its strategic alternatives review process.
Corporate Events
Going Concern. As of the filing of the Company’s annual report on Form 10-K for the fiscal year ended June 30, 2015, the Company reported that it had continued to experience liquidity constraints and had begun selling certain of its non-core assets to fund its operations, and there was substantial doubt about the Company’s ability to continue as a going concern. As of the filing of this annual report on Form 10-K for the fiscal year ended June 30, 2016, the Company continues to experience liquidity constraints. The Company has completed the sale of certain of its assets to fund its operations, which has resulted in a significant reduction in the Company’s monthly cash burn rate. However, these liquidity constraints continue and proceeds from these asset sales may not provide sufficient liquidity to fund the Company's operations for the next twelve months. As a result of these conditions and events, there is substantial doubt about the Company's ability to continue as a going concern. Because Tellurian’s assets do not currently generate revenues, the combined company is also likely to experience liquidity constraints. However, we believe that upon the closing of the merger with Tellurian, the combined company will be better positioned to raise capital to fund the combined company's operations due to the attributes of Tellurian’s business plan and management. Therefore, we believe that Magellan’s ability to continue as a going concern in the short-term is subject to the closing of the merger with Tellurian, the primary condition of which closing is the approval by the Company’s shareholders of the merger agreement that is expected to be sought in the fourth quarter of calendar year 2016. However, following the closing of the merger with Tellurian, the combined company may not be able to raise sufficient capital in a timely manner to fund the operations of the combined company. Should the merger with Tellurian not close, the Company will need to pursue other alternatives in order to continue as a going concern.
Exchange Agreement. On March 31, 2016, Magellan and One Stone entered into an Exchange Agreement (the “Exchange Agreement”). The Exchange Agreement provides, upon the terms and subject to the conditions set forth in the Exchange Agreement, for the transfer by One Stone to the Company of 100% of the outstanding shares of Magellan Series A Preferred Stock in consideration for the assignment to and assumption by One Stone of 100% of the outstanding membership interests in Nautilus Poplar LLC, and 51% of the outstanding common units in Utah CO2 LLC (“Utah CO2,” and together with Nautilus Poplar LLC, the "NP segment", and, the "CO2 Business"), as adjusted by the Cash Amount (as defined in the Exchange Agreement and discussed further below) (the “Exchange”). The Exchange Agreement was given economic effect as of September 30, 2015 (the “Effective Date”).
Pursuant to the Exchange Agreement, on April 15, 2016, Magellan and One Stone i) entered into a Secured Promissory Note (the “Note”), pursuant to which One Stone made a loan to Magellan in the aggregate amount of $625 thousand (the “Loan Amount”) and ii) simultaneously entered into a Pledge Agreement, pursuant to which Magellan pledged, assigned, and granted to One Stone a security interest in the Company’s interests in MPA, as collateral for the loan. The purpose of the Note was primarily to fund the payment of outstanding payables with certain vendors of the CO2 Business to maintain its ongoing operations between signing of the Exchange Agreement and closing of the Exchange. At the closing of the Exchange, the Loan Amount was deemed to be paid in full and no further amounts under the Note are required to be repaid by the Company.
On August 1, 2016, all the conditions to the closing of the Exchange were met and the Exchange was consummated. The primary conditions to closing included i) the receipt of the approval of the Exchange by the Company’s shareholders, which was received on July 13, 2016, during the Company’s annual and special meeting of the shareholders, ii) the consent of WTSB to release a guaranty provided by Magellan, and iii) the payment of the Cash Amount. On August 1, 2016, One Stone paid the Cash Amount to the Company, which was agreed to amount to $900 thousand. The purpose of the Cash Amount was primarily to reimburse the Company for the funding of the operations of the Poplar field during the period between September 30, 2015, and the closing of the Exchange, which operations were expected to result in a loss in the aggregate for the period. In addition, Messrs. Gluzman and Israel, One Stone’s representatives on the Company’s Board of Directors, agreed to forgo the amount of director compensation, in cash and stock, owed to them and outstanding as of the closing date, which was estimated at approximately $174 thousand in the aggregate. Following the closing of the Exchange, the Company canceled all issued and outstanding shares of the Series A Preferred Stock, and Messrs. Gluzman and Israel ceased serving as members of the Board.
Mereenie Bonus Sale. On May 18, 2016, Magellan entered into and completed a Sale and Purchase Deed with Macquarie to sell to Macquarie all the Company's rights to certain bonus payments, which bonus payments are based upon sales of hydrocarbons from the Mereenie field located in the Amadeus Basin in Australia ranging from 2,500 boepd to 10,000

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boepd and may result in cumulative potential payments ranging from AUD $5.0 million to of AUD $17.5 million the Mereenie Bonus. The consideration for the sale of the Mereenie Bonus paid by Macquarie was AUD $3.5 million. The Mereenie Bonus was not previously recorded as an asset on the Company's consolidated balance sheet in light of the contingent nature of these payments.
Considering i) the general uncertainties related to the ability to increase sales of hydrocarbons from the Mereenie field to the required thresholds to trigger the various bonus payments and ii) the pressing liquidity needs facing the Company during the second quarter of calendar year 2016, the Company believed that the monetization of this contingent asset was important to enable the continuation of the strategic alternatives review process. The Company’s ability to repatriate the proceeds from the sale of the Mereenie Bonus to the US was constrained by the terms of the Pledge Agreement the Company entered into in conjunction with the Note with One Stone. Approximately AUD $2.8 million was transferred to the US in May 2016 and the remainder became available for transfer upon closing of the Exchange on August 1, 2016.
Central Weald Sale. On June 10, 2016, MPUK entered into i) an Asset Transfer Agreement relating to the sale to UKOG of MPUK's 50% interests in PEDLs 231, 234, and 243 (the "Weald ATA"), ii) an Asset Transfer Agreement relating to the sale to UKOG of MPUK's 22.5% interest in the Offshore Petroleum Licence P1916 (the "IoW ATA"), and iii) a Settlement Agreement with Celtique. The consideration payable by UKOG to MPUK for the Weald ATA amounted to GBP 1.8 million in a combination of cash and shares of UKOG, the number and value of which shares was determined as of the time of execution of the Weald ATA. The consideration for the IoW ATA was the assumption of MPUK's outstanding payables related to its interests in the Offshore Petroleum Licence P1916. Pursuant to the terms of the Settlement Agreement, MPUK was due to pay Celtique GBP 500 thousand of the gross consideration, in a combination of cash and shares in UKOG pro rata to the consideration payable to MPUK for the Weald ATA. On August 11, 2016, the transactions contemplated by the Weald ATA and IoW ATA closed and the Settlement Agreement became effective, resulting in net cash proceeds to Magellan of GBP 446 thousand and the net issuance to Magellan of approximately 50.9 million shares of UKOG, which shares were worth approximately GBP 703 thousand at the time of closing. The number of shares of UKOG issued to Magellan was determined at the signing of the agreements based on a price per share of GBP 1.58 pence, and as of September 9, 2016, the price per share of UKOG was GBP 1.88 pence.
Reverse Stock Split. On July 10, 2015, the Company filed an amendment to its certificate of incorporation to effect a one share-for-eight shares reverse stock split of its common stock, effective July 10, 2015. All share and per share amounts relating to the common stock, stock options to purchase common stock, including the respective exercise prices of each such option, and the amounts of shares convertible upon conversion of the Series A convertible preferred stock for periods both prior and subsequent to the split have been adjusted in this report to reflect the reverse stock split. Market conditions tied to stock price targets contained within market-based options were similarly adjusted. The par value and the number of authorized, but unissued, shares remain unchanged following the reverse stock split. No fractional shares were issued following the reverse stock split, and the Company has paid cash in lieu of any fractional shares resulting from the reverse stock split. The purpose of the split was to enable the Company to regain compliance with NASDAQ listing rules.
NASDAQ Listing Requirements. On November 5, 2015, Magellan received a letter from the Listing Qualifications Department of the NASDAQ Stock Market ("NASDAQ") indicating that, based upon the closing bid price of the Company's common stock for the last 30 consecutive business days, the common stock had not met the minimum bid price of $1.00 per share required for continued listing on the NASDAQ Capital Market pursuant to NASDAQ Marketplace Rule 5550(a)(2). On March 4, 2016, the Company received a letter from NASDAQ notifying the Company that, since the closing bid price of the common stock for the previous 10 consecutive business days was at least $1.00, the Company had regained compliance with NASDAQ Marketplace Rule 5550(a)(2).
On May 17, 2016, Magellan received a letter from the Listing Qualifications Department of the NASDAQ indicating that the Company’s stockholders’ equity as reported in the Company’s quarterly report on Form 10-Q for the period ended March 31, 2016 did not meet the minimum $2.5 million required for continued listing on the NASDAQ Capital Market pursuant to NASDAQ Stock Market Rule 5550(b)(1). On June 30, 2016, the Company submitted materials to NASDAQ describing a number of transactions that it believed would enable it to report stockholders’ equity of approximately $4.1 million on a pro forma basis, as of March 31, 2016, and that it was engaged in negotiations with a specific party to enter into a potential business combination transaction. On July 29, 2016, Magellan received a letter from the Listing Qualifications Department of NASDAQ indicating that it had determined to grant Magellan an extension until October 14, 2016, to regain compliance with Rule 5550(b). In the letter dated July 29, 2016, the Listing Qualifications Department indicated that any future business combination with a non-NASDAQ entity would likely be considered a “change of control” of Magellan, which would require the post-combination company to apply for initial listing on the NASDAQ Capital Market and meet all applicable initial listing criteria.
Poplar (Montana, USA)

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Shallow Intervals. During the twelve months ended June 30, 2016, Magellan sold 60 Mboe (164 boepd) of oil attributable to its net revenue interests in Poplar. This production came primarily from production from the Charles formation.
Deep Intervals. During the twelve months ended June 30, 2016, there was no production from the Deep Intervals at Poplar.
United Kingdom
Weald Basin Licenses. In the central Weald Basin, which consists of Magellan's 50% interests in PEDLs 231, 234, and 243, there was no substantial operational activity. These licenses were due to expire on June 30, 2016, and were subject to “drill or drop” conditions, which were not met in early 2016, and potential progress was further hampered by the pending litigation with Celtique. The Company monetized its interests in these licenses through the transactions contemplated by the Weald ATA that closed on August 11, 2016.
Horse Hill. In PEDLs 137 and 246, where the Horse Hill-1 well ("HH-1") was drilled, the Company holds a 35% interest in HH-1 and these licenses following a farmout agreement with Horse Hill Development, Ltd ("HHDL") dated as of December 20, 2013, pursuant to which agreement the Company’s costs in relation to these licenses are 100% carried by HHDL until production and including costs related to conducting certain flow tests. During the first quarter of calendar year 2016, HHDL conducted a successful flow test of several formations of HH-1 including the Portland sandstone and two Kimmeridge limestone formations. UKOG, one of the principal interest owners of HHDL, then reported that the flow tests measured a stable dry oil rate of 1,688 barrels of oil per day in aggregate from these formations. Although the duration of the flow tests of each formation was relatively short, we were very encouraged by these results. We believe that HHDL is in the process of seeking regulatory permissions to conduct a significant long-term production testing and appraisal program of the productive Kimmeridge limestones and Portland oil-bearing reservoirs.
Other UK Licenses. During fiscal year ended June 30, 2016, there was no substantial activity in P1916, located offshore southern UK, near the Isle of Wight, and the Company disposed of its 22.5% interest through the execution of the IoW ATA.
Australia
NT/P82. During fiscal year ended June 30, 2016, the Company continued its efforts to try to sell or farmout its 100% interest in the NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia, with the support of its financial advisor for this matter, RFC Ambrian. The Company was unsuccessful in sourcing attractive potential transactions, which we believe was due to i) the weak commodity price environment and material reduction in current export LNG prices in Australia, which are believed to have resulted in a significant reduction in exploration budgets of large companies operating in the area and ii) the short remaining term of the license, which was due to expire by May 12, 2016, unless the work requirements of the license had been met.
During the last two months of calendar year 2012, the Company successfully conducted a 2-D and 3-D seismic survey over portions of its NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia. During calendar year 2013, the seismic data underwent complete processing and interpretation and resulted in the identification of three prospects, including a potential conventional reservoir formed by a structural trap against a fault line and two potential stratigraphic plays identified based on amplitude variance versus offset analysis. The potential volume of gas present in these prospects could amount to several Tcf of gas but these prospects are considered to be at the very early stage of the exploration phase and may not result in an actual discovery.
In April 2016, the Company applied to the National Offshore Petroleum Titles Administrator (“NOPTA”) to i) increase the Year 6 minimum work requirement from 600 km2 of 3-D seismic survey to 1,000 km2 of new seismic data acquisition and processing, and geological and geophysical studies, ii) suspend Year 6 conditions of title for 18 months, and iii) extend the permit term by 18 months to allow the varied minimum work condition to be undertaken. On June 29, 2016, NOPTA informed the Company that the Commonwealth-Northern Territory Offshore Petroleum Joint Authority approved these variations and the term of the license is now due to end on November 12, 2017.
Central Petroleum Shares. As partial consideration for the sale of the Company’s onshore Australia assets in fiscal year 2014, the Company received approximately 39.5 million shares of Central, a small oil and gas company listed on the Australian Securities Exchange. Between July 2015, and February 2016, the Company sold on the open market shares of Central in order to help finance its activities during the strategic alternatives review process. The Company’s ownership of shares of Central was reduced from 39.5 million shares in July 2015 to 8.2 million in February 2016, and the volume-weighted average price realized for the sale of these shares, excluding brokerage fees, amounted to approximately AUD $0.11 per share.
Magellan does not consider its shareholdings in Central to be a core asset and will potentially dispose of part or all of this interest. Following the closing of the Exchange, the Company's ability to sell its shares of Central is not restricted. The timing of the Company’s decision to dispose of its interests will depend upon i) the actual price per share of Central, which we

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believe could increase in the medium term as Central achieves certain operational milestones and ii) the foreign exchange rate between the AUD and the USD.
Financial Performance
As a result of the transactions related to the strategic alternatives review process, the assets and operations of NP, Utah CO2, and the Weald Basin were reclassified to held for sale, and discontinued operations, respectively for all periods presented. Therefore the Company does not report revenues herein, and the results of continuing operations herein exclude the results of these discontinued operations.
Loss from continuing operations. For the fiscal year ended June 30, 2016, loss from continuing operations, including preferred stock dividends and an adjustment to redemption value of the preferred stock totaled $1.0 million ($0.17/basic share), compared to $23.3 million ($4.09/basic share) in the prior year. The decrease in loss from continuing operations was primarily the result of a decrease in realized losses on securities available-for-sale related to the Company's investment in Central, and a decrease in general and administrative expenses. The Company recorded other-than-temporary impairment of its investment in Central of $14.9 million in the prior fiscal year. The Company also recognized a gain in the current fiscal year of $2.5 million related to the sale of the Mereenie Bonus, a reduction in general and administrative costs of $2.4 million, and a downward adjustment to the redemption value of the preferred stock of $4.2 million. These reductions in loss from continuing operations were partially offset by a fair value reduction of contingent consideration payable of $1.9 million recorded in the prior fiscal year.
Cash. As of June 30, 2016, Magellan had $1.7 million in cash and cash equivalents, compared to $0.8 million at the end of the prior fiscal year. The increase of $0.9 million was the result of net cash used in operating activities of $2.2 million, net cash provided by investing activities of $5.1 million, net cash provided by financing activities of $0.4 million, net cash used in discontinued operations of $2.3 million and a decrease in cash from the effect of changes in exchange rates of $0.1 million, and represents the net effect of monetization of certain of the Company's assets over its operating expenses during the year, which operating expenses from continuing operations were primarily general and administrative expense. The net cash used in operating activities of $2.2 million was primarily due to general and administrative expenses, net of stock-based compensation expenses and foreign transaction losses of $4.3 million and an increase in accounts payable of $1.7 million. The $5.1 million of net cash provided by investing activities was primarily the result of proceeds from the sale of the Mereenie Bonus of $2.5 million and $2.6 million related to proceeds from the sale of shares of Central stock.
Securities available-for-sale. As of June 30, 2016, Magellan had $0.6 million in securities available for sale, consisting of the Company's investment in shares of Central stock.
Pro forma financial information. Due to the significance of certain transactions that have closed during the third quarter of calendar year 2016, including the transactions contemplated by the Exchange Agreement, the Weald ATA, the IoW ATA and the Settlement Agreement, we have presented in Note 21 - Pro Forma Financial Information (Unaudited) of the Notes to Consolidated Financial Statements included in this report pro forma financial information showing the effects of these transactions on our consolidated balance sheet as of June 30, 2016, and on our consolidated statements of operations for the years ended June 30, 2016, and June 30, 2015, as if they had been completed on June 30, 2016, with respect to balance sheet data, and as if they had become effective on July 1, 2014, with respect to statement of operations data for the years ended June 30, 2016 and 2015.
On a pro forma basis considering the effects of these transactions, as of June 30, 2016 our pro forma consolidated cash was $2.7 million, our pro forma consolidated total assets were $7.3 million, our pro forma consolidated total equity was $3.7 million, and for the year ended June 30, 2016, our pro forma consolidated loss from continuing operations was $3.2 million, compared to a pro forma consolidated net loss from continuing operations of $21.4 million for the year ended June 30, 2015. Please refer to Note 21 - Pro Forma Financial Information (Unaudited) of the Notes to Consolidated Financial Statements included in this report for more information.
Commodity prices. During the twelve months ended June 30, 2016, the Company's results continued to be impacted by the steep decline in global oil prices that began in late 2014. Oil and gas prices are believed to have stabilized at levels lower than those in the summer of 2014, when oil prices averaged around approximately $100/bbl compared to the current prices of approximately $40/bbl. The decline has had the effect of negatively impacting the perceived present value of the Company's prospects in Australia and the UK, compared to prior estimates. While commodity futures markets suggest that the price of oil will increase gradually, there is no certainty that such an increase will occur.

OUTLOOK FOR FISCAL YEAR 2017
Following the rationalization of the Company’s portfolio of assets during the fiscal year ended June 30, 2016, and assuming the closing of the merger with Tellurian during the fourth quarter of calendar year 2016, Magellan will become a

9


company primarily focused on the development of LNG projects in the US Gulf Coast. The HH-1 well and related licenses in the UK and the Company’s interests in NT/P82 will provide additional option value to the shareholders. NT/P82 may provide a more strategic fit with the combined company’s business considering the connection between NT/P82's large gas prospect and other LNG infrastructure in Northern Territory, Australia.
Corporate Events
Merger with Tellurian. On August 2, 2016, Magellan, Tellurian, and River Merger Sub, Inc., a Delaware corporation and a direct wholly owned subsidiary of Magellan (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”). Pursuant to the Merger Agreement, each outstanding share of common stock, par value $0.001 per share, of Tellurian will be exchanged for 1.300 shares of common stock, par value $0.01 per share, of Magellan, and Merger Sub will merge with and into Tellurian (the “Merger”), with Tellurian continuing as the surviving corporation and a direct wholly owned subsidiary of Magellan.
The Merger Agreement and the Merger have been approved by the board of directors of each of Magellan and Tellurian. Stockholders of Magellan will be asked to vote on the approval of the transactions contemplated by the Merger Agreement at a special meeting that is expected to be held during the fourth quarter of calendar year 2016. In addition to the approval of the foregoing matters by the stockholders, the closing of the Merger is subject to customary closing conditions, including i) the receipt of Magellan and Tellurian stockholder approval; ii) all directors and officers of Magellan shall have resigned, except for any person(s) that might be designated by Tellurian; iii) a registration statement on Form S-4 to register the Magellan shares to be issued in the Merger shall have been declared effective by the US Securities and Exchange Commission (the “SEC”); and iv) shares of Magellan common stock to be issued in the Merger shall have been approved for listing on the NASDAQ. The Merger Agreement also contains a non-solicitation provision pursuant to which Magellan may not, directly or indirectly, take certain actions to negotiate or otherwise facilitate an “Alternative Proposal,” a term generally defined as an inquiry, proposal or offer relating to a business combination with or acquisition of the assets of Magellan by a person or entity other than Tellurian. Magellan’s non-solicitation obligations are qualified by “fiduciary out” provisions which provide that Magellan may take certain otherwise prohibited actions with respect to an unsolicited Alternative Proposal if the Board of Directors determines that the failure to take such action would be reasonably likely to be inconsistent with its fiduciary duties and certain other requirements are satisfied. The Merger Agreement may be terminated under certain circumstances, including in specified circumstances in connection with receipt of a "Superior Proposal," as such term is defined in the Merger Agreement. In connection with the termination of the Merger Agreement in the event of a Superior Proposal, a breach by Magellan of the non-solicitation provision noted above, or following a change by the Board of Directors of its recommendation to stockholders, Magellan will be required to pay to Tellurian a termination fee for any and all third-party transaction fees and expenses incurred by Tellurian with the drafting, negotiation, execution and delivery of the Merger Agreement and related documents (including fees and expenses for attorneys, accountants and other advisors), subject to a maximum of $1 million in the aggregate. A termination fee may also be payable in some circumstances in which an Alternative Proposal is made, the transaction fails to close and Magellan subsequently agrees to an Alternative Proposal. If the Merger Agreement is terminated by either party as a result of the failure to obtain the requisite approval by Tellurian stockholders, or by Magellan because Tellurian does not use commercially reasonable efforts to secure the approval for listing the Magellan shares of common stock to be issued in the Merger, then Tellurian will be required to pay to Magellan a reverse termination fee of $1 million.
Upon the closing of the Merger with Tellurian, Magellan will become a Houston-based energy company focusing on the development of LNG export projects. Tellurian’s management team is led by Charif Souki and Martin Houston, who have led and/or founded several industry-leading companies, specifically in the LNG sector. Mr. Souki is the former founder, Chairman, and CEO of Cheniere Energy, Inc., which is expected to operate in excess of 30 million tonne per annum (“mtpa”) of LNG export facilities. Mr. Houston retired in November 2013, as chief operating officer of BG Group plc (“BG”), after 30 years of service, during which he pioneered the development and optimization of BG’s global LNG portfolio. Tellurian was formed in February 2016 to develop low-cost, mid-scale LNG projects on the US Gulf Coast. Bechtel Corporation, General Electric and Chart Industries, Inc. are Tellurian’s commercial partners to deliver LNG facilities with best-in-class development costs on a global basis. Tellurian is currently focused on the development of the Driftwood LNG project, a 26-mtpa LNG export facility in Calcasieu Parish, LA, where Tellurian owns or leases a site of approximately 800 acres with marine access for LNG tankers. As a result of the Merger, Tellurian will gain greater access to the capital markets to finance the development of the Driftwood LNG project.
Special Committee. On June 5, 2015, the Company’s Board of Directors formed the Special Committee to consider various strategic alternatives potentially available to the Company and engaged Petrie as financial advisor. Following the closing of the Exchange with One Stone and the subsequent announced Merger with Tellurian, we believe that the task of the Special Committee has substantially been completed. The Special Committee will continue until the closing of the Merger with Tellurian has been consummated.

10


Management Changes.With the execution of various transactions and the Merger Agreement with Tellurian, various changes to the management team of the Company are expected during fiscal year ending June 30, 2017. On and effective August 5, 2016, Mr. Wilson, the Company’s director, President, and Chief Executive Officer, tendered his resignation as a director and officer, and Mr. Lafargue assumed the additional officer responsibilities until the closing of the Merger. At the closing of the Merger, Tellurian’s management team is expected to assume most of the managerial positions of the Company, with Mr. Lafargue expected to continue as Chief Financial Officer of the combined company.
United Kingdom
Horse Hill. We believe that HHDL is in the process of seeking regulatory permissions to conduct a significant long-term production testing and appraisal program of the productive Kimmeridge Limestones and Portland oil-bearing reservoirs. Since the results of the HH-1 well have been very encouraging to date and the Company’s costs in relation to these licenses are 100% carried by HHDL, we are planning to await the results of the next flow test and appraisal program before making a decision about our long-term participation in these licenses. However, the Company will continue to consider potential transactions on an opportunistic basis in light of the Company’s overall strategy and business plan.
Australia
NT/P82, Offshore Australia. Over the upcoming several months, the Company intends to establish a plan and schedule for executing its seismic survey work commitment for NT/P82. Considering the current stabilization of commodity prices and the greater certainty provided by the revised terms of the license received on June 29, 2016, including the 18-month extension of the term of the license to November 12, 2017, we believe that a farmout agreement also remains possible for this asset. In addition, given the large potential gas prospects contained within this license and the development of several fields in the Bonaparte Basin through LNG facilities, we believe that the potential strategic fit of this asset with the combined company’s overall strategy and business activities upon the closing of the Merger with Tellurian has improved.
Palm Valley Bonus Rights. Under the terms of the Share Sale and Purchase Deed dated February 17, 2014, between Magellan Petroleum (N.T.) Pty Ltd , a wholly owned subsidiary of Magellan, and Central, the Company is entitled to receive 25% of the revenues generated at the Palm Valley gas field from gas sales when the volume-weighted gas price realized at Palm Valley exceeds AUD $5.00/Gigajoule and AUD $6.00/Gigajoule for the first 10 years following the closing date and for the following five years, respectively, with such prices to be escalated in accordance with the Australian consumer price index (the “Palm Valley Bonus”). For further information related to the Palm Valley Bonus, please refer to Note 5 - Sale of Amadeus Basin Assets. The value of the rights to these bonus payments is not reflected on the Company’s financial statements and the Company believes there is significant risk to the potential realization of these rights. During fiscal year 2017, the Company may seek to monetize these rights, as it did with respect to the Mereenie Bonus during fiscal year 2016. We believe that our ability to enter into a transaction with respect to the Palm Valley Bonus will depend on certain operational and commercial development in the Amadeus Basin, particularly the ability of Central to enter into new gas sales contract with potential new customers.

OPERATIONS
Magellan operates in the single industry segment of oil and gas exploration and production. As of June 30, 2016, we have two reportable geographic segments, MPUK and MPA, corresponding to our operations in the UK and Australia, respectively, and maintain a corporate office in the United States which provides oversight for these segments and is treated as a cost center. MPUK's oil and gas assets consist of various exploration licenses in or adjacent to the Weald Basin located onshore and offshore southern England. MPA's oil and gas assets consist of NT/P82, an exploration block in the Bonaparte Basin, offshore Australia, and a 1.9% ownership interest in Central as of September 9, 2016.
As of March 31, 2016, NP, which formerly included the Company's operations in the United States, primarily in the Williston Basin, has been reclassified to discontinued operations and the carrying value of its assets have been included in assets held for sale for all periods presented. As of June 30, 2016, the Company's operations related to the central Weald licenses and the peripheral Weald license have also been reclassified to discontinued operations and the carrying value of the related assets have been included in assets held for sale for all periods presented. Following the closing of the One Stone Exchange on August 1, 2016 and the Weald ATA and IoW ATA and related transactions on August 11, 2016, which resulted in the sale of the Company's interests in the Poplar field in the US and of PEDLs 231, 234, 243, and P1916 in the UK, respectively, the Company does not conduct any operations in the US and its operations in the UK are limited to the Horse Hill-1 well and related licenses, which consist of PEDLs 137 and 246. 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 15 - Segment Information to the consolidated financial statements included in Part II, Item 8: Financial Statements and Supplementary Data of this report.

11



Magellan's Areas of Operations
operations2016a01.jpg
United States - Poplar
In the US, as of June 30, 2016, Magellan owned Poplar, an oil field located in Roosevelt County, Montana. Our acreage position covered substantially all of Poplar Dome, the largest geologic structure in the western Williston Basin with multiple stacked formations with hydrocarbon resource potential. However, following the closing of the Exchange on August 1, 2016, the Company has disposed of all of its interests in Poplar.
The field was discovered in the 1950s by Murphy Oil, which 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. The Charles formation at Poplar is highly prospective for development using the tertiary technique of CO2-EOR. The Company's primary focus at Poplar was the evaluation of the effectiveness of this technique through a CO2-EOR pilot.
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 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 acres.
Our interests within EPU (also referred to herein as "Poplar") included 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.
United Kingdom
As of June 30, 2016, Magellan's UK position consisted of interests in six exploration permits located in or adjacent to the Weald Basin, which is geographically situated southwest of London and which contains multiple conventional and potential unconventional oil and gas prospects. In the central Weald Basin, Magellan co-owned equally with Celtique three licenses (PEDLs 231, 234, and 243), representing 124 thousand net acres, that are prospective for unconventional oil and gas development from the Kimmeridge Clay and Liassic formations and may be prospective for conventional development in other formations. Celtique operated these licenses. On the periphery of the Weald Basin, Magellan maintained non-operated interests in three additional exploration licenses, representing an additional 15 thousand net acres, that may be prospective for conventional oil and gas targets. However, following the closing of the Weald ATA and the IoW ATA, the Company has disposed of its interests in PEDLs 231, 234, 243, and P1916.

12


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, following processing and interpretation during fiscal years 2013 and 2014, is currently developing plans to meet its revised seismic work requirements, which may include obtaining a suitable farmout partner to meet the revised work requirements in exchange for a portion of the Company's working interest in the permit. Based on the results of the 3-D and 2-D seismic surveys, the Company identified three potential prospects, including a potential reservoir in a structural trap against a fault line and a large amplitude-variation-with-offset anomaly. The Company is conducting a process to obtain a partner to evaluate these prospects further and engaged a financial advisor, RFC Ambrian to assist its efforts.
Central. Magellan is the owner of approximately 8.2 million shares of stock in Central, representing an approximate 1.9% ownership interest as of September 9, 2016. Central is a Brisbane-based junior exploration and production company that operates one of the largest holdings of prospective onshore acreage in Australia. Magellan received its shares in Central on March 31, 2014, as part of the consideration paid by Central to acquire Magellan's interests in the Palm Valley and Dingo gas fields. Following the closing of the Exchange with One Stone on August 1, 2016, the Company's ownership of these shares is not subject to any trading restrictions imposed by Central. In the future, Magellan may decide to dispose of all or part of its position in Central stock to fund some of the Company's activities. Although the Company does not intend to hold its position in Central's stock in the long term, the Company believes that there could be certain commercial or operational developments related to Central’s assets, which could positively impact the price per share of Central in the medium term. Therefore, the Company intends to monitor the stock price performance of Central to determine the appropriate time to dispose of its position. Further information about Central can be found on Central's website at www.centralpetroleum.com.au, which is not incorporated by reference into this report and should not be considered part of this document.

RESERVES
All reserves are related to the proved oil and gas properties of Poplar, which pursuant to the Exchange Agreement entered into on March 31, 2016, are included in assets held for sale at June 30, 2016. As a result of the closing of the Exchange on August 1, 2016, all reserves reported below were disposed of as of that date.
Estimates of reserves are inherently imprecise and continually subject to revision based on production history, results of additional exploration and development, price changes, the availability of financing and other factors. The following table presents a summary of our proved reserves as of June 30, 2016.
 
Oil
(Mbbls)
United States Reserves:
 
Proved developed producing ("PDP")
792

Proved developed not producing ("PDNP")
103

Proved undeveloped ("PUD")

Total reserves
895

 


PDP%
88
%
PDNP%
12
%
PUD%
%
 
 

13


Proved Undeveloped Reserves
The Company has not included PUD reserves in its total proved reserve estimates at June 30, 2016 or June 30, 2015 due to the uncertainty regarding its ability to continue as a going concern, the availability of capital that would be required to develop the PUD reserves, and its strategic plans to dispose and subsequent disposal of its interests in Poplar.
Probable Reserves
Consistent with our position regarding PUD reserves, due to the uncertainty of the Company's ability to continue as a going concern, the constrained availability of financing to develop the probable reserves, and its strategic plans to dispose and subsequent disposal of its interests in Poplar, the Company is not reporting probable reserves.
Internal Controls Over Reserve Estimates
Our internal controls over the recording of proved and probable reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with regulations established by the SEC. Historically, the Company relied upon a combination of internal technical staff and third party consulting arrangements for reserve estimation and review. Considering the disposal of the assets which contained the Company's proved reserves, the Company elected to solely rely on its internal resources to estimate its reserves as of June 30, 2016.
Reserve estimates as of June 30, 2016 were prepared by Guot Anyak, who was employed by the Company as a Petroleum Engineer from August 2012 until August 1, 2016. Mr. Anyak is a graduate of the Colorado School of Mines and holds a Bachelor of Science degree in Petroleum Engineering.  Mr. Anyak has been instrumental in the analysis of the economics of certain well workovers at Poplar, and has supported the preparation of the Company’s reserve estimates over the past several years. Reserve estimates as of June 30, 2015, were prepared by Hector Wills of Mi3 Petroleum Engineering ("Mi3"), a Golden, Colorado-based petroleum engineering firm that regularly performs petroleum engineering services for the Company with respect to Poplar. Mr. Wills has nearly 20 years of operation and technical engineering experience in the oil and gas industry. Prior to his time with Mi3, he served as a reservoir engineer at Stim-Lab, Inc., and prior to that as a drilling engineer at PDVSA Petroleos de Venezuela S.A. Mr. Wills holds a PhD in Petroleum Engineering from the Colorado School of Mines. The reserve estimates as of June 30, 2015 were audited by the Company's independent petroleum engineering firm, Allen & Crouch Petroleum Engineers ("A&C"). See "Third Party Reserve Audit" below. In addition, the preparation of the reserve estimates for both periods was subject to the oversight of our management and a summary review by the Audit Committee of our Board of Directors.
Third Party Reserve Audit
In light of the pending disposal at June 30, 2016 of the Company's interests in the assets that contain all of the Company's estimated reserves, and their subsequent disposal on August 1, 2016 upon closing of the One Stone Exchange, the Company did not engage an independent petroleum engineering firm to audit its estimates of reserves at June 30, 2016.
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 22 - Supplemental Oil and Gas Information (Unaudited)) to the consolidated financial statements included in Part II, Item 8 to this Form 10-K.

14



VOLUMES AND REALIZED PRICES
The following table summarizes volumes and prices realized from the sale of oil from properties in which we owned an interest during the periods presented. The table also summarizes operational costs per barrel of oil equivalent for the fiscal years ended:
 
June 30,
 
2016
 
2015
United States:
 
 
 
Volumes (Mbbls)
60

 
79

Average realized prices ($/bbl)
$33.17
 
$56.44
Lease operating expenses ($/bbl)
$42.67
 
$64.42
Sales volume for the year ended June 30, 2016, totaled 60 Mbbls (164 bopd), compared to 79 Mbbls (217 bopd) sold in the prior year, a decrease of 24%. The decrease was primarily the result of certain cost reduction measures at Poplar including shutting-in wells with high operating costs, the suspension of workovers, and the natural production decline of the field. The average realized price at the Poplar field decreased to $33.17/bbl from $56.44/bbl in the prior year. The decrease was primarily the result of a decline in the benchmark crude oil price, West Texas Intermediate (WTI). The average WTI price declined 39% from the prior fiscal year, which was partially offset by a 29% improvement in the differential from the previous fiscal year. The Company does not currently engage in any oil and gas hedging activities. Lease operating expenses decreased to $42.67/bbl from $64.42/bbl in the prior year. The decrease is primarily related to lower production taxes, which are due to lower revenues as a result of lower commodity prices and reduced workover activity and maintenance on wells.

PRODUCTIVE WELLS
Productive wells include producing wells and wells mechanically capable of production. The following table presents a summary of our productive wells, all of which were located in the United States at the Poplar field as of June 30, 2016:
 
Productive Wells
United States:
 
Gross oil wells (1)
24.0

Net oil wells (2)
21.0

(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 fiscal years ended:
 
June 30,
 
2016
 
2015
 
Productive (2)
 
Dry (3)
 
Productive (2)
 
Dry (3)
United States:
 
 
 
 
 
 
 
Development wells, net (1)

 

 

 

Exploratory wells, net (1)

 

 

 

Total net wells

 

 

 

(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.

15


As of August 1, 2016, two gross wells(1) (two net wells(2)) related to the CO2-EOR pilot that were included in wells-in-process as of June 30, 2016 were still in the process of being evaluated. These wells were subsequently disposed through the closing of the Exchange on August 1, 2016.

(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.

ACREAGE
The following table summarizes gross and net developed and undeveloped acreage by geographic area at June 30, 2016, which has not been adjusted for the impact of the Exchange and the Weald ATA and IoW ATA.
 
Developed (1)
 
Undeveloped (4)
 
Total
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
United States (Poplar)
22,913

 
22,669

 

 

 
22,913

 
22,669

United Kingdom
80

 
28

 
293,749

 
138,420

 
293,829

 
138,448

Australia (NT/P82)

 

 
1,566,647

 
1,566,647

 
1,566,647

 
1,566,647

Total
22,993

 
22,697

 
1,860,396

 
1,705,067

 
1,883,389

 
1,727,764

(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. As of June 30, 2016, Poplar contained 24 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. Upon the closing of the One Stone Exchange on August 1, 2016, Magellan has no further working interests in the US.
United Kingdom
In the UK, the petroleum licensing regime is administered by the UK Department of Energy and Climate Change ("DECC") and the Oil and Gas Authority ("OGA"), and PEDLs and Seaward Production Licenses (denoted by a "P") issued by the DECC are subject to the UK Petroleum Act of 1998. A licensee has the exclusive right to produce, explore, and develop petroleum from the land, subject to the payment of rental to the DECC. The maximum term of the license is 31 years. Licenses expire after the initial exploration term of six years if a well is not drilled and after a second exploration term of five years if a well is drilled but no development program is approved by the DECC. If a development program is approved by the DECC, a PEDL will convert into a production license with a term of approximately 20 years. The licensing regime also requires that 50% of the acreage of a PEDL be relinquished at the end of the initial exploration period. This 50% relinquishment is expected to be applicable to Magellan's licenses upon their respective initial expiration dates.
Following the signing of the Weald ATA, which closed on August 11, 2016, the Company and Celtique engaged in discussions with the OGA and UKOG to enable certain amendments to the terms of PEDLs 231, 234, and 243, while the closing of this transaction was pending. As a result of these discussions, Magellan and Celtique relinquished their interests in PEDLs 231 and 243 as of June 30, 2016, and received an extension of the term of PEDL 234, subject to certain work commitments, which became the responsibility of UKOG upon the closing of the Weald ATA on August 11, 2016. Refer to

16


Note 3 - Sale of Weald Basin Assets of the Notes to Consolidated Financial Statements included in this report for further information.
With respect to PEDLs 137 and 246, the Company and its partners negotiated with the OGA amendments to the terms of the licenses, which resulted in the extension of i) the second exploration term of PEDL 137 to September 30, 2016, and ii) the initial exploration term and the second exploration term of PEDL 246 to June 30, 2016, and June 30, 2019, respectively. Following the successful results of the flow test of HH-1, the OGA and the Secretary of State approved the creation of retention areas covering the entire geographic are of these licenses, new work plans for each of these licenses, and extended the terms of PEDL 137 and 246 to June 30, 2018 and 2017, respectively.
Pursuant to the Weald ATA, the Company disposed of its interests in PEDLs 231, 234, and 243, and pursuant to the IoW ATA, the Company disposed of its interests in P1916. Refer to Note 3 - Sale of Weald Basin Assets of the Notes to Consolidated Financial Statements included in this report for further information.
The following table summarizes the permits we maintain in the UK as of June 30, 2016.
License
 
Geologic basin
 
Expiration date
 
Operator
 
Ownership interest
 
Gross
acres (1)
 
Net
acres (2)
Central Weald licenses (3):
PEDL 231
 
Weald
 
6/30/2016
 
Celtique (4)
 
50%
 
98,800

 
49,400

PEDL 234
 
Weald
 
6/30/2017
 
Celtique (4)
 
50%
 
74,100

 
37,050

PEDL 243
 
Weald
 
6/30/2016
 
Celtique (4)
 
50%
 
74,100

 
37,050

Subtotal
 
 
 
 
 
 
 
 
 
247,000

 
123,500

 
 
 
 
 
 
 
 
 
 

 

Licenses containing Horse Hill-1:
PEDL 137
 
Weald
 
6/30/2018
 
HHDL
 
35%
 
24,525

 
8,584

PEDL 246
 
Weald
 
6/30/2017
 
HHDL
 
35%
 
10,769

 
3,769

Subtotal
 
 
 
 
 
 
 
 
 
35,294

 
12,353

 
 
 
 
 
 
 
 
 
 
 
 
 
Other licenses on periphery of Weald Basin (5):
P1916
 
Wessex
 
1/31/2017
 
UKOG
 
22.5%
 
11,535

 
2,595

 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
293,829

 
138,448

(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 the registrant in gross acres.
(3) The Company's interests in the Central Weald licenses have been classified as held for sale as of June 30, 2016, and for all prior periods presented, and the results of its operations have been classified as discontinued operations for the year ended June 30, 2016, and for all prior periods presented. On June 10, 2016, the Company entered into the Weald ATA to transfer its interests in these licenses to UKOG, with an effective date of March 31, 2016. The transactions contemplated by the Weald ATA closed on August 11, 2016, at which time all conditions to completion had been met. See Note 3 - Sale of Weald Basin Assets of the Notes to Consolidated Financial Statements included in this report for further information.
(4) See Note 16 - Commitments and Contingencies - Celtique Litigation, of the Notes to Consolidated Financial Statements included in this report for information regarding settlement of the legal proceeding initiated by Celtique with respect to this license.
(5) The Company's interest in the peripheral Weald license has been classified as held for sale as of June 30, 2016, and for all prior periods presented, and the results of its operations have been classified as discontinued operations for the year ended June 30, 2016, and for all prior periods presented. On June 10, 2016, the Company entered into the IoW ATA to transfer its interests in this license to UKOG, with an effective date of completion, which was on August 11, 2016, at which time all conditions to completion had been met. See Note 3 - Sale of Weald Basin Assets of the Notes to Consolidated Financial Statements included in this report for further information.
Australia
In Australia, Magellan’s offshore exploration license, NT/P82, is issued jointly by the Commonwealth and Northern Territory Governments and is subject to the Offshore Petroleum and Greenhouse Gas Storage Act. The licensee has the exclusive right to explore for petroleum in the license area, subject to fulfillment of a pre-agreed work program. The term of a petroleum license is six years, and a license may be renewed for an additional term of five years. On June 29, 2016, the NOPTA informed the Company that the Commonwealth-Northern Territory Offshore Petroleum Joint Authority approved certain variations to the term of the Company's NT/P82 permit, which under the revised terms of the variation is now due to expire on November 12, 2017.

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The following table summarizes the permit we maintain in Australia as of June 30, 2016.
License
 
Geologic basin
 
Expiration date
 
Operator
 
Ownership interest
 
Gross
acres (1)
 
Net
acres (2)
NT/P82
 
Bonaparte
 
11/12/2017
 
Magellan
 
100%
 
1,566,647

 
1,566,647

Total
 
 
 
 
 
 
 
 
 
1,566,647

 
1,566,647

(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 the registrant in gross acres.

MARKETING ACTIVITIES AND CUSTOMERS
Customers
The Company's consolidated oil production revenue, which is included in discontinued operations, is derived from its former NP segment and was generated from two customers for the years ended June 30, 2016, and 2015.
Delivery Commitments
None of our production sales agreements contain terms and conditions requiring us to deliver a fixed determinable quantity of product.

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. In general, the Company's working capital balances are not materially impacted by seasonal factors.
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 which have (i) greater technical, operational, and financial resources, or (ii) 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 position 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 and management's technical and operational expertise 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, 2016, the Company had a total of 13 full-time employees, including 6 employees in the field at Poplar. We maintain approximately 6,000 square feet of functional office space in Denver, Colorado for our executive and administrative headquarters.

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.

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The laws and regulations discussed below applied to our business as it was constituted through the fiscal year ended June 30, 2016. As previously disclosed, on August 1, 2016, we completed the sale of Nautilus Poplar LLC and our interest in Utah CO2 LLC (together, the “CO2 Business”).
US 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 (i) require 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") or lands under the jurisdiction of federally recognized Indian tribes pursuant to oil and gas leases administered by such tribes and 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, federal and Indian lease 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. In March 2015, the BLM adopted changes to its oil and gas regulations to impose new regulations on the practice of hydraulic fracturing. That rule has been stayed by a federal district court of Wyoming, but is on appeal to the Tenth Circuit Court of Appeals. The rule, if eventually upheld, will increase the costs of production using hydraulic fracturing methods. The BLM has amended, or is considering amending, Onshore Order Nos. 1, 3, 4 and 5 relating to measurement of oil and gas, site security and general oil and gas operations on federal and Indian lands, along with how natural gas production is reported for royalty purposes. In January 2016, the BLM issued a proposed rule which seeks to reduce methane emissions from oil and gas activities on federal lands by limiting venting and flaring of natural gas from wells and other equipment. The proposal also clarifies when operators owe royalties on flared gas, and would provide the agency greater flexibility to set royalty rates at or above 12.5% of the value of production.
The Environmental Protection Agency (the “EPA”) is increasing its regulation of venting, flaring and other emissions from oil and gas exploration and production. Permitting for oil and gas activities on federal lands can take significantly longer than the state permitting process. It is likely that the trend toward more federal regulation will continue, which will continue to raise costs.
The sale of natural gas in the US is 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 sales prices for natural gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the US Congress may not continue indefinitely.
Environmental, Health, and Safety Matters
General. The operations of the CO2 Business 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, rules, 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

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and plug abandoned wells.
These laws, rules, and regulations may also restrict the ability to produce oil or gas to 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 operating costs.
The following is a summary of some of the existing laws, rules, and regulations to which the CO2 Business is subject:
Waste handling. The Resource Conservation and Recovery Act ("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 EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in costs to manage and dispose of wastes.
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 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 contributing to warming of the earth's atmosphere and other climatic changes. Based on this determination, the EPA has been 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

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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 and more intensive storms and flooding, and could adversely affect the demand for oil and natural gas.
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 ("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 of 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 past exploration and production activities on federal and Indian lands require governmental permits that are subject to the requirements of NEPA.
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, we may do so in the future. The hydraulic fracturing 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 an Office of Unconventional Gas and Oil has been established to coordinate the related activities of various regulatory authorities. However, the EPA has 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. Recently, the BLM issued changes to its oil and gas regulations to impose new regulations on the practice of hydraulic fracturing. That rule has been stayed by a federal district court in Wyoming, but is on appeal to the Tenth Circuit Court of Appeals. The rule, if eventually upheld, will increase the costs of production using hydraulic fracturing methods.
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 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. In addition, local planning permission requirements in the UK may have the effect of restricting or delaying hydraulic fracturing activities. The UK Infrastructure Act 2015 seeks to include safeguards around hydraulic fracturing, and draft regulations issued in the UK in July 2015, are intended to define protected areas in which hydraulic fracturing will be prohibited. If new laws, rules, regulations, or other requirements that significantly restrict hydraulic fracturing are adopted, such requirements could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes more strictly regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, or becomes subject to regulatory restrictions at the local level, 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 any reserves.
Other initiatives. Public and regulatory scrutiny of the energy industry has resulted in increased environmental

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regulation and enforcement initiatives being either proposed or implemented. For example, the EPA's 2014 - 2016 National Enforcement Initiatives include "Assuring Energy Extraction Sector Compliance with Environmental Laws." According to the EPA's website, "some techniques for natural gas extraction pose a significant risk to public health and the environment." To address these concerns, the EPA's goal is to "address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment." The EPA has emphasized that this initiative will be focused on those areas of the US where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve an investigation of our facilities and processes, and could lead to potential enforcement actions, penalties, or injunctive relief against us. In addition, in August 2015, the EPA released proposed regulations that would set performance standards for emissions of methane and volatile organic compounds from new and modified sources in the upstream and midstream oil and gas sectors.
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.
Regulations Applicable to Foreign Operations
Several of the properties and investments 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 or investments. 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 or investments. 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.
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.
Our Australian investments and prospects 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 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, investment values, 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.

AVAILABLE INFORMATION
Our internet website address is www.magellanpetroleum.com. We routinely post important information for investors on

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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.
In addition, investors may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549, on official business days during the hours of 10:00 a.m. to 3:00 p.m. Investors may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information we file electronically with the SEC at www.sec.gov.



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.
RISKS RELATING TO TELLURIAN’S BUSINESS, THE MERGER, AND THE COMBINED COMPANY FOLLOWING THE MERGER
Magellan’s business is and will be subject to risks relating to Tellurian’s business, the proposed merger with Tellurian, and the combined business following the merger. For a description of these risks, see the risk factors set forth in Exhibit 99.2 to this report, which risk factors are incorporated by reference into this report and will be included in the joint proxy statement/prospectus that will form part of a registration statement on Form S-4 to be filed with the SEC shortly after the filing of this report, as such risk factors may be updated or supplemented in Magellan’s subsequently filed quarterly reports on Form 10-Q or current reports on Form 8-K.

RISKS RELATING TO OUR BUSINESS
There is substantial doubt about our ability to continue as a going concern.
The Company has incurred losses from operations for the year ended June 30, 2016, of $5.3 million, and as of June 30, 2016, its cash balance was $1.7 million. The Company continues to experience liquidity constraints and since July 2015, has been selling certain of its assets to fund its operations, which has resulted in a significant reduction in the Company’s monthly cash burn rate. However, these liquidity constraints continue and proceeds from these asset sales may not provide sufficient liquidity to fund the Company's operations for the next twelve months. As a result of these conditions and events, there is substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements included in this report do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.
We believe that upon the closing of the merger with Tellurian, the combined company will be better positioned to raise capital to fund the combined company's operations due to the attributes of Tellurian's business plan and management. Therefore, we believe that Magellan's ability to continue as a going concern in the short-term is subject to the closing of the merger with Tellurian, the primary condition of which closing is the approval by the Company’s shareholders of the merger agreement that is expected to be sought in the fourth quarter of calendar year 2016. However, following the closing of the merger with Tellurian, the combined company may not be able to raise sufficient capital in a timely manner to fund the operations of the combined company. Should the merger with Tellurian not close, the Company will need to pursue other alternatives in order to continue as a going concern.
Our current liquidity position is very constrained.

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As of June 30, 2016, we had $1.7 million in cash and cash equivalents. The increase in cash and cash equivalents during the fiscal year ended June 30, 2016 primarily reflects losses incurred by operations of the Poplar field and the ongoing general and administrative expenses related to the Company's public platform and international assets, offset by cost reductions and monetization of certain assets to meet the Company's capital needs. As of September 9, 2016, our cash balances amounted to approximately $1.3 million, and we currently have a monthly cash burn rate ranging between $200 thousand and $300 thousand. Accordingly, we are facing liquidity constraints in the short term, and there is a substantial risk that we will not be able to fund our activities beyond the anticipated closing of the merger with Tellurian. Although we have been implementing cost savings initiatives to fund our activities, there is no assurance that those initiatives will be successful. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Consolidated Liquidity and Capital Resources” included in this report.
Although we divested our largest and only revenue-producing asset in the One Stone Exchange, we retained certain contingent liabilities associated with the asset that could have a material adverse effect on our business, financial condition and results of operations.
As a result of the closing of the One Stone Exchange, we sold to One Stone all of our interest in the Poplar field. The Poplar field comprised approximately 78% of our assets on a book value basis and was our only revenue-producing asset. However, the Purchase and Sale Agreement between us and the owners of the interests in Nautilus Technical Group, LLC and Eastern Rider, LLC provides for potential future contingent production payments, payable by us in cash to the sellers, of up to a total of $5.0 million if certain increased average daily production rates for the underlying properties are achieved. These contingent production payments remain an obligation of ours. Although the contingent production payments are unlikely to come due based on the latest reserve estimates available to us, there is no assurance that we will not be required to make such production payments in the future. If this contingent liability comes due and we are unable to dispose of it before such time, then the obligation to pay the liability could have a material adverse effect on our business, financial condition and results of operations.
Regulations related to hydraulic fracturing could result in increased costs and operating restrictions or delays that could affect the value of our assets.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We own interests in the Horse Hill-1 well and related licenses in the Weald Basin, onshore UK. Although the UK government lifted a temporary moratorium on hydraulic fracturing in December 2012 and an Office of Unconventional Gas and Oil has 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. For example, local planning permission requirements in the UK may have the effect of restricting or delaying drilling activities in general or hydraulic fracturing in particular. If drilling activities are restricted or delayed or made more costly, the volumes of oil and natural gas that can be economically recovered could be reduced, which would adversely affect the value of our interests.
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.
We may not be successful in sharing the exploration and development costs of the fields, licenses, and permits in which we hold interests, such as our Australian NT/P82 prospect.
During fiscal year ended June 30, 2016, we tried to sell or farmout our 100% interest in the NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia, with the support of our financial advisor for this matter, RFC Ambrian. We were unsuccessful in executing a potential transaction, which we believe was due to i) the weak commodity price environment and material reduction in current export LNG prices in Australia, which are believed to have resulted in a significant reduction in exploration budgets of large companies operating in the area and ii) the short remaining term of the license, which was due to expire by May 12, 2016, unless the work requirements of the license had been met. In April 2016, we applied to the NOPTA to

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extend the permit term by 18 months to allow the varied minimum work condition to be undertaken. On June 29, 2016, NOPTA informed us that the Commonwealth-Northern Territory Offshore Petroleum Joint Authority approved these variations, and the term of the license is now due to end on November 12, 2017. If we are not able to secure a farm-in, farmout, or other arrangement 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 licenses and permits, in which case our results of operations, financial condition, and cash flows could be adversely affected and the market price of our common stock could decline.
We may not realize the expected value and potential liquidity from our investments in Central Petroleum Limited and UK Oil and Gas Investments PLC.
On March 31, 2014, we sold our non-core assets in the Amadeus Basin of Australia to Central Petroleum Limited, in exchange for AUD $20.0 million in cash and 39.5 million shares of Central's stock, which are listed for trading on the Australian Securities Exchange ("ASX") and which represented an approximately 11% equity ownership interest in Central. Under the terms of the agreement for that transaction, the Central shares were valued at AUD $15.0 million. As of June 30, 2016, we held approximately 8.2 million Central shares, which represented an approximately 1.9% equity ownership interest in Central and were carried on our consolidated balance sheet at a fair value of $0.6 million, based on the closing per share market price for Central stock as reported on the ASX on that date and applicable foreign currency translation adjustments. On August 11, 2016, the transactions contemplated by the Weald ATA and IoW ATA closed and the Settlement Agreement with Celtique became effective, resulting in the net issuance to Magellan of approximately 50.9 million shares of UKOG, which shares are listed for trading on the Alternative Investment Market of the London Stock Exchange and at the at the time of closing represented an approximately 2.0% equity ownership in UKOG and were worth approximately GBP 703 thousand.
Central is a Brisbane, Australia-based junior exploration and production company that operates one of the largest holdings of prospective onshore acreage in Australia. UKOG is a London-based oil and gas company focused in the Weald Basin in southern England. Accordingly, each of Central and UKOG and the value of its respective stock is subject to similar business, industry, and oil and natural gas price fluctuation risk factors that we are subject to, as well as each of Central's and UKOG's own particular risk factors based on its current circumstances and operating areas in Australia and England, respectively. As a result, or for other reasons, the market price of Central or UKOG stock may experience significant fluctuations, including significant decreases. We do not control Central or UKOG, and our investment is subject to the risk that Central or UKOG may make business, financial, or management decisions with which we do not agree. Although the shares of Central and UKOG that we hold are not restricted and may be sold on the ASX or Alternative Investment Market of the London Stock Exchange, respectively, the average daily trading volumes for Central and UKOG stock relative to the number of Central or UKOG shares that we hold may mean that our Central or UKOG shares would need to be sold over a substantial period of time, exposing our investment return to risks of downward movement in the market price during the intended disposition period. Accordingly, we may ultimately realize a lower value and potential liquidity from our investments in Central and UKOG than we expect.
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, general and industry economic and financial downturns can adversely affect the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas.

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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 or licensed properties within the applicable lease or license 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 material 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.
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. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.
We have limited management and staff and are dependent upon partnering arrangements.
We had 13 total employees as of June 30, 2016, and four total employees as of September 9, 2016. 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.
There are risks inherent in foreign operations and investments, such as adverse changes in currency values and foreign regulations relating to MPUK's, MPA's, and Central's exploration and development operations, and potential taxes or restrictions on dividends to MPC from foreign subsidiaries or investments.
The properties in which we have operating or investment interests that are located outside the United States are subject to certain risks related to the indirect ownership and development of, or investment in, foreign properties, including government expropriation and nationalization, adverse changes in currency values and foreign exchange controls, foreign taxes, United States taxes on the repatriation of funds to the United States, and other laws and regulations, any of which may have a material adverse effect on our properties, investments, financial condition, results of operations, or cash flows. Although there are currently no foreign exchange controls on the payment of dividends to MPC by its subsidiaries or other entities in which it has invested, such payments could be restricted by foreign exchange controls, if implemented.
Oil and natural gas prices are volatile. Further declines in prices could adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to grow.
Our 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 any 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;

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the extent of UK and Australian domestic oil and gas production and the consumption and importation of such fuels and substitute fuels in UK, 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;
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.
Further and sustained declines in oil and gas prices could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, and cash flows. Further, oil and gas prices do not necessarily move in tandem. Future oil and gas sales would generate lower revenue if oil and natural gas prices were to continue to decline. Prices for sales of 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 several years, the number of talented people available across all disciplines in the industry has not grown significantly, and in many cases, is declining due to the demographics of the industry.
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 or business sectors than our existing properties or business. To the extent acquired properties are substantially different than our existing properties or business, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.
Integrating acquired properties 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

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debt and contingent liabilities. As a result, future acquisitions or investments could cause dilution of existing equity interests and earnings per share.
Our operations are subject to complex laws and regulations, including environmental laws and regulations that result in substantial costs and other risks.
UK and Australian governmental authorities, extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil and natural gas production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations, and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.
Governmental authorities regulate various aspects of drilling for and the production of crude oil and natural gas, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, 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 or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Governmental authorities also may require any of our ongoing or planned operations on their leases or licenses to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a material adverse effect on our operations.
Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by 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 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. 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.

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Our estimated reserves as of June 30, 2016 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 such reserves.
This report contains estimates of our proved and probable reserves and the estimated future net revenues from our proved reserves as of June 30, 2016. All our reserves are related to the proved oil and gas properties of Poplar. As a result of the closing of the Exchange with One Stone on August 1, 2016, all our reserves were disposed of as of that date. In any case, the reserve 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. Estimates of proved reserves may be adjusted 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. In addition, our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties. Probable reserves are less certain to be recovered than proved reserves.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on the average, first-day-of-the-month price during the 12-month period preceding the measurement date, 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 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 has limited and may continue to limit in the future our ability to book proved undeveloped reserves as we pursue drilling programs on our undeveloped properties.
Substantial capital is required for our business and projects.
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, sales of non-core assets, and/or debt 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 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, the divestment of assets or farm-in, farmout or other arrangements. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, the proceeds offered to us for potential divestitures may not always be of acceptable value to us, and farm-in, farmout or other arrangements may not be available to us on terms which are economically attractive to us, or at all.
If we are not able to replace reserves, we will not be able to generate production.
All our reserves as of June 30, 2016 are related to the proved oil and gas properties of Poplar. As a result of the closing of the Exchange with One Stone on August 1, 2016, all our reserves were disposed of as of that date. Our future success depends, in part, upon our ability to find, develop, or acquire additional oil and gas reserves that are economically recoverable. 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 or probable reserves at acceptable costs.

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Future price declines may result in further 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 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 fair value (discounted future net cash flows of that depletion pool). For example, in the fiscal year ended June 30, 2016, as a result of significant declines in oil commodity prices, we incurred an impairment loss of $7.8 million on our proved oil and gas properties included in discontinued operations. Although only $337 thousand of capitalized well costs remain as of June 30, 2016, a further significant decline in oil or natural gas prices from current levels, or other factors, could cause a further impairment write-down of capitalized costs and a non-cash charge against future earnings. Once incurred, a write-down of capitalized assets cannot be reversed at a later date, even if oil or natural gas prices increase.
Oil and gas drilling and production 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. Drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings, and separated cables. If any of these or similar events 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, lease, or license, 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.
In recent years, the US, UK, Australian, and global economies and financial systems have 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 may be recovering, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Renewed weakness in the UK, Australian, or other large economies could materially adversely affect our business, financial condition, results of operations, and cash flows.
In addition, some of our oil and gas properties in the United Kingdom 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 UK 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 flow test, 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
selection of suitable technology.

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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 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 US dollar and the British pound, as well as the exchange rates between the Australian dollar and the US dollar, have fluctuated in recent periods and may fluctuate substantially in the future. 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 results of operations and financial condition. Our foreign exchange transaction loss for the fiscal year ended June 30, 2016, was $234 thousand and is included under general and administrative expenses in the consolidated statement of operations.
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 budget proposals have included recommendations that would, if enacted, make significant changes to US tax laws applicable to oil and natural gas exploration and production companies, and legislation has been previously introduced in the US Congress that would implement many of these proposals. These proposed changes include, but are not limited to:
eliminating the current deduction for intangible drilling and development costs;
eliminating the deduction for certain US production activities for oil and natural gas production;
repealing the percentage depletion allowance for oil and natural gas properties; and
extending the amortization period for certain geological and geophysical expenditures.
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.
Certain of our interests in the United Kingdom and Australia are subject to licenses that could be forfeited if certain drilling requirements are not met.
We own certain interests in the UK that are subject to licenses issued by the Secretary of State for Energy and Climate Change under the UK Petroleum Act 1998. In addition, we own a 100% interest in the NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia, issued by the Commonwealth-Northern Territory Offshore Petroleum Joint Authority that is subject to certain terms. In order to retain the interests granted by the licenses and permit, we are required to meet certain drilling, expenditure or seismic requirements. If the applicable requirements are not met or waived, the interests granted by the licenses or permit must be forfeited.
In the UK, with respect to PEDLs 137 and 246, we and our partners negotiated with the OGA an amendment to the terms of the licenses, whereby for PEDL 137, the expiration of the second exploration term was extended to September 30, 2016, and for PEDL 246, the expiration of the initial exploration term was extended to June 30, 2016, and the expiration of the second exploration term was extended to June 30, 2019. Following the successful results of the flow test at the HH-1, the OGA and Secretary of State approved the work plan for each of these licenses (extending the expiration dates for PEDLs 137 and 246 to June 30, 2018 and June 30, 2017, respectively) and the creation of retention areas covering the entire geographic area of them, which retention areas effectively replace the second term of the licenses.
In the case of the Australian NT/P82 prospect, the term of the license was due to expire by May 12, 2016, unless the work requirements of the license had been met. In April 2016, we applied to the NOPTA to extend the permit term by 18 months to allow the minimum work condition to be undertaken. On June 29, 2016, NOPTA informed us that the Commonwealth-Northern Territory Offshore Petroleum Joint Authority approved the extension of the term of the license to November 12, 2017.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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RISKS RELATING TO OUR COMMON STOCK
The market price of our common stock may fluctuate significantly, which may make certain projects uneconomical and/or 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 make certain projects uneconomical and/or result in losses for investors.
We may issue a significant number of shares of common stock under outstanding stock options and future equity awards under our 2012 Omnibus Incentive Compensation Plan, and common stockholders may be adversely affected by the issuance and sale of those shares.
As of June 30, 2016, we had 726,973 stock options outstanding, of which 384,528 were fully vested and exercisable. As of that date, there were 306,481 shares of common stock remaining available for future awards under our 2012 Omnibus Incentive Compensation Plan. If all of the 726,973 outstanding stock options, which have exercise prices ranging from $8.12 to $16.76 per share, are exercised, the shares of common stock issued would represent approximately 11% 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, our stockholders' equity must meet the minimum $2.5 million required for continued listing on the NASDAQ Capital Market pursuant to NASDAQ Stock Market Rule 5550(b)(1). On May 17, 2016, we received a letter from the Listing Qualifications Department of the NASDAQ Stock Market indicating that our stockholders’ equity as reported in our quarterly report on Form 10-Q for the period ended March 31, 2016 did not meet the minimum $2.5 million required for continued listing. After we submitted a plan to the NASDAQ Stock Market to regain compliance, on July 29, 2016, we received a letter from the Listing Qualifications Department of the NASDAQ Stock Market indicating that it had determined to grant us an extension until October 14, 2016 to regain compliance with Rule 5550(b). We believe that the combination of the One Stone exchange, the sale of the Mereenie Bonus and the Weald ATA should result in an increase of our stockholders’ equity sufficient to achieve compliance. As of June 30, 2016, pro forma for the One Stone Exchange closing and the sale of the Central Weald and Peripheral Weald licenses closing, our stockholders’ equity was $3.7 million.
Pursuant to the Merger Agreement with Tellurian, it is a condition to the completion of the Merger that the shares of Magellan common stock to be issued to Tellurian stockholders pursuant to the Merger be authorized for listing to be traded on the NASDAQ Capital Market, subject to official notice of issuance.
If our common stock were delisted from trading on the NASDAQ Capital Market, it may be eligible for trading on the OTCQB, but the delisting of our common stock could adversely impact the liquidity and value of our common stock and our ability to raise capital or consummate the merger with Tellurian.
The reverse stock split of our shares of common stock may have reduced and may continue to limit the market trading liquidity of the shares due to the reduced number of shares outstanding, and may potentially have an anti-takeover effect.
In July 2015, we effected a one share for eight shares reverse stock split of common stock in order to increase the bid price to more than $1.00 per share and thus maintain the listing for our common stock on the NASDAQ Capital Market. Although the reverse stock split was intended to avoid decreased liquidity for the shares in the event of a delisting from the NASDAQ Capital Market, the liquidity of the shares may be adversely affected by the reverse stock split as a result of the

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reduced number of shares outstanding following the reverse stock split. In addition, the reverse stock split may have increased the number of stockholders who own odd lots (less than 100 shares) of our common stock, creating the potential for such stockholders to experience an increase in the cost of selling their shares and greater difficulty effecting such sales. Further, since the stockholder-approved reverse stock split was accomplished without a corresponding reduction in the number of shares authorized for issuance under our certificate of incorporation, the relative increase in the number of shares authorized for issuance could, under certain circumstances, have an anti-takeover effect by enabling the Board of Directors to issue additional shares of common stock in a transaction making it more difficult for a party to obtain control of us by tender offer or other means.
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.
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. 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.
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.


ITEM 1B: UNRESOLVED STAFF COMMENTS
None.


ITEM 3: LEGAL PROCEEDINGS
The information required by this Item is incorporated herein by reference to the information set forth under "Celtique Litigation" in Note 16 - Commitments and Contingencies of the Notes to Consolidated Financial Statements included in this report.


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, as adjusted to give effect to the one share-for-eight shares reverse stock split approved by stockholders and completed on July 10, 2015 for all periods.
Quarter ended
 
High
 
Low
June 30, 2016
 
$1.41
 
$0.80
March 31, 2016
 
$1.49
 
$0.20
December 31, 2015
 
$0.83
 
$0.48
September 30, 2015
 
$3.60
 
$0.53
 
 
 
 
 
June 30, 2015
 
$5.44
 
$2.00
March 31, 2015
 
$7.44
 
$4.08
December 31, 2014
 
$17.36
 
$6.24
September 30, 2014
 
$18.64
 
$13.36

HOLDERS
As of September 9, 2016, based on information received from the Company's stock transfer agent, the number of record holders of Magellan's common stock was approximately 484 and, the number of beneficial owners was approximately 5,590.

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.
The payment of dividends on our common stock is subject to the rights of holders of our Series A Preferred Stock, which ranks senior to the common stock with respect to dividend rights. No cash dividends were paid on the Company's Series A Preferred Stock during the year ended June 30, 2016, and all accumulated dividends on our Series A Preferred Stock were paid in kind during the year ended June 30, 2016. On August 1, 2016, all of our outstanding shares of Series A Preferred Stock were redeemed in connection with the One Stone Exchange. For additional information see Note 12 - Preferred Stock, as well as Note 2 - One Stone Exchange and Note 20 - Subsequent Events to the consolidated financial statements included in this Form 10-K.

UNREGISTERED SALES OF EQUITY SECURITIES DURING THE FOURTH QUARTER OF FISCAL 2016
Pursuant to the terms and conditions of the Certificate of Designations of Series A Preferred Stock dated May 17, 2013, as amended, on June 30, 2016, the Company issued 390,133 shares of its Series A Preferred Stock as quarterly PIK dividends with respect to the 22,293,295 shares of Series A Preferred Stock outstanding as of the record date of June 15, 2016. One Stone Holdings II LP, as the sole holder of Series A Preferred Stock, received all of these PIK shares. The shares of Series A Preferred Stock were issued pursuant to the private placement exemption from registration under Section 4(a)(2) of the US Securities Act of 1933, as amended (the “Securities Act”). The facts relied upon to make such exemption available include that the private placement was with a single person that has represented that it is an "accredited investor" within the meaning of Rule 501 under the Securities Act, and the securities are restricted from transfer except pursuant to an effective registration statement under the Securities Act or an available exemption from such registration. Each share of Series A Preferred Stock is convertible at any time, at the holder's option, into shares of the Company's common stock, using a face amount per share of the Series A Preferred Stock based on the Purchase Price of $1.22149381 per share, and dividing by a conversion price of $9.77586545 per common share, subject to customary anti-dilution provisions. For additional information regarding the Series A Preferred Stock, see Note 12 - Preferred Stock of the Notes to Consolidated Financial Statements included in this report.

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ISSUER PURCHASES OF EQUITY SECURITIES
There were no purchases of the Company's common stock by the Company during fourth quarter of the fiscal year covered by this report. All share amounts listed in this section have been adjusted to reflect the effects of the one share-for-eight shares reverse stock split of our common stock which was completed on July 10, 2015 and is further described below.
On December 31, 2015, upon the vesting of 7,500 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 2,398 shares to settle withholding taxes. The withheld shares were immediately canceled.
On July 10, 2015, to effect the one share for-eight-shares reverse split of the Company's common stock, the Company paid cash in lieu of issuance of fractional shares totaling 2,284 post-split shares. The shares underlying the payment of cash in lieu were immediately canceled.
On July 1, 2015, upon the vesting of 12,500 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 2,822 shares to settle withholding taxes. The withheld shares were immediately canceled.
On October 10, 2014, Magellan repurchased 31,250 shares from William H. Hastings, a former Company executive, pursuant to an Options and Stock Purchase Agreement. See Note 11 - Stock-Based Compensation to the consolidated financial statements included in this report for further details. 
On July 1, 2014, upon the vesting of 18,750 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 5,981 shares to settle withholding taxes. The withheld shares were immediately canceled.
On January 14, 2013, the Company repurchased 1,158,080 shares of its common stock through a Collateral Agreement. See Note 13 - Stockholders' (Deficit) Equity to the consolidated financial statements included in this report for further details.
On September 24, 2012, the Company announced that its Board had approved a stock repurchase program authorizing the Company to repurchase up to a total value of $2.0 million in shares of its common stock. During November 2012, the Company repurchased 18,692 shares pursuant to this program. As of June 30, 2014, $1.9 million in shares of common stock remained authorized for repurchase under this program. This authorization superseded the prior plan announced on December 8, 2000, and expired on August 21, 2014, with no further repurchases of stock.
Reverse Stock Split
On July 10, 2015, pursuant to the Company's definitive proxy statement filed on June 8, 2015, the Company held a Special Meeting of Stockholders to approve an amendment to its Restated Certificate of Incorporation to effect a reverse stock split of its common stock at a ratio to be determined by the Board of Directors within a specific range set forth in the proxy statement, without reducing the number of authorized shares. The Company's shareholders approved the proposed amendment to the Restated Certificate of Incorporation, and the Board of Directors selected a reverse split ratio of one-for-eight (1:8). As a result of the reverse stock split, as of the close of business on July 10, 2015, each eight shares of common stock were converted into one share of common stock with any fractional shares being settled in cash. Immediately preceding the reverse stock split, there were 55,313,647 shares of common stock issued, including 9,675,114 treasury shares. The number of shares of Series A Preferred Stock did not change as a result of the split; however, following the reverse stock split the conversion price was adjusted to reflect the split from $1.22149381 to $9.77586545.
After the reverse stock split there were 6,911,921 shares of common stock issued, including 1,209,389 treasury shares. All share and per share amounts relating to the common stock, stock options to purchase common stock, including the respective exercise prices of each such option, and the conversion ratio of the Series A Preferred Stock included in the financial statements and footnotes have been adjusted to reflect the reduced number of shares resulting from the reverse stock split. Market conditions tied to stock price targets contained within market-based options were similarly adjusted. The par value and the number of authorized, but unissued, shares remain unchanged following the reverse stock split.


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.

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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 Items 1 and 2: Business and Properties and Item 8: Financial Statements and Supplementary Data of this Form 10-K. Amounts expressed in British pounds sterling and Australian dollars are indicated as "GBP" and "AUD," respectively.
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
Over the past few years, Magellan was focused on the potential development of Poplar in Montana using CO2-EOR as a technique to potentially recover significant volumes of hydrocarbons from the field. Over the second and third quarter of calendar year 2015, the Company reached the conclusion that using CO2-EOR at Poplar was a technical success and that it would be economically challenging to develop the project in the current commodity price environment, which was increasingly weakening over the period. As a result of these considerations, in June 2015, the Company formed the Special Committee with the primary objective of reviewing the strategic alternatives potentially available to the Company. During the twelve month period ended June 30, 2016, and the third quarter of calendar year 2016, the strategic alternatives review process (i) resulted in (A) the disposal of the Company's NP segment through the Exchange Agreement signed in March 2016 with One Stone; (B) the sale of the Mereenie Bonus in May 2016; and (C) the sale of the Weald Basin assets signed in June 2016; and (ii) reached a conclusion with the announced merger transaction with Tellurian in August 2016.
Although the Company was able to extrapolate from the CO2-EOR pilot project that significant hydrocarbons may be recovered from Poplar using CO2-EOR, we determined that the economic development of such project would require materially higher oil prices. Therefore, in light of the Company’s constrained liquidity position and continuing lower commodity price environment, we determined that Magellan was unlikely to have sufficient liquidity to finance this project and its other activities in the medium term until such time that commodity prices would recover to a level that would enable the necessary capital raising for the development of the project. The strategic alternatives review process also considered the possibility of focusing the Company’s business and strategy on certain of the Company’s other international assets. We estimated that although the prospects identified through the seismic surveys conducted in 2012 and 2013 over the NT/P82 block in the Bonaparte Basin, offshore Australia were promising, these prospects remained at an early stage of the exploration process and required significant capital to be further assessed, which capital may become available through potential farmout or other transactions, and therefore the Company’s interests in NT/P82 could not form the core business of the Company at this stage. With respect to the Company’s interests in the United Kingdom, the Company considered the following factors: i) the term of the main licenses in the central Weald Basin expiring in June 2016, ii) the pending litigation with Celtique which hampered our ability to strategically progress the potential play in the Weald, and iii) the challenging political and social environment in the United Kingdom, particularly evidenced by the rejection of the planning application of Cuadrilla Resources Limited’s proposed wells in Lancashire. Although the Horse Hill-1 well presents interesting prospects, these remained uncertain at the time of the review, and Magellan merely holds a 35% interest and is not the operator of the well, which combined with the prior factors undermined the potential to focus the Company’s business plan on its UK assets.
The Company then estimated that, in order to unlock the potential value of its assets and its public platform, it needed to dispose of its interests in its NP segment, which was incurring operating losses and further undermining the Company’s liquidity position, and to address its financial obligations primarily related to the term loan with WTSB and the Series A convertible preferred stock issued to One Stone, in order to preserve and maximize value for the Company’s shareholders. The Company engaged Petrie Partners to support its strategic alternatives review process and conducted a thorough process which eventually resulted in the signing of the Exchange Agreement with One Stone on March 31, 2016. The Company closed the One Stone Exchange on August 1, 2016, after the Company’s shareholders approved the transactions on July 13, 2016. Based

36


on the findings of the marketing process of NP, the analysis prepared by our financial advisor and the implied valuation at which we disposed our interests in NP, which valuation was based on the disposal value of the preferred shares and the assumption of the WTSB term loan and NP’s outstanding accounts payables, we believe that the terms of this transaction were attractive to the Company’s shareholders. As a result of the closing of the One Stone Exchange, the Company essentially became debt-free, since the term loan with WTSB was assumed by One Stone as part of the transaction, and the Company redeemed and canceled all the outstanding preferred shares which had been previously issued. The Company then executed in May 2016 the sale to Macquarie Bank of certain bonus rights related to the Mereenie field in Australia, which rights were contingent on certain gas sales volumes from the Mereenie field, the proceeds of which sale provided the Company with the necessary funding required to complete its strategic alternatives review process, which concluded with the signing of the merger agreement with Tellurian. Also critical to the ability to attract potential merger candidates was the ability to resolve the pending litigation with Celtique, in order to create a vehicle with some cash, no debt, no litigation, and certain assets. In June 2016, the Company entered into several contemporaneous agreements, resulting in the sale of the combined interests in the Weald Basin of Celtique and Magellan to UKOG in primarily PEDL 234, where the potential Broadford Bridge well is located, and the settlement of the litigation with Celtique. Following these transactions, the Company continues to own i) its 35% interests in the Horse Hill-1 well and related licenses, which interests are fully carried by Horse Hill Development Limited through the completion of its flow tests, ii) its 100% interest in the NT/P82 permit, the term of which permit was extended until November 2017, and iii) its shares of Central.
The execution of these various transactions enabled the Company to conduct an efficient marketing process to seek a potential business combination partner, which process was particularly active in the second quarter of calendar year 2016, following the announcement of the Exchange Agreement with One Stone. The Company engaged in discussions with several quality potential partners and eventually agreed to the terms of a merger with Tellurian on August 2, 2016, which merger remains subject to certain customary conditions and the approval of the Company’s shareholders. Based on the thorough process it conducted, its analysis of the terms of the merger with its financial advisor and other factors, the Company believes i) the ownership by Magellan’s shareholders of the combined company reflects appropriately the value of the Company’s remaining assets and of its public vehicle and ii) provides the Company’s shareholders a unique opportunity to participate in a business model of large scale under the leadership of a seasoned management team, which has a proven track record of delivering significant shareholder value. Upon the closing of the merger with Tellurian, which is expected in the fourth quarter of calendar year 2016, Magellan will enter a new chapter of its long history as a public company.

SIGNIFICANT DEVELOPMENTS IN FISCAL YEAR 2016
During fiscal year 2016, the Company was very active in the execution of various transactions related to its strategic alternatives review process.
Corporate Events
Going Concern. As of the filing of the Company’s annual report on Form 10-K for the fiscal year ended June 30, 2015, the Company reported that it had continued to experience liquidity constraints and had begun selling certain of its non-core assets to fund its operations, and there was substantial doubt about the Company’s ability to continue as a going concern. As of the filing of this annual report on Form 10-K for the fiscal year ended June 30, 2016, the Company continues to experience liquidity constraints. The Company has completed the sale of certain of its assets to fund its operations, which has resulted in a significant reduction in the Company’s monthly cash burn rate. However, these liquidity constraints continue and proceeds from these asset sales may not provide sufficient liquidity to fund the Company's operations for the next twelve months. As a result of these conditions and events, there is substantial doubt about the Company's ability to continue as a going concern. Because Tellurian’s assets do not currently generate revenues, the combined company is also likely to experience liquidity constraints. However, we believe that upon the closing of the merger with Tellurian, the combined company will be better positioned to raise capital to fund the combined company's operations due to the attributes of Tellurian’s business plan and management. Therefore, we believe that Magellan’s ability to continue as a going concern in the short-term is subject to the closing of the merger with Tellurian, the primary condition of which closing is the approval by the Company’s shareholders of the merger agreement that is expected to be sought in the fourth quarter of calendar year 2016. However, following the closing of the merger with Tellurian, the combined company may not be able to raise sufficient capital in a timely manner to fund the operations of the combined company. Should the merger with Tellurian not close, the Company will need to pursue other alternatives in order to continue as a going concern.
Exchange Agreement. On March 31, 2016, Magellan and One Stone entered into an Exchange Agreement (the “Exchange Agreement”). The Exchange Agreement provides, upon the terms and subject to the conditions set forth in the Exchange Agreement, for the transfer by One Stone to the Company of 100% of the outstanding shares of Magellan Series A convertible preferred stock (the “Preferred Stock”) in consideration for the assignment to and assumption by One Stone of 100% of the outstanding membership interests in Nautilus Poplar LLC, and 51% of the outstanding common units in Utah CO2

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LLC (“Utah CO2,” and together with Nautilus Poplar LLC, the "CO2 Business"), as adjusted by the Cash Amount (as defined in the Exchange Agreement and discussed further below) (the “Exchange”). The Exchange Agreement was given economic effect as of September 30, 2015 (the “Effective Date”).
Pursuant to the Exchange Agreement, on April 15, 2016, Magellan and One Stone i) entered into a Secured Promissory Note (the “Note”) pursuant to which One Stone made a loan to Magellan in the aggregate amount of $625 thousand (the “Loan Amount”) and ii) simultaneously entered into a Pledge Agreement pursuant to which Magellan pledged, assigned and granted to One Stone a security interest in the Company’s interests in MPA, as collateral for the loan. The purpose of the Note was primarily to fund the payment of outstanding payables with certain vendors of the CO2 Business to maintain its ongoing operations between signing of the Exchange Agreement and closing of the Exchange. At the closing of the Exchange, the Loan Amount was deemed to be paid in full and no further amounts under the Note are required to be repaid by the Company.
On August 1, 2016, all the conditions to the closing of the Exchange were met and the Exchange was consummated. The primary conditions to closing included i) the receipt of the approval of the Exchange by the Company’s shareholders which was received on July 13, 2016, during the Company’s annual and special meeting of the shareholders, ii) the consent of WTSB to release a guaranty provided by Magellan, and iii) the payment of the Cash Amount. On August 1, 2016, One Stone paid the Cash Amount to the Company, which was agreed to amount to $900 thousand. The purpose of the Cash Amount was primarily to reimburse the Company for the funding of the operations of the Poplar field during the period between September 30, 2015, and the closing of the Exchange, which operations were expected to result in a loss in the aggregate for the period. In addition, Messrs. Gluzman and Israel, One Stone’s representatives on the Company’s Board of Directors, agreed to forego the amount of director compensation, in cash and stock, owed to them and outstanding as of the closing date, which was estimated at approximately $174 thousand in the aggregate. Following the closing of the Exchange, the Company canceled all issued and outstanding shares of the Series A Preferred Stock, and Messrs. Gluzman and Israel ceased serving as members of the Board.
Mereenie Bonus Sale. On May 18, 2016, Magellan entered into and completed a Sale and Purchase Deed with Macquarie to sell to Macquarie all the Company's rights to certain bonus payments, which bonus payments are based upon sales of hydrocarbons from the Mereenie field located in the Amadeus Basin in Australia ranging from 2,500 boepd to 10,000 boepd and may result in cumulative potential payments ranging from AUD $5.0 million to of AUD $17.5 million (the "Mereenie Bonus"). The consideration for the sale of the Mereenie Bonus paid by Macquarie was AUD $3.5 million. The Mereenie Bonus was not previously recorded as an asset on the Company's consolidated balance sheet in light of the contingent nature of these payments.
In light of i) the general uncertainties related to the ability to increase sales of hydrocarbons from the Mereenie field to the required thresholds to trigger the various bonus payments and ii) the pressing liquidity needs facing the Company during the second quarter of calendar year 2016, the Company believed that the monetization of this contingent asset was important to enable the continuation of the strategic alternatives review process. The Company’s ability to repatriate the proceeds from the sale of the Mereenie Bonus to the US was constrained by the terms of the Pledge Agreement the Company entered into in conjunction with the Note with One Stone. Approximately AUD $2.8 million was transferred to the US in May 2016 and the remainder was available for transfer following the closing of the Exchange Agreement on August 1, 2016.
Central Weald Sale. On June 10, 2016, MPUK entered into i) an Asset Transfer Agreement relating to the sale to UKOG of MPUK's 50% interests in PEDLs 231, 234, and 243 (the "Weald ATA"), ii) an Asset Transfer Agreement relating to the sale to UKOG of MPUK's 22.5% interest in the Offshore Petroleum Licence P1916 (the "IoW ATA"), and iii) a Settlement Agreement with Celtique. The consideration payable by UKOG to MPUK for the Weald ATA amounted to GBP 1.8 million in a combination of cash and shares of UKOG, the number and value of which shares was determined as of the time of execution of the Weald ATA. The consideration for the IoW ATA was the assumption of MPUK's outstanding payables related to its interests in the Offshore Petroleum Licence P1916. Pursuant to the terms of the Settlement Agreement, MPUK was due to pay Celtique GBP 500 thousand of the gross consideration, in a combination of cash and shares in UKOG pro rata to the consideration payable to MPUK for the Weald ATA, the number and value of which UKOG shares was determined at the time of execution of the Settlement Agreement. On August 11, 2016, the transactions contemplated by the Weald ATA and IoW ATA closed and the Settlement Agreement became effective, resulting in net cash proceeds to Magellan of GBP 446 thousand and the net issuance to Magellan of approximately 50.9 million shares of UKOG, which shares were worth approximately GBP 703 thousand at the time of closing. The number of shares of UKOG issued to Magellan was determined at the signing of the transactions based on a price per share of GBP 1.58 pence and as of September 9, 2016, the price per share of UKOG was GBP 1.88 pence.
Reverse Stock Split. On July 10, 2015, the Company filed an amendment to its certificate of incorporation to effect a one share-for-eight shares reverse stock split of its common stock, effective July 10, 2015. All share and per share amounts relating to the common stock, stock options to purchase common stock, including the respective exercise prices of each such option, and the amounts of shares convertible upon conversion of the Series A convertible preferred stock for periods both prior and subsequent to the split have been adjusted in this report to reflect the reverse stock split. Market conditions tied to stock price targets contained within market-based options were similarly adjusted. The par value and the number of authorized, but

38


unissued, shares remain unchanged following the reverse stock split. No fractional shares were issued following the reverse stock split, and the Company has paid cash in lieu of any fractional shares resulting from the reverse stock split.
NASDAQ Listing Requirements. On November 5, 2015, Magellan received a letter from the Listing Qualifications Department of the NASDAQ Stock Market ("NASDAQ") indicating that, based upon the closing bid price of the Company's common stock for the last 30 consecutive business days, the common stock had not met the minimum bid price of $1.00 per share required for continued listing on the NASDAQ Capital Market pursuant to NASDAQ Marketplace Rule 5550(a)(2). On March 4, 2016, the Company received a letter from NASDAQ notifying the Company that, since the closing bid price of the common stock for the previous 10 consecutive business days was at least $1.00, the Company had regained compliance with NASDAQ Marketplace Rule 5550(a)(2).
On May 17, 2016, Magellan received a letter from the Listing Qualifications Department of the NASDAQ indicating that the Company’s stockholders’ equity as reported in the Company’s quarterly report on Form 10-Q for the period ended March 31, 2016 did not meet the minimum $2.5 million required for continued listing on the NASDAQ Capital Market pursuant to NASDAQ Stock Market Rule 5550(b)(1). On June 30, 2016, the Company submitted materials to NASDAQ describing a number of transactions that it believed would enable it to report stockholders’ equity of approximately $4.1 million on a pro forma basis, as of March 31, 2016, and that it was engaged in negotiations with a specific party to enter into a potential business combination transaction. On July 29, 2016, Magellan received a letter from the Listing Qualifications Department of NASDAQ indicating that it had determined to grant Magellan an extension until October 14, 2016 to regain compliance with Rule 5550(b). In the letter dated July 29, 2016, the Listing Qualifications Department indicated that any future business combination with a non-NASDAQ entity would likely be considered a “change of control” of Magellan, which would require the post-combination company to apply for initial listing on the NASDAQ Capital Market and meet all applicable initial listing criteria.
Poplar (Montana, USA)
Shallow Intervals. During the twelve months ended June 30, 2016, Magellan sold 60 Mboe (164 boepd) of oil attributable to its net revenue interests in Poplar. This production came primarily from production from the Charles formation.
Deep Intervals. During the twelve months ended June 30, 2016, there was no production from the Deep Intervals at Poplar.
United Kingdom
Weald Basin Licenses. In the central Weald Basin, which consists of Magellan's 50% interests in PEDLs 231, 234, and 243, there was no substantial operational activity. These licenses were due to expire in June 30, 2016, and were subject to “drill or drop” conditions, which were not met in early 2016, and potential progress was further hampered by the pending litigation with Celtique. The Company monetized its interests in these licenses through the transactions contemplated by the Weald ATA that closed on August 11, 2016.
Horse Hill. In PEDLs 137 and 246, where the Horse Hill-1 well ("HH-1") was drilled, the Company holds a 35% interest in HH-1 and these licenses following a farmout agreement with Horse Hill Development, Ltd ("HHDL") dated as of December 20, 2013, pursuant to which agreement the Company’s costs in relation to these licenses are 100% carried by HHDL until production and including costs related to conducting certain flow tests. During the first quarter of calendar year 2016, HHDL conducted a successful flow test of several formations of HH-1 including the Portland sandstone and two Kimmeridge limestone formations. UKOG, one of the principal interest owners of HHDL, then reported that the flow tests measured a stable dry oil rate of 1,688 barrels of oil per day in aggregate from these formations. Although the duration of the flow tests of each formation was relatively short, we were very encouraged by these results. We believe that HHDL is in the process of seeking regulatory permissions to conduct a significant long-term production testing and appraisal program of the productive Kimmeridge Limestones and Portland oil-bearing reservoirs.
Other UK Licenses. During fiscal year ended June 30, 2016, there was no substantial activity in P1916, located offshore southern UK, near the Isle of Wight, and the Company disposed of its 22.5% interest through the execution of the IoW ATA.
Australia
NT/P82. During fiscal year ended June 30, 2016, the Company continued its efforts to try to sell or farmout its 100% interest in the NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia, with the support of its financial advisor for this matter, RFC Ambrian. The Company was unsuccessful in sourcing attractive potential transactions, which we believe was due to i) the weak commodity price environment and material reduction in current export LNG prices in Australia, which are believed to have resulted in a significant reduction in exploration budgets of large companies operating in the area and ii) the short remaining term of the license, which was due to expire by May 12, 2016, unless the work requirements of the license had been met.

39


During the last two months of calendar year 2012, the Company successfully conducted a 2-D and 3-D seismic survey over portions of its NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia. During calendar year 2013, the seismic data underwent complete processing and interpretation and resulted in the identification of three prospects, including a potential conventional reservoir formed by a structural trap against a fault line and two potential stratigraphic plays identified based on amplitude versus offset analysis. The potential volume of gas present in these prospects could amount to several Tcf of gas but are considered to be at the very early stage of the exploration phase and may not result in an actual discovery.
In April 2016, the Company applied to the National Offshore Petroleum Titles Administrator (“NOPTA”) to i) increase the Year 6 minimum work requirement from 600 km2 of 3D seismic survey to 1,000 km2 new seismic data acquisition and processing and geological and geophysical studies, ii) suspend Year 6 conditions of title for 18 months, and iii) extend the permit term by 18 months to allow the varied minimum work condition to be undertaken. On June 29, 2016, NOPTA informed the Company that the Commonwealth-Northern Territory Offshore Petroleum Joint Authority approved these variations and the term of the license is now due to end on November 12, 2017.
Central Petroleum Shares. As partial consideration for the sale of the Company’s onshore Australia assets in fiscal year 2014, the Company received approximately 39.5 million shares of Central Petroleum Limited, a small oil and gas company listed on the Australian Securities Exchange. Between July 2015, and February 2016, the Company sold on the open market shares of Central in order to help finance its activities during the strategic alternatives review process. The Company’s ownership of shares of Central was reduced from 39.5 million shares in July 2015 to 8.2 million in February 2016, and the volume-weighted average price realized for the sale of these shares, excluding brokerage fees, amounted to approximately AUD $0.11 per share.
Magellan does not consider its shareholdings in Central to be a core asset and will potentially dispose of part or all of this interest. The timing of the Company’s decision to dispose of its interests will depend upon i) the actual price per share of Central, which we believe could increase in the medium term as Central achieves certain operational milestones and ii) the foreign exchange rate between the AUD and the USD.
OUTLOOK FOR FISCAL YEAR 2017
Following the rationalization of the Company’s portfolio of assets during the fiscal year ended June 30, 2016, and assuming the closing of the merger with Tellurian during the fourth quarter of calendar year 2016, Magellan will become a company primarily focused on the development of LNG projects in the US Gulf Coast. The HH-1 well and related licenses in the UK and the Company’s interests in NT/P82 will provide additional option value to the shareholders, with NT/P82 potentially providing a more strategic fit with the combined company’s assets considering the potential large gas prospect, which might be tied to other LNG infrastructure in Northern Territory, Australia.
Corporate Events
Merger with Tellurian. On August 2, 2016, Magellan, Tellurian, and River Merger Sub, Inc., a Delaware corporation and a direct wholly owned subsidiary of Magellan, entered into an Agreement and Plan of Merger. Pursuant to the Merger Agreement, each outstanding share of common stock, par value $0.001 per share, of Tellurian will be exchanged for 1.300 shares of common stock, par value $0.01 per share, of Magellan, and Merger Sub will merge with and into Tellurian, with Tellurian continuing as the surviving corporation and a direct wholly owned subsidiary of Magellan.
The Merger Agreement and the Merger have been approved by the board of directors of each of Magellan and Tellurian. Stockholders of Magellan will be asked to vote on the approval of the transactions contemplated by the Merger Agreement at a special meeting that is expected to be held during the fourth quarter of calendar year 2016. In addition to the approval of the foregoing matters by the stockholders, the closing of the Merger is subject to customary closing conditions, including i) the receipt of Magellan and Tellurian stockholder approval; ii) all directors and officers of Magellan shall have resigned, except for any person(s) that might be designated by Tellurian; iii) a registration statement on Form S-4 to register the Magellan shares to be issued in the Merger shall have been declared effective by the US Securities and Exchange Commission (the “SEC”); and iv) shares of Magellan common stock to be issued in the Merger shall have been approved for listing on the NASDAQ. The Merger Agreement also contains a non-solicitation provision pursuant to which Magellan may not, directly or indirectly, take certain actions to negotiate or otherwise facilitate an “Alternative Proposal,” a term generally defined as an inquiry, proposal or offer relating to a business combination with or acquisition of the assets of Magellan by a person or entity other than Tellurian. Magellan’s non-solicitation obligations are qualified by “fiduciary out” provisions which provide that Magellan may take certain otherwise prohibited actions with respect to an unsolicited Alternative Proposal if the Board of Directors determines that the failure to take such action would be reasonably likely to be inconsistent with its fiduciary duties and certain other requirements are satisfied. The Merger Agreement may be terminated under certain circumstances, including in specified circumstances in connection with receipt of a "Superior Proposal," as such term is defined in the Merger Agreement. In connection with the termination of the Merger Agreement in the event of a Superior Proposal, a breach by Magellan of the non-

40


solicitation provision noted above, or following a change by the Board of Directors of its recommendation to stockholders, Magellan will be required to pay to Tellurian a termination fee for any and all third-party transaction fees and expenses incurred by Tellurian with the drafting, negotiation, execution and delivery of the Merger Agreement and related documents (including fees and expenses for attorneys, accountants and other advisors), subject to a maximum of $1 million in the aggregate. A termination fee may also be payable in some circumstances in which an Alternative Proposal is made, the transaction fails to close and Magellan subsequently agrees to an Alternative Proposal. If the Merger Agreement is terminated by either party as a result of the failure to obtain the requisite approval by Tellurian stockholders, or by Magellan because Tellurian does not use commercially reasonable efforts to secure the approval for listing the Magellan shares of common stock to be issued in the Merger, then Tellurian will be required to pay to Magellan a reverse termination fee of $1 million.
Upon the closing of the Merger with Tellurian, Magellan will become a Houston-based energy company focusing on the development of LNG export projects. Tellurian’s management team is led by Charif Souki and Martin Houston, who have led and/or founded several industry-leading companies, specifically in the LNG sector. Mr. Souki is the former founder, Chairman, and CEO of Cheniere Energy, Inc., which is expected to operate in excess of 30 million tonne per annum (“mtpa”) of LNG export facilities. Mr. Houston retired in November 2013, as chief operating officer of BG Group plc (“BG”), after 30 years of service, during which he pioneered the development and optimization of BG’s global LNG portfolio. Tellurian was formed in February 2016 to develop low-cost, mid-scale LNG projects on the US Gulf Coast. Bechtel Corporation, General Electric and Chart Industries, Inc. are Tellurian’s commercial partners to deliver LNG facilities with best-in-class development costs on a global basis. Tellurian is currently focused on the development of the Driftwood LNG project, a 26-mtpa LNG export facility in Calcasieu Parish, LA, where Tellurian owns or leases a site of approximately 800 acres with marine access for LNG tankers. As a result of the Merger, Tellurian will gain greater access to the capital markets to finance the development of the Driftwood LNG project.
Special Committee. On June 5, 2015, the Company’s Board of Directors formed the Special Committee to consider various strategic alternatives potentially available to the Company and engaged Petrie Partners, LLC ("Petrie") as financial advisor. Following the closing of the Exchange with One Stone, the subsequently announced Merger with Tellurian and the departures of Messrs. Gluzman, Israel and Wilson from the Board, we believe that the task of the Special Committee has substantially been completed.
United Kingdom
Horse Hill. We believe that HHDL is in the process of seeking regulatory permissions to conduct a significant long-term production testing and appraisal program of the productive Kimmeridge Limestones and Portland oil-bearing reservoirs. Since the results of the HH-1 well have been very encouraging to date and the Company’s costs in relation to these licenses are 100% carried by HHDL, we are planning to await the results of the next flow test and appraisal program before making a decision about our long-term participation in these licenses. However, the Company will continue to consider potential transactions on an opportunistic basis in light of the Company’s overall strategy and business plan.
Australia
NT/P82, Offshore Australia. Over the upcoming several months, the Company intends to establish a plan and a schedule for executing its seismic survey work commitment for NT/P82. Considering the current stabilization of commodity prices and the greater certainty provided by the revised terms of the license received on June 29, 2016, including the 18-month extension of the term of the license to November 12, 2017, we believe that a farmout agreement also remains possible for this asset. In addition, given the large potential gas prospects contained within this license and the development of several fields in the Bonaparte Basin through LNG facilities, we believe that this asset represents a potential strategic fit with the combined company’s overall strategy and business activities upon the closing of the Merger with Tellurian.
Palm Valley Bonus Rights. Under the terms of the Share Sale and Purchase Deed dated February 17, 2014, between Magellan Petroleum (N.T.) Pty Ltd , a wholly owned subsidiary of Magellan, and Central, the Company is entitled to receive 25% of the revenues generated at the Palm Valley gas field from gas sales when the volume-weighted gas price realized at Palm Valley exceeds AUD $5.00/Gigajoule and AUD $6.00/Gigajoule for the first 10 years following the closing date and for the following five years, respectively, with such prices to be escalated in accordance with the Australian consumer price index (the “Palm Valley Bonus”). For further information related to the Palm Valley Bonus, please refer to Note 5 - Sale of Amadeus Basin Assets. The value of the rights to these bonus payments is not reflected on the Company’s financial statements and the Company believes there is significant risk to the potential realization of these rights. During fiscal year 2017, the Company may seek to monetize these rights, as it did with respect to the Mereenie Bonus during fiscal year 2016. We believe that our ability to enter into a transaction with respect to the Palm Valley Bonus will depend on certain operational and commercial development in the Amadeus Basin, particularly the ability of Central to enter into new gas sales contract with potential new customers.


41



SUMMARY RESULTS OF OPERATIONS FOR THE YEAR ENDED JUNE 30, 2016
As a result of the transactions related to the strategic alternatives review process, the assets and operations of NP, Utah CO2, and the Weald Basin were reclassified to held for sale and discontinued operations, respectively, for all periods presented. Therefore, the Company does not report revenues herein, and the results of continuing operations herein exclude the results of these discontinued operations.
Loss from continuing operations. Loss from continuing operations, including preferred stock dividends and an adjustment to redemption value of the preferred stock, for the fiscal year ended June 30, 2016 totaled $1.0 million ($0.17/basic share), compared to a loss from continuing operations of $23.3 million ($4.09/basic share) in the prior year. The decrease in loss from continuing operations was primarily the result of a decrease in realized losses on available-for-sale securities related to the Company's investment in Central. The Company recorded an other-than-temporary impairment of its investment in Central of $14.9 million in the prior fiscal year. The Company also recognized a gain in the current fiscal year of $2.5 million related to the sale of bonus rights for the Mereenie field, a reduction in general and administrative costs of $2.4 million, and a downward adjustment to the redemption value of the preferred stock of $4.2 million. These reductions in loss from continuing operations were partially offset by a fair value reduction of contingent consideration payable of $1.9 million recorded in the prior fiscal year.
Cash. As of June 30, 2016, Magellan had $1.7 million in cash and cash equivalents, compared to $0.8 million at the end of the prior fiscal year. The increase of $0.9 million was the result of net cash used in operating activities of $2.2 million, net cash provided by investing activities of $5.1 million, net cash provided by financing activities of $0.4 million, and a decrease in cash from the effect of changes in exchange rates of $0.1 million, and represents the net effect of monetization of certain of the Company's assets over its operating expenses during the year, which operating expenses from continuing operations were primarily general and administrative expenses. The $2.2 million of net cash used in operating activities was primarily due to general and administrative expenses, net of stock-based compensation expense and foreign transaction losses of $4.3 million and an increase in accounts payable of $1.7 million. The $5.1 million of net cash provided by investing activities was primarily the result of $2.5 million of proceeds from the sale of the Mereenie Bonus rights and $2.6 million related to proceeds from the sale of shares of Central stock.
Securities available-for-sale. As of June 30, 2016, Magellan had $0.6 million in securities available for sale, consisting of the Company's investment in shares of Central stock.
Pro forma financial information. Due to the significance of certain transactions that have closed during the third quarter of calendar 2016, including the Exchange Agreement, the Weald ATA, the IoW ATA and the Settlement Agreement, we have presented pro forma financial information in Note 21 - Pro Forma Financial Information (Unaudited) of the Notes to Consolidated Financial Statements included in this report showing the effects of these transactions on our consolidated balance sheet at June 30, 2016, and on our consolidated statements of operations for the years ended June 30, 2016, and June 30, 2015, as if they had been completed on June 30, 2016, with respect to balance sheet data, and as if they had become effective on July 1, 2014, with respect to statement of operations data for the years ended June 30, 2016 and 2015.
On a pro forma basis considering the effects of these transactions, as of June 30, 2016 our pro forma consolidated cash was $2.7 million, our pro forma consolidated total assets were $7.3 million, our pro forma consolidated total equity was $3.7 million, and for the year ended June 30, 2016, our pro forma consolidated loss from continuing operations was $3.2 million, compared to a pro forma consolidated net loss from continuing operations of $21.4 million for the year ended June 30, 2015. Please refer to Note 21 - Pro Forma Financial Information (Unaudited) of the Notes to Consolidated Financial Statements included in this report for more information.
Commodity prices. During the twelve months ended June 30, 2016, the Company's results continued to be impacted by the steep decline in global oil prices that began in late 2014. Oil and gas prices are believed to have stabilized at levels lower than those in the summer of 2014, when oil prices averaged around approximately $100/bbl compared to the current prices of approximately $40/bbl. The decline has had the effect of negatively impacting the perceived present value of the Company's prospects in Australia and the UK, compared to prior estimates. While commodity futures markets suggest that the price of oil will increase gradually, there is no certainty that such an increase will occur.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES
The Company has incurred losses from operations for the year ended June 30, 2016, of $5.3 million, and during the twelve months ended June 30, 2016, the Company's cash and cash equivalents increased by $0.9 million to $1.7 million as of June 30, 2016. During fiscal year 2016, the Company’s activities were primarily financed through i) revenues from the sale of oil production from Poplar, which are included in discontinued operations, ii) the sale of shares of Central in the open market,

42


iii) an active cash management of the Company’s disbursements, resulting in an increase in the Company’s accounts payables as of June 30, 2016 compared to June 30, 2015, and iv) in the second quarter of calendar year 2016, by the sale of certain assets including the sale of the Mereenie Bonus and the transactions contemplated by the Exchange Agreement with One Stone, which included a $625 thousand Note to the Company to finance certain outstanding invoices related to the Poplar field. During the fiscal year ended June 30, 2016 and in the period since then, the Company has continued to experience liquidity constraints and sold Poplar, which was the only source of recurring revenues for the Company.
As of September 9, 2016, our cash balances amounted to approximately $1.3 million, which reflect the impact of the Exchange and the Weald ATA transactions, and our securities available for sale, which consist of our interests in Central and UKOG, amounting to an additional $1.9 million of potential liquidity. Following i) the closing of the Exchange with One Stone on August 1, 2016, which resulted in the exchange of the Company’s interests in Poplar for the release of the Company’s financial obligations in relation to the term loan with WTSB and the Series A Preferred Stock, ii) the sale of the Company’s interests in the central Weald Basin pursuant to the Weald ATA and related transactions, iii) the fully carried nature of our interests in HH-1, and iv) the limited activity in Australia pending a potential farmout of our interests in NT/P82, we believe that the Company’s monthly cash burn rate has been significantly reduced to approximately $200 thousand to $300 thousand on a pro forma basis as of September 9, 2016. Considering that we expect the Merger with Tellurian will be consummated in the fourth quarter of calendar year 2016, we believe that the funds available to the Company, including the Company’s shareholdings in Central, are sufficient to fund the Company’s activities until the closing of the transactions contemplated by the Merger Agreement. However, proceeds from these asset sales may not provide sufficient liquidity to fund the Company's operations for the next twelve months, and if the transactions contemplated by the Merger Agreement were not approved by the shareholders or were not consummated according to the terms of the Merger Agreement, our ability to continue as a going concern would be further impaired. As a result of these conditions and events, there is substantial doubt about the Company's ability to continue as a going concern. Because Tellurian's assets do not currently generate revenues, the combined company is also likely to experience liquidity constraints. However, we believe that upon the closing of the Merger with Tellurian, the combined company will be better positioned to raise capital to fund the combined company's operations due to the attributes of Tellurian's business plan and management. Therefore, we believe that Magellan's ability to continue as a going concern in the short-term is subject to the closing of the Merger with Tellurian, the primary condition of which closing is the approval by the Company's shareholders of the Merger Agreement that is expected to be sought in the fourth quarter of calendar year 2016. However, following the closing of the Merger with Tellurian, the combined company may not be able to raise sufficient capital in a timely manner to fund the operations of the combined company. Should the Merger with Tellurian not close, the Company will need to pursue other alternatives in order to continue as a going concern.
Uses of Funds
Capital Expenditure Plans. Magellan has limited capital expenditure obligations as a result of various transactions the Company entered into during the fiscal year ended June 30, 2016. Following the closing of transactions contemplated by the Exchange Agreement, the Company does not have any remaining obligations related to Poplar. As to the Company’s interests in the UK, primarily related to HH-1, the Company's share of costs are fully carried by HHDL, which includes expenditures related to flow tests; therefore, the Company does not expect to incur any costs in relation to this asset. With respect to NT/P82, pursuant to the terms of the extension granted by NOPTA, the Company is due to conduct a 1,000 km2 3-D seismic survey over part of the license. The Company intends to farmout its interests in the license in a transaction which would consist of a farmout partner incurring 100% of the costs related to the seismic survey in exchange for the right to earn an ownership interest in the permit. Such a potential farmout transaction would result in the Company not incurring any costs for this asset in the medium term.
Series A Preferred Dividend. Following the closing on August 1, 2016, of the transactions contemplated by the Exchange Agreement with One Stone, One Stone transferred to the Company, and the Company subsequently canceled, 100% of the outstanding shares of the Preferred Stock, including accumulated dividends paid in kind. The Company does not have any remaining amounts due or outstanding in connection with the Preferred Stock.
Transaction Costs and Related Items. Upon closing on August 1, 2016, of the transactions contemplated by the Exchange Agreement with One Stone, a cash transaction success fee in the amount of $450 thousand became due and payable to Petrie. Upon signing of the Merger Agreement with Tellurian on August 2, 2016, a fairness opinion fee in the amount of $300 thousand became due and payable to Petrie. Upon resignation of the Company's former President and CEO on August 5, 2016, accrued vacation, severance, and medical benefits in the aggregate amount of $441 thousand became due and payable to the former President and CEO, with amounts relating to accrued vacation payable upon such resignation, amounts relating to severance payable in equal installments over twelve months following such resignation, and amounts relating to medical benefits payable over up to eighteen months following such resignation. Upon completion of transactions contemplated by the Weald ATA, the IoW ATA, and the Settlement Agreement with Celtique on August 11, 2016, accrued amounts payable to Celtique in the amount of GBP 500 thousand became due and payable, and were settled from proceeds of the Weald ATA and paid directly to Celtique.

43


Upon closing of the Merger, a success fee payable in 409,800 shares of the Company to be issued on or before closing, with an aggregate value of $500 thousand as calculated upon signing of the Merger Agreement, will become due and payable to Petrie.
Contractual Obligations. Please refer to the contractual obligations table below in this Part II, Item 7 of our 2016 Form 10-K for information on all material contractual obligations as of June 30, 2016.
Sources of Funds
Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $1.7 million of cash and cash equivalents as of June 30, 2016, compared to $0.8 million as of June 30, 2015. Following the closing of the Exchange with One Stone, which included a $900 thousand payment in cash in relation to the Cash Amount, and the closing of the transactions contemplated by the Weald ATA, which included a net cash payment to the Company of GBP 450 thousand, the Company's cash and cash equivalents as of September 9, 2016, amounted to $1.3 million. 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 to their maturity that they present insignificant risk of changes in value because of changes in interest rates.
Due to the international components of its operations, the Company is exposed to foreign currency exchange rate risks and 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 MPUK and 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. However, upon the closing of the Merger, which constitutes a change in control, there is a risk that most of the Company's tax attributes may not be available to the Company to reduce the Company's potential US federal and state income taxes. As of June 30, 2016, the Company had foreign tax credit carry forwards amounting to $9.1 million, which, based on the Company’s estimated tax rate as of June 30, 2016, have the potential to offset approximately $26.8 million of taxable income. Additional information about the Company’s tax attributes is available in Note 10 - Income Taxes of the Notes to Consolidated Financial Statements included in this report.
Central Shares. In connection with the Note the Company entered into with One Stone on April 15, 2016, the Company entered into a Pledge Agreement, which limited the Company's ability to sell its shares of Central. However, following the closing of the Exchange, the Company is not subject to any restrictions in its ability to sell its remaining shares of Central. As of June 30, 2016, and as of September 9, 2016, the Company owns 8.2 million shares of Central. In the future, Magellan may decide to dispose of all or part of its position in Central stock to fund some of the Company's activities. Although the Company does not intend to hold its position in Central's stock in the long term, the Company believes that there could be certain commercial or operational developments related to Central’s assets, which could positively impact the price per share of Central in the medium term. Therefore, the Company intends to monitor the stock price performance of Central to determine the appropriate time to dispose of its position.
Based on the closing price on September 9, 2016, the shares of Central stock represent $602.2 thousand of additional potential liquidity.
UKOG Shares. On August 11, 2016, the Company received 50.9 million shares of UKOG, which are listed on the AIM market in the UK as part of the consideration for the Weald ATA. However, pursuant to the terms of the Weald ATA, which include a six month lock-in period, the Company may not sell its shares of UKOG until February 10, 2017. Considering the current volume of trading activity of UKOG shares, the Company believes that it will be able to dispose of its shareholdings effectively once it decides to monetize these shares. The Company does not consider its shareholdings in UKOG to constitute a core asset of the Company and will monitor the performance of the price per share of UKOG and the operational results of HH-1 and UKOG’s other assets to determine the appropriate time to dispose of its shareholdings. Based on the price per share of UKOG as of September 9, 2016, the Company’s shareholdings in UKOG amounted to approximately $1.3 million, which could be available to fund the Company’s activities.
Palm Valley Bonus. Under the terms of the Share Sale and Purchase Deed dated February 17, 2014, between the Company and Central, the Company is entitled to receive 25% of the revenues generated at the Palm Valley gas field from gas sales when the volume-weighted gas price realized at Palm Valley exceeds AUD $5.00/Gigajoule and AUD $6.00/Gigajoule for the first 10 years following the closing date of March 31, 2014, and for the following five years, respectively, with such prices to be escalated in accordance with the Australian consumer price index (the “Palm Valley Bonus”). Following the sale of the Mereenie Bonus, the Company will continue to seek to monetize the Palm Valley Bonus, although there can be no assurance that the Company will be able to execute such a transaction.
Existing Credit Facilities. A summary of the Company's existing credit facilities is as follows:

44


 
June 30, 2016
 
June 30, 2015
 
(in thousands)
Outstanding borrowings:
 
 
 
Notes payable
783

 

Total
$
783

 
$


Insurance Premium Notes. Between September 2015 and March 2016, the Company entered into three separate insurance premium financing agreements (the "Premium Notes") to finance the insurance premiums related to the annual renewal of the Company's insurance policies. The Premium Notes have an aggregate original principal amount of $353 thousand, bear interest ranging between 6.25% and 6.50%, and have amortization terms from nine to ten months. The aggregate principal and interest payments due monthly under the Premium Notes range between $38 thousand and $21 thousand.
Secured Promissory Note. Pursuant to the Exchange Agreement, on April 15, 2016, Magellan and One Stone i) entered into a Secured Promissory Note (the “Note”) pursuant to which One Stone made a loan to Magellan in the aggregate amount of $625 thousand (the “Loan Amount”) and ii) simultaneously entered into a Pledge Agreement pursuant to which Magellan pledged, assigned and granted to One Stone a security interest in the Company’s interests in MPA, as collateral for the loan. Magellan was required to use the borrowed amounts to satisfy transaction costs and pay certain outstanding accounts payable primarily related to the CO2 Business. The purpose of the Note was to finance certain ongoing operations at Poplar between signing of the Exchange Agreement and closing. The Note did not bear interest up until closing of the Exchange and was expected to be forgiven upon closing of the Exchange, and if the Exchange had not closed, would have become due and payable on August 1, 2016, or, in the case of a breach of the Exchange Agreement by One Stone, August 1, 2017, and would have borne interest from the date of termination of the Exchange Agreement at a rate of the Prime Rate of interest plus 1% (4.5% at June 30, 2016). The Note is included in Notes Payable at June 30, 2016 in the accompanying consolidated balance sheet. Upon the closing of the Exchange on August 1, 2016, the Loan Amount was deemed paid in full and no further amounts under the Note are required to be repaid by the Company.
Term Loan. The Company, through its former wholly owned subsidiary NP, maintained a term loan (the "Term Loan") with WTSB, which, upon closing of the Exchange on August 1, 2016, has been assumed by One Stone pursuant to the terms of the Exchange Agreement. As of June 30, 2016, the outstanding amount of the Term Loan was $5.5 million. There are no additional amounts available to borrow under the Term Loan. The Term Loan will mature on June 30, 2020, and is subject to monthly floating interest payments based on the Prime Rate (3.50% at June 30, 2016) plus 1.50% and a floor rate of 4.75%. From July 1, 2015 to June 30, 2016, the payment obligations under the Term Loan consisted of interest payments only, and from July 1, 2016 to June 30, 2020, the payment obligations include the interest payments and the amortization payments of the principal amount of the Term Loan. The Term Loan was secured by substantially all of NP's assets, including a first lien on NP's oil and gas leases from the surface to the top of the Bakken, but excluding any rights to assets within or below the Bakken. Magellan, the parent entity of NP, provided a guarantee of the Term Loan secured by a pledge of its membership interest in NP, the consent to release of which guarantee constituted one of the closing conditions of the Exchange Agreement. Magellan and NP are subject to certain customary restrictive covenants under the terms of the Term Loan. As of June 30, 2016, the Company was in compliance with all such covenants.

45


Contractual Obligations. The following table summarizes our obligations and commitments as of June 30, 2016, 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)
Contractual obligations payable from continuing operations:
 
 
 
 
 
 
 
 
 
Retention benefits
$
425

 
$
425

 
$

 
$

 
$

Operating leases
249

 
175

 
74

 

 

Notes payable
158

 
158

 

 

 

Contingent consideration payable (1)

 

 

 

 

Total contractual obligations payable from continuing operations
832

 
758

 
74

 

 

Contractual obligations settled upon closing of agreements related to discontinued operations subsequent to June 30, 2016:
 
 
 
 
 
 
 
 
 
Note payable (2)
625

 
625

 

 

 

Litigation settlement held for sale (3)
670

 
670

 

 

 

Asset retirement obligations held for sale (4)
2,818

 

 

 
1,588

 
1,230

Term loan held for sale (4) (5)
6,039

 
1,613

 
3,019

 
1,407

 

Total contractual obligations settled upon closing of agreements related to discontinued operations subsequent to June 30, 2016
10,152

 
2,908

 
3,019

 
2,995

 
1,230

Total contractual obligations as of June 30, 2016
$
10,984

 
$
3,666

 
$
3,093

 
$
2,995

 
$
1,230

(1) Assumptions for the timing of these payments are based on our reserve report and planned drilling activity.
(2) In connection with the closing of the One Stone Exchange on August 1, 2016, this obligation was deemed paid in full without repayment by the Company as part of the settlement of the final Cash Amount.
(3) In connection with the closing of the transactions contemplated by the Weald ATA, the Company and Celtique entered into a Settlement Agreement, which terminated all claims and counterclaims with Celtique and provided for payment of this obligation directly to Celtique from gross proceeds of the Weald ATA. Amount represents GBP 500 thousand as converted to USD at June 30, 2016.
(4) In connection with the closing of the One Stone Exchange on August 1, 2016, these obligations were transferred to One Stone.
(5) Includes commitments for interest payments according to a loan amortization schedule totaling $539 thousand.

Cash Flows
The following table presents the Company's cash flow information for the fiscal years ended:
 
June 30,
 
2016
 
2015
 
(In thousands)
Cash (used in) provided by:
 
 
 
Operating activities
$
(2,156
)
 
$
(6,593
)
Investing activities
5,108

 
18

Financing activities
385

 
3,204

Discontinued operations
(2,310
)
 
(11,319
)
Effect of exchange rate changes on cash and cash equivalents
(116
)
 
(661
)
Net increase (decrease) in cash and cash equivalents
$
911

 
$
(15,351
)
Cash used in operating activities during the year ended June 30, 2016, was $2.2 million, compared to $6.6 million for the year ended June 30, 2015. The decrease in cash used in operating activities primarily resulted from a decrease in general and administrative expenses (excluding stock-based compensation and foreign transaction loss) of $2.1 million, and an increase in accounts payable and accrued liabilities of continuing operations of $1.7 million.

46


Cash provided by investing activities during the year ended June 30, 2016, amounted to $5.1 million, compared to cash provided of $18 thousand in 2015. During fiscal year 2016, the Company received cash proceeds from the sale of the shares of Central and of the Mereenie Bonus of $2.6 million and $2.5 million, respectively.
Cash provided by financing activities during the year ended June 30, 2016, amounted to $0.4 million, compared to $3.2 million in 2015. During the fiscal year ended June 30, 2016, cash provided by financing activities primarily related to borrowings on notes payable to One Stone of $625 thousand, which were partially offset by principal payments on the Premium Notes of $195 thousand.
Cash used in discontinued operations during the year ended June 30, 2016, amounted to $2.3 million, compared to $11.3 million in the fiscal year ended June 30, 2015. Cash used in discontinued operations in fiscal year 2016 primarily related to operating losses at Poplar of $2.1 million. Cash used in discontinued operations in the prior fiscal year related to cash used in the operations of the Poplar field of $2.0 million and investing activities of $9.3 million, which were primarily related to the CO2-EOR pilot at Poplar.
During the year ended June 30, 2016, the effect of changes in foreign currency exchange rates negatively impacted the translation of our GBP and AUD denominated cash and cash equivalent balances into US dollars and resulted in a decrease of $116 thousand in cash and cash equivalents, compared to a decrease of $661 thousand in fiscal year 2015.
COMPARISON OF FINANCIAL RESULTS AND TRENDS BETWEEN FISCAL 2016 AND 2015
The following table presents results of continuing operations information for the fiscal years ended:
 
June 30,
 
 
 
 
 
2016
 
2015
 
Difference
 
Percent change
Selected operating expenses (USD):
(in thousands)
 
 
 
 
Depreciation
$
54

 
$
148

 
$
(94
)
 
(64
)%
Exploration
71

 
239

 
(168
)
 
(70
)%
General and administrative
5,214

 
7,946

 
(2,732
)
 
(34
)%
Depreciation expense. Depreciation expenses decreased by $94 thousand to $54 thousand, or (64)%, during the year ended June 30, 2016. The decrease in depreciation expense was due to certain assets becoming fully depreciated during the current year.
Exploration Expenses. Exploration expenses decreased by $168 thousand to $71 thousand, or (70)%, during the year ended June 30, 2016. Current year exploration expenses primarily consisted of $53 thousand related to the NT/P82 offshore license in Australia and $18 thousand related to the licenses for the HH-1 well in the UK. In the prior year, the Company incurred exploration expenses consisting of $148 thousand for related licenses in the UK and $91 thousand related to NT/P82 in Australia.
General and Administrative Expenses. The following table presents general and administrative expenses for the fiscal years ended:
 
June 30,
 
 
 
 
 
2016
 
2015
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
General and administrative (excluding stock-based compensation and foreign transaction loss)
$
4,279

 
$
6,420

 
$
(2,141
)
 
(33
)%
Stock-based compensation
701

 
891

 
(190
)
 
(21
)%
Foreign transaction loss
234

 
635

 
(401
)
 
(63
)%
Total
$
5,214

 
$
7,946

 
$
(2,732
)
 
(34
)%
During the year ended June 30, 2016, general and administrative expenses decreased by $2.7 million to $5.2 million. General and administrative expenses, excluding stock-based compensation and foreign transaction losses, amounted to $4.3

47


million, a decrease of $2.1 million. This decrease primarily resulted from i) decreased salaries and benefits of $684 thousand due to reductions in office staff, ii) reductions in legal and professional fees of $724 thousand related to the reverse stock split, the establishment of the ATM facility and the formation of Utah CO2 in the prior fiscal year, iii) a reduction of investor relations expenses of $119 thousand, iv) a decrease in travel of $202 thousand, v) a reduction in corporate fees and expenses of $162 thousand, primarily related to corporate franchise taxes, and vi) a decrease in general and administrative expenses in the Australia of $658 thousand. These reductions were partially offset by an increase in accrued retention bonuses of $425 thousand. The decrease in non-cash stock-based compensation expense is primarily related to a decrease in expenses recognized on performance-based equity awards to officers and employees due to various forfeitures that occurred during the fiscal year ended June 30, 2016. The foreign transaction loss was the result of the strengthening of the US dollar against the currencies of our foreign subsidiaries, the Australian dollar and the British pound. During fiscal year 2015, we settled intercompany loans from our foreign subsidiaries and recognized foreign transaction losses in relation to those loans that had previously been recorded as a component of other comprehensive income.
Results of discontinued operations. On March 31, 2016, the Company entered into the Exchange Agreement with One Stone, which closed on August 1, 2016. In addition, on June 10, 2016, MPUK entered into the Weald ATA and IoW ATA. Therefore, the results of operations of the CO2 Business and of the PEDLs disposed of pursuant to the Weald ATA and IoW ATA were reclassified to discontinued operations.
The following table presents the results of the Company's discontinued operations:
 
June 30,
 
 
 
 
 
2016
 
2015
 
Difference
 
Percent change
Poplar:
 
 
 
 
 
 
 
Oil revenue (in thousands)
$
1,990

 
$
4,459

 
$
(2,469
)
 
(55
)%
Oil sales volume (Mbbls)
60

 
79

 
(19
)
 
(24
)%
Oil sales volume (bopd)
164

 
217

 
(53
)
 
(24
)%
Average realized oil price ($/bbl)
$33.17
 
$56.44
 
$
(23.27
)
 
(41
)%
Oil Revenue
Revenues for the year ended June 30, 2016, totaled $2.0 million, compared to $4.5 million in the prior year, a decrease of 55%. Of the $2.5 million decrease in revenue from the prior year, $1.9 million was attributable to lower commodity prices and $0.6 million was related to lower production.
Oil Sales Volume
Sales volume for the year ended June 30, 2016, totaled 60 Mbbls (164 bopd), compared to 79 Mbbls (217 bopd) sold in the prior year, a decrease of 24%. The decrease was primarily the result of cost reductions at Poplar, which included shutting-in wells with high operating costs and the suspension of workovers, and the natural production decline of the field.
Average Realized Oil Price
The average realized price for the year ended June 30, 2016, was $33.17/bbl, compared to $56.44/bbl in the prior year, a decrease of 41%. The decrease was primarily the result of a decrease in the benchmark pricing (WTI), partially offset by an improvement in the differential realized at the Poplar field. The Company does not currently engage in any oil and gas hedging activities.

48


Operating and Other Expenses
The following table presents selected operating expenses related to the discontinued operations for the fiscal years ended:
 
June 30,
 
 
 
 
 
2016
 
2015
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Selected operating expenses:
 
 
 
 
 
 
 
Lease operating
$
2,560

 
$
5,089

 
$
(2,529
)
 
(50
)%
Depletion, depreciation, amortization, and accretion
$
651

 
$
1,001

 
$
(350
)
 
(35
)%
Impairment
$
11,280

 
$
17,353

 
$
(6,073
)
 
(35
)%
Exploration
$
240

 
$
1,324

 
$
(1,084
)
 
(82
)%
General and administrative
$
631

 
$
200

 
$
431

 
216
 %
 
 
 
 
 
 
 
 
Selected operating expenses ($/bbl):
 
 
 
 
 
 
 
Lease operating
43

 
64

 
(21
)
 
(33
)%
Depletion, depreciation, amortization, and accretion
11

 
13

 
(2
)
 
(15
)%
Impairment
188

 
220

 
(32
)
 
(15
)%
Exploration
4

 
17

 
(13
)
 
(76
)%
General and administrative
11

 
3

 
8

 
267
 %

Lease Operating Expenses. Lease operating expenses decreased by $2.5 million to $2.6 million, or $43/bbl, during the year ended June 30, 2016. The decrease in lease operating expenses is primarily related to a decrease in operating expenses commensurate with a reduction in production volumes, lower production taxes of $452 thousand as a result of lower commodity prices and production, as well as a decrease in workover expense of $287 thousand due to reduced activity.
Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the fiscal years ended:
 
June 30,
 
 
 
 
 
2016
 
2015
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Depreciation and amortization
$
31

 
$
51

 
$
(20
)
 
(39
)%
Depletion
449

 
779

 
(330
)
 
(42
)%
ARO accretion
171

 
171

 

 
 %
Total
$
651

 
$
1,001

 
$
(350
)
 
(35
)%

Depletion, depreciation, amortization, and accretion expenses decreased by $350 thousand to $651 thousand, or $11/bbl, during the year ended June 30, 2016. The decrease in depletion expenses was due to a decrease in the depletion rate, which resulted from the impairment of the Company's proved oil and gas properties during the fiscal year ended June 30, 2015, and to lower production.
Impairment of oil and gas properties. The Company recorded an impairment related to its oil and gas properties of $11.3 million as of March 31, 2016. The impairment was the result of an evaluation of the fair value of the net assets of NP in connection with the Exchange and transferring the assets to held for sale as of March 31, 2016. The decline in the fair value of its reserves was primarily due to a decline in commodity prices during fiscal year 2016. The Company also recorded an impairment of NP's proved oil and gas properties of $17.4 million in the prior fiscal year. The decline in the fair value of the reserves was due to i) lower commodity prices, and ii) the exclusion of PUD reserves from the classification of proved reserves due to the uncertainty related to the Company's ability to continue as a going concern and to obtain the necessary capital to fund its drilling program related to the development of the PUDs.
Exploration Expenses. Exploration expenses decreased by $1.1 million to $240 thousand, or $4/bbl, during the year ended June 30, 2016. The decrease in exploration expenses was primarily due to reduction in exploration activities related to

49


Utah CO2 of $687 thousand, NP for the evaluation of the CO2-EOR pilot of $230 thousand, and the Weald Basin prospects of $168 thousand.

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 consolidated 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 included in this report. 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 exploration expense as dry hole costs and included within the consolidated statement of operations. Exploration expenses include dry hole costs and geological and geophysical expenses. Exploration expenses are also 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"). The accuracy of our reserve estimates is a function of many factors, including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the reserves estimates. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve 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 consolidated 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 uneconomical 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 exploration and development program, as well as future economic conditions. Effective with the classification of the assets of the CO2 Business to held for sale on March 31, 2016, we have not recorded further depletion, depreciation and amortization of our oil and gas properties.
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

50


fair value. We compare the carrying value of properties to the expected future cash flows on an undiscounted basis using the expected future prices at the date of the assessment 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 a discount rate of 10% to calculate the net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment.
Asset Retirement Obligations. 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 after 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 in the month in which the delivery to the purchaser occurred and title transferred. We receive payment approximately one month 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 Company estimates the fair value of performance-based options ("PBOs") and time-based options ("TBOS") using the Black Scholes Merton pricing model. The fair value for market-based options ("MBOs") is estimated using Monte Carlo simulation techniques. The simplified method is used to estimate the expected term of stock options due to a lack of related historical data regarding exercise, cancellation, and forfeiture. The valuation methods used incorporate assumptions regarding expected volatility of our common stock, risk-free interest rates, expected term of the awards, and other assumptions regarding a number of complex and subjective variables, 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 TBOs are recognized as an expense on a straight-line basis over the vesting period. MBOs are expensed on a straight-line basis over the derived service period, even if the market condition is not achieved. PBOs are amortized on a straight-line basis between the date upon which the achievement of the relevant performance condition is deemed probable and the date the performance condition is expected to be achieved. Management re-assesses whether achievement of performance conditions is probable at the end of each reporting period. As of June 30, 2016, 332,028 stock options with market-based vesting provisions or PBOs were unvested. If changes in the estimated outcome of the performance conditions affect the quantity of the awards expected to vest, the cumulative effect of the change is recognized in the period of change.
Income Taxes and Uncertain Tax Positions
We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our consolidated financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of our deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions.
Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Previously recognized uncertain tax positions that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. There are no uncertain tax positions that would meet the more-likely-than-not recognition threshold as of and for the fiscal year ended June 30, 2016.
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, and the Company may not have sufficient net operating loss and foreign tax credit carry forwards available to offset any resulting tax liabilities.

51


Foreign Currencies and Foreign Currency Adjustment of Intercompany Loans
When intercompany foreign currency transactions between entities included in the consolidated financial statements are of a long-term investment nature (i.e., those for which settlement is not planned or anticipated in the foreseeable future) foreign currency translation adjustments resulting from those transactions are included in stockholders' equity as accumulated other comprehensive income. When intercompany transactions are deemed to be of a short-term nature, translation adjustments are required to be included in the consolidated statements of operations.
A component of accumulated other comprehensive income will be released into income when the Company executes a partial or complete sale of an investment in a foreign subsidiary or a group of assets of a foreign subsidiary considered a business and/or when the Company no longer holds a controlling financial interest in a foreign subsidiary or group of assets of a foreign subsidiary considered a business. In the event certain intercompany transactions and/or investments are no longer considered long term in nature, any subsequent foreign currency translation adjustments associated with such items could be required to be reflected in the Company's future statements of operations. Accordingly, if foreign currency translation adjustments are required to be reported in our future statements of operations, exchange rate volatility could have a significant effect on future period results of operations.
During the year ended June 30, 2015, the Company made a determination that it was no longer permanently invested in its foreign subsidiaries because (i) the Company had begun an effort to repay its intercompany balances through the repatriation of cash from these subsidiaries and (ii) the Company was increasingly focusing on its US operations. As such, the Company recorded on its statement of operations an expense reclassification from accumulated other comprehensive income arising from foreign currency exchange losses on its intercompany account balances.
Accounting for Business Combinations
The Company has signed an agreement and plan of merger with Tellurian and River Merger Sub, Inc., whereby Tellurian will become the accounting acquirer. We have accounted for all of our business combinations to date in accordance with guidelines established by the Financial Accounting Standards Board, using the acquisition method of accounting, which involves the use of significant judgment.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate, adjusted for risk, determined to be appropriate at the time of the acquisition.
The calculation of the contingent consideration payable is a significant management estimate and is calculated using production projections and the estimated timing of production payouts. The Company also utilizes a discount which is consistent with the Company's credit-adjusted incremental borrowing rate.
Authoritative Accounting Matters
See "Recently Issued Accounting Standards" under Note 1 for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8: Financial Statements and Supplementary Data of this Form 10-K.

MANAGEMENT ANALYSIS OF CERTAIN MARKET RISK ISSUES
The Company is exposed to market risk in the form of foreign currency exchange rate risk, commodity price risk related to world prices for crude oil, and equity price risk related to investments in marketable securities. The exchange rates between the Australian dollar and the US dollar and the exchange rates between the US dollar and the British pound have changed in recent periods, and may fluctuate substantially in the future. Any appreciation of the US dollar against the Australian dollar is likely to result in decreased 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 Australian and US dollars could have a negative impact on our business, operating results, and financial condition.
For the twelve months ended June 30, 2016, oil sales represented 100% of total oil and gas revenues, which are included in discontinued operations. Based on fiscal year 2016 sales volume and revenues, a 10% change in oil price would increase or decrease oil revenues by $0.2 million. All oil and gas revenues are related to the oil and gas properties of Poplar. As a result of the closing of the Exchange with One Stone on August 1, 2016, the oil and gas properties of Poplar were disposed of as of that date.

52


At June 30, 2016, the fair value of our investments in securities available-for-sale was $601 thousand, with all of that amount attributable to the 39.5 million shares of Central received as part of the consideration for the sale of the Amadeus Basin assets. Central's stock is traded on the Australian Securities Exchange (the "ASX"), and we determined the fair value of our investment in Central using Central's closing stock price on the ASX on June 30, 2016, of AUD $0.098 per share, which translated to $0.073 per share in US dollars on that date. As of the date of this report, the Company continues to own approximately 8.2 million shares of Central, which at the current share price of approximately AUD $0.096 and assuming a foreign exchange rate of 0.761 US dollars per AUD, represent approximately $602 thousand of potential liquidity. Due to the number of Central shares that we own and Central's general daily trading volumes, we may not be able to obtain the currently quoted market price in the event we sell our Central shares. In addition, a 10% across-the-board change in the underlying equity market price per share for our investment would result in a $60 thousand change in the fair value of our investments.
At June 30, 2016, the carrying value of cash and cash equivalents was approximately $1.7 million, which approximates the fair value.
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words "anticipate," "assume," "believe," "budget," "could," "estimate," "expect," "forecast," "initial," "intend," "may," "plan," "potential," "project," "should," "will," "would," and similar expressions are intended to identify forward-looking statements.
These forward looking statements about the Company and its subsidiaries appear in a number of places in this report and may relate to statements about the merger with Tellurian, including the terms of the merger agreement, the tax implications of the merger, the closing of the transaction, the timing of such closing and the effects of closing; our businesses and prospects; our ability to continue as a going concern; planned or estimated capital expenditures; availability of liquidity and capital resources; the disposition of oil and gas properties and related assets or other securities investments; the ability to enter into acceptable farmout arrangements; revenues, expenses, operating cash flows and projected cash burn rates; progress in developing the Company's projects; future values of those projects or other interests or rights that the Company holds; the listing of our common stock on the NASDAQ; borrowings; commodity prices; government regulations; and other matters that involve a number of risks and uncertainties that may cause actual results to differ materially from results expressed or implied in the forward-looking statements. These risks and uncertainties include the following: risks associated with our ability to complete the merger with Tellurian on the terms anticipated or at all; the uncertain nature of oil and gas prices in the UK and Australia, including uncertainties about the duration of the currently depressed oil commodity price environment and the related impact on our project developments and ability to obtain financing; uncertainties regarding our ability to maintain sufficient liquidity and capital resources to implement our projects or otherwise continue as a going concern; uncertainties regarding the ability to realize the expected benefits from the sale of the Amadeus Basin assets to Central pursuant to the Sale Deed, including through the future value of Central stock; uncertainties regarding the value of Central stock; our ability to attract and retain key personnel; our limited amount of control over activities on our non-operated properties; our reliance on the skill and expertise of third-party service providers; the ability of our vendors to meet their contractual obligations; the uncertain nature of the anticipated value and underlying prospects of our UK acreage position; government regulation and oversight of drilling and completion activity in the UK, including possible restrictions on hydraulic fracturing that could affect our ability to realize value from unconventional resource projects in the UK; the uncertainty of drilling and completion conditions and results; the availability of drilling, completion, and operating equipment and services; the results and interpretation of 2-D and 3-D seismic data related to our NT/P82 interest in offshore Australia and our ability to obtain an attractive farmout arrangement for NT/P82; uncertainties regarding our ability to maintain the NASDAQ listing of our common stock, and the related potential impact on our ability to obtain financing; risks and uncertainties inherent in management estimates of future operating results and cash flows; risks and uncertainties associated with litigation matters; and other matters referred to in the Risk Factors section of this report. For a more complete discussion of the risk factors that may apply to any forward-looking statements, you are directed to the discussion presented in Item 1A ("Risk Factors") of this Form 10-K. Any forward-looking statements in this report should be considered with these factors in mind. Any forward-looking statements in this report speak as of the filing date of this report. The Company assumes no obligation to update any forward looking statements contained in this report, whether as a result of new information, future events or otherwise, except as required by securities laws.

53



ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.


54



ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Stockholders of
Magellan Petroleum Corporation
Denver, Colorado

We have audited the consolidated balance sheets of Magellan Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2016 and 2015, and the related consolidated statements of operations, comprehensive loss, stockholders’ (deficit) equity, and cash flows for each of the years ended June 30, 2016 and 2015. Magellan Petroleum Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Magellan Petroleum Corporation and subsidiaries as of June 30, 2016 and 2015, and the results of their operations and their cash flows for each of the years ended June 30, 2016 and 2015, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations and negative cash flows from operations which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As described in Notes 2 and 3 to the consolidated financial statements, subsequent to June 30, 2016, the Company entered into certain transactions to dispose of substantially all of its operating assets. In connection therewith, the Company has provided certain unaudited pro forma financial information in Note 21 to the consolidated financial statements, which reflect the impacts of those significant events. The information within Note 21 is unaudited and we express no assurance or opinion over the pro forma financial information.


/s/ EKS&H LLLP
September 13, 2016
Denver, Colorado




55


MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
 
June 30,
 
2016
 
2015
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
1,680

 
$
769

Securities available-for-sale
601

 
4,230

Accounts receivable 
16

 
46

Prepaid and other assets
2,087

 
2,023

Current assets held for sale (Note 4)
26,042

 
1,514

Total current assets
30,426

 
8,582

 
 
 
 
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
 
 
 
Unproved oil and gas properties
32

 
38

Wells in progress
337

 
350

Land, buildings, and equipment (net of accumulated depreciation of $517 and $463 as of June 30, 2016, and 2015, respectively)
86

 
139

Property and equipment held for sale (Note 4)

 
36,546

Net property and equipment
455

 
37,073

 
 
 
 
OTHER NON-CURRENT ASSETS:
 
 
 
Goodwill, net
500

 
500

Other long-term assets
169

 
169

Long-term assets held for sale (Note 4)

 
376

Total other non-current assets
669

 
1,045

Total assets
$
31,550

 
$
46,700

 
 
 
 
LIABILITIES AND STOCKHOLDERS' (DEFICIT) EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
791

 
$
298

Accrued and other liabilities
2,826

 
2,119

Notes payable
783

 

Current liabilities held for sale (Note 4)
10,638

 
2,237

Total current liabilities
15,038

 
4,654

 
 
 
 
LONG-TERM LIABILITIES:
 
 
 
Long-term liabilities held for sale (Note 4)

 
8,251

Total long-term liabilities

 
8,251


56


COMMITMENTS AND CONTINGENCIES (Note 16)


 


 
 
 
 
PREFERRED STOCK (Note 12):
 
 
 
Series A convertible preferred stock (par value $0.01 per share): Authorized 28,000,000 shares; issued and outstanding 22,683,428 and 21,162,697 shares as of June 30, 2016, and 2015, respectively; liquidation preference of $29,093 and $28,435, respectively
23,501

 
25,850

Total preferred stock
23,501

 
25,850

 
 
 
 
STOCKHOLDERS' (DEFICIT) EQUITY:
 
 
 
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, issued 6,972,023 and 6,917,027 as of June 30, 2016, and 2015, respectively
70

 
69

Treasury stock (at cost): 1,209,389 shares as of June 30, 2016, and 2015
(9,806
)
 
(9,806
)
Capital in excess of par value
94,069

 
93,386

Accumulated deficit
(96,234
)
 
(81,006
)
Accumulated other comprehensive income
4,912

 
5,302

Total stockholders' (deficit) equity
(6,989
)
 
7,945

Total liabilities, preferred stock and stockholders' (deficit) equity
$
31,550

 
$
46,700


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

57


MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per share amounts)
 
For the years ended June 30,
 
2016
 
2015
OPERATING EXPENSES:
 
 
 
Depreciation
$
54

 
$
148

Exploration
71

 
239

General and administrative
5,214

 
7,946

Loss on sale of assets

 
316

Total operating expenses
5,339

 
8,649

 
 
 
 
Loss from operations
(5,339
)
 
(8,649
)
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
Net interest expense
(4
)
 

Loss on investment in securities
(587
)
 
(15,087
)
Gain on sale of bonus rights (Note 5)
2,514

 

Fair value revision of contingent consideration payable

 
1,888

Other income
88

 
252

Total other income (expense)
2,011

 
(12,947
)
 
 
 
 
Loss from continuing operations, before tax
(3,328
)
 
(21,596
)
Income tax expense

 

 
 
 
 
Loss from continuing operations, net of tax
(3,328
)
 
(21,596
)
 
 
 
 
DISCONTINUED OPERATIONS (Note 4):
 
 
 
Loss from discontinued operations, net of tax
(14,249
)
 
(21,404
)
Net loss from discontinued operations
(14,249
)
 
(21,404
)
 
 
 
 
Net loss
(17,577
)
 
(43,000
)
 
 
 
 
Preferred stock dividends
(1,858
)
 
(1,740
)
Adjustment of preferred stock to redemption value (Note 12)
4,207

 

 
 
 
 
Net loss attributable to common stockholders
$
(15,228
)
 
$
(44,740
)
 
 
 
 
Loss per common share (Note 14):
 
 
 
Weighted average number of basic shares outstanding
5,746,307

 
5,710,288

Weighted average number of diluted shares outstanding
5,746,307

 
5,710,288

 
 
 
 
Basic and diluted loss per common share:
 
 
 
Net loss from continuing operations, including preferred stock dividends and adjustment to redemption value of preferred stock
$(0.17)
 
$(4.09)
Net loss from discontinued operations
$(2.48)
 
$(3.75)
Net loss attributable to common stockholders
$(2.65)
 
$(7.83)

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

58


MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
 
For the years ended June 30,
 
2016
 
2015
Net loss
$
(17,577
)
 
$
(43,000
)
 
 
 
 
Other comprehensive (loss) income, net of tax:
 
 
 
Foreign currency translation loss
(125
)
 
(2,141
)
Reclassification of foreign currency translation loss on intercompany account balances to earnings upon reversal of permanent investment in foreign subsidiaries

 
659

Reclassification of impairment loss on securities available-for-sale to earnings due to determination as other than temporary

 
15,087

Unrealized holding losses on securities available-for-sale
(265
)
 
(6,294
)
Other comprehensive (loss) income, net of tax
(390
)
 
7,311


 
 
 
Comprehensive loss
$
(17,967
)
 
$
(35,689
)

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


59


MAGELLAN PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' (DEFICIT) EQUITY
(In thousands, except share and per share amounts)
 
Common Stock
 
Capital in Excess of Par Value
 
Treasury Stock
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income
 
Total Stockholders' (Deficit) Equity
 
Shares
 
Amount
 
 
 
 
 
Fiscal year ended June 30, 2014
6,875,605

 
$
69

 
$
93,467

 
$
(9,344
)
 
$
(36,266
)
 
$
(2,009
)
 
$
45,917

Net loss

 

 

 

 
(43,000
)
 

 
(43,000
)
Other comprehensive income, net of tax

 

 

 

 

 
7,311

 
7,311

Stock and stock-based compensation
30,791

 

 
1,606