Edgar Filing: MAGELLAN PETROLEUM CORP /DE/

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 December 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 February 8, 2016 was 5,762,634, which is net of 1,209,389 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	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	40
ITEM 1A	RISK FACTORS	40
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	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)



	December 31, 2015			June 30, 2015
				(Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	429		$	1,051
Securities available-for-sale	2,535			4,230
Accounts receivable — trade	212			420
Accounts receivable — working interest partners and other	109			130
Inventories	554			651
Prepaid and other assets	1,995			2,100
Total current assets	5,834			8,582

PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Proved oil and gas properties	20,841			20,857
Less accumulated depletion, depreciation, amortization and accretion	(4,652		)	(4,355		)
Unproved oil and gas properties	519			709
Wells in progress	19,927			19,660
Land, buildings, and equipment (net of accumulated depreciation of $735 and $682 as of December 31, 2015, and June 30, 2015, respectively)	150			202
Net property and equipment	36,785			37,073

OTHER NON-CURRENT ASSETS:
Goodwill, net	500			500
Other long term assets	510			545
Total other non-current assets	1,010			1,045
Total assets	$	43,629		$	46,700

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,137		$	2,534
Accrued and other liabilities	2,595			2,120
Current portion of notes payable	760			—
Total current liabilities	6,492			4,654

LONG TERM LIABILITIES:
Notes payable, net of current portion	4,813			5,500
Asset retirement obligations	2,731			2,647
Other long term liabilities	98			98
Total long term liabilities	7,642			8,245



COMMITMENTS AND CONTINGENCIES (Note 14)

PREFERRED STOCK (Note 9):
Series A convertible preferred stock (par value $0.01 per share): Authorized 28,000,000 shares, issued 21,909,872 and 21,162,697 as of December 31, 2015, and June 30, 2015, respectively; liquidation preference of $29,439 and $28,435 as of December 31, 2015, and June 30, 2015, respectively	26,763			25,850
Total preferred stock	26,763			25,850

EQUITY:
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, issued, 6,972,023 and 6,917,027 as of December 31, 2015, and June 30, 2015, respectively	70			69
Treasury stock (at cost): 1,209,389 and 1,209,389 shares as of December 31, 2015, and June 30, 2015, respectively	(9,806		)	(9,806		)
Capital in excess of par value	93,675			93,386
Accumulated deficit	(86,338		)	(81,006		)
Accumulated other comprehensive income	5,149			5,302
Total equity attributable to Magellan Petroleum Corporation	2,750			7,945
Non-controlling interest in subsidiary	(18		)	6
Total equity	2,732			7,951
Total liabilities, preferred stock and equity	$	43,629		$	46,700

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						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
REVENUE FROM OIL PRODUCTION	$	566		$	1,265		$	1,215		$	2,855

OPERATING EXPENSES:
Lease operating	601			1,270			1,586			2,484
Depletion, depreciation, amortization, and accretion	238			260			436			515
Exploration	10			486			257			908
General and administrative	1,225			2,137			3,203			4,526
Total operating expenses	2,074			4,153			5,482			8,433

Loss from operations	(1,508		)	(2,888		)	(4,267		)	(5,578		)

OTHER INCOME (EXPENSE):
Net interest expense	(72		)	(17		)	(139		)	(17		)
Gain (loss) on investment in securities	118			—			(143		)	—
Other income	82			20			106			82
Total other income (expense)	128			3			(176		)	65

Loss before tax	(1,380		)	(2,885		)	(4,443		)	(5,513		)

Income tax expense	—			—			—			—

Net loss	(1,380		)	(2,885		)	(4,443		)	(5,513		)

Net loss attributable to non-controlling interest in subsidiary	13			170			24			170

Net loss attributable to Magellan Petroleum Corporation	(1,367		)	(2,715		)	(4,419		)	(5,343		)

Preferred stock dividends	(461		)	(430		)	(913		)	(859		)

Net loss attributable to common stockholders	$	(1,828	)	$	(3,145	)	$	(5,332	)	$	(6,202	)

Loss per common share (Note 11):
Weighted average number of basic shares outstanding	5,757,533			5,709,692			5,730,157			5,708,276
Weighted average number of diluted shares outstanding	5,757,533			5,709,692			5,730,157			5,708,276

Basic and diluted loss per common share:
Net loss attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.32)			$(0.55)			$(0.93)			$(1.09)
Net loss attributable to common stockholders	$(0.32)			$(0.55)			$(0.93)			$(1.09)

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 (UNAUDITED)

(In thousands)



	THREE MONTHS ENDED						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
Net loss	$	(1,380	)	$	(2,885	)	$	(4,443	)	$	(5,513	)

Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss)	127			(615		)	(245		)	(1,831		)
Unrealized holding gain (loss) on securities available-for-sale	911			(6,550		)	92			(7,774		)
Other comprehensive income (loss), net of tax	1,038			(7,165		)	(153		)	(9,605		)
Comprehensive loss	$	(342	)	$	(10,050	)	$	(4,596	)	$	(15,118	)

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, 2015	$	69	$	(9,806	)	$	93,386		$	(81,006	)	$	5,302		$	6		$	7,951
Net loss	—		—			—			(4,419		)	—			(24		)	$	(4,443	)
Other comprehensive loss, net of tax	—		—			—			—			(153		)	—			$	(153	)
Stock and stock based compensation	1		—			306			—			—			—			$	307
Net shares repurchased for employee tax costs upon vesting of restricted stock	—		—			(11		)	—			—			—			$	(11	)
Payment of cash in lieu of issuance of fractional shares in one share for eight shares reverse stock split	—		—			(6		)	—			—			—			$	(6	)
Preferred stock dividend	—		—			—			(913		)	—			—			$	(913	)
December 31, 2015	$	70	$	(9,806	)	$	93,675		$	(86,338	)	$	5,149		$	(18	)	$	2,732

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)



	SIX MONTHS ENDED
	December 31,
	2015			2014
OPERATING ACTIVITIES:
Net loss	$	(4,443	)	$	(5,513	)
Adjustments to reconcile net loss to net cash used in operating activities:
Foreign transaction loss	53			—
Depletion, depreciation, amortization, and accretion	436			515
Amortization of deferred finance costs	9			—
Accretion expense of contingent consideration payable	—			36
Allowance for doubtful accounts	59			—
Inventory book to physical adjustment	55			123
Loss on investment in securities	143			—
Stock compensation expense	307			427
Severance and retention benefit costs	425			—
Net changes in operating assets and liabilities:
Accounts receivable	220			345
Inventories	22			(198		)
Prepayments and other current assets	104			(55		)
Accounts payable and accrued liabilities	578			128
Net cash used in operating activities	(2,032		)	(4,192		)

INVESTING ACTIVITIES:
Additions to property and equipment	(215		)	(5,390		)
Proceeds from sale of investment securities	1,443			—
Proceeds from sale of unproved oil and gas properties	175			—
Utah CO₂ option	—			(268		)
Net cash provided by (used in) investing activities	1,403			(5,658		)

FINANCING ACTIVITIES:
Purchase of common stock	(11		)	(566		)
Purchase of stock options	—			(983		)
Proceeds from issuance of common stock, net	—			115
Payment of cash in lieu of issuance of fractional shares in one share for eight shares reverse stock split	(6		)	—
Payment of preferred stock dividend	—			(859		)
Deferred financing costs, net	(24		)	—
Borrowings (repayments) on line of credit, net	—			3,501
Proceeds from issuance of notes payable	108			—
Payments on notes payable	(35		)	—
Capital contributions by non-controlling interest	—			145
Net cash provided by financing activities	32			1,353

Effect of exchange rate changes on cash and cash equivalents	(25		)	(520		)
Net decrease in cash and cash equivalents	(622		)	(9,017		)
Cash and cash equivalents at beginning of period	1,051			16,422
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	429		$	7,405

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Supplemental schedule of non-cash activities:
Unrealized holding gain and foreign currency translation loss on securities available-for-sale	$	(32	)	$	(8,973	)
Change in accounts payable and accrued liabilities related to property and equipment	$	86		$	(311	)
Accrued preferred stock dividends	$	—		$	430
Preferred stock dividends paid in kind	$	913		$	—
Increase in both accrued or other liabilities and prepaid or other assets related to Sopak	$	54		$	26
Property contributed for capital and deferred capital contribution of non-controlling interest	$	—		$	200

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 "MPC" or "we") is an independent oil and gas exploration and production company focused on 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") in the UK, and Magellan Petroleum Australia Pty Ltd ("MPA") in Australia.

Our strategy is to enhance shareholder value by maximizing the value of our existing assets. Our portfolio of operations includes several early stage oil and gas exploration and development projects, the successful development of which requires significant capital, as well as significant engineering and management resources.

We 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.

Going Concern

The Company has incurred losses from operations for the six months ended December 31, 2015, of $4.3 million. In addition, during the six months ended December 31, 2015 working capital has decreased from $3.9 million at June 30, 2015, to negative $658 thousand at December 31, 2015, and the Company's cash balance has decreased to $429 thousand as of December 31, 2015. The Company continues to experience liquidity constraints and continues to sell certain of its non-core assets to fund its operations. However, proceeds from these asset sales may not provide sufficient liquidity to fund operations for the next twelve months. These factors raise substantial doubt about the Company's ability to continue as a going concern. The accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.

As part of the Company's current strategic alternatives review process discussed below, the Company is currently looking for potential merger candidates that may offer improved liquidity and the ability to raise additional capital. The Company is focused on maintaining production while efficiently reducing its operating and general and administrative costs.

Special Committee of the Board of Directors

On June 5, 2015, the Board of Directors of the Company formed a special committee of the Board of Directors (the "Special Committee") to i) engage in a strategic alternatives review process and ii) amend compensation arrangements of executives and employees for the purpose of retention and alignment of interests with the interests of the common stockholders during such strategic alternatives review process.

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 six months ended December 31, 2015, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2016. 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, 2015 (the "2015 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.

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During the year ended June 30, 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 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 51% 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 consolidated financial statements relates to the non-controlling interest in this entity, including the participation interest.

As of December 31, 2015, the Company owned a 5.7% 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 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, 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 income, a separate component of stockholders' equity. A component of accumulated other comprehensive income will be released into income when the Company executes a partial or complete sale of an investment in a foreign subsidiary or a group of assets of a foreign subsidiary considered a business and/or when the Company no longer holds a controlling financial interest in a foreign subsidiary or group of assets of a foreign subsidiary considered a business.

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 year ended June 30, 2015, the Company made a determination that it was no longer permanently invested in its foreign subsidiaries because (i) the Company 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 for the year ended June 30, 2015, an expense reclassification from accumulated other comprehensive loss arising from foreign currency exchange losses on its intercompany account balances. For the six months ended December 31, 2015, the Company has continued to record foreign currency exchange gains and losses arising from its intercompany account balances in its condensed consolidated statement of operations.

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 an other-than-temporary impairment. On June 30, 2015, the Company conducted this analysis and determined that the value of one of its investments had suffered an other-than-temporary impairment. The Company therefore recognized the difference between the investment's cost and fair value at June 30, 2015, in its consolidated statement of operations for the year ended June 30, 2015. At December 31, 2015, there were no unrealized losses on securities available-for-sale held by the Company.

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 costs. Exploration expenses include dry hole costs, geological, and geophysical expenses. Non-commercial development well costs are charged to impairment expense if circumstances indicate that a decline in the recoverability of the carrying value may have occurred.

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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. The sale of a partial interest in an unproved oil and gas property is accounted for as a recovery of cost, with any excess of the proceeds over such cost or related carrying amount recognized as gain.

Impairment of Long-Lived Assets

The Company reviews the carrying amount of its oil and gas properties and unproved leaseholds for impairment whenever events and / or changes in 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 six months ended December 31, 2015 as a result of continued declines in oil prices, and concluded that no further impairment of its oil and gas properties was required.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. For the six months ended December 31, 2015, there were no significant changes in events or circumstances that suggested further potential impairment of the Company's goodwill balances at December 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 collection of the revenue is probable.

Major Customers

The Company's consolidated oil production revenue is derived from its NP segment and was generated from a single customer for the six months ended December 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

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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 condensed consolidated balance sheets and 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.

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 potentially dilutive securities in the determination of diluted earnings per share are the dilutive effect of stock options and the shares of Series A Preferred Stock.

The potentially dilutive impact of stock options is determined using the treasury stock method. The potentially dilutive impact of the shares of Series A 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 anti-dilutive. The Series A Preferred Stock is convertible at a rate of one common share for one preferred share, multiplied by an applicable conversion ratio. We did not include any stock options, nor common stock issuable upon the conversion of the Series A Preferred Stock in the calculation of diluted loss per share during each of the six months ended December 31, 2015, and 2014, as their effect would have been antidilutive.

Segment Information

As of June 30, 2015, 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. As of December 31, 2015, these three operating segments met the minimum quantitative threshold to qualify for separate segment reporting.

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. The presentation of all segment information herein reflects the manner in which the Company's management monitors performance and allocates resources. For information pertaining to our reporting segments, see Note 12 - Segment Information, and Part II, Item 8 of our 2015 Form 10-K.

Recently Issued Accounting Standards

In January 2016, the the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. This standard will be effective for the Company for its first interim period in its fiscal year ending June 30, 2019, with earlier application not permitted with the exception of certain specific provisions. The Company is evaluating the impact of the adoption of this standard on its condensed consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17, which simplifies the presentation of deferred income taxes in the classified balance sheet, by removing the requirement to separate current and noncurrent deferred taxes and requiring deferred tax assets and liabilities to be classified as noncurrent. This standard will be effective for the Company for its first interim period in its fiscal year ending June 30, 2018, and early adoption is permitted. The Company does not expect adoption of ASU 2015-17 to have a material effect on its condensed consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, which simplifies the accounting for adjustments made to provisional amounts recognized at the acquisition date in a business combination, by eliminating the requirement to retrospectively account for such adjustments for which the accounting is incomplete by the end of the reporting period in which the combination occurs. This standard will be effective for the Company for its first interim period in its fiscal year ending June 30, 2017. The Company is evaluating the impact of the adoption of this standard on its condensed consolidated financial statements.

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In August 2015, the FASB issued ASU No. 2015-15, which amends presentation and disclosure requirements outlined in ASU 2015-03 (discussed below) by clarifying guidance for debt issuance costs related to line of credit arrangements, providing that the SEC would not object to presentation of debt issuance costs related to a line of credit arrangement as an asset, and amortizing them ratably over the term of the line of credit arrangement. The Company does not expect adoption of ASU 2015-15 to have a material effect on its condensed consolidated financial statements.

In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU 2014-09 (discussed below) by one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date.

In July 2015, the FASB issued ASU No. 2015-11, which requires that inventory that is measured using first-in, first-out or average cost method be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The standard will be effective for the first interim period within the Company's fiscal year beginning after December 15, 2016 and is required to be adopted prospectively; early adoption is permitted. The Company does not expect the adoption of this accounting standard to have a significant impact on its condensed consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts. Prior to the issuance of ASU 2015-03, debt issuance costs were required to be presented as deferred charge assets, separate from the related debt liability. ASU 2015-03 does not change the recognition and measurement requirements for debt issuance costs. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, and early adoption is permitted. At December 31, 2015, adoption of this standard would have resulted in a reclassification from other long term assets to a reduction of notes payable of $65 thousand on the Company's accompanying condensed consolidated balance sheet.

In August 2014, the FASB issued ASU No. 2014-15, which provides 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, which requires a reporting entity to treat a performance target included within a share-based payment award 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 consolidated financial statements.

In May 2014, the FASB issued ASU No. 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 amended by ASU 2015-14 discussed above, will be effective for us in the first quarter of our fiscal year 2019; unless early adopted in the prior fiscal year as permitted under the amendment. The Company is currently evaluating the timing of adoption, which transition approach to use and the impact of the adoption of this standard on its 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 million, (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 million. 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.

Note 3 - 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, all of which are attributable to the Company's investment in Central stock, as follows:



	December 31, 2015
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Fair value
	(In thousands)
Equity securities	$	2,567	$	—	$	(32	)	$	2,535

	June 30, 2015
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Fair value
	(In thousands)
Equity securities	$	4,230	$	—	$	—		$	4,230

During the six months ended December 31, 2015, the Company began selling part of its investment in Central due to the Company's liquidity constraints and financing needs. The realized price at which the Company sold shares of its investment in Central was lower than the Company's amortized cost, on a per share basis, of its investment. Consequently, the Company determined that unrealized losses incurred through June 30, 2015 related to its investment in Central were other-than-temporary, and recognized an impairment loss in the amount of $14.9 million as of June 30, 2015, equal to the difference between the carrying value of its investment in Central and the market price of Central's common stock on the Australian Exchange at June 30, 2015, including applicable foreign currency translation. As of December 31, 2015, there were no unrealized losses on securities available-for-sale held by the Company.

Note 4 - Debt

Notes Payable. On September 17, 2014, the Company, through its wholly owned subsidiary NP, entered into a senior secured revolving loan facility (the "Revolving Loan Facility") with West Texas State Bank ("WTSB"). The Revolving Loan Facility had a floating interest rate based on the prime rate with a floor rate of 3.25%, with interest payable quarterly, a maturity of September 30, 2015, and a total available borrowing limit of $8.0 million, of which $5.5 million was drawn as of June 30, 2015, when the Company entered into an amendment to the Revolving Loan Facility whereby the Revolving Loan Facility was converted into a single term loan (the "Term Loan"). The maturity of the Term Loan was extended to June 30, 2020 and bears

interest at the prime rate plus 1.50% with an interest rate floor of 4.75%. The Term Loan is secured by substantially all of NP's assets and a guarantee of Magellan secured by a pledge of its membership interest in NP. During the first twelve months of the Term Loan, only monthly interest payments are payable. Principal is amortized over its remaining four year term. Under the terms of the Term Loan, Magellan and NP are subject to certain restrictive covenants customary in similar loan agreements. At December 31, 2015, the Company was in compliance with all such covenants.

Note 5 - 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 six months ended December 31, 2015:



	Total
	(In thousands)
Fiscal year opening balance	$	2,647
Accretion expense	84
Balance at December 31, 2015	2,731
Less current asset retirement obligation	—
Long term asset retirement obligation	$	2,731

Note 6 - 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.

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 six months ended December 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 exposed to concentrations of credit risk primarily consist of cash and cash equivalents and accounts receivable. The carrying values for cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and current portion of notes payable reflect these items' cost, which approximates fair value based on the timing of the anticipated cash flows and current market conditions. The recorded value of the Term Loan (see Note 4 - Debt) approximates fair value due to the variable interest rate structure of the note.

Items required to be measured at fair value on a recurring basis by the Company include securities available-for-sale and contingent consideration payable (as discussed further below). Within the valuation hierarchy, the Company measures the fair

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value of securities available-for-sale using Level 1 inputs, and the fair value of contingent consideration payable using Level 3 inputs. As of December 31, 2015, and June 30, 2015, the fair value of securities available-for-sale was $2.5 million and $4.2 million, respectively. As of both December 31, 2015, and June 30, 2015, the fair value of contingent consideration payable was $0. The following table presents items required to be measured at fair value on a recurring basis as of the periods presented:



	December 31, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Securities available-for-sale	$	2,535	$	—	$	—	$	2,535

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

	June 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Securities available-for-sale	$	4,230	$	—	$	—	$	4,230

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

⁽¹⁾ See Note 14 - Commitments and Contingencies, below for additional information about this item.

The contingent consideration payable as discussed in Note 14 - Commitments and Contingencies - Contingent production payments is a potential 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 potential 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.

The Company has previously recorded a liability and resulting accretion expense for the estimated fair value of the contingent consideration payable. The Company undertook a review of its planned drilling program at Poplar with respect to its undeveloped resource locations as of June 30, 2015, and determined, in light of the then current oil price environment and liquidity situation, 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 not recorded any contingent consideration payable as of June 30, 2015 or December 31, 2015, in the accompanying condensed consolidated financial statements. See Note 14 - Commitments and Contingencies, below for additional information about this item.

Adjustments to the fair value of the contingent consideration payable are recorded in the unaudited condensed consolidated statements of operations under other (expense) income.

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 six months ended December 31, 2015, the Company reviewed its proved oil and gas properties for a possible further impairment since June 30, 2015 and concluded that no further impairment had occurred as of December 31, 2015.

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Note 7 - 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 six months ended December 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 year ended June 30, 2015, the Company made a determination that it was no longer permanently invested in its foreign subsidiaries. As of December 31, 2015, the Company has an overall deferred tax asset net of a deferred tax liability related to the basis difference in its foreign subsidiaries. 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, 2015, the Company maintains a full valuation allowance recorded against all DTAs. The Company therefore had no recorded DTAs as of December 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.

Note 8 - 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 625,000 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 36,054 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 125,000, 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 62,500. The maximum term of the 2012 Stock Incentive Plan is ten years.

During the six months ended December 31, 2015, 194,531 stock options previously granted under the 1998 Stock Plan expired without exercise. 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.

In October 2014, pursuant to an Options and Stock Purchase Agreement, the Company repurchased 189,062 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 six months ended December 31, 2015, the Company granted no stock options. During the six months ended December 31, 2014, the Company granted 156,250 PBOs and 50,000 MBOs to executives.

Exercises

During the six months ended December 31, 2015, no stock options were exercised. During the six months ended December 31, 2014, 61,849 stock options were exercised, resulting in the issuance of 34,112 shares of common stock, which number is net of shares withheld to satisfy employee tax and exercise price obligations.

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Forfeitures / Cancellations

During the six months ended December 31, 2015, 13,958 stock options were forfeited or canceled. The forfeiture of unvested options during the six months ended December 31, 2015 resulted in the reversal of previously recorded compensation expense of $41 thousand, which was recorded as an offset to general and administrative expense in the accompanying unaudited condensed consolidated statement of operations. During the six months ended December 31, 2014, 360,261 stock options were canceled or forfeited, including 189,062 options repurchased from a former executive.

Expirations

During the six months ended December 31, 2015, 246,612 stock options expired without exercise. During the prior year period, 1,563 stock options expired without exercise.

As of December 31, 2015, a total of 332,028 MBOs and PBOs had not vested, and 261,690 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 December 31, 2016, to January 12, 2025.

The following table summarizes the stock option activity for the six months ended December 31, 2015:



	Number of Shares			WAEPS ⁽¹⁾
Fiscal year opening balance	1,032,334			$11.15
Granted	—			$0.00
Exercised	—			$0.00
Forfeited/canceled	(13,958	)		$7.60
Expired	(246,612	)		$9.98
Balance at December 31, 2015	771,764			$11.59
Weighted average remaining contractual term	6.63		years

⁽¹⁾ Weighted average exercise price per share.

Stock Compensation Expense

The Company recorded $307 thousand and $427 thousand of related stock compensation expense for the six months ended December 31, 2015 and 2014, respectively. Stock compensation expense is included in general and administrative expense in the unaudited condensed consolidated statements of operations. The $307 thousand of stock compensation expense for the six months ended December 31, 2015 consisted of expense amortization related to prior period awards of $348 thousand, partially offset by forfeitures as described above. As of December 31, 2015, and 2014, the unrecorded expected future compensation expense related to stock option awards was $607 thousand and $1.8 million, respectively.

Stock Awards

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 with a value equal to $35,000, with the determination of the exact number of shares to be made on July 1st, or on the date of the subsequent annual stockholders' meeting (the "Stock Award"). In either case, the number of shares to be awarded is determined using the fair value of the shares as of July 1. In addition, there is an annual cash award alternative to the annual Stock Award whereby a non-employee Director may elect to receive $35,000 in cash to exercise previously awarded options to acquire Common Stock, the exercise price of which is at least equal in value to the Common Stock eligible for receipt by the Director pursuant to the Stock Award (with the difference in value of the options and $35,000 to be paid in cash, referred to as the Make-Up Payment). On July 3, 2015, the Special Committee determined that the director's annual stock award would be deferred and revisited in a few months after the strategic alternatives review process has advanced further and liquidity issues have been addressed. As of December 31, 2015, the Company had not made the Stock Award payment that is to be determined as of July 1, but has accrued a total of $175,000, representing the $35,000 equity value of the Stock Award to each non-employee director. On July 1, 2014, the Company issued a total of 12,041 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 2,734 shares upon exercise.

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

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grants of 12,500 shares of restricted stock in aggregate under the 2012 Stock Incentive Plan to the Company's three senior executives and 6,250 shares of restricted stock to the Chairman of the Board.

On October 12, 2015, as further discussed in Note 16 - Employee Retention and Severance Costs, the Company granted 62,500 shares of restricted stock, a cash award based on the market value of the Company's common stock, and a phantom stock award based on the value of 62,500 notional shares to its Chief Financial Officer, all subject to doubling in certain circumstances under an override bonus agreement, and all vesting upon completion of a qualifying transaction.

Note 9 - 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 $1.22149381 per share (the "Purchase Price"), for aggregate proceeds of approximately $23.5 million. Subject to certain conditions, the shares of Series A Preferred Stock and any related unpaid accumulated dividends are convertible into shares of the Company's Common Stock, par value $0.01 per share, using a face amount per share of the Series A Preferred Stock based on the Purchase Price, and dividing by a conversion price of $9.77586545 per share, which conversion price has been adjusted to reflect the one share for eight shares reverse split of the Company's Common Stock effective July 10, 2015. Please refer to Note 10 - Preferred Stock of the Notes to the Consolidated Financial Statements in the Company's 2015 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 are 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 $23.5 million. 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 six months ended December 31, 2015, nor during the year ended June 30, 2015.

On August 3, 2015, pursuant to a First Amendment to the Series A Purchase Agreement (the "Series A First Amendment"), Magellan and One Stone agreed to amend and extend the standstill provisions of the Series A Purchase Agreement to December 31, 2015. In addition to extending the duration of the standstill provisions, which have now expired, the Company agreed to provide One Stone with all material information with respect to the Company's properties and assets and related activities thereto at Poplar, and with any material updates thereto, it being also agreed that such information need not include any information regarding the status or other aspects of the Company's strategic alternatives review process. Certain definitions were also updated in the Series A First Amendment.

For the six months ended December 31, 2015 and 2014, the Company recorded preferred stock dividends of $913 thousand and $859 thousand, respectively, related to the Series A Preferred Stock. The preferred stock dividends for the six months ended December 31, 2015, were paid in kind. Accordingly, the value of these dividends of $913 thousand was recorded and added to the preferred stock balance on the Company's balance sheet at December 31, 2015.

The activity related to the Series A Preferred Stock for the six months ended December 31, 2015, and the fiscal year ended June 30, 2015, is as follows:



	SIX MONTHS ENDED			FISCAL YEAR ENDED
	December 31, 2015			June 30, 2015
	Number of shares	Amount		Number of shares	Amount
	(In thousands, except share amounts)
Fiscal year opening balance	21,162,697	$	25,850	20,089,436	$	24,539
Current year PIK dividend shares issued	747,175	913		1,073,261	1,311
Balance at end of period	21,909,872	$	26,763	21,162,697	$	25,850

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Note 10 - Stockholders' Equity

Treasury Stock

On December 31, 2015, upon the vesting of 7,500 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 2,398 shares to settle withholding taxes. The withheld shares were immediately canceled.

On July 10, 2015, to effect the one share for eight shares reverse split of the Company's common stock, the Company paid cash in lieu of issuance of fractional shares totaling 2,284 post-split shares. The shares underlying the payment of cash in lieu were immediately canceled.

On July 1, 2015, upon the vesting of 12,500 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 2,822 shares to settle withholding taxes. The withheld shares were immediately canceled.

On October 10, 2014, Magellan repurchased 31,250 shares from William H. Hastings, a former Company executive, pursuant to an Options and Stock Purchase Agreement. See Note 8 - Stock Based Compensation for further details.

On July 1, 2014, upon the vesting of 18,750 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 5,981 shares to settle withholding taxes. The withheld shares were immediately canceled.

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:



	SIX MONTHS ENDED					FISCAL YEAR ENDED
	December 31, 2015					June 30, 2015
	Number of shares		Amount			Number of shares		Amount
	(In thousands, except share amounts)
Fiscal year opening balance	1,209,389		$	9,806		1,178,139		$	9,344
Shares repurchased from former executive	—		—			31,250		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	5,220		11			5,981		104
Net shares repurchased to eliminate fractional shares in July 10, 2015 one share for eight shares reverse stock split	2,284		6			—		—
Cancellation of shares repurchased	(7,504	)	(17		)	(5,981	)	(104		)
Balance at end of period	1,209,389		$	9,806		1,209,389		$	9,806

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Note 11 - Loss Per Common Share

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



	THREE MONTHS ENDED						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
	(In thousands, except share and per share amounts)
Net loss	$	(1,380	)	$	(2,885	)	$	(4,443	)	$	(5,513	)
Preferred stock dividend	(461		)	(430		)	(913		)	(859		)
Net loss, including preferred stock dividends	(1,841		)	(3,315		)	(5,356		)	(6,372		)
Net loss attributable to non-controlling interest in subsidiary	13			170			24			170
Net loss attributable to common stockholders	$	(1,828	)	$	(3,145	)	$	(5,332	)	$	(6,202	)

Basic weighted average shares outstanding	5,757,533			5,709,692			5,730,157			5,708,276
Add: dilutive effects of in-the-money stock options	—			—			—			—
Diluted weighted average common shares outstanding	5,757,533			5,709,692			5,730,157			5,708,276

Basic loss per common share:
Net loss attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.32)			$(0.55)			$(0.93)			$(1.09)
Net loss attributable to common stockholders	$(0.32)			$(0.55)			$(0.93)			$(1.09)

Diluted loss per common share:
Net loss attributable to Magellan Petroleum Corporation, including preferred stock dividends	$(0.32)			$(0.55)			$(0.93)			$(1.09)
Net loss attributable to common stockholders	$(0.32)			$(0.55)			$(0.93)			$(1.09)

There is no dilutive effect on loss 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		SIX MONTHS ENDED
	December 31,		December 31,
	2015	2014	2015	2014
In-the-money stock options	—	234,453	—	234,453
Common shares issuable upon conversion of Series A Preferred Stock	2,737,637	2,554,102	2,737,637	2,554,102
Total	2,737,637	2,788,555	2,737,637	2,788,555

Note 12 - 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						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
	(In thousands)
Revenue from oil production:
NP	$	566		$	1,265		$	1,215		$	2,855

Net (loss) income:
NP	$	(238	)	$	(657	)	$	(1,041	)	$	(544	)
MPUK	(294		)	(149		)	(481		)	(581		)
MPA	(86		)	(122		)	(483		)	(757		)
Corporate	(766		)	(1,957		)	(2,446		)	(3,631		)
Inter-segment elimination	4			—			8			—
Consolidated net loss	$	(1,380	)	$	(2,885	)	$	(4,443	)	$	(5,513	)


							December 31, 2015			June 30, 2015
							(In thousands)
Total assets:
NP							$	36,463		$	37,130
MPUK							1,903			2,373
MPA							2,876			4,593
Corporate							79,307			79,474
Inter-segment elimination ⁽¹⁾							(76,920		)	(76,870		)
Total assets							$	43,629		$	46,700

⁽¹⁾ Asset inter-segment eliminations are primarily attributable to investments in subsidiaries.

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Note 13 - Oil and Gas Activities

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



	December 31, 2015			June 30, 2015
	(In thousands)
Proved oil and gas properties:
United States	$	20,841		$	20,857
Less accumulated depletion, depreciation, and amortization	(4,652		)	(4,355		)
Total net proved oil and gas properties	$	16,189		$	16,502

Unproved oil and gas properties:
United States ⁽¹⁾	$	293		$	468
United Kingdom	226			241
Australia	—			—
Total unproved oil and gas properties	$	519		$	709

Wells in Progress:
United States	$	18,875		$	18,560
United Kingdom	1,052			1,100
Total wells in progress	$	19,927		$	19,660

⁽¹⁾On December 29, 2015, the Company entered into a farmout agreement with respect to the Company’s interests in the oil and gas leases which form the Poplar field specifically in relation to the formations located below the top of the Ordovician Winnipeg formation (the “Deep Formations”), which is estimated to be located at a depth of approximately 8,896 feet. Pursuant to the terms of the farmout agreement, the farmees made a $175 thousand non-refundable payment to the Company at signing of the farmout agreement and are required to i) commence the deepening of the EPU120 well before June 30, 2017, and ii) make an additional payment of $150 thousand to the Company to earn a 75% interest in the Company’s approximately 50% interests in the Deep Formations. The farmees intend to explore the Deep Formations for potential hydrocarbons and helium. The Company has reduced the capitalized cost for its unproved oil and gas properties, which at acquisition were assigned to the Deep Formations, by the amount of the $175 thousand non-refundable payment.

Note 14 - Commitments and Contingencies

Refer to Note 14 - Commitments and Contingencies of the Notes to the Consolidated Financial Statements in our 2015 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 6 - 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) 1,158,080 shares of the Company's Common Stock and (ii) a warrant granting Sopak the right to purchase from the Company an additional 543,478 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 $1.7 million and $1.7 million as of December 31, 2015, and June 30, 2015, 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 $1.7 million and $1.7 million as of December 31, 2015, and June 30, 2015, 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 $1.7 million and $1.7 million as of December 31, 2015, and June 30, 2015, respectively, under prepaid and other assets in the unaudited condensed consolidated balance sheets.

Celtique Litigation. On March 3, 2015, MPUK received a claim form and particulars of claim that was issued in the

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High Court of Justice, Queen’s Bench Division, Commercial Court in London, England on February 26, 2015, pursuant to which Celtique Energie Weald Limited ("Celtique") 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 £1.5 million (equivalent to $2.2 million as of December 31, 2015) for the outstanding cash calls related to the Broadford Bridge-1 well along with interest on that amount at 5% above base rate until payment (the "Celtique Claim").

On March 24, 2015 Celtique filed for summary judgment on the Celtique Claim. On April 1, 2015, MPUK filed a defense and counterclaim asserting, among other things, that the cash calls by Celtique are not 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. On June 15, 2015, Celtique’s application for summary judgment was heard and dismissed on the basis that MPUK had a real prospect of successfully defending against the Celtique Claim. Celtique was ordered to pay MPUK’s costs of responding to the application, assessed at £60,000 (equivalent to $94 thousand as of June 30, 2015), which was paid by Celtique on June 29, 2015.

MPUK believes that it has strong defenses and intends to vigorously contest the Celtique Claim. However, due to the early stage of this matter and the uncertainty and risks inherent in litigation, the Company cannot predict an ultimate outcome. As such, a meaningful estimate of a reasonably possible loss, if any, or range of reasonably possible losses, if any, cannot be made as of the date of these consolidated financial statements. As of December 31, 2015, the Company had approximately $896 thousand in capitalized costs related to these licenses included in the accompanying consolidated balance sheet.

Utah CO2 Option. In May 2015, in accordance with an option agreement between Magellan, Utah CO2, and Savoy Energy, LLC ("Savoy"), Utah CO2 exercised the CO₂ purchase option available under the Utah CO2 Option Agreement. Exercise of the CO₂ purchase option allows Utah CO2 to negotiate in good faith and enter into a purchase agreement for CO₂with Savoy, the key terms of which should be consistent with the terms detailed in the Utah CO2 Option Agreement, which included a fifty year term, an attractive CO₂ price per mcf, the exclusive access to CO₂ volumes recoverable from Farnham Dome for CO₂-EOR projects in Utah, and no CO₂ purchase obligations for the first three years.

NT/P82 Seismic Survey. In June 2015, the Australian Commonwealth-Northern Territory Offshore Petroleum Joint Authority and the National Offshore Petroleum Titles Administrator ("NOPTA") approved a variation in MPA's work program commitments under the NT/P82 permit in the Bonaparte basin. In addition to retaining the requirement for geotechnical studies that were to be completed on or before May 12, 2015, at an estimated cost of AUD $500 thousand, the new work program commitment replaced the commitment to drill an exploration well on or before May 12, 2016, carrying an estimated cost of AUD $25 million, with the requirement to complete a minimum of 600 km²3-D seismic survey on or before May 12, 2016, the cost of which seismic survey is estimated at AUD $16 million. NOPTA also advised that a suspension and extension of the work requirement for the permit years ending May 12, 2015, and 2016, may be considered, and any renewal application will be expected to include plans for drilling of an exploratory well.

Engagement of RFC Ambrian as financial advisor for farmout of NT/P82. In July 2015, the Company engaged RFC Ambrian as its financial advisor to run a formal bid process for the farm-out of its 100% operating interest in the NT/P82 permit in the Bonaparte basin, offshore Australia, to fund future exploration costs and recover back-costs incurred. The terms of the engagement include cash payments of $20 thousand and $80 thousand for the two initial stages of the engagement through a written offer, and a success fee upon completion of a legally binding agreement ranging from $250 thousand to 5% of the farm-out value of the agreement to the Company.

Petrie Engagement. In June 2015, the Special Committee engaged Petrie Partners, LLC ("Petrie") to act as its financial advisor (the "Petrie Engagement"). Under the terms of the Petrie Engagement, the Company has agreed to pay Petrie certain fees contingent upon the successful closing of certain transactions ranging from $0 to 3% of the value of such transaction, together with reimbursement of expenses. The Petrie Engagement may be terminated by either party with 5 days written notice.

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 15 - Related Party Transactions). Pursuant to the terms of a master services contract, as amended on November 4, 2015, Mi3 is entitled to a payment in the amount of $100 thousand, contingent upon the completion of a transaction resulting in the sale of Poplar to a third party, in addition to a fixed payment for certain services provided.

NASDAQ Listing Requirements. On November 5, 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 indicated that the Company will be provided with a compliance period of 180 calendar days, or until May 3, 2016, in which to regain compliance, pursuant to NASDAQ Marketplace Rule 5810(c)(3)(A). The letter further indicated that if, at any time during the 180-day

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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.

Note 15 - Related Party Transactions

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 $31 thousand and $125 thousand of consulting fees related to Devizes during the six months ended December 31, 2015, and 2014, respectively.

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 CO₂ from Farnham Dome, on August 14, 2014, the Company formed a subsidiary, Utah CO2. On December 1, 2014, two other non-controlling interest owners became members of Utah CO2, one of which is Mi4 Oil and Gas LLC ("Mi4"), a Colorado limited liability company majority owned by Mi3. Mi3 performs ongoing consulting work for both Utah CO2 and other Magellan entities. During the six months ended December 31, 2015, and 2014, the Company recorded $292 thousand and $528 thousand of consolidated expense related to fees payable to Mi3.

Note 16 - Employee Retention and Severance Costs

The Company is required to record charges for one-time employee severance benefits and other associated costs as incurred.

Incentive Agreements with Chief Financial Officer

On October 12, 2015, the Company entered into a series of new incentive compensation agreements with Antoine J. Lafargue, the Company's Chief Financial Officer (the "CFO Incentive Agreements"). The CFO Incentive Agreements include i) amendments to the provisions for severance payments available to the CFO under his existing employment agreement dated October 31, 2014 (pursuant to an amendment of such employment agreement), to include provisions for the payment of up to two years' salary as severance in the event that the CFO’s employment with the Company is terminated under certain circumstances within a period ending ten months after the date on which a qualifying transaction (as generally defined below) occurs, capped at $600 thousand; ii) a restricted stock award agreement whereby a restricted stock grant was made to the CFO on October 12, 2015 totaling 62,500 shares of common stock that are to vest immediately prior to the completion of a qualifying transaction; iii) a potential cash award pursuant to a transaction incentive agreement, which cash award is contingent upon the completion of a qualifying transaction and would range from $0 to $1 million based on the market value of the Company's common stock reflected in the qualifying transaction, with the amount of cash award to be equal to $2,750 for each one cent of market value per share of the Company’s common stock reflected in the qualifying transaction above a minimum market value threshold of $1.60 per share; iv) a phantom stock award, also pursuant to the transaction incentive agreement, with payment contingent upon completion of a qualifying transaction and to be based on the value of 62,500 notional shares; and v) an override bonus agreement which provides for a potential bonus outside of the Company’s 2012 Omnibus Incentive Compensation Plan that would double the amounts payable under the awards available under ii, iii, and iv, above, in certain circumstances. For purposes of the CFO Incentive Agreements, a qualifying transaction is generally defined to mean an acquisition of more than 50% of the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors, or the sale or other disposition of greater than 95% of the value of the gross assets of the Company, in either case occurring prior to December 31, 2017. No accrual has been made in the accompanying condensed consolidated financial statements for the CFO Incentive Agreements as amounts were contingent on the occurrence of future events and service. The Company does not consider the future events to meet the definition of "probable" due to the nature of the events being contingent upon third parties outside of the Company's control.

Employee Retention Cash Bonus Plan

On June 5, 2015, the Compensation, Nominating and Governance Committee of the Board of Directors of the Company and the Board of Directors of the Company approved a cash bonus plan for the Company's non-executive officer employees for the purpose of retention of certain key accounting, human resource, and administrative employees through certain key milestone events (the "Employee Retention Cash Bonus Plan"). The terms of the Employee Retention Cash Bonus Plan specify payment of retention bonuses for such employees upon the achievement of the milestones, which are i) the filing of the Company's annual report on Form 10-K for the year ended June 30, 2015 (which occurred in October, 2015), and ii) the completion of a strategic transaction. The maximum bonus payable to the employees under each of the milestones is as follows:

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i) $168 thousand, and ii) $286 thousand, respectively. As of December 31, 2015, the Company has recorded an accrual in the amount of $425 thousand in the accompanying consolidated financial statements for the Employee Retention Cash Bonus Plan.

Severance and Termination Benefit Payments

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 six months ended December 31, 2014, the Company expensed and paid total employee-related severance costs of $475 thousand.

Note 17 - Subsequent Events

Partial Sale of Central Investment

From January 1, 2016, through February 8, 2016, the Company sold approximately 3.0 million shares of Central in the open market and generated approximately AUD $353 thousand (USD $251 thousand) of proceeds. As of February 8, 2016, the Company continues to own approximately 20.9 million shares of Central, which at the closing per share market price as of February 8, 2016 of AUD $0.105 and foreign exchange rate of 0.71, represented approximately $1.6 million of potential liquidity.

On January 15, 2016, the Company entered into a Premium Finance Agreement (the "Second Premium Note") to finance its insurance premiums in connection with its global umbrella policy renewal. The Second Premium Note has a principal amount of $42 thousand, bears interest at 6.25% and has an amortization term of nine months. Principal and interest payments of $5 thousand are due monthly February 2016 through October 2016.

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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 2015 Form 10-K, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the 2015 Form 10-K. Any capitalized terms used but not defined in the following discussion have the same meaning given to them in the 2015 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 2015 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

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we") is an independent oil and gas exploration and production company focused on 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, and as of February 8, 2016, a 4.8% ownership stake in Central Petroleum Limited (ASX:CTP) ("Central"), a Brisbane based junior exploration and production company that operates one of the largest holdings of prospective onshore acreage in Australia.

On July 10, 2015, the Company completed a one share-for-eight shares reverse stock split with respect to the Company's common stock. Prior amounts of shares of common stock and per share prices with respect to common stock have been adjusted in this report to reflect the reverse stock split.

SUMMARY RESULTS OF OPERATIONS

The Company has incurred losses from operations for the three months ended December 31, 2015, of $1.5 million. In addition, during the six months ended December 31, 2015, working capital has decreased from $3.9 million at June 30, 2015, to a working capital deficit of $658 thousand at December 31, 2015, and the Company's cash balance has decreased to $429 thousand as of December 31, 2015. The Company continues to experience liquidity constraints and has begun selling certain of its non-core assets to fund its operations. However, proceeds from these asset sales may not provide sufficient liquidity to fund operations for the next twelve months. These factors raise substantial doubt about the Company's ability to continue as a going concern.

Revenues. Revenues for the three months ended December 31, 2015, totaled $566 thousand, compared to $1.3 million for the prior year period, a decrease of 55%. The $699 thousand decrease in revenue was primarily due to a decrease in the realized pricing per barrel of $24.86 due to the decline in WTI, the relevant oil price benchmark.

Net loss. Net loss for the three months ended December 31, 2015 totaled $1.4 million ($(0.32)/basic share), compared to a net loss of $2.9 million ($(0.55)/basic share) in the prior year. The decrease in net loss was primarily the result of a decrease in lease operating expense of $669 thousand, a reduction in exploration expenses of $476 thousand and a decrease in general and administrative expense of $912 thousand, which were partially offset by a decrease in oil sales revenues of $699 thousand. In addition, the Company realized a gain on the sale of shares of Central of $118 thousand.

Adjusted EBITDAX. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) for the three months ended December 31, 2015, totaled negative $1.2 million, compared to negative $1.8 million in the prior year period.

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The increase in Adjusted EBITDAX resulted from a decrease in lease operating expenses and general and administrative expenses, which were partially offset by a decrease in oil sales revenue.

Cash. As of December 31, 2015, Magellan had $429 thousand in cash and cash equivalents, compared to $1.1 million at June 30, 2015. The decrease of $622 thousand was the result of net cash used in operating activities of $2.0 million, net cash provided by investing activities of $1.4 million, net cash provided by financing activities of $32 thousand, and net decrease in cash from the effect of exchange rate changes of $25 thousand. The net cash provided by investing activities primarily related to proceeds from the sale of shares of Central stock.

CORPORATE EVENTS

Strategic Alternatives Review Process

In light of the Company's currently constrained capital resources and the significant capital requirements to develop Poplar using CO₂-EOR, on June 5, 2015, the Company formed a special committee of independent members of the Board of Directors of the Company (the "Special Committee") to i) consider various strategic alternatives potentially available to the Company, which may include, but are not limited to, sales of some or all of the assets of the Company, joint ventures, a recapitalization, and a sale or merger of the Company and ii) amend compensation arrangements of executives and employees for the purpose of retention and alignment of interests with the interests of the common stockholders during such strategic alternatives review process. The Special Committee engaged Petrie Partners, LLC as financial advisor to assist in the consideration of such matters. The Special Committee has been and continues to be actively engaged in the strategic alternatives review process, and is currently in non-binding discussions regarding a specific potential transaction. Although substantial negotiations in furtherance of the parameters of the potential transaction have occurred, as of the filing date of this report these negotiations have not resulted in the execution of a definitive agreement. In addition, as of the filing date of this report, no final decision on any particular strategic alternative or transaction has been reached, and there is no assurance that any future definitive agreement will be reached, or that any future sale or other strategic alternative transaction or transactions will occur.

NASDAQ Listing Requirements

On November 5, 2015, the Company received a letter from 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 indicated that the Company will be provided with a compliance period of 180 calendar days, or until May 3, 2016, in which to regain compliance, pursuant to NASDAQ Marketplace Rule 5810(c)(3)(A). The letter further indicated 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. We believe that the Company's platform as a public entity carries certain intrinsic value and that stockholders benefit from the enhanced liquidity provided by the listing of the Company's common stock on NASDAQ.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES

During the three months ended December 31, 2015, in parallel with the ongoing strategic alternatives review process, the Company continued to operate its projects to evaluate and determine the potential of its exploration and production properties.

Poplar (Montana, USA)

CO₂-EOR pilot project. During fiscal year 2015, and the three months ended September 30, 2015, the Company concluded that the use of the CO₂-EOR technique at Poplar was technically effective to recover substantial additional volumes of hydrocarbons, and that the development of Poplar on a full field basis using CO₂-EOR will require significant capital to invest, the amount of which we estimate at several hundreds of millions of dollars. In addition, the economic viability of the development of Poplar using the CO₂-EOR technique will depend on a recovery of oil prices. The Company’s assessment of this project in conjunction with the commodity price environment led us to initiate the strategic alternatives review process, which has been ongoing since June 2015.

During the three months ended December 31, 2015, oil continued to be produced from the producing wells of the CO₂-EOR pilot project, and the Company monitored constantly the key data arising from the wells of the CO₂-EOR pilot, including pressure, temperature, and production rates, which data is integrated in the Company's reservoir simulation model, with the assistance of third party consultants. During the three months ended December 31, 2015, injection of CO₂ or water, pursuant to a water alternating gas process, was not resumed, primarily due to the Company’s current liquidity constraints. We believe that

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the engineering work and data collected over the past several years at Poplar is sufficient to effectively conduct the strategic alternatives review process, and that the additional data which may become available from resuming CO₂ or water injection in the CO₂-EOR pilot project would not provide material incremental benefit relative to the necessary costs considering the Company’s current liquidity position.

Shallow Intervals. During the three months ended December 31, 2015, Magellan sold 16 Mboe (174 boepd) of oil attributable to its net revenue interests in Poplar. The production mainly came from primary production from the Charles formation. During the three months ended December 31, 2015, the Company continued the implementation of certain cost saving initiatives, including a program of shutting-in certain wells which were estimated by the Company to be uneconomical in the current price environment, halting workovers, and the optimization of the utilization of the Company’s employees and third party service providers. For the three months ended December 31, 2015, we estimated that in aggregate the operations at Poplar nearly achieved break-even cash flows from operations. However, considering the continuing decrease in WTI, the Company’s relevant oil price benchmark, the Company’s ability to generate positive cash flow from operations at Poplar will be further challenged. We believe that Poplar is a critical component to maximize the chances of success of the strategic alternatives review process and therefore currently intend to continue to operate the field in the present oil price environment, in order to maintain the Company's title to the oil and gas leases that cover Poplar, which leases are held by production.

Deep Intervals. During the three months ended December 31, 2015, there was no production from the Deep Intervals at Poplar. In addition, on December 29, 2015, the Company entered into a farmout agreement with respect to the Company’s interests in the oil and gas leases which form the Poplar field specifically in relation to the formations located below the top of the Ordovician Winnipeg formation (the “Deep Formations”), which is estimated to be located at a depth of approximately 8,896 feet. Pursuant to the terms of the farmout agreement, the farmees made a $175 thousand non-refundable payment to the Company at signing of the farmout agreement and are required to i) commence the deepening of the EPU120 well before June 30, 2017, and ii) make an additional payment of $150 thousand to the Company to earn a 75% interest in the Company’s approximately 50% interests in the Deep Formations. The farmees intend to explore the Deep Formations for potential hydrocarbons and helium.

United Kingdom

UK - Horse Hill. During the three months ended December 31, 2015, our partner in the Horse Hill-1 well (“HH-1”), Horse Hill Development Limited (“HHDL”), progressed certain analysis and studies of the data collected from the drilling of HH-1 and prepared for the flow test of certain formations of HH-1. On February 8, 2016, HHDL commenced an extended flow test over three separate zones in the HH-1 well. The extended flow test is designed to test the conventional formations, particularly the Upper Portland Sandstone and two Kimmeridge limestone formations beneath the Portland. Magellan is fully carried by HHDL for the cost of performing the flow test under the terms of the farmout agreement with HHDL. Once the Company receives the results of the flow test, the Company will determine what it believes is the most appropriate path to generate value for its shareholders, which path may include a sale or further farmout agreement of the Company’s interest in HH-1 and PEDLs 137 and 246, and which will reflect consideration of the overall political and social environment in the UK with respect to conventional and unconventional oil and gas developments.

UK - Central Weald Licenses. In regards to PEDLs 231, 234, and 243, which are co-owned with Celtique, during the three months ended December 31, 2015, the Company continued to manage the pending litigation with Celtique. Potential resolutions of the pending litigation could include a possible sale of the Company’s interests in these licenses. Considering the pending litigation and that these licenses are subject to drill-or-drop obligations with license terms ending June 30, 2016, there is a risk that the litigation with Celtique will not be resolved in time to avoid the relinquishment of these licenses.

Peripheral Weald Licenses. With respect to P1916, there was very limited activity during the three months ended December 31, 2015, and no further material activity is planned during fiscal year 2016. Considering the risk profile of this prospect and the challenges in securing a potential drilling site, the Company may decide to withdraw from this license. Total inception to date costs related to the license of $39 thousand have been included in exploration expenses.

Australia

NT/P82. In July 2015, the Company engaged RFC Ambrian as a financial advisor to support the Company’s efforts to conduct a farmout process. As part of the potential 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 meet the work requirements under the terms of the license and potential renewal term. Although the Company is actively working on negotiating the terms of a potential farmout agreement, there is a risk that the negative impact of the commodity price environment and the early stage exploration nature of this prospect could prevent the Company from finalizing a farmout or sale agreement. Given the high level of offshore seismic activity currently being planned in the Bonaparte Basin, the Company is trying to develop an alternative approach to allow the Company to meet the terms required under the permit by seeking a farmout agreement with 3-D seismic service providers.

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CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES

During the six months ended December 31, 2015, the Company used $622 thousand in cash and, as of December 31, 2015, had $429 thousand in cash and cash equivalents on its balance sheet. The relatively limited reduction in the Company’s cash and cash equivalents is primarily the result of i) an active management of the Company’s disbursements, ii) the halt of workovers and of CO₂ injection at Poplar, iii) the impact of certain cost saving initiatives, and iv) the sale of shares of Central to finance the Company’s activities. As of February 8, 2016, the cash balances of the Company amounted to approximately $190 thousand and the Company continues to face significant liquidity constraints in the short term. The Company has sold some of its shares in Central and currently intends to continue to sell shares of Central to finance the Company’s activities and to manage its operational cash flows in the short-term, while the strategic alternatives review process discussed above remains ongoing. There can be no assurance that any transaction from the strategic alternatives review process will occur. Considering the current liquidity position of the Company, there is a risk that the Company will not be able to finance its activities until such time that a transaction, if any, can be completed or that the Special Committee's efforts do not result in a transaction or series of transactions that allow the Company to continue as a going concern.

Since June 30, 2015, and through February 8, 2016, the Company has sold 18.6 million shares of Central in the open market and generated approximately AUD $2.3 million (USD $1.7 million) of proceeds. As of February 8, 2016, the Company continues to own approximately 20.9 million shares of Central, which at the closing per share market price on February 8, 2016, of AUD $0.105 and the foreign exchange rate of 0.71, represented approximately $1.6 million of potential liquidity.

Depending upon WTI prices and the impact of ongoing cost saving initiatives, we expect that the net cash burn rate at Poplar could range from positive inflows to outflows of $50 thousand per month. The Company projects that it will incur net cash uses per month ranging between $500 thousand and $700 thousand, which is comprised of the following broad components: (i) net cash burn of approximately $0 to $50 thousand at Poplar; (ii) no additional expenses in relation to running the CO₂-EOR pilot; (iii) general and administrative expenses of $450 thousand to $550 thousand; and (iv) approximately $50 thousand to $100 thousand in other expenses. The Company is currently working on certain additional measures which could result in further reductions to monthly cash expenditures. 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.

We believe that, based on the current estimated net cash burn rate of the Company, the sale of shares of Central should be sufficient to finance the Company’s activities for at least the following three months while the Special Committee continues to advance the strategic alternatives review process, and that the Company has the following additional potential means to finance its activities during this period: a farmout of NT/P82, a farmout or sale of the Company’s interests in Horse Hill, and a monetization of the Mereenie and Palm Valley bonus rights discussed in Note 2 to the condensed consolidated financial statements (unaudited) included under Part I, Item 1 of this report.

Uses of Funds

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. At December 31, 2015, there were 28 wells producing at Poplar.

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 CO₂-EOR pilot, which is expected to continue to produce during fiscal year 2016. During the three months ended December 31, 2015, ongoing expenditures related to the CO₂-EOR pilot have been curtailed significantly, which will result in significantly reduced costs related to the operation of the CO₂-EOR pilot, and the Company expects that this reduced level of activity will be maintained until the results of the strategic alternatives review process can be ascertained.

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 2016, and in the Deep Formations the Company is fully carried by the farmees until the deepening of the first well has been completed.

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, the Company received a cash call from Celtique for the advancement of estimated expenses

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in the amount of approximately $2 million in connection with the Broadford Bridge-1 well, and the Company is evaluating its alternatives under the applicable joint operating agreement. Also as previously reported, Celtique initiated a legal proceeding against the Company with respect to that cash call and related issues. See Note 14 - Commitments and Contingencies - Celtique Litigation of the Notes to 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 UK in PEDLs 137 and 246, where the Horse Hill well was drilled, on February 8, 2016, HHDL, the Company’s 65% partner in these licenses, commenced an extended flow test over three separate zones in the HH-1 well. The extended flow test is designed to test the conventional formations, particularly the Upper Portland Sandstone and two Kimmeridge limestone formations beneath the Portland. The cost of the flow test is due to be fully paid by HHDL in accordance with the terms of the farmout agreement between HHDL and MPUK.

In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, as amended in June 2015, the Company is required to obtain 600km² of 3-D seismic data on the permit by May 2016. Following the completion of prior seismic surveys in the license area and the associated processing and interpretation of the data from these surveys, the Company is actively engaged in a process to obtain a farmout partner, which partner would be expected to obtain the remaining 3-D seismic data on our behalf, and the Company has engaged a financial advisor to assist in the farmout process. The Company does not expect to incur further significant capital expenditures on its own through the end of the term of the license.

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 quarter ended December 31, 2015, the Company paid the dividend in kind. The decision to pay the dividend in kind for the quarter ended December 31, 2015, was primarily driven by the liquidity position of the Company and its efforts to conserve cash. In addition, the per share market price of the Company's common stock is materially lower than the conversion price of the Series A Preferred Stock, which is approximately $9.78 per share following the impact of the one share for eight shares reverse split of the Company's common stock effective July 10, 2015.

Contractual Obligations. Please refer to the contractual obligations table in Part II, Item 7 of our 2015 Form 10-K for information on all material contractual obligations as of June 30, 2015, and see Note 14 - Commitments and Contingencies to the accompanying condensed consolidated financial statements included in this report for additional information, including 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 $429 thousand of cash and cash equivalents as of December 31, 2015, compared to $1.1 million as of June 30, 2015. The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates.

Due to the international 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 or MPA to the US, the Company is potentially liable for incremental US federal and state income tax, which may be reduced by the US federal and state net operating loss and foreign tax credit carry forwards available to the Company at that time. We believe that we currently have sufficient net operating loss and foreign tax credit carry forwards to offset any potential future tax obligation as a result of repatriation.

Central Shares. The Company currently intends to continue to gradually monetize its position in Central stock to finance its activities. The Company is not constrained in its ability to sell its shares in Central by contractual arrangements with Central. Since June 30, 2015, through February 8, 2016, the Company has sold approximately 18.6 million shares of Central stock, and as of February 8, 2016 continues to own approximately 20.9 million shares of Central stock, which based on the Central closing market price on February 8, 2016, represented a total value of $1.6 million of potential liquidity.

Since June 30, 2015, the price of Central stock has been volatile with closing prices ranging between AUD $0.10 to AUD $0.29 per share, having been impacted by i) the previously anticipated announcement by the Australian government to award a contract to develop a pipeline interconnection between the Amadeus Gas Pipeline located in the Northern Territory, Australia and the New South Wales gas pipeline network, which is commonly referred to as the North East Gas Interconnector (“NEGI”), which could allow additional gas to become available to supply the LNG terminals currently under construction in Queensland, which tend to benefit from higher sale prices than current gas sales contracts in the Northern Territory, ii) the issuance by Central of additional shares of stock to investors on November 17, 2015, and December 11, 2015, iii) the potential new gas sales agreement following the award of the NEGI development contract, and iv) the overall commodity price environment.

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



	December 31, 2015			June 30, 2015
	(In thousands)
Outstanding borrowings:
Premium note	$	73		$	—
Term loan	5,500			5,500
Total	$	5,573		$	5,500
Less current portion	(760		)	—
Long-term portion	$	4,813		$	5,500

On September 17, 2015, the Company entered into a Premium Finance Agreement (the "Premium Note") to finance its insurance premiums in connection with its annual property and casualty insurance renewal. The Premium Note had an original principal amount of $108 thousand, bears interest at 6.50% and has an amortization term of nine months. Principal and interest payments of $12 thousand are due monthly October 2015 through June 2016. At December 31, 2015, $73 thousand was outstanding on the Premium Note. In addition, on January 15, 2016, the Company extended the policy term of its foreign umbrella liability policy and entered into an additional Premium Finance Agreement with a principal amount of $42 thousand (the "Additional Premium Note"). The Additional Premium Note bears interest at 6.25% and has an amortization term of nine months. Principal and interest payments of $5 thousand are due monthly February 2016 through October 2016.

The Company, through its wholly owned subsidiary NP, maintains a term loan (the "Term Loan") with West Texas State Bank ("WTSB"). As of December 31, 2015 the outstanding amount of the Term Loan was $5.5 million. There are no additional amounts available to borrow under the Term Loan. The Term Loan will mature on June 30, 2020, and is subject to monthly floating interest payments based on the Prime Rate (currently approximately 3.25%) plus 1.50% and a floor rate of 4.75%. From July 1, 2015 to June 30, 2016, the payment obligations under the Term Loan will consist of interest payments only, and from July 1, 2016 to June 30, 2020, the payment obligations will include the interest payment and the amortization payments of the principal amount of the Term Loan. The Term Loan 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 Term Loan 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 Term Loan. As of December 31, 2015, the Company was in compliance with all such covenants.

Registered Equity Facility. 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 (the "Shelf"), 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 registered the issuance of up to $100 million in equity securities of the Company and is currently planned to be effective through December 2017.

Depending on various factors, including market conditions for the Company's equity securities, 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.

Other Sources of Financing. In addition to its existing liquid capital resources, the Company has various alternatives to fund its activities. In addition to the alternatives to address short-term liquidity issues discussed above, these alternatives could potentially include mezzanine financing from a bank and the alternative investment markets, equity issuances via a PIPE or secondary offering, and a partial or complete divestiture or farmout of a portion of the development program of some of the Company's assets.

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Cash Flows

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



	December 31,
	2015			2014
	(In thousands)
Cash (used in) provided by:
Operating activities	$	(2,032	)	$	(4,192	)
Investing activities	1,403			(5,658		)
Financing activities	32			1,353
Effect of exchange rate changes on cash and cash equivalents	(25		)	(520		)
Net decrease in cash and cash equivalents	$	(622	)	$	(9,017	)

Cash used in operating activities during the six months ended December 31, 2015, was $2.0 million, compared to cash used in operating activities of $4.2 million for the same period in 2014. The decrease in cash used in operating activities was primarily due to reductions in lease operating expenses of $898 thousand, exploration expenses of $651 thousand, general and administrative expenses, excluding non-cash stock based compensation and foreign currency gains of $1,256 thousand, and an increase in the change in accounts payable and accrued liabilities of $701 thousand as the Company managed its disbursements to preserve cash, which were partially offset by the reduction of oil sales revenues of $1,640 thousand.

Cash provided by investing activities during the six months ended December 31, 2015, was $1.4 million, compared to cash used of $5.7 million for the same period in 2014. The change in cash flows from investing activities was primarily due to a decrease in capital expenditures of $5.2 million on the CO₂-EOR Pilot at Poplar, and proceeds from the sales of Central stock amounting to $1.4 million. In addition, the Company received $175 thousand from the farmout of the Deep Formation rights at Poplar.

Cash provided by financing activities during the six months ended December 31, 2015, was $32 thousand, compared to cash provided of $1.4 million in the prior year period. Cash provided by financing activities in the current year period was primarily due to the Company entering into a short-term note to finance the renewal of insurance premiums, which was partially offset by the payment of deferred financing costs related to the WTSB Term Loan. Cash provided in the prior year period related to borrowings on the line of credit of $3.5 million, which were partially offset by cash payments of dividends on the Series A Preferred Stock of $859 thousand, and the repurchase of stock and stock options of $566 thousand and $983 thousand, respectively.

During the six months ended December 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 $25 thousand in cash and cash equivalents, compared to a decrease of $520 thousand for the same period in 2014.

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

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



	December 31,
	2015		2014		Difference			Percent change
Poplar:
Oil revenue (In thousands)	$	566	$	1,265	$	(699	)	(55	)%
Oil sales volume (Mbbls)	16		21		(5		)	(24	)%
Oil sales volume (bopd)	174		228		(54		)	(24	)%
Average realized oil price ($/bbl)	$	35.38	$	60.24	$	(24.86	)	(41	)%

Oil Revenue

Revenues for the three months ended December 31, 2015, totaled $566 thousand, compared to $1.3 million in the prior year period, a decrease of 55%. The $699 thousand decrease in revenue from the prior year period was primarily due to a decrease in the sales price realized from production from the Poplar field.

Oil Sales Volume

Sales volume for the three months ended December 31, 2015, totaled 16 Mbbls (174 bopd), compared to 21 Mbbls (228 bopd) in the prior year period, a decrease of 24%. The decrease was primarily attributable to the natural production decline of the Poplar field and shutting in certain uneconomic wells during the quarter.

Average Realized Oil Price

The average realized price for the three months ended December 31, 2015, was $35.38/bbl, compared to $60.24/bbl during the same period in the prior year, a decrease of 41%. 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 Expenses

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



	December 31,
	2015		2014		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	601	$	1,270	$	(669	)	(53	)%
Depletion, depreciation, amortization, and accretion	$	238	$	260	$	(22	)	(8	)%
Exploration	$	10	$	486	$	(476	)	(98	)%
General and administrative	$	1,225	$	2,137	$	(912	)	(43	)%

Selected operating expenses (USD/bbl):
Lease operating	$	38	$	60	$	(22	)	(37	)%
Depletion, depreciation, amortization, and accretion	$	15	$	12	$	3		25	%
Exploration	$	1	$	23	$	(22	)	(96	)%

Lease Operating Expenses. Lease operating expenses decreased $669 thousand to $601 thousand, or $38/bbl, during the three months ended December 31, 2015, as a result of a reduction of $171 thousand in production taxes related proportionally to decreased production and pricing in the current period, a decrease of $149 thousand in salt water disposal expenses, as a result of shutting in some of the uneconomic wells, and decreases in field salaries, contract labor, workovers, parts and supplies, location maintenance, and other expenses totaling $366 thousand, related to lower activity at the Poplar field, which were partially offset by CO₂ costs of $66 thousand allocated to the producing CO₂wells.

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



	December 31,
	2015		2014		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	24	$	50	$	(26	)	(52	)%
Depletion	172		165		7			4	%
ARO accretion	42		45		(3		)	(7	)%
Total	$	238	$	260	$	(22	)	(8	)%

Depletion, depreciation, amortization, and accretion expenses decreased $22 thousand to $238 thousand, or $15/bbl, during the three months ended December 31, 2015, compared to $260 thousand or $12/bbl in the prior year period. The change was primarily due to a decrease in depreciation of $26 thousand. Depletion increased $7 thousand as a result of the increase in the depletion rate from $8/bbl to $11/bbl due to the exclusion of previously booked PUD reserves in the depletion calculation for the three months ended December 31, 2015, which was partially offset by the $17.4 million impairment of proved properties recorded in fiscal year 2015, and lower production volumes.

Exploration Expenses. Exploration expenses decreased by $476 thousand to $10 thousand, or $1/bbl, during the three months ended December 31, 2015. The decrease was primarily the result of a reduction in expenditures related to the

Company's activities in the UK in the current year period.

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



	December 31,
	2015			2014		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation expense and foreign transaction gain)	$	1,117		$	1,754	$	(637	)	(36	)%
Stock compensation expense	199			383		(184		)	(48	)%
Foreign transaction gain from investment in subsidiaries	(92		)	—		(92		)	NA
Total	$	1,225		$	2,137	$	(912	)	(43	)%

General and administrative expenses decreased by $912 thousand, or 43%, to $1.2 million during the three months ended December 31, 2015, compared to the prior year period. General and administrative expenses, excluding stock based compensation and foreign transaction gain, decreased by $637 thousand, or 36%, to $1.1 million. This decrease was primarily the result of reductions in expenses related to corporate office salaries and benefits of $192 thousand, director fees of $54 thousand, professional fees of $205 thousand, travel of $81 thousand and expenses related to our Australian office of $58 thousand. Stock compensation expense decreased $184 thousand as a result of expense reversals for options forfeited by former employees and changes in the performance target dates for certain PBOs.

COMPARISON OF RESULTS BETWEEN THE SIX MONTHS ENDED DECEMBER 31, 2015 AND 2014

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



	December 31,
	2015		2014		Difference			Percent change
Poplar:
Oil revenue (In thousands)	$	1,215	$	2,855	$	(1,640	)	(57	)%
Oil sales volume (Mbbls)	34		40		(6		)	(15	)%
Oil sales volume (bopd)	185		217		(32		)	(15	)%
Average realized oil price ($/bbl)	$	35.74	$	71.38	$	(35.64	)	(50	)%

Oil Revenue

Revenues for the six months ended December 31, 2015, totaled $1.2 million, compared to $2.9 million in the prior year period, a decrease of 57% . The $1.6 million decrease in revenue from the prior year period was primarily due to a decrease in the sales price realized from production from the Poplar field, and a decrease in production.

Oil Sales Volume

Sales volume for the six months ended December 31, 2015, totaled 34 Mbbls (185 bopd), compared to 40 Mbbls (217 bopd) in the prior year period, a decrease of 15% . The decrease was primarily attributable to the natural production decline of the Poplar field.

Average Realized Oil Price

The average realized price for the six months ended December 31, 2015, was $35.74/bbl, compared to $71.38/bbl during the same period in the prior year, a decrease of 50%. 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 Expenses

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



	December 31,
	2015		2014		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	1,586	$	2,484	$	(898	)	(36	)%
Depletion, depreciation, amortization, and accretion	$	436	$	515	$	(79	)	(15	)%
Exploration	$	257	$	908	$	(651	)	(72	)%
General and administrative	$	3,203	$	4,526	$	(1,323	)	(29	)%

Selected operating expenses (USD/bbl):
Lease operating	$	47	$	62	$	(15	)	(24	)%
Depletion, depreciation, amortization, and accretion	$	13	$	13	$	—		—	%
Exploration	$	8	$	23	$	(15	)	(65	)%

Lease Operating Expenses. Lease operating expenses decreased $898 thousand to $1.6 million, or $47/bbl, during the six months ended December 31, 2015, as a result of a reduction of $324 thousand in production taxes, related proportionally to decreased production and pricing in the current period, a decrease in workover expense of $196 thousand, a decrease in salt water disposal costs of $167 thousand from shutting in uneconomic wells, and reductions in field salaries, contract labor, contract service rig costs, location maintenance, equipment rental, and other LOE totaling $248 thousand as a result of lower activity at the Poplar field, which were partially offset by CO₂ costs of $66 thousand allocated to the producing CO₂ wells.

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



	December 31,
	2015		2014		Difference			Percent change
	(In thousands)
Depreciation and amortization	$	54	$	102	$	(48	)	(47	)%
Depletion	298		322		(24		)	(7	)%
ARO accretion	84		91		(7		)	(8	)%
Total	$	436	$	515	$	(79	)	(15	)%

Depletion, depreciation, amortization, and accretion expenses decreased $79 thousand to $436 thousand, or $13/bbl, during the six months ended December 31, 2015, compared to $515 thousand or $13/bbl in the prior year period. The change was primarily due to a $48 thousand decrease in depreciation due to assets that became fully depreciated in the current period. Depletion decreased $24 thousand as the result of lower production during the current year. The depletion rate increased from $8/bbl to $9/bbl due to excluding previously booked PUD reserves in the depletion calculation for the six months ended December 31, 2015.

Exploration Expenses. Exploration expenses decreased by $651 thousand to $257 thousand, or $8/bbl, during the six months ended December 31, 2015. The decrease was primarily the result of a reduction in expenditures related to the Company's activities in the UK in the current year period.

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



	December 31,
	2015		2014		Difference			Percent change
	(In thousands)
General and administrative (excluding stock based compensation expense and foreign transaction gain)	$	2,843	$	4,099	$	(1,256	)	(31	)%
Stock compensation expense	307		427		(120		)	(28	)%
Foreign transaction gain from investment in subsidiaries	53		—		53			NA
Total	$	3,203	$	4,526	$	(1,323	)	(29	)%

General and administrative expenses decreased by $1.3 million, or 29%, to $3.2 million during the six months ended December 31, 2015, compared to the prior year period. General and administrative expenses, excluding stock based compensation and foreign transaction gain, decreased by $1.3 million, or 31%, to $2.8 million. This decrease was primarily the result of reductions in expenses related to corporate office salaries and benefits of $258 thousand, director expense of $81 thousand, professional fees of $362 thousand, travel of $92 thousand, franchise taxes of $119 thousand, and salaries in Australia of $666 thousand, which were partially offset by an accrual for the payment of retention bonuses to certain administrative employees of $425 thousand. Stock compensation expense decreased $120 thousand as a result of expense reversals for options forfeited by former employees and changes in the performance target dates for certain PBOs.

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 (gain) loss from investment in subsidiaries; (iv) stock based compensation expense; (v) (gain) loss on investment in securities; (vi) net interest expense; (vii) other (income) expense; and (viii) income tax expense (benefit). Adjusted EBITDAX is not a measure of net income (loss) 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 historical 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 loss to Adjusted EBITDAX for the following periods:



	THREE MONTHS ENDED						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
	(In thousands)
Net loss	$	(1,380	)	$	(2,885	)	$	(4,443	)	$	(5,513	)
Depletion, depreciation, amortization, and accretion expense	238			260			436			515
Exploration expense	10			486			257			908
Foreign transaction (gain) loss from investment in subsidiaries	(92		)	—			53			—
Stock based compensation expense	199			383			307			427
(Gain) loss on investment in securities	(118		)	—			143			—
Net interest expense	72			17			139			17
Other income	(82		)	(20		)	(106		)	(82		)
Income tax expense (benefit)	—			—			—			—
Adjusted EBITDAX	$	(1,153	)	$	(1,759	)	$	(3,214	)	$	(3,728	)

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, (ii) general and administrative expense; plus (iii) foreign transaction (gain) loss from investment in subsidiaries, and (iv) stock based compensation expense.

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



	THREE MONTHS ENDED						SIX MONTHS ENDED
	December 31,						December 31,
	2015			2014			2015			2014
	(In thousands)
REVENUE FROM OIL PRODUCTION	$	566		$	1,265		$	1,215		$	2,855
Less:
Lease operating	(601		)	(1,270		)	(1,586		)	(2,484		)
General and administrative	(1,225		)	(2,137		)	(3,203		)	(4,526		)
Plus:
Foreign transaction (gain) loss from investment in subsidiaries	(92		)	—			53			—
Stock based compensation expense	199			383			307			427
Adjusted EBITDAX	$	(1,153	)	$	(1,759	)	$	(3,214	)	$	(3,728	)

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 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. The decline in oil prices, as well as the Company's current liquidity constraints, has led the Company to curtail expenditures related to the CO₂-EOR Pilot project at Poplar, and to delay indefinitely its plans for a development program related to the Company's undeveloped resource locations as of June 30, 2015 and December 31, 2015.

Based on our evaluation of the data collected from the CO₂-EOR pilot at Poplar, we concluded that the development of Poplar using CO₂-EOR will require significant capital to invest, the amount of which we estimate at several hundreds of millions of dollars, and that the economic viability will depend on a recovery of oil prices. Considering that the development of Poplar is expected to span over several decades and the incremental volume of oil potentially recoverable from Poplar using

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CO₂-EOR, we believe that, despite the current depressed commodity price environment, Poplar should be attractive to potential investors that would have a long term view of the oil industry and commodity prices.

During the fourth quarter of fiscal year 2015, the Company recorded an impairment of its proved oil and gas properties of $17.4 million. As a result of continued declines in oil prices during the three months ended December 31, 2015, the Company undertook an impairment review of the recoverability of the carrying value of its proved oil and gas properties. The review included comparing the carrying value of its proved oil and gas properties to the expected undiscounted future cash flows of its proved developed producing and proved developed non-producing reserves using the December 31, 2015 WTI forward price curve and the current differential. As of December 31, 2015, the expected undiscounted future cash flows exceeded the carrying value of the proved properties, and thus no further impairment adjustment was required. However, since December 31, 2015, oil prices have continued to decline, and on February 4, 2016, the Company performed a similar review using the WTI forward price curve and differential on that date, which indicated that the carrying value of its proved oil and gas properties exceeded the expected undiscounted future cash flows of its proved reserves, and thus the proved would be further impaired unless prices recover. While it is difficult to project future impairment adjustments due to the volatility of oil and gas prices and other variables involved, using the expected future cash flows discounted at 10% as an estimate of fair value on February 4, 2016, the Company would have had an additional impairment of approximately $13.2 million based on relevant price levels as of that date. The Company will continue to monitor its oil and gas properties for impairment, and unless expected future oil prices recover to the level they were at December 31, 2015, or a potential transaction occurs as a result of the strategic alternatives review process, or otherwise, the Company may record an additional impairment in the future.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Information regarding critical accounting policies and estimates is contained in Item 7 of our 2015 Form 10-K. There have been no changes to the Company's critical accounting policies during the six months ended December 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," "could," "estimate," "expect," "forecast," "initial," "intend," "may," "plan," "potential," "project," "should", "will," "would," and similar expressions are intended to identify forward looking statements. These forward looking statements about the Company and its subsidiaries appear in a number of places in this report and may relate to statements about our businesses and prospects, planned or estimated capital expenditures, including estimates of capital expenditures for the potential full field CO₂-EOR development of Poplar, 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, progress in developing the Company's projects, future values of those projects or other interests or rights that the Company holds, the process and progress of reviewing potential strategic alternatives for the Company, 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 CO₂-EOR techniques 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 CO₂injection, including the ability to sustain CO₂ pressures at sufficient effective levels to sweep the oil across the formation to production wells, and the ability to acquire a long term CO₂ supply for full field development; possible adverse changes to the CO₂-EOR industry; possible geologic or other obstacles to the further development of Poplar; possible geologic or other obstacles to obtaining the anticipated production from other 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 or otherwise continue as a going concern; uncertainties regarding the ability to realize the expected benefits from the sale of the Amadeus Basin assets to Central pursuant to the Sale Deed, including through the future value of Central stock; uncertainties regarding NEGI and its potential impact on the value of Central stock and the potential value of our Mereenie and Palm Valley gas sales bonus rights; 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

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reliance on the skill and expertise of third party service providers; the ability of our vendors to meet their contractual obligations; the uncertain nature of the anticipated value and underlying prospects of our UK acreage position; government regulation and oversight of drilling and completion activity in the UK, including possible restrictions on hydraulic fracturing that could affect our ability to realize value from unconventional resource projects in the UK; the uncertainty of drilling and completion conditions and results; the availability of drilling, completion, and operating equipment and services; the results and interpretation of 2-D and 3-D seismic data related to our NT/P82 interest in offshore Australia and our ability to obtain an attractive farmout arrangement for NT/P82; uncertainties regarding our ability to maintain the NASDAQ listing of our common stock, and the related potential impact on our ability to obtain financing; risks and uncertainties inherent in management estimates of future operating results and cash flows; risks and uncertainties associated with litigation matters, including the current legal proceeding initiated by Celtique; and other matters referred to in the Risk Factors section of this report. For a more complete discussion of the risk factors that may apply to any forward looking statements, you are directed to the discussion presented in Item 1A ("Risk Factors") of our 2015 Form 10-K. In addition, as of the filing date of this report, no final decision on any particular strategic alternative or transaction has been reached and there is no guarantee that any definitive agreement will be entered into or any future sale or other strategic transaction will occur. 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. With respect to any net proceeds from the planned farmout of NT/P82 in Australia, any appreciation of the US dollar against the Australian dollar is expected to result in decreased operating results. With respect to any net expenditures for 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 six months ended December 31, 2015, oil sales represented 100% of total revenues. Based on the current six month sales volumes and revenues, a 10% change in oil price would increase or decrease oil revenues by $57 thousand.

At December 31, 2015, the fair value of our investment in securities available for sale was $2.5 million, with all of that amount attributable to the 24.0 million shares held as of December 31, 2015 from the 39.5 million Central shares received initially 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 December 31, 2015, of AUD $0.145 per share, which translated to $0.106 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 investment would result in a $254 thousand change in the fair value of our investment.

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

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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 December 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 "Celtique Litigation" in Note 14 - 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 2015 Form 10-K sets forth information relating to important risks and uncertainties that could materially affect our business, financial condition, operating results, or cash flows. There have been no material changes in the Risk Factors described in such Form 10-K, 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.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

UNREGISTERED SALES OF EQUITY SECURITIES

Pursuant to the terms and conditions of the Certificate of Designations of Series A Preferred Stock dated May 17, 2013, as amended, on December 31, 2015, the Company issued 376,828 shares of its Series A Preferred Stock as quarterly PIK dividends with respect to the 21,533,044 shares of Series A Preferred Stock outstanding as of the record date of December 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 shares of the Company's Common Stock at a conversion price of $9.77586545, subject to customary anti-dilution provisions. For additional information regarding the Series A Preferred Stock, see Note 9 - 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

The table below provides information about purchases of the Company's common stock by the Company during the three months ended December 31, 2015.

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Period	Total Number of Shares Purchased		Average Price Paid per Share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs
October 1 - 31, 2015	—		$	—	—	—
November 1 - 30, 2015	—		—		—	—
December 1 - 31, 2015	2,398	⁽¹⁾	0.55		—	—
Total	2,398		$	0.55	—	—
(1) On December 31, 2015, upon the vesting of a total of 7,500 shares of restricted stock previously granted to executives of the Company and pursuant to the tax withholding provisions of the Company's restricted stock award agreements, the Company withheld on a cashless basis 2,398 shares to settle withholding taxes. The withheld shares were immediately canceled.

The payment of dividends on our Common Stock is subject to the rights of holders of our Series A Preferred Stock, which ranks senior to the Common Stock with respect to dividend rights. For additional information, see Note 9 of the Notes to condensed consolidated financial statements (unaudited) included under Part I, Item 1 of this report.

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).
2.3	Sale Agreement among Magellan Petroleum (NT) Pty Ltd, Santos QNT Pty Ltd, and Santos Limited, dated September 14, 2011 (filed as Exhibit 2.3 to the registrant's Quarterly Report on Form 10-Q filed on November 14, 2011 and incorporated herein by reference)
3.1	Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware, as amended by an Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware (filed as Exhibit 4.B. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference).
3.2	Certificate of Amendment of Restated Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware (filed as Exhibit 3(a) to the registrant's Quarterly Report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference).
3.3	Certificate of Amendment of Restated Certificate of Incorporation related to Articles Twelfth and Fourteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.3 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
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 Amendment of Restated Certificate of Incorporation as filed on July 10, 2015 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on July 10, 2015 and incorporated herein by reference)
3.7	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).
3.8	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).
3.9	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).

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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 Employment Agreement effective as of October 12, 2015 between Magellan Petroleum Corporation and Antoine J. Lafargue (filed as Exhibit 10.23 to the registrant’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015 and incorporated herein by reference).
10.2++	Restricted Stock Award Agreement effective as of October 12, 2015 between Magellan Petroleum Corporation and Antoine Lafargue (filed as Exhibit 10.24 to the registrant’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015 and incorporated herein by reference).
10.3++	Transaction Incentive Agreement effective as of October 12, 2015 between Magellan Petroleum Corporation and Antoine J. Lafargue (filed as Exhibit 10.25 to the registrant’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015 and incorporated herein by reference).
10.4++	Override Bonus Agreement effective as of October 12, 2015 between Magellan Petroleum Corporation and Antoine J. Lafargue (filed as Exhibit 10.26 to the registrant’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015 and incorporated herein by reference).
31.1 *	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 *	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 **	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 **	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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.


+	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:	February 12, 2016	By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)

Date:	February 12, 2016	By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue, Senior Vice President - Chief Financial Officer, Treasurer, and Corporate Secretary
			(as Principal Financial and Accounting Officer)