TELLURIAN INC. /DE/ - Quarter Report: 2015 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(MARK ONE)


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

For the quarterly period ended March 31, 2015


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

For the transition period from to

Commission File Number 001-5507

MAGELLAN PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Delaware	06-0842255
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 1950, Denver, CO	80203
(Address of principal executive offices)	(Zip Code)

(720) 484-2400

(Registrant's telephone number, including area code)

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. þ Yes ¨ 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). þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No

The number of shares outstanding of the issuer's single class of common stock as of May 13, 2015 was 45,701,107, which is net of 9,675,114 treasury shares held by the registrant.

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ITEM		PAGE
	PART I — FINANCIAL INFORMATION

ITEM 1	FINANCIAL STATEMENTS (UNAUDITED)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Comprehensive (Loss) Income	3
	Condensed Consolidated Statement of Stockholders' Equity	4
	Condensed Consolidated Statements of Cash Flows	5
	Notes to Condensed Consolidated Financial Statements	7
ITEM 2	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38
ITEM 4	CONTROLS AND PROCEDURES	38

	PART II — OTHER INFORMATION
ITEM 1	LEGAL PROCEEDINGS	39
ITEM 1A	RISK FACTORS	39
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 5	OTHER INFORMATION	40
ITEM 6	EXHIBITS	41
	SIGNATURES	43

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PART I - FINANCIAL INFORMATION

ITEM 1 FINANCIAL STATEMENTS (UNAUDITED)

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share amounts)



	March 31, 2015			June 30, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,031		$	16,422
Securities available-for-sale	4,122			11,935
Accounts receivable — trade	287			886
Accounts receivable — working interest partners	218			—
Inventories	656			739
Prepaid and other assets	1,899			2,105
Total current assets	10,213			32,087

PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Proved oil and gas properties	29,850			29,335
Less accumulated depletion, depreciation, and amortization	(4,056		)	(3,575		)
Unproved oil and gas properties	695			550
Wells in progress	27,464			21,296
Land, buildings, and equipment (net of accumulated depreciation of $633 and $483 as of March 31, 2015, and June 30, 2014, respectively)	248			368
Net property and equipment	54,201			47,974

OTHER NON-CURRENT ASSETS:
Goodwill	1,174			1,174
Other long term assets	571			200
Total other non-current assets	1,745			1,374
Total assets	$	66,159		$	81,435

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Short term line of credit	$	3,501		$	—
Current portion of asset retirement obligations	356			397
Accounts payable	3,283			3,586
Accrued and other liabilities	2,109			2,121
Accrued dividends	—			429
Total current liabilities	9,249			6,533

LONG TERM LIABILITIES:
Asset retirement obligations, net of current portion	2,596			2,476
Contingent consideration payable	—			1,852
Other long term liabilities	126			118
Total long term liabilities	2,722			4,446



COMMITMENTS AND CONTINGENCIES (Note 15)

PREFERRED STOCK (Note 10):
Series A convertible preferred stock (par value $0.01 per share): Authorized 28,000,000 shares, issued 20,798,719 and 20,089,436 as of March 31, 2015, and June 30, 2014, respectively; liquidation preference of $29,217 and $28,220 as of March 31, 2015, and June 30, 2014, respectively	25,406			24,539
Total preferred stock	25,406			24,539

EQUITY:
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, issued, 55,376,221 and 55,004,838 as of March 31, 2015, and June 30, 2014, respectively	554			550
Treasury stock (at cost): 9,675,114 and 9,425,114 shares as of March 31, 2015, and June 30, 2014, respectively	(9,806		)	(9,344		)
Capital in excess of par value	92,851			92,986
Accumulated deficit	(45,020		)	(36,266		)
Accumulated other comprehensive loss	(9,879		)	(2,009		)
Total equity attributable to Magellan Petroleum Corporation	28,700			45,917
Non-controlling interest in subsidiary	82			—
Total equity	28,782			45,917
Total liabilities, preferred stock and equity	$	66,159		$	81,435

The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except share and per share amounts)



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
REVENUE FROM OIL PRODUCTION	$	688		$	1,907		$	3,543		$	5,674

OPERATING EXPENSES:
Lease operating	1,417			1,397			3,901			4,714
Depletion, depreciation, amortization, and accretion	246			337			761			956
Exploration	368			1,605			1,276			2,776
General and administrative	2,664			1,588			7,190			6,411
Loss on investment in securities	168			—			168			—
Total operating expenses	4,863			4,927			13,296			14,857

Loss from operations	(4,175		)	(3,020		)	(9,753		)	(9,183		)

OTHER INCOME (EXPENSE):
Net interest expense	(25		)	(80		)	(42		)	(103		)
Fair value revision of contingent consideration payable	1,888			—			1,888			—
Other income (expense)	75			28			157			(78		)
Total other income (expense)	1,938			(52		)	2,003			(181		)

Loss from continuing operations, before tax	(2,237		)	(3,072		)	(7,750		)	(9,364		)
Income tax expense	(43		)	—			(43		)	—
Loss from continuing operations, net of tax	(2,280		)	(3,072		)	(7,793		)	(9,364		)

DISCONTINUED OPERATIONS:
Loss from discontinued operations, net of tax	—			(2,589		)	—			(5,245		)
Gain on disposal of discontinued operations, net of tax	—			30,182			—			30,182
Net income from discontinued operations	—			27,593			—			24,937

Net (loss) income	(2,280		)	24,521			(7,793		)	15,573

Net loss attributable to non-controlling interest in subsidiary	165			—			335			—

Net (loss) income attributable to Magellan Petroleum Corporation	(2,115		)	24,521			(7,458		)	15,573

Preferred stock dividends	(437		)	(432		)	(1,296		)	(1,267		)

Net (loss) income attributable to common stockholders	$	(2,552	)	$	24,089		$	(8,754	)	$	14,306

(Loss) income per common share (Note 12):
Weighted average number of basic shares outstanding	45,701,107			45,348,709			45,677,673			45,348,753
Weighted average number of diluted shares outstanding	45,701,107			45,348,709			45,677,673			45,348,753

Basic and diluted loss per common share:
Net loss from continuing operations attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.06)			$(0.08)			$(0.19)			$(0.23)
Net income from discontinued operations	$0.00			$0.61			$0.00			$0.55
Net (loss) income attributable to common stockholders	$(0.06)			$0.53			$(0.19)			$0.32

The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (UNAUDITED)

(In thousands)



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
Net (loss) income	$	(2,280	)	$	24,521		$	(7,793	)	$	15,573

Other comprehensive (loss) income, net of tax:
Foreign currency translation (loss) gain	(431		)	823			(2,262		)	744
Reclassification of foreign currency translation loss on intercompany account balances to earnings upon reversal of permanent investment in foreign subsidiaries	659			—			659			—
Reclassification of foreign currency translation gain to earnings upon sale of subsidiary	—			(6,049		)	—			(6,049		)
Reclassification of impairment loss on securities available-for-sale to earnings due to determination as other than temporary	168			—			168			—
Unrealized holding (loss) gain on securities available-for-sale	1,339			1,004			(6,435		)	1,012
Other comprehensive (loss) income, net of tax	1,735			(4,222		)	(7,870		)	(4,293		)
Comprehensive (loss) income	$	(545	)	$	20,299		$	(15,663	)	$	11,280

The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)

(In thousands)



	Common Stock			Treasury Stock			Capital in Excess of Par Value			Accumulated Deficit			Accumulated Other Comprehensive Loss			Non-controlling Interest			Total Stockholders' Equity
June 30, 2014	$	550		$	(9,344	)	$	92,986		$	(36,266	)	$	(2,009	)	$	—		$	45,917
Formation of Utah CO2 LLC	—			—			—			—			—			96			$	96
Contributions to Utah CO2 LLC	—			—			—			—			—			321			$	321
Net loss	—			—			—			(7,458		)	—			(335		)	$	(7,793	)
Other comprehensive loss, net of tax	—			—			—			—			(7,870		)	—			$	(7,870	)
Stock and stock based compensation	2			—			1,313			—			—			—			$	1,315
Executive and employee forfeiture of options upon resignation	—			—			(430		)	—			—			—			$	(430	)
Executive forfeiture of restricted stock upon resignation	(1		)	—			(43		)	—			—			—			$	(44	)
Purchase of stock and options from former executive	—			(462		)	(983		)							—			$	(1,445	)
Net shares repurchased for employee tax costs upon vesting of restricted stock	—			—			(104		)	—			—			—			$	(104	)
Stock options exercised, net of shares withheld to satisfy employee tax obligations	3			—			112			—			—			—			$	115
Preferred stock dividend	—			—			—			(1,296		)	—			—			$	(1,296	)
March 31, 2015	$	554		$	(9,806	)	$	92,851		$	(45,020	)	$	(9,879	)	$	82		$	28,782

The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)



	NINE MONTHS ENDED
	March 31,
	2015			2014
OPERATING ACTIVITIES:
Net (loss) income	$	(7,793	)	$	15,573
Adjustments to reconcile net (loss) income to net cash used in operating activities:
Foreign transaction loss	659			—
Depletion, depreciation, amortization, and accretion	761			956
Fair value revision of contingent consideration payable	(1,888		)	—
Accretion expense of contingent consideration payable	36			234
Inventory book to physical adjustment	123			—
Loss on investment in securities	168			—
Gain on disposal of Amadeus Basin assets	—			(30,182		)
Exploration costs previously capitalized	20			733
Stock compensation expense	841			1,667
Net changes in operating assets and liabilities:
Accounts receivable	542			(64		)
Inventories	(86		)	165
Prepayments and other current assets	162			(410		)
Accounts payable and accrued liabilities	(65		)	473
Net cash used in operating activities of continuing operations	(6,520		)	(10,855		)

INVESTING ACTIVITIES:
Additions to property and equipment	(7,157		)	(16,710		)
Utah CO₂ option	(371		)	—
Proceeds from first cash installment for the sale of Amadeus Basin assets	—			13,859
Net cash used in investing activities of continuing operations	(7,528		)	(2,851		)

FINANCING ACTIVITIES:
Purchase of common stock	(566		)	(11		)
Purchase of stock options	(983		)	—
Proceeds from issuance of common stock, net	115			—
Payment of preferred stock dividend	(859		)	—
Borrowings (repayments) on line of credit, net	3,501			—
Short term debt issuances	—			1,000
Short term debt repayments	—			(1,303		)
Capital contributions by non-controlling interest	147			—
Net cash provided by (used in) financing activities of continuing operations	1,355			(314		)

CASH FLOWS FROM DISCONTINUED OPERATIONS:
Adjustments to reconcile net loss to net cash provided by operating activities of discontinued operations	—			1,366
Net cash used in investing activities of discontinued operations	—			(1,265		)
Net cash provided by discontinued operations	—			101

Effect of exchange rate changes on cash and cash equivalents	(698		)	464
Net decrease in cash and cash equivalents	(13,391		)	(13,455		)

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Cash and cash equivalents at beginning of period	16,422			32,469
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,031		$	19,014

Supplemental disclosure of cash flow information:
Cash paid for interest	$	33		$	28
Cash paid for income taxes	$	43		$	—

Supplemental schedule of non-cash activities:
Unrealized holding loss and foreign currency translation loss on securities available-for-sale	$	(7,813	)	$	922
Change in accounts payable and accrued liabilities related to property and equipment	$	(666	)	$	1,070
Preferred stock dividends paid in kind	$	867		$	1,038
Increase in both accrued or other liabilities and prepaid or other assets related to Sopak	$	79		$	545
Property contributed for capital contribution of non-controlling interest	$	102		$	—
Property contributed for deferred capital contribution of non-controlling interest	$	98		$	—
Accrued capital contributions of non-controlling interest	$	168		$	—

The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Basis of Presentation

Description of Operations

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we") is an independent oil and gas exploration and production company focused on the development of CO₂-enhanced oil recovery ("CO₂-EOR") projects in the Rocky Mountain region. Historically active internationally, Magellan also owns significant exploration acreage in the Weald Basin, onshore UK, and an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia, which the Company currently plans to farmout.

The Company conducts its operations through three wholly owned subsidiaries corresponding to the geographical areas in which the Company operates: Nautilus Poplar LLC ("NP") in the US, Magellan Petroleum (UK) Limited ("MPUK"), and Magellan Petroleum Australia Pty Ltd ("MPA").

Our strategy is to enhance shareholder value by maximizing the value of our CO₂-EOR business and our international projects. We are committed to efficiently investing financial, technical, and management capital in our projects in order to achieve the greatest risk-adjusted value and returns for our shareholders.

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

Our principal executive offices are located at 1775 Sherman Street, Suite 1950, Denver, Colorado 80203, and our phone number is (720) 484-2400.

Principles of Consolidation and Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP, MPUK, and MPA, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X published by the US Securities and Exchange Commission (the "SEC"). Accordingly, these interim unaudited condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete annual period financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature. All intercompany transactions have been eliminated. Operating results for the nine months ended March 31, 2015, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2015. This report should be read in conjunction with the consolidated financial statements and footnotes thereto included in the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2014 (the "2014 Form 10-K"). All amounts presented are in US dollars, unless otherwise noted. Amounts expressed in Australian currency are indicated as "AUD."

Certain amounts in our prior period financial statements have been reclassified to conform to the current period presentation.

During the nine months ended March 31, 2015, the Company formed a majority owned subsidiary, Utah CO2 LLC, a Delaware limited liability company ("Utah CO2"), through which the Company purchased an option to acquire CO₂ at Farnham Dome in Utah. The Company owns a controlling 51% of the equity in Utah CO2 and consolidates this entity in the accompanying condensed consolidated financial statements. The remaining 49% is owned by two separate third parties. Another third-party owns a 10% economic participation interest in the Company's equity interest in Utah CO2, which participation interest does not bear any governance rights over the Company's investment in Utah CO2. The non-controlling interest reported in the accompanying condensed consolidated financial statements relates to the non-controlling interest in this entity, including the participation interest.

The Company owns an 11% interest in Central Petroleum Limited (ASX:CTP) ("Central"), a Brisbane-based exploration and production company traded on the Australian Securities Exchange. The Company accounts for this investment as securities available-for-sale in the accompanying condensed consolidated financial statements.

Use of Estimates

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities,

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disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements, and the reported amounts of revenues and expenses, including stock-based compensation expense, during the reporting periods. Actual results could differ from those estimates.

Foreign Currency Translation

The functional currency of our foreign subsidiaries is their local currency. Assets and liabilities of foreign subsidiaries are translated to US dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the reporting periods. Resulting translation adjustments are recorded in accumulated other comprehensive loss, a separate component of stockholders' equity. A component of accumulated other comprehensive loss 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.

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

During the three months ended March 31, 2015, the Company made a determination that it was no longer permanently invested in its foreign subsidiaries because (i) the Company has begun an effort to repay its intercompany balances through the repatriation of cash from these subsidiaries and (ii) the Company is increasingly focusing on its US operations. As such, the Company recorded on its statement of operations an expense reclassification from accumulated other comprehensive loss arising from foreign currency exchange losses on its intercompany account balances.

Securities available-for-sale

Securities available-for-sale are comprised of investments in publicly traded securities and are carried at quoted market prices. Unrealized gains and losses are excluded from earnings and recorded as a component of accumulated other comprehensive loss in stockholders' equity, net of deferred income taxes. The Company recognizes gains or losses when securities are sold. On a quarterly basis, we perform an assessment to determine whether there have been any events or economic circumstances to indicate that a security with an unrealized loss has suffered other-than-temporary impairment. As a result of this review, during the nine months ended March 31, 2015, a loss of $168 thousand was recognized. Refer to Note 4 - Securities Available-for-Sale for further information. No impairment was recorded during the nine months ended March 31, 2014.

Oil and Gas Exploration and Production Activities

The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, all property acquisition costs, and costs of exploratory and development wells are capitalized until a determination is made that the well has found proved reserves or is deemed noncommercial. If an exploratory well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost. Exploration expenses include dry hole costs, geological and geophysical expenses. Noncommercial development well costs are charged to impairment expense if circumstances indicate that a decline in the recoverability of the carrying value may have occurred.

The Company records its proportionate share in joint venture operations in the respective classifications of assets, liabilities, and expenses. The cost of CO₂ injection is capitalized until a production response is seen as a result of the injection and it is determined that the well has found proved reserves. After oil production from the well begins, CO₂ injection costs are expensed as incurred.

Depreciation, depletion, and amortization ("DD&A") of capitalized costs related to proved oil and gas properties is calculated on a property-by-property basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.

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

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The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs, using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. The Company undertook such a review during the quarter ended March 31, 2015, as a result of the recent decline in oil prices and concluded that no impairment was needed as of March 31, 2015.

Asset Retirement Obligations

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

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is probable. Transportation costs, if and when they arise, are included in lease operating expenses.

Major Customers

The Company's consolidated oil production revenue is derived from its NP segment and was generated from a single customer for the nine months ended March 31, 2015 and 2014.

Stock Based Compensation

Stock option grants may contain time based, market based, or performance based vesting provisions. Time based options ("TBOs") are expensed on a straight-line basis over the vesting period. Market based options ("MBOs") are expensed on a straight-line basis over the derived service period, even if the market condition is not achieved. Performance based options ("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. 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.

The fair value of the stock options is determined on the grant date and is affected by our stock price and other assumptions regarding a number of complex and subjective variables. These variables include our expected stock price volatility over the term of the awards, risk free interest rates, expected dividends, and the expected option exercise term. The Company estimates the fair value of PBOs and time based stock options using the Black-Scholes-Merton pricing model. 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. For MBOs, the fair value is estimated using Monte Carlo simulation techniques.

Accumulated Other Comprehensive Loss

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

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Loss per Common Share

Income and losses per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The effects of potential dilutive securities in the determinations of diluted earnings per share are the dilutive effects of stock options, non-vested restricted stock, and the shares of Series A convertible preferred stock.

The potential dilutive impact of stock options and non-vested restricted stock is determined using the treasury stock method. The potential dilutive impact of the shares of Series A convertible preferred stock is determined using the "if-converted" method. In applying the if-converted method, conversion is not assumed for purposes of computing dilutive shares if the effect would be antidilutive. The Series A convertible preferred stock is convertible at a rate of one common share for one preferred share. We did not include any stock options, non-vested restricted stock, or common stock issuable upon the conversion of the Series A convertible preferred stock in the calculation of diluted loss per share during the three and nine months ended March 31, 2015, and 2014, as their effect would have been antidilutive.

Segment Information

As of June 30, 2013, the Company determined, based on the criteria of ASC Topic 280, that it operates in three segments, NP, MPUK, and MPA, as well as a head office, Magellan ("Corporate"), which is treated as a cost center.

The Company's chief operating decision maker is J. Thomas Wilson (President and CEO of the Company), who reviews the results and manages operations of the Company in the three reporting segments of NP, MPUK, and MPA, as well as Corporate. For information pertaining to our reporting segments, see Note 13 - Segment Information, and Part II, Item 8 of our 2014 Form 10-K.

Recently Issued Accounting Standards

In August 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-15, Presentation of Financial Statements - Going Concern. The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. The Company is evaluating the impact of the adoption of this standard on its condensed consolidated financial statements.

In June 2014, the FASB issued ASU No. 2014-12, “Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period.” ASU 2014-12 requires a reporting entity to treat a performance target that affects vesting and that could be achieved after the requisite service period as a performance condition. It is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted. ASU 2014-12 may be adopted either prospectively for share-based payment awards granted or modified on or after the effective date, or retrospectively, using a modified retrospective approach. The modified retrospective approach would apply to share-based payment awards outstanding as of the beginning of the earliest annual period presented in the financial statements on adoption, and to all new or modified awards thereafter. The Company has chosen to early adopt this standard retrospectively to July 1, 2013, which adoption did not impact the Company's condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. The ASU allows for the use of either the full or modified retrospective transition method, and the standard as written will be effective for us in the first quarter of our fiscal year 2018 unless a deferral for adoption is provided by the FASB; early adoption is not permitted. In April, 2015, the FASB issued a proposed ASU that would defer adoption of ASU 2014-09 by one year. If the proposed ASU is adopted, ASU 2014-9 will be effective for us in the first quarter of our fiscal year 2019. The Company is currently evaluating which transition approach to use and the impact of the adoption of this standard on its condensed consolidated financial statements.

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Note 2 - Sale of Amadeus Basin Assets

On March 31, 2014 (the "Central Closing Date"), pursuant to the Share Sale and Purchase Deed dated February 17, 2014 (the "Sale Deed"), the Company sold its Amadeus Basin assets, the Palm Valley and Dingo gas fields ("Palm Valley" and "Dingo," respectively), to Central through the sale of the Company's wholly owned subsidiary, Magellan Petroleum (N.T.) Pty. Ltd ("MPNT"), to Central's wholly owned subsidiary Central Petroleum PV Pty. Ltd ("Central PV"). In exchange for the assets, Central paid to Magellan (i) AUD $20,000 thousand, (ii) customary purchase price adjustments amounting to AUD $800 thousand; and (iii) 39.5 million newly issued shares of Central stock (ASX: CTP), equivalent to an ownership interest in Central of approximately 11%.

The Sale Deed also provides that 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 ("GJ") and AUD $6.00/GJ for the first 10 years following the Central Closing Date and for the following 5 years, respectively, with such prices to be escalated in accordance with the Australian CPI. Between the third and fifth anniversaries of the Central Closing Date, inclusive, the Company may seek from Central a one-time payment (the "Bonus Discharge Amount") corresponding to the present value, assuming an annual discount rate of 10%, of any expected remaining bonus payments in exchange for foregoing future bonus payments. If the Company receives the Bonus Discharge Amount, bonus payments and the Bonus Discharge Amount together may not exceed AUD $7,000 thousand. The Company also retained its rights to receive any and all bonuses (the "Mereenie Bonus") payable by Santos Ltd ("Santos") and contingent upon production at the Mereenie oil and gas field achieving certain threshold levels. The Mereenie Bonus was established in 2011 pursuant to the terms of the asset swap agreement between the Company and Santos for the sale of the Company's interest in Mereenie to Santos and the Company's purchase of the interests of Santos in the Palm Valley and Dingo gas fields. For additional information, see Note 3 - Discontinued Operations.

Note 3 - Discontinued Operations

As discussed in detail in Note 2 - Sale of Amadeus Basin Assets, on March 31, 2014, pursuant to the Sale Deed, the Company completed the sale of Palm Valley and Dingo to Central PV. The assets of Palm Valley and Dingo were previously reported under the MPA segment. Accordingly, MPA's results of operations associated with this sale were reclassified to discontinued operations in the third quarter of fiscal year 2014. Prior period amounts related to discontinued operations in the unaudited condensed consolidated statement of operations and statement of cash flows have also been reclassified to conform to the current period presentation. Summarized results of the Company's discontinued operations are as follows:



		THREE MONTHS ENDED					NINE MONTHS ENDED
		March 31,					March 31,
		2015		2014			2015		2014
	(In thousands)					(In thousands)
Revenue		$	—	$	356		$	—	$	814
Net income from discontinued operations		$	—	$	27,593		$	—	$	24,937

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The Company recorded purchase price adjustments pursuant to the Sale Deed relating to the reimbursement of Dingo development costs and post completion costs. As of March 31, 2014, the gain related to the Company's discontinued operations is summarized as follows:



	March 31, 2014
	(In thousands)
Assets and liabilities sold
Property and equipment, net	$	(10,100	)
Deferred income taxes	(7,217		)
Goodwill allocated to disposal group	(1,000		)
Asset retirement obligations	4,457
Other assets and liabilities, net	1,178
Total assets and liabilities of discontinued operations	(12,682		)

Consideration
First cash installment - received on Central Closing Date	13,859
Second cash installment - received on April 15, 2014	4,624
Stock of Central	19,147
Total consideration	37,630

Reclassification of foreign currency translation gains to earnings upon sale of foreign subsidiary	6,049
Transaction costs	(815		)
Gain on disposal of discontinued operations, net of tax	$	30,182

For additional information about the sale of the Amadeus Basin assets and the Sale Deed, see Note 2 - Sale of Amadeus Basin Assets.

Note 4 - Securities Available-for-Sale

The following table presents the amortized cost, gross unrealized gains, gross unrealized losses, and fair market value of available-for-sale equity securities, nearly all of which are attributable to the Company's investment in Central stock, as follows:



	March 31, 2015
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Fair value
	(In thousands)
Equity securities	$	19,339	$	—	$	(15,217	)	$	4,122

	June 30, 2014
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Fair value
	(In thousands)
Equity securities	$	19,339	$	—	$	(7,404	)	$	11,935

Subsequent to March 31, 2015, the Company began the process of selling its investment in the common stock of an ASX-listed offshore exploration company other than Central for expected proceeds of approximately $24 thousand. The Company entered into this investment in 2009 and 2010 at an amortized cost of $192 thousand. Although the Company still held the investment as of March 31, 2015, as of the date of release of the accompanying condensed consolidated financial statements, the cumulative unrealized loss on this investment was deemed other-than-temporary and therefore an impairment loss of $168 thousand was recognized for the three and nine months ended March 31, 2015.

Note 5 - Debt

Note Payable. The outstanding principal of a $1.7 million note payable by NP, re-issued in January 2011 (the "Note Payable"), was fully amortized as of June 30, 2014.

Line of Credit. The Company, through its wholly owned subsidiary NP, maintains a line of credit note (the "LCN") with West Texas State Bank ("WTSB"). As of March 31, 2015, $3,501 thousand of the total available $8,000 thousand LCN was drawn and $4,499 thousand remained available to borrow. The LCN will mature on September 30, 2015, and is subject to quarterly floating interest payments based on the Prime Rate (currently approximately 3.25%) and a floor rate of 3.25%. The LCN is 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 LCN secured by a pledge of its membership interest in NP. Magellan and NP are subject to certain customary restrictive covenants under the terms of the LCN. As of March 31, 2015, the Company was in compliance with all such covenants. As of May 13, 2015, the outstanding balance on the LCN totaled $5,500 thousand. The Company is currently in discussions with WTSB to convert the LCN to a term loan before the maturity date. If the Company is unable to obtain such conversion, the Company plans to repay the outstanding balance with expected proceeds from the contemplated sale of certain of its assets.

Note 6 - Asset Retirement Obligations

The estimated valuation of asset retirement obligations ("AROs") is based on the Company's historical experience and management's best estimate of plugging and abandonment costs by field. Assumptions and judgments made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statements of operations. If the recorded value of ARO requires revision, the revision is recorded to both the ARO and the asset retirement capitalized cost.

The following table summarizes the ARO activity for the nine months ended March 31, 2015:



	Total
	(In thousands)
Fiscal year opening balance	$	2,873
Accretion expense	130
Effect of exchange rate changes	(51		)
Balance at March 31, 2015	2,952
Less current asset retirement obligation	356
Long term asset retirement obligation	$	2,596

In April 2015, the Company sold for nominal consideration its 40% interest in PEDL 126, the exploration license that contains the Markwells Wood-1 wellbore ("MW-1"). By selling the license and the wellbore, the Company will be able to eliminate as of June 30, 2015, $346 thousand of current asset retirement obligation liability related to MW-1 recorded on its balance sheet at March 31, 2015. Concomitantly, approximately $296 thousand of costs related to MW-1 included in wells in progress as of March 31, 2015 will be charged to operations during the three month period ending June 30, 2015.

Note 7 - Fair Value Measurements

The Company follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:


•	Level 1: Quoted prices in active markets for identical assets.


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


•	Level 3: Significant unobservable inputs.

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The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Company's policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed above for all periods presented. During the nine months ended March 31, 2015, and 2014, there were no transfers in or out of Level 1, Level 2, or Level 3.

Assets and liabilities measured on a recurring basis

The Company's financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities, are carried at cost, which approximates fair value due to the short term maturity of these instruments. The recorded value of the LCN (see Note 5 - Debt) approximates fair value due to its variable interest rate structure.

The following table presents items required to be measured at fair value on a recurring basis by the level in which they are classified within the valuation hierarchy as follows:



	March 31, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Securities available-for-sale	$	4,122	$	—	$	—	$	4,122

	June 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Securities available-for-sale	$	11,935	$	—	$	—	$	11,935

Liabilities:
Contingent consideration payable ⁽¹⁾	$	—	$	—	$	1,852	$	1,852

⁽¹⁾ See Note 15 - Commitments and Contingencies, below for additional information about this item.

The contingent consideration payable is a standalone liability that is measured at fair value on a recurring basis for which there is no available quoted market price, principal market, or market participants. The inputs for this instrument are unobservable and therefore classified as Level 3 inputs. The calculation of this liability is a significant management estimate and uses drilling and production projections based in part on the Company's reserve report for NP to estimate future production bonus payments and a discount rate that is reflective of the Company's credit adjusted borrowing rate.

Inputs are reviewed by management on an annual basis or more frequently as deemed appropriate, and the liability is estimated by converting estimated future production bonus payments to a single net present value using a discounted cash flow model. Payments of future production bonuses are sensitive to Poplar's 60 days rolling gross production average. The contingent consideration payable would increase with significant production increases and/or a reduction in the discount rate.

During the three months ended March 31, 2015, the Company undertook a review of its planned drilling program at Poplar with respect to its proved undeveloped reserves as of June 30, 2014, and determined, in light of the current oil price environment, to defer this drilling program for an indefinite period. Without this drilling program and the production volumes anticipated therefrom, the Company does not currently anticipate that the conditions for the payment of the contingent consideration will be met in the foreseeable future. As such, the Company has reversed the contingent consideration payable in its entirety as of March 31, 2015, in the accompanying condensed consolidated financial statements.

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The following table presents information about significant unobservable inputs to the Company's Level 3 financial liability measured at fair value on a recurring basis as follows:



Description	Valuation technique	Significant unobservable inputs	March 31, 2015	June 30, 2014
Contingent consideration payable	Discounted cash flow model	Discount rate	N/A	8.0%
		First production payout	N/A	June 30, 2015
		Second production payout	N/A	N/A

Adjustments to the fair value of the contingent consideration payable are recorded in the unaudited condensed consolidated statements of operations under other (expense) income. The following table presents a roll forward of the contingent consideration payable for the nine months ended March 31, 2015:



	Total
	(In thousands)
Fiscal year opening balance	$	1,852
Accretion expense of contingent consideration payable	36
Fair value revision of contingent consideration payable	(1,888		)
Balance at March 31, 2015	$	—

Assets and liabilities measured on a nonrecurring basis

The Company also utilizes fair value to perform an impairment test on its oil and gas properties annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Fair value is estimated using expected discounted future cash flows from oil and gas properties. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are also classified within Level 3. For the nine months ended March 31, 2015, the Company reviewed its proved oil and gas properties for a possible impairment as a result of the recent decline in oil prices and concluded that no impairment had occurred as of March 31, 2015.

Note 8 - Income Taxes

The Company has estimated the applicable effective tax rate expected for the full fiscal year. The Company's effective tax rate used to estimate income taxes on a current year-to-date basis for the nine months ended March 31, 2015, and 2014, is 0% and 0%, respectively. Deferred tax assets ("DTAs") are recognized for the expected future tax consequences of temporary differences between the financial reporting and tax basis of assets and liabilities and for operating losses and foreign tax credit carry forwards.

During the three months ended March 31, 2015, the Company made a determination that it was no longer permanently invested in its foreign subsidiaries. As of March 31, 2015, the Company has estimated that it has an overall deferred tax asset of $3,580 thousand, net of a deferred tax liability related to the basis difference in its foreign subsidiaries of $9,308 thousand. A valuation allowance reduces DTAs to the estimated realizable value, which is the amount of DTAs management believes is "more-likely-than-not" to be realized in future periods.

We review our DTAs and valuation allowance on a quarterly basis. As part of our review, we consider positive and negative evidence, including cumulative results in recent years. Consistent with the position at June 30, 2014, the Company maintains a full valuation allowance recorded against all DTAs. The Company therefore had no recorded DTAs as of March 31, 2015. We anticipate that we will continue to record a valuation allowance against our DTAs in all jurisdictions of the Company until such time as we are able to determine that it is "more-likely-than-not" that those DTAs will be realized.

During the year ended June 30, 2014, the Company utilized all of its available net operating loss carryforwards from the state of Montana. As a result, the Company is subject to taxation in the state of Montana based upon its apportioned income to that state, calculated using a waters edge methodology. The Company has recorded $43 thousand of income tax expense related to the state of Montana for the three and nine months ended March 31, 2015.

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Note 9 - Stock Based Compensation

The 2012 Stock Incentive Plan

On January 16, 2013, the Company's shareholders approved the Magellan Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (the "2012 Stock Incentive Plan"). The 2012 Stock Incentive Plan replaced the Company's 1998 Stock Incentive Plan (the "1998 Stock Plan"). The 2012 Stock Incentive Plan provides for the granting of stock options, stock appreciation rights, restricted stock and/or restricted stock units, performance shares and/or performance units, incentive awards, cash awards, and other stock based awards to selected employees, including officers, directors, and consultants of the Company (or subsidiaries of the Company). The stated maximum number of shares of the Company's common stock authorized for awards under the 2012 Stock Incentive Plan is 5,000,000 shares plus the remaining number of shares under the 1998 Stock Plan immediately before the effective date of the 2012 Stock Incentive Plan, which was 288,435 as of January 15, 2013. The number of aggregate shares available for issuance will be reduced by 1 share for each share granted in the form of a stock option or stock appreciation right and 2 shares for each share granted in the form of any award that is not a stock option or stock appreciation right that is settled in stock. The maximum aggregate annual number of options or stock appreciation rights that may be granted to one participant is 1,000,000, and the maximum annual number of performance shares, performance units, restricted stock, or restricted stock units that may be granted to any one participant is 500,000. The maximum term of the 2012 Stock Incentive Plan is ten years. In October 2014, the Company repurchased 1,512,500 options from a former executive, which options were previously granted under the Company's 1998 Stock Plan. Pursuant to the terms of the 2012 Stock Incentive Plan, the unissued shares underlying these unexercised options were added to the shares available for issuance under the 2012 Stock Incentive Plan.

Stock Option Grants

Under the 2012 Stock Incentive Plan, stock option grants may contain vesting provisions such that options are TBOs, PBOs, or MBOs. During the nine months ended March 31, 2015, the Company granted 135,000 TBOs, 1,250,000 PBOs, and 400,000 MBOs to executives and employees. During the nine months ended March 31, 2014, the Company granted 1,500,000 PBOs and 1,500,000 MBOs to executives and employees.

Performance targets that trigger the vesting of the 1,250,000 PBOs granted in October 2014 include: (i) procuring a commercially viable commitment for the supply of CO₂ to a full-field CO₂-EOR development at Poplar at or below a certain price threshold (weighted 20%); (ii) preparing Poplar for a commercially viable CO₂-EOR development (weighted 40%); (iii) progressing the Company's UK operations by participation in a well in the Weald Basin (weighted 20%); and (iv) moving forward with the Farnham Dome project by both exercising one of the options related to the purchase of CO₂ at Farnham Dome and identifying an applicable oil project to utilize CO₂ from Farnham Dome (weighted 20%). The determination of whether any of these performance targets has been met is subject to a determination of the Board. As of March 31, 2015, no performance targets had been met.

The 400,000 MBOs granted in October 2014 will vest and become exercisable, subject to certain provisions related to ongoing employment and a three-year vesting period, if, at the end of any period of 90 trading days (a “Window”), (A) the closing price of the common stock as reported by NASDAQ (the “Closing Price”) on each of the first 10 trading days of a Window equals or exceeds $5.00 per share; and (B) the median of the Closing Prices for the common stock during such Window equals or exceeds $5.00 per share.

Performance metrics used to measure the potential vesting of the PBOs granted in October 2013 consist of: (i) completing the drilling of the CO₂-EOR pilot program at Poplar (weighted 10%); (ii) Board approval of a full field CO₂-EOR development project at Poplar (weighted 40%); (iii) sale of substantially all of the Amadeus Basin assets (weighted 20%); (iv) approval of a farmout agreement or the ability to participate in drilling one well in the Weald Basin with internally developed funding, including proceeds from a sale of assets (weighted 20%); and (v) approval and execution of a farmout agreement for drilling one well in the Bonaparte Basin (weighted 10%). As of March 31, 2015, performance metrics (i), (iii) and (iv) had been met met.

Vesting of the market based stock options granted in October 2013 is subject to the Company maintaining a $2.35 per share closing price for 10 consecutive trading days and a median stock price of $2.35 over a period of 90 days.

During the nine months ended March 31, 2015, 494,791 stock options were exercised, resulting in the issuance of 272,898 shares of common stock, which number is net of shares withheld to satisfy certain employee tax and exercise price obligations. During the prior year period, no stock options were exercised.

During the nine months ended March 31, 2015, 2,882,085 stock options were forfeited or canceled, including 1,512,500 options repurchased from a former executive (see Note 11). During the prior year period, 41,666 stock options were canceled or forfeited.

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During the nine months ended March 31, 2015, 25,000 stock options expired without exercise. During the prior year period, no stock options expired.

As of March 31, 2015, a total of 3,131,250 MBOs and PBOs had not vested, and 658,698 options, including forfeited or canceled options, remained available for future issuance under the 2012 Stock Incentive Plan. Stock options outstanding have expiration dates ranging from April 30, 2015, to January 12, 2025.

The following table summarizes the stock option activity for the nine months ended March 31, 2015:



	Number of Shares			WAEPS ⁽¹⁾
Fiscal year opening balance	10,492,291			$1.26
Granted	1,785,000			$1.73
Exercised	(494,791	)		$1.09
Forfeited/canceled	(2,882,085	)		$1.14
Expired	(25,000	)		$1.03
Balance at March 31, 2015	8,875,415			$1.40
Weighted average remaining contractual term	5.97		years

⁽¹⁾ Weighted average exercise price per share.

The fair value of stock options granted under the 2012 Stock Incentive Plan was estimated using the following weighted-average assumptions for the nine months ended:



	March 31,
	2015							2014
	TBOs	PBOs			MBOs			PBOs			MBOs
Number of options	135,000	1,250,000			400,000			1,500,000			1,500,000
Weighted-average grant date fair value per share	$0.47	$0.88			$1.17			$0.57			$0.69
Expected dividend yield	—%	—%			—%			—%			—%
Forfeiture rate	22.6%	15.0%			15.0%			—%			—%
Risk free interest rate	1.5%	1.7%			2.4%			1.5%	-	1.7%	2.8%
Expected life (years)⁽¹⁾	6.0	5.3	-	5.4	3.2	-	3.9	0.4	-	1.6	2.6
Expected volatility (based on historical price)	57%	54%			64%			62%			67%

⁽¹⁾ Expected life assumed to be the midpoint between vesting and contractual expiry.

Cancellations

On October 10, 2014, Magellan entered into an Options and Stock Purchase Agreement (the "Agreement") with William H. Hastings, a former executive officer and director of the Company and a beneficial owner of more than 5% of the Company’s Common Stock as of October 10, 2014. The Agreement provided for the repurchase by the Company from Mr. Hastings of 250,000 shares of the Company’s Common Stock and options to acquire 1,512,500 shares of the Company’s Common Stock. The gross proceeds that were paid to Mr. Hastings on October 17, 2014, pursuant to the Agreement totaled $1.4 million (the "Proceeds") and were subject to applicable tax withholdings. Of the Proceeds, $983 thousand related to the repurchase of the options, which amount was subject to applicable withholding tax withheld from and remitted on behalf of the former executive in the amount of $318 thousand. The Company canceled the 1,512,500 repurchased options and, pursuant to the terms of the 2012 Stock Incentive Plan, added the unissued shares underlying these unexercised options to the shares available for issuance under the 2012 Stock Incentive Plan. Of the Proceeds, the remaining $462 thousand related to the repurchase of the shares of Common Stock. See Note 11 - Stockholders' Equity for further detail.

Stock Compensation Expense

The Company recorded $841 thousand and $1,667 thousand of related stock compensation expense for the nine months ended March 31, 2015 and 2014, respectively. Stock compensation expense is included in general and administrative

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expense in the unaudited condensed consolidated statements of operations. The $841 thousand of stock compensation expense for the nine months ended March 31, 2015 consisted of expense amortization related to prior period awards of $441 thousand, expense amortization related to current period option grants of $561 thousand, and stock awards and forfeitures as described below. As of March 31, 2015, and 2014, the unrecorded expected future compensation expense related to stock option awards was $1,424 thousand and $1,500 thousand, respectively.

Stock Awards

In connection with certain executive promotions effective on October 31, 2014, the Board’s Compensation, Nominating and Governance Committee (the “CNG Committee”) established a new 2015 incentive compensation program that included grants of an aggregate of 100,000 shares of restricted stock under the 2012 Stock Incentive Plan to the Company's three senior executives and 50,000 shares of restricted stock under the 2012 Stock Incentive Plan to the Chairman of the Board. Total compensation expense from the issuance of restricted stock to executives for the nine months ended March 31, 2015, was $57 thousand.

The Company's director compensation policy is designed to provide the Company's non-employee directors with a portion of their annual base Board service compensation in the form of equity. On July 1, 2014, the Company issued a total of 96,330 shares of its Common Stock to non-employee directors and one board-observer pursuant to this policy and the 2012 Stock Incentive Plan. Pursuant to the compensation policy, one director elected to apply his annual compensation to the exercise of a portion of his previously awarded and vested options in lieu of receiving a share award, resulting in the issuance of an additional 21,875 shares upon exercise. Total compensation expense from the issuance of non-employee director compensation for the nine months ended March 31, 2015, was $256 thousand.

Forfeitures

During the nine months ended March 31, 2015, 1,369,585 unvested stock options and 100,000 unvested shares of restricted stock that were previously granted were forfeited. The forfeiture of unvested options and unvested restricted stock resulted in the reversal of previously recorded compensation expense of $430 thousand and $44 thousand, respectively, which was recorded as an offset to general and administrative expense during the nine months ended March 31, 2015 in the accompanying unaudited condensed consolidated statement of operations.

Note 10 - Preferred Stock

Series A Convertible Preferred Stock Financing

On May 10, 2013, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the "Series A Purchase Agreement") with One Stone Holdings II LP ("One Stone"), an affiliate of One Stone Energy Partners, L.P. Pursuant to the terms of the Series A Purchase Agreement, on May 17, 2013 (the "Closing Date"), the Company issued to One Stone 19,239,734 shares of Series A Convertible Preferred Stock, par value $0.01 per share (the "Series A Preferred Stock"), at a purchase price of approximately $1.22 per share (the "Purchase Price"), for aggregate proceeds of approximately $23,501 thousand. Subject to certain conditions, each share of Series A Preferred Stock and any related unpaid accumulated dividends are convertible into one share of the Company's Common Stock, par value $0.01 per share, at an initial conversion price equal to the Purchase Price. Please refer to Note 10 - Preferred Stock of the Notes to the Consolidated Financial Statements in the Company's 2014 Form 10-K for further information regarding key terms and registration rights applicable to the Company's Series A Preferred Stock.

The Company has analyzed the embedded features of the Series A Preferred Stock and has determined that none of the embedded features is required under US GAAP to be bifurcated from the Series A Preferred Stock and accounted for separately as a derivative. The Company recorded the transaction by recognizing the fair value of the Series A Preferred Stock at the time of issuance in the amount of $23,501 thousand. The Company will accrete the Series A Preferred Stock to the redemption value if events or circumstances indicate that redemption is probable. No accretion was recorded during the nine months ended March 31, 2015, nor during the year ended June 30, 2014.

For the nine months ended March 31, 2015 and 2014, the Company recorded preferred stock dividends of $1,296 thousand and $1,267 thousand, respectively, related to the Series A Preferred Stock. The preferred stock dividends for the six months ended March 31, 2015, were paid in kind. Accordingly, the value of these dividends of $867 thousand was recorded and added to the preferred stock balance on the Company's balance sheet at March 31, 2015.

The activity related to the Series A Preferred Stock for the nine months ended March 31, 2015, and the fiscal year

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ended June 30, 2014, is as follows:



	NINE MONTHS ENDED			FISCAL YEAR ENDED
	March 31, 2015			June 30, 2014
	Number of shares	Amount		Number of shares	Amount
	(In thousands, except share amounts)
Fiscal year opening balance	20,089,436	$	24,539	19,239,734	$	23,502
PIK dividend shares issued for previously accrued dividend	—	—		164,607	202
Current year PIK dividend shares issued	709,283	867		685,095	835
Balance at end of period	20,798,719	$	25,406	20,089,436	$	24,539

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Note 11 - Stockholders' Equity

Treasury Stock

On July 1, 2014, upon the vesting of 150,000 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 47,920 shares to settle withholding taxes. The withheld shares were immediately canceled.

On October 10, 2014, Magellan repurchased 250,000 shares from William H. Hastings, a former Company executive, pursuant to an Options and Stock Purchase Agreement. See Note 9 - Stock Based Compensation for further details.

All repurchased shares of Common Stock currently being held in treasury are being held at cost, including any direct costs of repurchase. The following table summarizes the Company's treasury stock activity as follows:



	NINE MONTHS ENDED					FISCAL YEAR ENDED
	March 31, 2015					June 30, 2014
	Number of shares		Amount			Number of shares	Amount
	(In thousands, except share amounts)
Fiscal year opening balance	9,425,114		$	9,344		9,414,176	$	9,333
Shares repurchased from former executive	250,000		462			—	—
Net shares repurchased for employee tax and option exercise price obligations related to the vesting of restricted stock and the exercise of employee stock options	47,920		104			10,938	11
Cancellation of shares repurchased	(47,920	)	(104		)	—	—
Balance at end of period	9,675,114		$	9,806		9,425,114	$	9,344

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Note 12 - (Loss) Income Per Common Share

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



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
	(In thousands, except share and per share amounts)
Loss from continuing operations, net of tax	$	(2,280	)	$	(3,072	)	$	(7,793	)	$	(9,364	)
Preferred stock dividend	(437		)	(432		)	(1,296		)	(1,267		)
Net loss from continuing operations, including preferred stock dividends	(2,717		)	(3,504		)	(9,089		)	(10,631		)
Net income from discontinued operations	—			27,593			—			24,937
Net loss attributable to non-controlling interest in subsidiary	165			—			335			—
Net (loss) income attributable to common stockholders	$	(2,552	)	$	24,089		$	(8,754	)	$	14,306

Basic weighted average shares outstanding	45,701,107			45,348,709			45,677,673			45,348,753
Add: dilutive effects of in-the-money stock options and non-vested restricted stock grants ⁽¹⁾	—			—			—			—
Diluted weighted average common shares outstanding	45,701,107			45,348,709			45,677,673			45,348,753

Basic loss per common share:
Net loss from continuing operations attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.06)			$(0.08)			$(0.19)			$(0.23)
Net income from discontinued operations	$0.00			$0.61			$0.00			$0.55
Net (loss) income attributable to common stockholders	$(0.06)			$0.53			$(0.19)			$0.32

Diluted loss per common share:
Net loss from continuing operations attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.06)			$(0.08)			$(0.19)			$(0.23)
Net income from discontinued operations	$0.00			$0.61			$0.00			$0.55
Net (loss) income attributable to common stockholders	$(0.06)			$0.53			$(0.19)			$0.32
⁽¹⁾ All diluted earnings per share calculations are dictated by results from continuing operations; accordingly, there were no dilutive effects on earnings per share in the periods presented since all such periods had a net loss from continuing operations.

There is no dilutive effect on earnings per share in periods with net losses. Stock options or shares of Common Stock issuable upon the conversion of the Series A Preferred Stock were not considered in the calculations of diluted weighted average common shares outstanding as they would be antidilutive. Potentially dilutive securities excluded from the calculation of diluted shares outstanding in periods with net losses are as follows:



	THREE MONTHS ENDED		NINE MONTHS ENDED
	March 31,		March 31,
	2015	2014	2015	2014
In-the-money stock options	—	5,143,666	7,776,666	907,500
Non-vested restricted stock	350,000	450,000	350,000	450,000
Convertible preferred stock	20,798,719	20,089,436	20,798,719	20,089,436
Total	21,148,719	25,683,102	28,925,385	21,446,936

Note 13 - Segment Information

The Company conducts its operations through three wholly owned subsidiaries: NP, which operates in the US; MPUK, which includes our operations in the UK; and MPA, which includes our operations in Australia. Oversight for these subsidiaries is provided by Corporate, which is treated as a cost center.



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
	(In thousands)
Revenue from oil production:
NP	$	688		$	1,907		$	3,543		$	5,674

Net (loss) income from continuing operations:
NP	$	481		$	40		$	(63	)	$	(536	)
MPUK	(300		)	(1,349		)	(881		)	(2,495		)
MPA	(402		)	—			(1,159		)	—
Corporate	(2,059		)	(1,949		)	(5,690		)	(6,700		)
Inter-segment elimination	—			186			—			367
Consolidated net loss from continuing operations	$	(2,280	)	$	(3,072	)	$	(7,793	)	$	(9,364	)


							March 31, 2015			June 30, 2014
							(In thousands)
Total assets:
NP ⁽¹⁾							$	29,997		$	27,299
MPUK ⁽¹⁾							3,102			4,486
MPA ⁽¹⁾							4,819			14,073
Corporate							105,490			111,113
Inter-segment elimination ⁽²⁾							(77,249		)	(75,536		)
Total assets of continuing operations							$	66,159		$	81,435

⁽¹⁾Intercompany payable balances netted in arriving at segment assets

⁽²⁾ Asset inter-segment eliminations are primarily derived from investments in subsidiaries.

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Note 14 - Oil and Gas Activities

The following table presents the capitalized costs under the successful efforts method for oil and gas properties as of:



	March 31, 2015			June 30, 2014
	(In thousands)
Proved oil and gas properties:
United States	$	29,850		$	29,335
Less accumulated depletion, depreciation, and amortization	(4,056		)	(3,575		)
Total net proved oil and gas properties	$	25,794		$	25,760

Unproved oil and gas properties:
United States	$	468		$	268
United Kingdom	227			282
Australia	—			—
Total unproved oil and gas properties	$	695		$	550

Wells in Progress:
United States	$	25,769		$	19,686
United Kingdom	1,695			1,610
Total wells in progress	$	27,464		$	21,296

Note 15 - Commitments and Contingencies

Refer to Note 14 - Commitments and Contingencies of the Notes to the Consolidated Financial Statements in our 2014 Form 10-K for information on all commitments.

Contingent production payments. In September 2011, the Company entered into a Purchase and Sale Agreement (the "Nautilus PSA") among the Company and the non-controlling interest owners of NP for the Company's acquisition of the sellers' interests in NP. The Nautilus PSA provides for potential future contingent production payments, payable by the Company 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. J. Thomas Wilson, a director and executive officer of the Company, has an approximately 52% interest in such contingent payments. See Note 7 - Fair Value Measurements above for information regarding the estimated discounted fair value of the future contingent consideration payable related to the Nautilus PSA.

Sopak Collateral Agreement. On January 14, 2013, the Company entered into a Collateral Purchase Agreement (the "Collateral Agreement") with Sopak AG, a Swiss subsidiary of Glencore International plc ("Sopak"), pursuant to which the Company agreed to purchase: (i) 9,264,637 shares of the Company's Common Stock and (ii) a warrant granting Sopak the right to purchase from the Company an additional 4,347,826 shares of Common Stock. The Collateral Agreement was subsequently amended on January 15, 2013, and completed on January 16, 2013. The Company has estimated that there is the potential for a statutory liability of approximately $1,650 thousand and $1,571 thousand as of March 31, 2015, and June 30, 2014, respectively, related to US Federal tax withholdings and related penalties and interest related to the Collateral Agreement. As a result, we have recorded a total liability of $1,650 thousand and $1,571 thousand as of March 31, 2015, and June 30, 2014, respectively, under accrued and other liabilities in the unaudited condensed consolidated balance sheets included in this report. The Company has a legally enforceable right to collect from Sopak any amounts owed to the IRS as a result of the Collateral Agreement. As a result, we have recorded a corresponding receivable of $1,650 thousand and $1,571 thousand as of March 31, 2015, and June 30, 2014, respectively, under prepaid and other assets in the unaudited condensed consolidated balance sheets.

Broadford Bridge-1 Well. As previously reported, during the three months ended December 31, 2014, the Company received a cash call from Celtique for the advancement of estimated expenses in the amount of approximately $2,000 thousand in connection with the Broadford Bridge-1 well, and the Company is evaluating its alternatives under the applicable joint operating agreement. On March 3, 2015, MPUK received a claim form and particulars of claim issued in the High Court of Justice, Queen’s Bench Division, Commercial Court in London, England on February 26, 2015, pursuant to which Celtique Energie Weald Limited as the claimant seeks, among other things, a declaration that MPUK’s 50% equal co-ownership rights with Celtique in PEDLs 231, 234 (within which license area the Broadford Bridge-1 well site is located), and 243 in the central Weald Basin in the UK have been forfeited to Celtique, and payment of £1,540 thousand (equivalent to $2,284 thousand as of March 31, 2015) for the outstanding cash calls along with interest on that amount at 5% above base rate until payment. On April 1, 2015, MPUK filed a defense and counterclaim asserting, among other things, that the cash calls by Celtique are not

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valid due to the failure of Celtique as operator of the PEDLs to comply with the contractual accounting procedures, adhere to an agreed-upon drilling schedule and otherwise properly execute the parties’ development plans, and seeking to recover damages from Celtique as a result of Celtique’s unilateral actions following the purported forfeiture of the PEDL interests. MPUK believes that it has strong defenses to, and intends to vigorously contest, the claims by Celtique. However, due to the early stage of this matter and the uncertainty and risks inherent in litigation, the Company cannot predict the ultimate outcome of this matter and believes that a meaningful estimate of a reasonably possible loss, if any, or range of reasonably possible losses, if any, cannot currently be made.

Poplar CO₂-EOR Pilot Bonus. MI3 Petroleum Engineering ("MI3") is a Golden, Colorado, based petroleum engineering firm that advises the Company with respect to its CO₂-EOR activities, including the Company's CO₂-EOR pilot at Poplar (See Note 16 - Related Party Transactions). Pursuant to the terms of a master services contract with MI3, in addition to contracted rates for services performed, certain contingent bonuses may become payable to MI3. The first of these will become payable upon a decision by the Company to pursue a full-field CO₂-EOR development at Poplar and is estimated at $255 thousand as of March 31, 2015. The remainder of the bonuses are based on triggers related to project funding and full-field production rates.

Note 16 - Related Party Transactions

Davis Graham & Stubbs LLP. Milam Randolph Pharo, a Director of the Company until December 11, 2014, is currently of counsel at Davis Graham & Stubbs LLP (“DGS”), a Denver-based law firm with over 140 attorneys, of which over 65 are partners. Mr. Pharo has held that position since April 2013. Mr. Pharo has a compensation arrangement with DGS such that Mr. Pharo has an interest in the amount of fees paid by the Company to DGS for certain legal services performed by DGS for the Company. During the nine months ended March 31, 2015, and 2014, the Company recorded $307 thousand and $82 thousand, respectively, of legal fees related to DGS, with respect to which amounts Mr. Pharo had a compensation interest of $0 and less than $2,500, respectively.

Devizes International Consulting Limited. A director of Celtique, with which the Company co-owns equally several licenses in the UK, is also the sole owner of Devizes International Consulting Limited ("Devizes"). Devizes performs consulting related services to MPUK. The Company recorded $137 thousand and $85 thousand of consulting fees related to Devizes during the nine months ended March 31, 2015, and 2014, respectively.

Key Energy Services, Inc. ("KES"). J. Robinson West, the Chairman of the Board of Directors of the Company, also served as a non-employee director on the board of directors for KES until May 2014. KES performed contract drilling rig services for the Company in Poplar during the first and second quarters of fiscal year 2014. The total contract fees payable to KES from activities during the nine months ended March 31, 2014, was $2,200 thousand. During the nine months ended March 31, 2015, KES performed no services for the Company, and J. Robinson West was no longer a director of KES.

Mervyn Cowie. Mervyn Cowie, a former employee of the Company's MPA subsidiary, currently serves both as a director of MPA and its subsidiaries and as a consultant to MPA. Since December 1, 2014, the recurring monthly fee payable to Mr. Cowie for his consulting services amounts to AUD $5,400.

MI3 Petroleum Engineering. In association with its purchase of an option to acquire Farnham Dome, the Company established Utah CO_2,a majority owned subsidiary having two non-controlling interest owners, one of which is MI4 Oil and Gas LLC ("MI4"). MI4 is a Colorado limited liability company majority owned by Carlos Pereira, who is also the majority owner of MI3. MI3 performs ongoing consulting work for both Utah CO₂ and other Magellan entities. During the nine months ended March 31, 2015, the Company recorded $502 thousand of fees payable to MI3 with respect to work performed for Utah CO₂.

Note 17 - Employee Severance Costs

The Company is required to record charges for one-time employee severance benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs payable in connection with the termination of the employment of certain employees pursuant to the terms of their employment agreements, $250 thousand of which were paid during the nine months ended March 31, 2014.

On March 31, 2014, the Company sold its interests in Palm Valley and Dingo to Central. Pursuant to the Sale Deed, the Company incurred severance costs payable in connection with the termination of certain MPA employees. For the nine months ended March 31, 2014, the Company expensed total employee-related severance costs of approximately $1,500 thousand, all of which were charged to loss from discontinued operations, net of tax, in the unaudited condensed consolidated

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statement of operations. All related severance benefits were paid as of June 30, 2014.

On August 31, 2014, the Company provided a notice of termination to the only remaining employee of its MPA subsidiary. As a result, during the nine months ended March 31, 2015, the Company expensed and paid total employee-related severance costs of $475 thousand.

ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our 2014 Form 10-K, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the 2014 Form 10-K. Any capitalized terms used but not defined in the following discussion have the same meaning given to them in the 2014 Form 10-K. Unless otherwise indicated, all references in this discussion to Notes are to the Notes to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report. Our discussion and analysis includes forward looking statements that involve risks and uncertainties and should be read in conjunction with the Risk Factors under Item 1A of Part II of this report and under Item 1A of the 2014 Form 10-K, along with the cautionary discussion about forward looking statements at the end of this section, for information about the risks and uncertainties that could cause our actual results to be materially different than the results expressed or implied in our forward looking statements.

OVERVIEW OF THE COMPANY

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 executive offices are located at 1775 Sherman Street, Suite 1950, Denver, Colorado 80203, and our phone number is (720) 484-2400.

SUMMARY RESULTS OF OPERATIONS

Commodity prices. During the three months ended March 31, 2015, the Company's results continued to be impacted by a steep decline in global oil prices in late 2014. While commodity futures markets suggest that the price of oil will increase gradually, there is no certainty that such an increase will occur. Nonetheless, the Company currently plans to continue with its pilot project at Poplar in the short term. If successful, the pilot will lead to a full-field CO₂-EOR development that would require approximately two to three years to implement before yielding material production and cash flows. Furthermore, CO₂-EOR projects tend to yield very stable production over multi-decade time frames. As such, depressed oil prices in the short-term should not significantly impact the perceived net present value of a full field project at Poplar to the extent that oil prices are expected to return to normalized levels in the medium to long-term. In addition, the Company believes that its current efforts to farmout its offshore block, NT/P82, in the Bonaparte Basin, which efforts are expected to return cash proceeds to the Company in the short-term, are not impacted by the current decline in oil prices, as NT/P82 holds natural gas prospects, and the gas market in Northern Territory, Australia, is currently robust and expected to improve further.

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Revenues. Revenues for the three months ended March 31, 2015, totaled $688 thousand, compared to $1,907 thousand for the prior year period, a decrease of 64%. The $1,219 thousand decrease in revenue was primarily due to decreased realized pricing per barrel due to the decline in WTI, the relevant oil price benchmark.

Net Loss and Loss per Share. Net loss attributable to common stockholders for the three months ended March 31, 2015, totaled $2,552 thousand ($(0.06)/basic share), compared to net income of $24,089 thousand ($0.53/basic share) for the prior year period. The change in net (loss) income was primarily the result of a gain from discontinued operations related to the sale of our Amadeus Basin assets in the prior year period.

Adjusted EBITDAX. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) for the three months ended March 31, 2015, totaled negative $2,320 thousand, compared to negative $477 thousand in the prior year period. The decrease in Adjusted EBITDAX resulted primarily from a decrease in revenues and an increase in general and administrative expenses.

Cash. As of March 31, 2015, Magellan had $3,031 thousand in cash and cash equivalents, compared to $16,422 thousand at June 30, 2014. The decrease of $13,391 thousand was the result of net cash used in operating activities of $6,520 thousand, net cash used in investing activities of $7,528 thousand, net cash provided by financing activities of $1,355 thousand, and net change in cash from the effect of exchange rate changes of $698 thousand. The net cash used in investing activities primarily related to expenditures on the CO₂-EOR pilot at Poplar.

CORPORATE EVENTS

Utah CO₂ Option

On December 1, 2014, Magellan, through Utah CO₂ LLC ("Utah CO₂"), a majority owned subsidiary, acquired an option to acquire a large CO₂ reservoir called Farnham Dome located in Carbon County, Utah. Pursuant to the agreement, the seller, Savoy Energy, LLC, has granted Utah CO₂ the right to either purchase the field outright or purchase uncontracted CO₂ at a fixed price. Pursuant to an option extension agreement negotiated by the partners in Utah CO2, the option, that was originally scheduled to expire on March 31, 2015, is currently scheduled to expire on May 31, 2015. This extension will allow more time to negotiate with potential off-takers of Farnham Dome's CO₂ before determining whether or not to exercise the option.

Over the last two years the Company has developed considerable expertise in utilizing CO₂ to enhance recovery from older fields with large volumes of original oil in place. On the basis of this expertise, the Company has made a strategic decision to focus on EOR opportunities in North America. Pursuant to that decision, Magellan is seeking to identify both attractive candidates for CO₂-EOR projects and a reliable, low-cost supply of CO₂. If completed, the acquisition of Farnham Dome CO₂ would address the latter while the Company actively evaluates opportunities to utilize such CO₂ to substantially increase its reserves at attractive costs. The Company believes that the experience we are gaining at Poplar Dome can be applied to other fields in the vicinity of Farnham Dome.

NASDAQ Listing Requirements

On January 27, 2015, the Company received a letter from The NASDAQ Stock Market LLC ("NASDAQ") indicating that, based upon the closing bid price of the Company's common stock for the previous 30 consecutive business days, the Common Stock did not meet 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). The letter also indicates that the Company will be provided with a compliance period of 180 calendar days, or until July 27, 2015, in which to regain compliance, pursuant to NASDAQ Marketplace Rule 5810(c)(3)(A). The letter further indicates that if, at any time during the 180-day compliance period, the closing bid price of the Common Stock is at least $1.00 for a minimum of ten consecutive business days, NASDAQ will provide the Company with written confirmation that it has achieved compliance with the minimum bid price requirement. The Company intends to continue to monitor the bid price levels for the Common Stock, and will consider appropriate alternatives to achieve compliance within the 180-day compliance period.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES

During the three months ended March 31, 2015, the Company progressed a number of initiatives for its operational assets to evaluate and determine the potential of its exploration and production properties.

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Poplar (Montana, USA)

CO₂-EOR pilot project. During the three months ended March 31, 2015, the Company continued to conduct the CO₂-EOR pilot (the "Pilot") at Poplar with the objective of obtaining meaningful preliminary results by the end of summer 2015.

In early April 2015, the Company concluded that the Pilot has been a technical success and demonstrates that the CO₂-EOR technique is a technically viable tertiary recovery method in the Charles formation at Poplar Dome. The Company reached this conclusion on the basis of the oil production response observed in, and other injection and pressure data gathered from, the Pilot.

CO₂ injection into the Pilot's single injector well began in August 2014. In October, the Pilot's four producer wells were opened for production. Since then, oil production has increased in three of the four producer wells in response to CO₂ injection, and the Company expects the fourth well will demonstrate an oil production response soon. The current run-rate of production from the three producing wells together is between 50 and 75 bopd and is expected to increase gradually through the summer.

Demonstrating that CO₂-EOR works in practice at Poplar is a major milestone that substantially de-risks the technical feasibility aspects of this project. The Company's next objective is to demonstrate that this technique is economic at Poplar, which requires an understanding of (i) how much CO₂ a full field development will require and (ii) what the cost of that CO₂ will be. Running the Pilot for several more months should address the former, and ongoing discussions with CO₂ suppliers are addressing the latter.

Although oil prices also affect the economics of the project and the current oil price environment remains depressed, the Company believes that the potential long-term value of CO₂-EOR development at Poplar is encouraging, since a full field CO₂-EOR development at Poplar would require approximately two to three years to implement, and CO₂-EOR projects tend to yield stable production over multi-decade time frames. Overall, the Pilot continues to exceed the Company's expectations, and management believes that the Company is on track to establish the economic viability and attractiveness of Poplar as a prime CO₂-EOR candidate.

Shallow Intervals. During the three months ended March 31, 2015, Magellan sold 19 Mboe (211 boepd) of oil attributable to its net revenue interests in Poplar. This production came primarily from primary production from the Charles formation.

Deep Intervals. During the three months ended March 31, 2015, there was no production from the Deep Intervals at Poplar.

United Kingdom

Central Weald Licenses. In the central Weald Basin, Magellan co-owns equally with Celtique Energie Holdings Ltd ("Celtique") three licenses, PEDLs 231, 234, and 243, representing 124 thousand net acres, that may be prospective for oil and gas development from the Kimmeridge Clay, Liassic, and other formations. These licenses are subject to drill-or-drop obligations and will expire in June 2016 unless such obligations are met.

As previously reported, during the three months ended December 31, 2014, the Company received a cash call from Celtique for the advancement of estimated expenses in the amount of $2,000 thousand in connection with the Broadford Bridge-1 well, and the Company is evaluating its alternatives under the applicable joint operating agreement. During the three months ended March 31, 2015, Celtique initiated a legal proceeding against the Company with respect to that cash call and related issues. See Note 15 - Commitments and Contingencies - Broadford Bridge-1 Well of the notes to the accompanying condensed consolidated financial statements included in this report for further information. The Company cannot predict the ultimate outcome of this matter, which may have a material adverse effect on the Company’s interests in the central Weald licenses.

Peripheral Weald Licenses. On the periphery of the Weald Basin, Magellan currently maintains non-operated interests in three exploration licenses (PEDLs 137 and 246, and P1916), representing 15 thousand net acres, that may be prospective for conventional oil and gas targets.

With respect to PEDLs 137 and 246, which cover the Horse Hill structure, Magellan is encouraged by the technical analysis performed on the Horse Hill prospect by UK Oil & Gas Investments PLC, an interest owner of the Horse Hill-1 well ("HH-1"), and its partners. HH-1 confirmed that the Upper Jurassic section is thermally mature (i.e., in the oil window) and contains two thick limestone intervals that may act as conventional reservoirs for a significant oil play in the Weald Basin. This confirmation suggests that the Upper Jurassic throughout the greater Weald Basin is also thermally mature and therefore serves as an important data point in evaluating the potential of the Company's central Weald licenses.

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HH-1 will be put on a production test from the Portland Sandstone section in calendar year 2015 pending regulatory approvals. Pursuant to a farmout agreement executed in December 2013, Magellan owns a 35% working interest in the HH-1 well and is being carried for its share of well costs through testing and completion.

With respect to P1916, there was no activity during the three months ended March 31, 2015, and no further activity is planned during fiscal year 2015.

Australia

NT/P82. During the three months ended March 31, 2015, the Company continued its farmout process, begun in the fourth quarter of fiscal year 2014, to identify a farmout partner experienced in offshore drilling. In completing a farmout, the Company expects to relinquish a portion of its working interest in, and operatorship of, NT/P82, in exchange for a commitment from the partner to fund an exploration program by May 2016 over the large gas prospects identified in the block. Given the high level of offshore drilling activity in the Bonaparte Basin, the network of installed gas infrastructure in the relative vicinity of our block, and the relatively shallow depths of water in the license, the Company believes it is well positioned to successfully execute a farmout agreement by end of summer 2015.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES

During the nine months ended March 31, 2015, the Company used $13,391 thousand in cash and, as of March 31, 2015, had $3,031 thousand in cash and cash equivalents on its balance sheet. The decline in cash and cash equivalents and the recent trend of net cash burn have increased the risk that the Company will face liquidity issues in the short-term. Currently, the Company projects that it will incur approximately $1,000 thousand in net cash uses per month, which amount is comprised of the following broad components: (i) revenues from oil production at Poplar approximately offsetting the associated lease operating expenses; (ii) approximately $400 thousand of expenses to be incurred monthly in relation to running the Pilot; (iii) approximately $500 thousand to be incurred monthly for general and administrative expenses; and (iv) approximately $100 thousand in other expenses.

However, the Company believes it has several alternatives for addressing in the short-term its liquidity position and anticipated cash burn that can potentially be accomplished by September 2015. These alternatives include: (i) completing a farmout of NT/P82, which could result in cash proceeds to the Company; (ii) a partial or complete sale of the Company's position in the common stock of Central or the execution of a loan collateralized by these shares; (iii) a partial or complete sale of the Company's positions in various UK exploration licenses; and (iv) a partial sale of Poplar field.

The above cash burn rate projections are subject to various risks and uncertainties inherent in management estimates, and actual cash burn rates may differ materially from the projections due to, among other things, (i) changes in oil commodity prices; (ii) other changes in results of operations and cash flows as the Pilot continues to generate additional information; (iii) changes in currently available funds as a result of liquidity constraints or potential alternative funding mechanisms such as those discussed above; or (iv) other risks and uncertainties referred to under “Forward Looking Statements” below.

The Company believes that it will be in a position by the end of summer 2015 to make a determination as to the economic potential of its CO₂-EOR project at Poplar Dome. If it can be demonstrated that a full-field CO₂-EOR project at Poplar is economic in the current oil price environment, then the Company believes Poplar could represent a net present value that would be material relative to the Company's current market valuation, and Poplar could then be used to attract financing or proceeds into the Company on terms that would be attractive to its shareholders. Therefore, in pursuing the various short-term liquidity alternatives discussed above, the Company's objective is to procure sufficient cash to fund the Company's ongoing operations while preserving the maximum possible exposure to the economic upside of its assets until such time that it can make a determination as to Poplar's economics.

In addition to pursuing these alternatives, since March 31, 2015, the Company has drawn an additional $2,000 thousand on its LCN with WTSB (both terms defined below), and the Company is in discussions with WTSB to convert the LCN into a term loan that amortizes over time.

Uses of Funds

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Capital Expenditure Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Approximately 80% of the acreage has been unitized as a federal exploratory unit, which is held by economic production from any one well in the unit. Currently, Poplar contains 36 productive wells.

In the Shallow Intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans for the foreseeable future will be determined primarily by the requirements of the Pilot, which is expected to continue through at least December 2015. Ongoing expenditures related to the Pilot are anticipated to relate primarily to the purchases of CO₂, which averaged approximately $300 thousand per month during the three months ended March 31, 2015. Total remaining costs for the Pilot will ultimately depend on how long and how much CO₂ is required to be injected in order to obtain a full suite of results and whether the currently ongoing pilot in the B-2 zone of the Charles formation will be followed by a pilot in the B-1 or other zone.

In addition, in the Shallow Intervals the Company may incur capital expenditures related to recompletions on existing wells and drilling of certain newly identified proved undeveloped ("PUD") locations. However, as a result of low commodity prices and the Company's current liquidity constraints, during the three months ended December 31, 2014, the Company deferred for an indefinite period its plans to drill wells associated with PUD reserves reflected in its reserves report as of June 30, 2014.

In the Deep Intervals, which are operated by the Company and in which the Company has a working interest of 50% in the majority of the leases, the Company does not intend to incur material capital expenditures in fiscal year 2015.

In the UK, the Company's interests are governed by various PEDLs and one Seaward Production License. PEDLs 231, 234, and 243, which the Company co-owns equally with Celtique, are subject to "drill-or-drop" obligations with a deadline of June 2016. As previously reported, during the three months ended December 31, 2014, the Company received a cash call from Celtique for the advancement of estimated expenses in the amount of approximately $2,000 thousand in connection with the Broadford Bridge-1 well, and the Company is evaluating its alternatives under the applicable joint operating agreement. During the three months ended March 31, 2015, Celtique initiated a legal proceeding against the Company with respect to that cash call and related issues. See Note 15 - Commitments and Contingencies - Broadford Bridge-1 Well of the notes to the accompanying condensed consolidated financial statements included in this report for further information. The Company cannot predict the ultimate outcome of this matter, which may have a material effect on the ultimate amount and/or timing of the Company’s capital expenditures with respect to PEDLs 231, 234, and 243.

In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, the Company is required to drill one exploratory well on the license by May 2016. Following the successful completion of seismic surveys in the license area and the associated processing and interpretation, the Company is actively engaged in a farmout process to identify a partner experienced in offshore exploratory drilling to drill at least one exploratory well on our behalf. The Company does not expect to incur further significant capital expenditures of its own until after the first exploration well has been drilled.

Series A Preferred Dividend. The Company may elect at its discretion to pay the quarterly dividends on the Series A Preferred Stock either in cash or in kind. For the three months ended March 31, 2015, the Company paid the dividend in kind. In the future, the Company intends to pay the dividend in cash if the Company's common stock share price materially exceeds the Series A Preferred Stock Conversion Price of approximately $1.22 (the "Conversion Price"). In such cases, the Company may decide to issue shares of common stock to finance the cash dividend in order to realize a positive arbitrage between the common stock share price and the Conversion Price. The total expected cost of paying dividends on the Series A Preferred Stock through the end of the current fiscal year, if they were to be paid in cash, is $445 thousand.

Contractual Obligations. Please refer to the contractual obligations table in Part II, Item 7 of our 2014 Form 10-K for information on all material contractual obligations as of June 30, 2014, and see Note 15 - Commitments and Contingencies to the accompanying condensed consolidated financial statements included in this report for further information with respect to a previously reported cash call received from Celtique for the advancement of estimated expenses in connection with the Broadford Bridge-1 well.

Sources of Funds

Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $3,031 thousand of cash and cash equivalents as of March 31, 2015, compared to $16,422 thousand as of June 30, 2014. The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates.

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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 to the US, the Company is potentially liable for incremental US Federal and State Income Tax, which may be reduced by the US Federal and State net operating loss and foreign tax credit carry forwards available to the Company at that time.

Existing Credit Facilities. A summary of the Company's existing credit facilities is as follows:



	March 31, 2015		June 30, 2014
	(In thousands)
Outstanding borrowings:
Line of credit	$	3,501	$	—
Total	$	3,501	$	—

The Company, through its wholly owned subsidiary NP, maintains a line of credit note (the "LCN") with West Texas State Bank ("WTSB"). As of March 31, 2015, $3,501 thousand of the total available $8,000 thousand LCN was drawn and $4,499 thousand remained available to borrow. The LCN will mature on September 30, 2015, and is subject to quarterly floating interest payments based on the Prime Rate (currently approximately 3.25%) and a floor rate of 3.25%. The LCN is 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 LCN secured by a pledge of its membership interest in NP. Magellan and NP are subject to certain customary restrictive covenants under the terms of the LCN. As of March 31, 2015, the Company was in compliance with all such covenants. As of May 13, 2015, the outstanding balance on the LCN totaled $5,500 thousand. The Company is currently in discussions with WTSB to convert the LCN to a term loan before the maturity date. If the Company is unable to obtain such conversion, the Company plans to repay the outstanding balance with expected proceeds from the contemplated sale of certain of its assets.

Sales of Registered Equity Facilities. On December 24, 2014, the Company implemented an "at-the-market" (ATM) facility under which the Company can raise up to $10 million through the issuance of new common shares into the market. The ATM facility is registered under the Company's "shelf" registration statement on Form S-3, which was filed with the U.S. Securities and Exchange Commission on November 17, 2014, and which went effective on December 3, 2014. The Shelf registers the issuance of up to $100 million in equity securities of the Company and is effective through December 2017.

The Company may use the ATM facility and the Shelf on an as-needed basis for general corporate purposes, which may include the payment of dividends on its Series A Preferred Stock or the funding of the development of the Company's CO2-EOR business at Poplar or in Utah. The Company has no immediate plans to issue shares pursuant to the ATM facility or the Shelf, which are intended to provide financial flexibility going forward. As of the date hereof, no securities have been issued under either the Shelf or the ATM facility.

Central Shares. The Company currently intends to continue holding its position in Central's stock, subject to a potential sale of some or all of its position as an alternative to address short-term liquidity issues as discussed above. The Company believes that Central is executing its operational projects in line with its stated plans at the time of the issuance of this stock to Magellan and that these projects have upside value potential material to the valuation of Central based on its current share price. Given the strong gas market fundamentals in Australia and Central's operational focus on gas producing assets, the Company believes that Central has significant assets that are materially insulated from the recent decline in global oil prices.

The Company is not constrained in its ability to sell its shares in Central by contractual arrangements with Central. In the future, Magellan may decide to dispose of part or all of its position in Central's stock to fund some of the Company's activities. In addition, we may consider taking out a margin or similar loan collateralized by the Company's shares of Central. Such a loan would allow the Company to realize cash proceeds from this position in the short-term while materially preserving the economic upside that the Company believes is represented by this position.

Based on the Central closing price on May 13, 2015, these shares of stock represent a total value of $4,391 thousand, or a $14,756 thousand decrease over the amortized cost.

Other Sources of Financing. In addition to its existing liquid capital resources, the Company has various alternatives to fund the development of its assets. In addition to the alternatives to address short-term liquidity issues discussed above, these

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alternatives could potentially include a reserve-based loan facility, a project finance loan facility, mezzanine financing from a bank and the alternative investment markets, equity issuances via a PIPE or secondary offering, and a partial or complete divestiture or farmout of a portion of the development program of some of the Company's assets.

Cash Flows

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



	March 31,
	2015			2014
	(In thousands)
Cash (used in) provided by:
Operating activities	$	(6,520	)	$	(10,855	)
Investing activities	(7,528		)	(2,851		)
Financing activities	1,355			(314		)
Discontinued operations	—			101
Effect of exchange rate changes on cash and cash equivalents	(698		)	464
Net decrease in cash and cash equivalents	$	(13,391	)	$	(13,455	)

Cash used in operating activities during the nine months ended March 31, 2015, was $6,520 thousand, compared to cash used in operating activities of $10,855 thousand for the same period in 2014. The decrease in cash used in operating activities was primarily due to the inclusion of loss from discontinued operations in the prior year period, which loss was not continued in the current year.

Cash used in investing activities during the nine months ended March 31, 2015, was $7,528 thousand, compared to $2,851 thousand for the same period in 2014. Capital expenditures in both periods primarily related to the CO₂-EOR Pilot at Poplar, with the increase in the current period partially due to the capitalization of expenses incurred for the purchase of CO2 volumes injected in the Pilot. See Note 1 - Basis of Presentation to the accompanying condensed consolidated financial statements for further detail on the accounting treatment of CO₂ purchases.

Cash provided by financing activities during the nine months ended March 31, 2015, was $1,355 thousand, compared to cash used of $314 thousand in the prior year period. Cash provided in the current year period resulted primarily from net drawdowns on the LCN, partially offset by repurchases of stock and options and the payment of the June and September 2014 preferred stock dividends. Cash used in the prior year period related primarily to net repayments of the Company's then outstanding debt facilities.

Cash used in discontinued operations in the prior year period is related to the operations of the Amadeus Basin assets disposed of in March 2014, and no continuing impact on cash flows is expected from discontinued operations.

During the nine months ended March 31, 2015, the effect of changes in foreign currency exchange rates negatively impacted the translation of our foreign denominated cash and cash equivalent balances into USD and resulted in a decrease of $698 thousand in cash and cash equivalents, compared to an increase of $464 thousand for the same period in 2014.

COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014

The following table presents results of operations for the three months ended:



	March 31,
	2015		2014		Difference			Percent change
Poplar:
Oil revenue (In thousands)	$	688	$	1,907	$	(1,219	)	(64	)%
Oil sales volume (Mbbls)	19		23		(4		)	(17	)%
Oil sales volume (bopd)	211		256		(45		)	(18	)%
Average realized oil price ($/bbl)	$	36.21	$	82.91	$	(46.70	)	(56	)%

Oil Revenue

Revenues for the three months ended March 31, 2015, totaled $688 thousand, compared to $1,907 thousand in the prior year period, a decrease of 64%. The $1,219 thousand decrease in revenue from the prior year period was primarily due to a decrease in the average realized oil price.

Oil Sales Volume

Sales volume for the three months ended March 31, 2015, totaled 19 Mbbls (211 bopd), compared to 23 Mbbls (256 bopd), a decrease of 17%. The decrease was primarily attributable to the natural production decline of the field.

Average Realized Oil Price

The average realized price for the three months ended March 31, 2015, was $36.21/bbl, compared to $82.91/bbl during the same period in the prior year, a decrease of 56%. The decrease was primarily due to a decrease in WTI, the relevant oil price benchmark, partially offset by an improvement in the differential relative to WTI realized at Poplar. The Company currently does not engage in any oil and gas hedging activities.

Operating and Other Expenses

The following table presents operating expenses for the three months ended:



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	1,417	$	1,397	$	20		1	%
Depletion, depreciation, amortization, and accretion	$	246	$	337	$	(91	)	(27	)%
Exploration	$	368	$	1,605	$	(1,237	)	(77	)%
General and administrative	$	2,664	$	1,588	$	1,076		68	%

Selected operating expenses (USD/bbl):
Lease operating	$	75	$	61	$	14		23	%
Depletion, depreciation, amortization, and accretion	$	13	$	15	$	(2	)	(13	)%
Exploration	$	19	$	70	$	(51	)	(73	)%

Lease Operating Expenses. Lease operating expenses increased $20 thousand to $1,417 thousand, or $75/bbl, during the three months ended March 31, 2015, remaining relatively in line with the prior year period.

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



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	48	$	75	$	(27	)	(36	)%
Depletion	158		221		(63		)	(29	)%
ARO accretion	40		41		(1		)	(2	)%
Total	$	246	$	337	$	(91	)	(27	)%

Depletion, depreciation, amortization, and accretion expenses decreased $91 thousand to $246 thousand, or $13/bbl, during the three months ended March 31, 2015, compared to $337 thousand in the prior year period. The change was primarily due to a decrease in depletion resulting from a decrease in production and a decrease in the depletion rate as a result of a revision in reserves estimates for certain formations.

Exploration Expenses. Exploration expenses decreased by $1,237 thousand to $368 thousand, or $19/bbl, during the three months ended March 31, 2015. The decrease was primarily the result of decreased UK expenditures in the current year period, partially offset in the current year period by increased expenditures related to the evaluation of whether to exercise an option to acquire CO₂ at Farnham Dome.

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



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation expense and foreign transaction loss (gain))	$	1,591	$	987	$	604		61	%
Stock compensation expense	414		601		(187		)	(31	)%
Foreign transaction loss (gain) from investment in subsidiaries	659		$	—	659			NA
Total	$	2,664	$	1,588	$	1,076		68	%

General and administrative expenses increased by $1,076 thousand, or 68%, to $2,664 thousand during the three months ended March 31, 2015, compared to the prior year period. During the same period, general and administrative expenses, excluding stock based compensation and foreign transaction loss (gain), increased by $604 thousand, or 61%, to $1,591 thousand. This increase was primarily the result of increased expenses in the US, partially as a result of legal and consulting work related to Utah CO2, and increased consulting expenses in the UK. A foreign transaction loss of $659 thousand, which was previously reflected in other comprehensive income, was recognized in the current period following the Company's determination that it was no longer permanently invested in certain of its foreign subsidiaries. See Note 1 - Basis of Presentation of the accompanying condensed consolidated financial statements for further information on this determination.

Net (Loss) from Discontinued Operations

Net (loss) from discontinued operations relates to the Amadeus Basin assets sold in March 2014 and includes loss from discontinued operations of $0 and $2,589 thousand for the three months ended March 31, 2015, and 2014, respectively. Net income from discontinued operations also includes the gain on sale of discontinued operations in the amount of $30,182 thousand for the three months ended March 31, 2014.

COMPARISON OF RESULTS BETWEEN THE NINE MONTHS ENDED MARCH 31, 2015 AND 2014

The following table presents results of operations for the nine months ended:



	March 31,
	2015		2014		Difference			Percent change
Poplar:
Oil revenue (In thousands)	$	3,543	$	5,674	$	(2,131	)	(38	)%
Oil sales volume (Mbbls)	59		66		(7		)	(11	)%
Oil sales volume (bopd)	215		241		(26		)	(11	)%
Average realized oil price ($/bbl)	$	60.05	$	85.97	$	(25.92	)	(30	)%

Oil Revenue

Revenues for the nine months ended March 31, 2015, totaled $3,543 thousand, compared to $5,674 thousand for the same period in the prior year, a decrease of 38%. The decrease was primarily due to a decrease in the average realized oil price.

Oil Sales Volume

Sales volume for the nine months ended March 31, 2015, totaled 59 Mbbls (215 bopd), compared to 66 Mbbls (241 bopd) sold in the prior year period, a decrease of 11%. The decrease in production was primarily attributable to the natural production decline of the field.

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Average Realized Oil Price

The average realized price for the nine months ended March 31, 2015, was $60.05/bbl compared to $85.97/bbl in the prior year period, a decrease of 30%. The decrease was primarily due to a decrease in WTI, the relevant oil price benchmark. The Company currently does not engage in any oil and gas hedging activities.

Operating and Other Expenses

The following table presents operating expenses for the nine months ended:



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	3,901	$	4,714	$	(813	)	(17	)%
Depletion, depreciation, amortization, and accretion	$	761	$	956	$	(195	)	(20	)%
Exploration	$	1,276	$	2,776	$	(1,500	)	(54	)%
General and administrative	$	7,190	$	6,411	$	779		12	%

Selected operating expenses (USD/bbl):
Lease operating	$	66	$	71	$	(5	)	(7	)%
Depletion, depreciation, amortization, and accretion	$	13	$	14	$	(1	)	(7	)%
Exploration	$	22	$	42	$	(20	)	(48	)%

Lease Operating Expenses. Lease operating expenses decreased $813 thousand to $3,901 thousand, or $66/bbl, during the nine months ended March 31, 2015, compared to the prior year period. The decrease is primarily attributable to decreased workover expense and reduced production taxes due to decreased revenue in the current period.

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



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	150	$	160	$	(10	)	(6	)%
Depletion	481		674		(193		)	(29	)%
ARO accretion	130		122		8			7	%
Total	$	761	$	956	$	(195	)	(20	)%

Depletion, depreciation, amortization, and accretion expenses decreased $195 thousand to $761 thousand, or $13/bbl, during the nine months ended March 31, 2015, as compared to the prior year period. The change was primarily due to a decrease in depletion resulting from a decrease in production and a decrease in the depletion rate as a result of a revision in reserves estimates for certain formations.

Exploration Expenses. Exploration expenses decreased by $1,500 thousand to $1,276 thousand, or $22/bbl, during the nine months ended March 31, 2015, compared to the prior year period. The $1,500 thousand decrease primarily resulted from decreased exploration in the current period related to the Company's UK operations, partially offset by increased expenditures related to the evaluation of whether to exercise an option to acquire CO₂ at Farnham Dome in Utah.

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



	March 31,
	2015		2014		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation expense and foreign transaction loss (gain))	$	5,690	$	4,744	$	946		20	%
Stock compensation expense	841		1,667		(826		)	(50	)%
Foreign transaction loss (gain) from investment in subsidiaries	659		$	—	659			N/A
Total	$	7,190	$	6,411	$	779		12	%

General and administrative expenses increased $779 thousand to $7,190 thousand, during the nine months ended March 31, 2015, compared to the prior year period. During the same period, general and administrative expenses, excluding stock based compensation and foreign transaction loss (gain), increased by $946 thousand to $5,690 thousand. This increase was primarily due to employee severance costs of $475 thousand and approximately $300 thousand of other costs incurred with respect to the Company's efforts to scale down its Australian operations following the sale of the Amadeus Basin assets in March 2014. The decrease in non-cash stock based compensation expense was primarily the result of the forfeiture of restricted stock and stock options resulting from the resignations of an executive and employees during the current year period, which forfeitures resulted in an expense reversal of $474 thousand. A foreign transaction loss of $659 thousand, which was previously reflected in other comprehensive income, was recognized in the current period following the Company's determination that it was no longer permanently invested in certain of its foreign subsidiaries. See Note 1 - Basis of Presentation of the accompanying condensed consolidated financial statements for further information on this determination.

Net (Loss) from Discontinued Operations

Net loss from discontinued operations relates to the Amadeus Basin assets sold on March 31, 2014, and includes loss from discontinued operations of $0 and $5,245 thousand for the nine months ended March 31, 2015, and 2014, respectively. Net income from discontinued operations also includes the gain on sale of discontinued operations in the amount of $30,182 thousand for the nine months ended March 31, 2014.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATION

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (minus): (i) depletion, depreciation, amortization, and accretion expense; (ii) exploration expense; (iii) foreign transaction loss (gain) from investment in subsidiaries; (iv) stock based compensation expense; (v) loss on investment in securities; (vi) net interest expense (income); (vii) fair value revision of contingent consideration payable; (viii) other (income) expense; (vii) income tax expense (benefit); and (viii) net loss (income) from discontinued operations. Adjusted EBITDAX is not a measure of net income or cash flow as determined by GAAP and excludes certain items that we believe affect the comparability of operating results.

Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our company without regard to historical cost basis and certain items that affect the comparability of period to period operating results, including items involving point-in-time estimates of asset and liability values subject to currency rate and commodity price fluctuations.

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



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
	(In thousands)
Net (loss) income	$	(2,280	)	$	24,521		$	(7,793	)	$	15,573
Depletion, depreciation, amortization, and accretion expense	246			337			761			956
Exploration expense	368			1,605			1,276			2,776
Foreign transaction loss (gain) from investment in subsidiaries	659			—			659			—
Stock based compensation expense	414			601			841			1,667
Loss on investment in securities	168			—			168			—
Net interest expense	25			80			42			103
Fair value revision of contingent consideration payable	(1,888		)	—			(1,888		)	—
Other (income) expense	(75		)	(28		)	(157		)	78
Income tax expense (benefit)	43			—			43			—
Net income attributable to discontinued operations	—			(27,593		)	—			(24,937		)
Adjusted EBITDAX	$	(2,320	)	$	(477	)	$	(6,048	)	$	(3,784	)

For clarification purposes, the table below provides an alternative method for calculating Adjusted EBITDAX, which can also be calculated as revenue less (i) lease operating expense and (ii) general and administrative expense; plus stock based compensation expense.

The following table provides the alternative method for calculating Adjusted EBITDAX for the following periods:



	THREE MONTHS ENDED						NINE MONTHS ENDED
	March 31,						March 31,
	2015			2014			2015			2014
	(In thousands)
REVENUE FROM OIL PRODUCTION	$	688		$	1,907		$	3,543		$	5,674
Less:
Lease operating	(1,417		)	(1,397		)	(3,901		)	(4,714		)
General and administrative	(2,664		)	(1,588		)	(7,190		)	(6,411		)
Plus:
Stock based compensation expense	414			601			841			1,667
Foreign transaction loss (gain) from investment in subsidiaries	659			—			659			—
Adjusted EBITDAX	$	(2,320	)	$	(477	)	$	(6,048	)	$	(3,784	)

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.

EFFECTS OF COMMODITY PRICES

Material changes in oil and gas prices may impact (i) the Company's revenues; (ii) estimates of future reserves, depletion expense, impairment assessments of oil and gas properties and goodwill, and values of properties in purchase and sale transactions; (iii) decisions by the Company to proceed with further development of its key projects, including the development of PUD reserves and the Company's CO₂-EOR project at Poplar; and (iv) the value of oil and gas companies and their ability to raise capital, borrow money, and retain personnel. While oil prices in the US have declined recently, the Company currently does not anticipate that such decline would result in the Company's decision to not proceed with its key operational projects, in particular the Pilot CO₂-EOR project at Poplar and, if the Pilot demonstrates that full-field development

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would be economic, a full-field development of Poplar. The decline in oil prices, as well as the Company's current liquidity constraints, has led the Company to delay indefinitely its plans for a PUD development program related to the Company's reserves as of June 30, 2014.

The Pilot was originally conceived as an investment to prove the viability of a much larger full field development and was not expected to be economic in itself. If the Pilot demonstrates that full-field development would be economic, a full-field CO₂-EOR development would require approximately two to three years to implement before yielding material production and cash flows. Furthermore, CO₂-EOR projects tend to yield very stable production over multi-decade time frames. As such, depressed oil prices in the short-term should not significantly impact the perceived net present value of a full field project at Poplar to the extent that oil prices are expected to return to normalized levels in the medium to long-term.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Information regarding critical accounting policies and estimates is contained in Item 7 of our 2014 Form 10-K. There have been no changes to the Company's critical accounting policies during the nine months ended March 31, 2015.

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," "estimate," "expect," "forecast," "initial," "plan," "potential," "project," "should," "will," 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 our businesses and prospects, planned capital expenditures, availability of liquidity and capital resources, increases or decreases in oil and gas production, the acquisition or disposition of oil and gas properties and related assets, the ability to enter into acceptable farmout arrangements, revenues, expenses, operating cash flows, projected cash burn rates, borrowings, 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: the uncertainties associated with our planned CO₂-EOR program at Poplar, including uncertainties about the technical and economic viability of CO₂-EOR techniques at Poplar, drilling results from the Pilot project, the results of CO₂ injection, including the ability to sustain CO₂ pressures at sufficient effective levels to sweep the oil across the formation to production wells, and our ability to acquire a long term CO₂ supply for the program; possible adverse changes to the CO₂-EOR industry; possible geologic or other obstacles to the further development of our Poplar project; possible geologic or other obstacles to obtaining the anticipated production from our CO₂-EOR projects and the timing of development milestones; uncertainties inherent in projecting future rates of production from CO₂-EOR activities, and whether enhanced production expected from CO₂-EOR will be comparable to other CO₂-EOR projects or otherwise meet our expectations; the uncertain nature of oil and gas prices in the US, UK, and Australia, including uncertainties about the duration of the currently depressed oil commodity price environment and the related impact on our revenues, project developments, and ability to obtain financing; uncertainties regarding our ability to maintain sufficient liquidity and capital resources to implement our projects; uncertainties regarding the ability to realize the expected benefits from the sale of the Amadeus Basin assets to Central, including through the future value of Central's stock; uncertainties regarding our ability to successfully acquire CO₂ at Farnham Dome in Utah and realize the expected benefits thereof; 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 develop 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, including the current legal proceeding initiated by Celtique; and other matters discussed in the Risk Factors sections of our 2014 Form 10-K, Quarterly Report on Form 10-Q for the quarter ended December 31, 2014, and 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

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presented in the Item 1A ("Risk Factors") sections of our 2014 Form 10-K, Quarterly Report on Form 10-Q for the quarter ended December 31, 2014, and this Form 10-Q. 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.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 British pound and US dollar have changed in recent periods, and may fluctuate substantially in the future. As a result of anticipated net proceeds related to the planned farmout of NT/P82 in Australia, any appreciation of the US dollar against the Australian dollar is likely to result in decreased net income. As a result of anticipated net expenditures for planned development in the UK, any material appreciation of the US dollar against the British pound could have a positive impact on our business, operating results, and financial condition.

For the three and nine months ended March 31, 2015, oil sales represented 100% of total revenues. Based on the current three and nine months sales volumes and revenues, a 10% change in oil price would increase or decrease oil revenues by $69 thousand and $354 thousand, respectively.

At March 31, 2015, the fair value of our investments in securities available for sale was $4,122 thousand, with substantially 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 in March 2014. 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 March 31, 2015, of AUD $0.14 per share, which translated to $0.10 per share in US dollars on that date. 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 elect to sell our Central shares. In addition, a 10% across-the-board change in the underlying equity market price per share for our investments would result in a $412 thousand change in the fair value of our investments.

ITEM 4 CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Under the supervision and with the participation of certain members of the Company's management, including the Chief Executive Officer and the Chief Financial Officer, the Company completed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in SEC Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report. Based on this evaluation, the Company's Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report to provide reasonable assurance that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and is accumulated and communicated to the Company's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended March 31, 2015, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1 LEGAL PROCEEDINGS

The information required by this Item is incorporated herein by reference to the information set forth under "Broadford Bridge-1 Well" in Note 15 - Commitments and Contingencies of the notes to the condensed consolidated financial statements included in Part I, Item 1 of this report.

ITEM 1A RISK FACTORS

Item 1A ("Risk Factors") of our 2014 Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended December 31, 2014, (the "Second Quarter 10-Q") sets forth information relating to important risks and uncertainties that could materially affect our business, financial condition, operating results, or cash flows. Except as set forth below, there have been no material changes in the Risk Factors described in such Form 10-K and Second Quarter 10-Q, and those Risk Factors continue to be relevant to an understanding of our business, financial condition, operating results, and cash flows. Accordingly, you should review and consider such Risk Factors in making any investment decision with respect to our securities. An investment in our securities continues to involve a high degree of risk.

A legal proceeding initiated by Celtique may have a material adverse effect on our interests in the central Weald Basin of the UK.

In the central Weald Basin of the UK, we co-own equally with Celtique three licenses, PEDLs 231, 234, and 243, representing 124 thousand net acres that may be prospective for oil and gas development. As previously reported, during the three months ended December 31, 2014, we received a cash call from Celtique for the advancement of estimated expenses in the amount of $2,000 thousand in connection with the Broadford Bridge-1 well, the site for which is located within the PEDL 234 license area, and we are evaluating our alternatives under the applicable joint operating agreement. During the three months ended March 31, 2015, Celtique initiated a legal proceeding against us with respect to that cash call and related issues. See Note 15 - Commitments and Contingencies - Broadford Bridge-1 Well of the notes to the accompanying condensed consolidated financial statements included in this report for further information. We cannot predict the ultimate outcome of this matter, which may have a material adverse effect on our interests in the central Weald licenses and/or require the payment of amounts for which we would need to obtain funding.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pursuant to the terms and conditions of the Certificate of Designations of Series A Preferred Stock dated May 17, 2013, as amended, on March 31, 2015, the Company issued 357,718 shares of its Series A Preferred Stock as quarterly PIK dividends with respect to the 20,441,001 shares of Series A Preferred Stock outstanding as of the record date of March 15, 2015. 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 U.S. 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 one share of the Company's Common Stock, subject to customary anti-dilution provisions. For additional information regarding the Series A Preferred Stock, see Note 10 - Preferred Stock of the Notes to unaudited condensed consolidated financial statements included under Part I, Item 1 of this report.

ISSUER PURCHASES OF EQUITY SECURITIES

During the three months ended March 31, 2015, the Company did not make any purchases of the Company's common stock.

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ITEM 5 OTHER INFORMATION

We have elected to include the following information in this Form 10-Q in lieu of reporting it in a separately filed Form 8-K. This information would otherwise have been reported in a Form 8-K under the heading "Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers."

On May 13, 2015, Matthew R. Ciardiello notified the Company that he will be resigning as Vice President - Chief Financial Officer, Treasurer, and Corporate Secretary of Magellan, effective June 19, 2015, to pursue a chief financial officer opportunity at another company. As a result of his resignation, the Company currently plans to restructure current management assignments.

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ITEM 6 EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference into this report:



2.1 +	Share Sale and Purchase Deed dated February 17, 2014, among Magellan Petroleum Australia Pty Ltd, Magellan Petroleum (N.T) Pty. Ltd., Magellan Petroleum Corporation, Jarl Pty. Ltd., Central Petroleum PVD Pty. Ltd, and Central Petroleum Limited (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on February 18, 2014 and incorporated herein by reference).
2.2	Escrow Agency Deed dated February 17, 2014, between Magellan Petroleum Australia Pty Ltd and Central Petroleum PVD Pty. Ltd. (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on February 18, 2014 and incorporated herein by reference).
3.1	Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware, as amended by an Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware (filed as Exhibit 4.B. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference).
3.2	Certificate of Amendment of Restated Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware (filed as Exhibit 3(a) to the registrant's Quarterly Report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference).
3.3	Certificate of Amendment of Restated Certificate of Incorporation related to Articles Twelfth and Fourteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.3 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.4	Certificate of Amendment of Restated Certificate of Incorporation related to Article Thirteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.4 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.5	Certificate of Amendment of Restated Certificate of Incorporation related to Article Fourth as filed on December 10, 2010 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference).
3.6	Certificate of Designations of Series A Convertible Preferred Stock as filed on May 17, 2013 with the State of Delaware (filed as Exhibit 3.6 to the registrant's Current Report on Form 8-K filed on June 26, 2013 and incorporated herein by reference).
3.7	Certificate of Amendment to Certificate of Designations of Series A Convertible Preferred Stock as filed on August 19, 2013 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on August 19, 2013 and incorporated herein by reference).
3.8	By-Laws, as amended on June 13, 2013 (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on June 18, 2013 and incorporated herein by reference).
4.1 ++	Registration Rights Agreement dated May 17, 2013 between Magellan Petroleum Corporation and One Stone Holdings II LP (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on June 26, 2013 and incorporated herein by reference).
10.1 ++	Amendment to Amended and Restated Employment Agreement executed on February 11, 2015, effective as of October 31, 2014, between Magellan Petroleum Corporation and J. Thomas Wilson (filed as Exhibit 10.9 to the registrant's Quarterly Report on Form 10-Q filed on February 12, 2015, and incorporated herein by reference).
31.1 *	Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2 *	Certification of Matthew R. Ciardiello, Vice President - Chief Financial Officer, Treasurer, and Corporate Secretary, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1 **	Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 **	Certification of Matthew R. Ciardiello, Vice President - Chief Financial Officer, Treasurer, and Corporate Secretary, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS *	XBRL Instance Document
101.SCH *	XBRL Taxonomy Extension Schema Document
101.CAL *	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF *	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB *	XBRL Taxonomy Extension Label Linkbase Document
101.PRE *	XBRL Taxonomy Extension Presentation Linkbase Document


*	Filed herewith.


**	Furnished herewith.

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+	Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments have been omitted. The registrant hereby agrees to furnish supplementally a copy of any omitted schedule or attachment to the U.S. Securities and Exchange Commission upon request.


++	Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		MAGELLAN PETROLEUM CORPORATION
		(Registrant)

Date:	May 15, 2015	By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)

Date:	May 15, 2015	By:	/s/ Matthew R. Ciardiello
			Matthew R. Ciardiello, Vice President - Chief Financial Officer, Treasurer, and Corporate Secretary
			(as Principal Financial and Accounting Officer)